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.






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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 or 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 set 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.
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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 containing 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 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 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.

Additionally, there 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 Total Dissolved Solids. 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, 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.
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144.15 4. Adding § 144.15 to read as follows.

§ 144.15 Prohibition of nonexperimental Class V wells for 

geologic sequestration.

The construction, operation or 

maintenance of any non-experimental 

Class V geologic 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, III 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 VI wells 

through the end of the post closure monitoring 

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) introductory text to read 

as follows:

§ 144.39 Modification or revocation 

and reissuance of permits.

* * * * *

144.39 (a) * * * For Class I hazardous 
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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 sentence 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 this 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 notice 
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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 permit 

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, (other 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 injection 

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.* * *

* * * * *
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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, III, 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 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. 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. Wells 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 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 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 

See 144.6
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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 II.

146.25

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 

requirements:

(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). However, 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.

Part 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.
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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 gaseous, 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, 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 dioxide may occur during or in connection 

with EOR or EGR operations and/or activities.

See 144.6

Deleted ―gaseous, liquid or supercritical‖ 

because it was added to the definition of CO2 

stream.

(c) This subpart applies to 

owners and operators of permit or ruleauthorized 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).

(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 wells 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:

(c) This subpart applies to owners and 

operators of permit or rule-authorized Class I 

industrial, 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 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). Class VI 

requirements. Class II wells permitted for CO2 

injection and that have demonstrated MIT are 

exempt from the requirements at §§146.86 
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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 sound 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 this subpart. To the 

extent that these definitions conflict with 

those in § 146.3 these definitions govern:

Area of review means the region 

surrounding the 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 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. subsurface three-dimensional 

extent of the carbon dioxide plume, associated 

pressure 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 EPA. 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.

Carbon 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 or 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 

any physical state or form, and any associated

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 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 

Source of CO2 is not an issue 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. 

Original text would have precluded injection of 

CO2 from some sources. 
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part 261.

Confining zone means a geologic 

formation, group of formations, or part of 

a formation stratigraphically overlying the 

injection zone that acts as a barrier to 

fluid movement.

Corrective action means the use of 

Director approved methods to assure 

that wells within the area of review do not 

serve as conduits for the movement of 

fluids into underground sources of 

drinking water (USDW).

Geologic sequestration means the longterm containment of a gaseous, liquid or 

supercritical carbon dioxide stream in 

subsurface geologic formations. This 

term does not apply to its capture or 

transport.

Geologic sequestration 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.
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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 threedimensional extent of 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 lowermost formation 

containing a USDW into an injection zone 

exclusively for the purpose of geologic 

sequestration. It includes the subsurface threedimensional extent of the carbon dioxide plume, 

associated pressure front, and displaced brine, 

as well as the surface 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 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.

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 sequestration 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 associated 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 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.

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 

incorporated 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.
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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/time, 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 fault 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 allow 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 construction 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. Within 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 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, 

(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 location of all 

known injection wells, producing wells, 

abandoned wells, plugged wells or dry holes, 

deep stratagraphic 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 

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 

remove any implication that an applicant has 

to conduct studies to determine the location of 

wells that are not currently documented in 

some fashion. 
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if known or suspected. Only information

of public record 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 review

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 that 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 confining 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 with 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, 

permeability and capillary pressure of the 

injection and confining zone(s); including 

geology/facies changes based on field 

data which may include geologic cores, 

outcrop data, seismic surveys, well logs, 

(3) Information on seismic history that 

have affected the proposed area of review,

including knowledge of previous seismic events,

including the presence and depth of seismic 

sources and a determination that the seismicity 

would not interfere with containment;

(4) Data on the depth, areal extent, 

thickness, mineralogy, porosity, permeability and

capillary reservoir pressure of the injection and 

confining zone(s) within the area of review; 

including geologic/facies changes based on field 

data which may 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 too 

hard to measure outside of the lab. Using 

sidewall cores, it may be difficult to determine 

capillary pressure. Additionally, full cores are 
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and names and lithologic descriptions;

(5) Geomechanical information 

on fractures, stress, ductility, rock 

strength, and in situ fluid pressures 

within the confining zone; and

(6) Geologic and topographic 

maps and cross sections illustrating 

regional geology, hydrogeology, and the 

geologic structure of the local area.

data, seismic surveys, well logs, and names and 

lithologic descriptions;

(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

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 wells 

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, location, 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 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; Potentiometric (water 

level) surface map(s) of existing aquifers being 

utilized as private 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 injection 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 CO2 leakage.
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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 analysis 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;

Technical 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 construction details of the well and 

surface wellhead construction.

This responsibility is best left with EPA.

Technical clarification.
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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 Director, 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.
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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 volumes 

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 contain the injected carbon dioxide 

stream and displaced formation fluids and allow 

injection at proposed maximum pressures and 

volumes without initiating or propagating 

fractures in the confining zone(s); and 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 

opportunities 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 interfere 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 

modeling 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 well as the overlying 

formations and surface area above that 

Edits make this provision consistent with the 

definition of ―Area of Review‖, which was 

revised. 
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the injected carbon dioxide stream. delineated region.

(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 

acceptable to the Director. As a part of 

the permit application for approval by the 

Director, the owner or operator must 

submit an area of review and corrective 

action plan that includes the following 

information:

(1) The method for delineating 

the area of review that meets the 

requirements of paragraph (c) of this 

section, including the model to be used, 

assumptions that will be made, and the 

site characterization data on which the 

model will be based;

(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 Director. As a part of 

the permit application, for approval by the 

Director the owner or operator must submit an 

area of review and corrective action plan that 

includes the following information:

Clarification.

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

(i) The minimum fixed frequency, 

not to exceed 10 years, the owner or 

operator proposes to reevaluate the area 

of review;

(ii) The monitoring and 

operational conditions that would warrant 

a reevaluation of the area of review prior 

to the next scheduled reevaluation as 

determined by the minimum fixed 

frequency established in paragraph 

(b)(2)(i) of this section.

(iii) How monitoring and 

operational data (e.g., injection rate and 

pressure) will be used to inform an area 

(i) The minimum fixed frequency, not to exceed 

10 years, the owner or operator proposes to 

reevaluate the area of review;

(ii) The monitoring and operational 

conditions that would warrant a reevaluation of 

the area of review prior to the next scheduled 

reevaluation as determined by the minimum fixed 

frequency established in paragraph (b)(2)(i) of 

this section.

(iii)(i) How monitoring and operational data (e.g., 

injection rate and pressure) will be used to inform 

an area of review reevaluation; and
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of review reevaluation; and

(iv) How corrective action will be 

conducted to meet the requirements of 

paragraph (d) of this section, including 

what corrective action will be performed 

prior to injection and what, if any, 

portions of the area of review will have 

corrective action addressed on a phased 

basis and how the phasing will be 

determined; how corrective action will be 

adjusted if there are changes in the area 

of review; and how site access will be 

guaranteed for future corrective action.

(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 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 boundaries 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) Predict, using computational 

modeling, the projected lateral and 

vertical migration of the carbon dioxide 

plume and formation fluids in the 

subsurface from the commencement of 

injection activities until the plume 

movement ceases, pressure differentials 

sufficient to cause the movement of 

injected fluids or formation fluids into a 

USDW are no longer present, or after a 

fixed time period as determined by the 

Director. The model must:

(1) Predict, using computational modeling, the 

projected lateral and vertical migration of the 

carbon dioxide plume and formation fluids in the 

subsurface from the commencement of injection 

activities until the plume movement ceases, 

pressure differentials sufficient to cause the 

movement of injected fluids or formation fluids 

into a USDW are no longer present, or 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 zone 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 additional 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. 
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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, and 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 

information the Director may require; and

.

(2) Using methods approved by the Director,

Identify 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 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 additional information 

the Director may require; and

Changed for consistency 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 abandoned 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 corrosion 

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 use of many conventional 

materials that might not meet the technical 

definition of ―corrosion resistant‖.
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(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.

(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.

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.

(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 or 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, as specified in the approved area of 

review and corrective action plan, or When 

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 

reevaluated 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 area 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 corrective 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, regardless of whether or not 

corrective action in the area of review is 

phased.
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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 

requirements of § 146.84), injection well 

plugging (that meets the requirements of 

§ 146.92), post-injection site care and 

site closure (that meets the requirements 

of § 146.93), and emergency and 

remedial response (that meets the 

requirements of

§ 146.94) in a manner prescribed by the 

Director until:

(1) The Director receives and 

approves the completed post-injection 

site care and site closure plan; and

(2) The Director determines that 

the site has reached the end of the postinjection site care period.

(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 site 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 to 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 postinjection site care and site closure plan 

(§ 146.93).

(b) The owner or operator must provide 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 bankruptcy, 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 carry 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 

has reason to believe that original the most 

Clarification.
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believe that the original demonstration is 

no longer adequate to cover the cost of 

injection well plugging (as required by § 

146.92) and post-injection site care and 

site closure (as required by § 146.93).

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. Injection well construction 

requirements

(a) General. The owner or 

operator must ensure that all Class VI 

wells are constructed and completed to:

(1) Prevent the 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;

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.;

The proposed changes reflect the nonendangerment 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, 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:

(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 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 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 geologic sequestration project 

could be different than the life of the well. 

Class VI well design should be based on the 

life of the well.
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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 specification 

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 stream 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 or 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 

sequestration 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 surface 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 is 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 involving 
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USDWs. annular casing pressure. Industry experience 

with CO2 EOR under the Class II program 

demonstrates the effectiveness of existing 

cementing procedures.

146.86(b) (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.

(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 

channels 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.

Experience with CO2 EOR under the Class 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) Characteristics of the carbon (ii) Composition of the carbon dioxide stream. There is no method for measurement of 
December 23, 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. The 

composition of the CO2 stream is more 

relevant to the design of a tubing and packer 

system. 

146.86(c)(2) (iii) Injection pressure;

(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 pressure;

(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 formation fluids in, 

all relevant geologic formations to assure 

conformance with the injection well 

construction requirements under § 

146.86, and to establish accurate 

baseline data against which future 

measurements may be compared. The 

owner or operator must submit to the 

Director a descriptive report prepared by 

a knowledgeable log analyst that 

includes an interpretation of the results of 

such logs and tests. At a minimum, such 

logs and tests must include:

(a) During the drilling and construction of a Class 

VI injection well, the owner or operator must run 

appropriate logs, surveys and tests to determine 

or verify the depth, thickness, porosity, 

permeability, and lithology of, and the salinity of 

any formation fluids in, all relevant geologic 

formations to assure 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 minimum, such logs 

and tests must include: The Director may require 

such logs and tests as may be needed 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 well progresses and these may include the 

following:

Obtaining the geologic information will not 

assure conformance with well construction 

requirements, just measure or evaluate it.

In well defined areas, these evaluations 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 

drilled, the logging of surface hole yields little 

useful additional information.

In particular, this change would allow the 

Director to reduce the requirements when 

multiple wells are installed for a project.
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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 

intervals to determine the location of the 

borehole and to assure that vertical 

avenues for fluid movement in the form 

of diverging holes are not created during 

drilling; and

146.87(a) (2) Before and upon installation 

of the surface casing:

(i) Resistivity, 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 unnecessary 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 density 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 change 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 conditions and risk-based factors for the 

given geology before the casing is installed; and

It is acceptable 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 provides more flexibility 

to select the appropriate log to demonstrate 
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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 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

(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 the Director whole 

cores or sidewall cores of the injection 

zone and confining system and formation 

fluid samples from the injection zone(s). 

The Director may accept cores from 

nearby wells if the owner or operator can 

demonstrate that core retrieval is not

possible and that such cores are 

representative of conditions at the well. 

The Director may require the owner or 

operator to core other formations in the 

borehole.

(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 properly 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 

operator 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.
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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 and 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 has 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 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 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.

The 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 

fracture 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 conducting 

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 well

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 realities 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 stimulation, 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 not 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 concerned 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, which is what really matters 
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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 confining 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 

certainty, 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 fluids 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 

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 

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 

where 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 outermost casing protecting USDWs and the 

well bore is prohibited.

(b) Injection of the CO2 stream 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. 
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(c) The owner or operator must 

fill the annulus between the tubing and 

the long string casing with a noncorrosive 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 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. 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 necessary 

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.
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146.88 (e) The owner or operator must 

install and use continuous recording 

devices to monitor: The injection 

pressure; the rate, volume, and 

temperature of the carbon dioxide 

stream; and the pressure on the annulus 

between the tubing and the long string 

casing and annulus fluid volume; and 

must install and use alarms and 

automatic down-hole shut-off systems, 

designed to alert the operator and shut-in 

the well when operating parameters such 

as annulus pressure, injection rate or 

other parameters approved by the 

Director diverge beyond permitted 

ranges and/or gradients specified in the 

permit;

(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 between 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 shutin the well when operating parameters such as 

injection 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 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 

tubing 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 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 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 immediately 

investigate and identify as expeditiously 

as possible the cause of the shutoff. If, 

upon such investigation, the well appears 

to be lacking mechanical integrity, or if 

monitoring required under paragraph (e) 

of this section otherwise indicates that 

the well may be lacking mechanical 

(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 

expeditiously as possible the cause of the 

shutoff. If, upon such investigation, the well 

appears to be lacking mechanical integrity, or if 

monitoring required under paragraph (e) of this 

section otherwise indicates that the well may be 

lacking mechanical integrity, the owner or 

operator must: 

Technical clarification given changes above.
December 23, 2008

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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 any 

unauthorized zone;

(3) Notify the Director within 24 

hours;

(4) Restore and demonstrate 

mechanical integrity to the satisfaction of 

the Director prior to resuming injection; 

and

(5) Notify the Director when 

injection can be expected to resume.

(3) Notify 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 pressure, 

rate, injected volumes, and pressure on 

the annulus between tubing and long 

stem casing and annulus fluid volume as 

specified in § 146.88(e);

(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 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 

specified in §146.88 (e);

Technical clarification.
December 23, 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 oxygenactivation 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 

available. 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 it 

requires the tubing to be pulled 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 

mechanical integrity other than those 

listed above with the written approval of 

the Administrator. To obtain approval, 

the Director must submit a written 

request to the Administrator, which must 

set forth the proposed test and all 

technical data supporting its use. The 

Administrator must approve the request if 

it will reliably demonstrate the 

mechanical integrity of wells for which its 

use is proposed. Any alternate method 

approved by the Administrator will be 

published in the Federal Register and 

may be used in all States in accordance 

with applicable State law unless its use is 

restricted at the time of approval by the 

Administrator.
December

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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, the 

owner or operator and the Director must 

apply methods and standards generally 

accepted in the industry. When the 

owner or operator reports the results of 

mechanical integrity tests to the Director, 

he/she shall include a description of the 

test(s) and the method(s) used. In 

making his/her evaluation, the Director 

must review monitoring and other test 

data submitted since the previous 

evaluation.

(f) The Director may require 

additional or alternative tests if the 

results presented by the owner or operator under paragraph (d) of this 

section are not satisfactory to the 

Director to demonstrate that there is no 

significant leak in the casing, tubing or 

packer or significant movement of fluid 

into or between USDWs resulting from 

the injection activity as stated in 

paragraphs (a)(1) and (2) of this section.

146.90 Testing and monitoring requirements

The owner or operator of a Class VI well 

must prepare, maintain, and comply with 

a testing and monitoring plan to verify 

that the geologic sequestration project is 

operating as permitted and is not 

endangering USDWs. The testing and 

monitoring plan must be submitted with 

the permit application, for Director 

approval, and must include a description 

of how the owner or operator will meet 

the requirements of this section. Testing 

and monitoring associated with geologic 

sequestration projects must, at a 

minimum, include:
December 23, 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 characteristics;

(b) Installation and use, except 

during well workovers as defined in § 

146.86(d), of continuous recording 

devices to monitor injection pressure, 

rate and volume; the pressure on the 

annulus between the tubing and the long 

string casing; and the annulus fluid 

volume;

(b) Installation and use, except during well 

workovers as defined in §146.88(d), of 

continuous recording monitoring devices 

(including digital devices capturing periodic data)

to monitor injection pressure, rate and volume; 

and record 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 

continuous 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-specific 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 performed on 

a quarterly basis to ensure that the well 

components meet the minimum 

standards for material strength and 

performance set forth in § 146.86(b) by:

(c) Where conditions warrant, corrosion 

monitoring of the well materials for loss of mass, 

thickness, cracking, 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 to 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 

construction materials in contact with the 

carbon dioxide stream; or

(2) Routing the carbon dioxide 

stream through a loop constructed with 

the material used in the well; or

(3) Using an alternative method 

approved by the Director;

(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 inspecting the materials in the loop; or 

(3) Using an alternative method, materials, or 

time period approved by the Director; 

Clarifying edits.
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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 through the confining zone or 

additional identified zones:

(1) The location and number of 

monitoring wells must be based on 

specific information about the geologic 

sequestration project, including injection 

rate and volume, geology, the presence 

of artificial penetrations and other 

factors;

(2) The monitoring frequency 

and spatial distribution of monitoring 

wells must be based on baseline 

geochemical data that has been 

collected under § 146.82(a)(6) and any 

modeling results in the area of review 

evaluation required 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 

carbon 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 geophysical 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 § 

146.89(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 demonstration 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 dynamics 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 

detection tools);

(g) Testing and monitoring as appropriate to 

support the model for to tracking 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.
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146.90 (h) At the Director‘s discretion, 

surface air monitoring and/or soil gas 

monitoring to detect movement of carbon 

dioxide that could endanger a USDW.

(h) At the Director‘s discretion based on sitespecific 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 spatial distribution of surface air 

monitoring and/or soil gas monitoring 

must reflect baseline data and the 

monitoring plan must include how the 

proposed monitoring will yield useful 

information on the area of review 

delineation and/or compliance with 

standards under 40 CFR 144.12;

(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 monitoring, as 

required by the Director, necessary to 

support, upgrade, and improve 

computational modeling of the area of 

review evaluation required under § 

146.84(b) and to determine compliance 

with standards under 40 CFR 144.12; 

and

(j) A quality assurance and 

surveillance plan for all testing and 

monitoring requirements.

(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 characteristics 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 will 
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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 description 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 volume 

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 significant 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 with 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 pressure, 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.
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determine bottomhole reservoir pressure, 

and perform a final mechanical integrity 

test.

materials remaining. 

146.92(b) (b) Well Plugging Plan. The 

owner or operator of a Class VI well must 

prepare, maintain, and comply with a 

plan that is acceptable to the Director. 

The requirement to maintain and 

implement an approved plan is directly 

enforceable regardless of whether the 

requirement is a condition of the permit. 

The well plugging plan must be 

submitted as part of the permit 

application and must include the 

following information:

(1) Appropriate test or measure 

to determine bottomhole reservoir 

pressure; 

(2) Appropriate testing methods 

to ensure mechanical integrity as 

specified in § 146.89;

(3) The type and number of 

plugs to be used;

(4) The placement of each plug 

including the elevation of the top and 

bottom of each plug;

(5) The type and grade and 

quantity of material to be used in 

plugging. The material must be 

compatible with the carbon dioxide 

stream; and

(6) The method of placement of 

the plugs.

(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) Notice of intent to plug. The 

owner or operator must notify the 

Director at least 60 days before plugging 

of a well. At this time, if any changes 

have been made to the original well 

plugging plan, the owner or operator 

must also provide the revised well 
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plugging 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 submit a plugging report to the 

Director. If the semi-annual report is due 

less than 15 days after completion of 

plugging, then the report must be 

submitted within 60 days after plugging. 

The report must be certified as accurate 

by the owner or operator and by the 

person who performed the plugging 

operation (if other than the owner or 

operator.)

(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 must be submitted 

within 60 days after plugging. The report must 

be certified as accurate by the owner or operator 

and by the person who performed the plugging 

operation (if other than the owner or operator.) 

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 postinjection site care and site closure plan as a part 

of the permit application to be approved by the 

Director. shall continue to conduct monitoring 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 closure 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 preinjection 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)
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(ii) The predicted position of the 

carbon dioxide plume and associated 

pressure front at site closure as 

demonstrated in the area of review 

evaluation required under § 146.84(b);

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 postinjection site care and site closure plan 

or demonstrate to the Director through 

monitoring data and modeling results 

that no amendment to the plan is 

needed.

(4) The owner or operator may 

modify and resubmit the post-injection 

site care and site closure plan for the 

Director‘s approval within 30 days of 

such change.

(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 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 demonstrate that USDWs are not 

being endangered.

(1) The owner or operator shall 

continue to conduct monitoring as 

specified in the Director-approved postinjection 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 Directorapproved 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 

API, along with the MSDG, believes 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 

counterproductive. A straight performance 

standard is preferable to this or any other 

fixed time period because 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. Cessation of plume movement is 

not necessarily essential to show that a 
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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 what the operator must show.

API, in concert with the MSDG, recommends

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 the requisite 

information to make the appropriate 

determination. The advantage of this 

approach is that it establishes clear criteria 

that an operator must demonstrate 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 fixedduration. Furthermore, it is more stringent 

than a purely discretionary approach 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.
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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 sequestration project no 

longer poses an endangerment to 

USDWs, the Director may approve an 

amendment to the post-injection site care 

and site closure plan to reduce the 

frequency of monitoring or may authorize 

site closure before the end of the 50-year 

period.

(2) If The 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 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.

(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 sitespecific data, that the carbon dioxide 

plume and pressure front have stabilized 

and that no additional monitoring is 

needed to assure that the geologic 

sequestration project does not pose an 

endangerment to USDWs.

(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-specific 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 demonstrates, based 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 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 zone 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.
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(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.

(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 necessary 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 site closure 

plan, the owner or operator must also 

provide the revised plan. At the 

discretion of the Director, a shorter notice 

period may be allowed.

146.93(d) (d) After the Director has 

authorized site closure, the owner or 

operator must plug all monitoring wells in 

a manner which will not allow movement 

of injection or formation fluids that 

endangers a USDW.

(e) Once the Director has 

authorized site closure, the owner or 

operator must submit a site closure 

report within 90 days that must thereafter 

be retained at a location designated by 

the Director. The report must include:

(1) Documentation of appropriate 

injection and monitoring well plugging as 

specified in § 146.92 and paragraph (c) 

of this section. 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 authorizesd site 

closure, the owner or operator must submit a site 

closure report within 90 days that must thereafter 

be retained at a location designated by the 

Director. 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 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(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 the steward of 

information for the project.
December

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Regional Office;

(2) Documentation of appropriate 

notification and information to such 

State, local and tribal authorities as have 

authority over drilling activities to enable 

such State and local authorities to 

impose appropriate conditions on 

subsequent drilling activities that may 

penetrate the injection and confining 

zone(s); and

(3) Records reflecting the nature, 

composition and volume of the carbon 

dioxide stream.

146.93 (f) Each owner or operator of a 

Class VI injection well must record a 

notation on the deed to the facility 

property or any other document that is 

normally examined during title search 

that will in perpetuity provide any 

potential purchaser of the property the 

following information:

(1) The fact that land has been 

used to sequester carbon dioxide;

(2) The name of the State 

agency, local authority, and/or tribe with 

which the survey plat was filed, as well 

as the address of the Regional 

Environmental Protection Agency Office 

to which it was submitted; and

(3) The volume of fluid injected, 

the injection zone or zones into which it 

was injected, and the period over which 

injection occurred.

(g) The owner or operator must 

retain for three years following site 

closure, records collected during the 
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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. Emergency and remedial response.

(a) As part of the permit 

application, the owner or operator must 

provide the Director with an emergency 

and remedial response plan that 

describes actions to be taken to address 

movement of the injection or formation 

fluids that may cause an endangerment 

to a USDW during construction, 

operation, closure and post-closure 

periods.

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

obtains evidence that the injected carbon 

dioxide stream and associated pressure 

front may cause an endangerment to a 

USDW, the owner or operator must:

(1) Immediately cease injection;

(2) Take all steps reasonably 

necessary to identify and characterize 

any release;

(3) Notify the Director within 24 

hours; and

(4) Implement the emergency 

and remedial response plan approved by 

the Director.

(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 becoming 

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 to 

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 to 
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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 supports 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. 

EPA 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 EOR 

continues to be handled under the Class II program. 

Additionally, API supports 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 proposes 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 performance 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.

Restricting injection to formations 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 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, 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.
2

Rule Provisions EPA Preamble Question API Response

146.81(b)

146.81(d)

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 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 VI 

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 is 

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 original 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 

management 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 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.

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 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 CO2 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 

considerations 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 provide 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 pressure 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 shown 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 proposed 

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

146.90(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 of 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 

sole basis for determining the AoR. Other 

technologies such 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 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 models (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 proprietary 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 peerreviewed studies to model CO2 sequestration. 

When using a proprietary model, owners or 

operators should 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 proprietary models should be allowed. EPA’s

Confidential Business Information 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 inform 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 injection 

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 to 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 

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. 

API opposes the requirement for cementing 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 

operators 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 grandfathering 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 

demonstrated 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 deemed to meet the 

requirements of 146.86 and 146.87 upon notification.

The purpose of grandfathering 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 under 
5

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 43509.

Drilling of directional and 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 horizontal 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 purposes 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 predict 

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 Notice 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 strength 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 tubing 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 pulling the devise by wireline or by pulling the 

entire tubing string depending on the type of devise 
6

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 injection 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 lowermost 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 injection formation. Retaining 

the restriction would remove a significant 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, 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, 

when 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 injection, 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-specific 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 depth 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 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 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. 

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.

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 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-specific basis). Recording should generally 

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 level of 

risk posed by the injection operation.

146,89(c)

146,90(e)

29. EPA seeks 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 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, 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 flexibility 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 with 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 

relatively 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 

operational injection. Following the first year, the 

frequency should be at the discretion of the Director 

but the frequency should be aligned with the 
8

Rule Provisions EPA Preamble Question API Response

reevaluation of the AoR. 

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

EPA believes that tracking the 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 Notice 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 from the injection formation 

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 usefulness of indirect 

geophysical monitoring and surface air and soil 

gas monitoring. In addition, EPA seeks 

comment regarding the use of a Directorapproved monitoring plan for GS sites. EPA 

Notice 43517.

Monitoring techniques and frequency should be 

determined 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 does not add value 

to the protection of USDWs. Many of the surface 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 defer 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 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. EPA seeks comment on the merits 

of requiring plans for monitoring, AoR, and postinjection 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 permit 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. 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 monitoring plan at

the start of the project, particularly considering that 

these activities will not occur for many years after the 

project starts.

146.91 35. EPA seeks comment on the frequency 

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 with 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 reporting 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 electronic 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 annual 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 report. 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 shorten 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-year 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 operations. Criteria for determining the period 

for post-injection site care should be performancebased 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, postinjection site care, and site closure, including 

the proposed requirements for the post-injection 

time 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 should 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 financial 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 period 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, consistent 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 appropriate 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 guidance 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 companies using a selfguarantee, 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 current 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 response 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 participation 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 public 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 

characterization stage of a GS project, particularly 

given that many sites might be characterized in the 

process of winnowing down the portfolio of potential 

sites. 

73 FR 43523 48. To gain authority 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, 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 requirements. 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, 

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 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 classes 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 Agency 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 characteristics. 

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 three 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 

necessary.

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

To: Steve Crookshank; American Petroleum Institute

From: Michael Godec; Advanced Resources International, Inc.

Date: 10/17/2008

Re: Comments re the EPA’s Preliminary Cost Analyses for Underground Injection of 

CO2 for the Purpose of Geologic Sequestration

On July 25, 2008, EPA published proposed federal requirements under the Safe 

Drinking Water Act (SDWA) for underground injection of carbon dioxide (CO2) 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 these proposed requirements.

This memo summarizes the results of our review of the two main documents serving to 

support the EPA benefit/cost analyses:

“Geologic CO2 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 be 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 examples 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 requires. The 

rule contains over four pages 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. 43492-43541, (July 25, 2008)
October 17, 2008

2

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

Demonstration that the injection zone is: (1) sufficiently porous to receive the CO2

without fracturing and (2) extensive enough to receive 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 demonstrate the lateral extent and thickness, strength, capacity, 

porosity, and permeability of subsurface formations. They must demonstrate that the

injection zone 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 

displacing 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 “pinchouts” (i.e., thinning or tapering out) can affect storage potential, would need to be 

examined.

Data on the local geologic structure, including information on the presence of any 

faults and fractures that transect the confining zone and a demonstration that they 

would not interfere with containment. These data are to support determinations 

about whether these features, 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, 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. Information on insitu 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 techniques 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 subsurface 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 pressure 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 CO2 and displaced brines.

Demonstration of the maximum sustainable injection pressures that will not cause 

unpermitted fluid movement, in order to assure that owners or operators not exceed 

an injection pressure that would initiate or propagate fractures in the confining zone.

This should be based on geomechanical studies of fault stability and rock 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, 2008

3

Information on the geochemistry of formation 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 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. Owners or operators are to submit geochemical data on a) the 

injection zone, b) the confining zones, c) containment zones above the confining 

zones 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 proposed monitoring 

program. 

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-months 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 International 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, meeting 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. No 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 permitting 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 CO2 Storage Reservoirs, 

IEA/CON/04/108, Report prepared for the IEA Greenhouse Gas R&D Programme, January 17, 2007
October 17, 2008

4

Financial Responsibility Requirements

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 rule 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 some 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 

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 saline 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 characterization (cross 

sections, performing inter-well seismic, 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 often 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 EPA 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, while 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 year, and a 

“representative” engineer’s salary of $44,000 to $56,000 per year.
October 17, 2008

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 assignments 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 engineering tasks associated 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. 

The 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 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 types of activities) where the 

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.

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 are 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 the order of about $60,000 per GS site.

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, importantly, the situation where demand for well drilling 

services in the GS industry expands 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. 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 costs associated with well drilling and completion increases

the range to from $280 to $320 per foot for a 9,000 foot well.

 

3

http://www.aapg.org/explorer/salarysurvey.cfm

4

http://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/Salary
October 17, 2008

6

According to the latest drilling cost survey by the American Petroleum Institute (for 

2006):

7

The average costs of drilling and completing 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 to 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 CO2, today’s proposal includes enhancements to typical 

deep well construction procedures to provide 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 

 

7

American Petroleum Institute, 2006 Joint Association Survey on Drilling Costs, April 2008
October 17, 2008

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 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.

EPA appears not to consider the costs of surface equipment associated with CO2

injection operations

In addition to the Injection wells, additional surface equipment can often be associated 

with CO2 injection operations. These costs include CO2 storage vessels, high pressure 

pumps and vaporizers, distribution/production headers, and CO2 distribution lines when 

multiple injection wells are needed. It is not apparent that all of these costs are included 

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 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 conditions, 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 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 

regional incentive programs.8

EPA does recognize that alternative assumptions about the future deployment of 

projects could dramatically change the potential costs of the proposed rule,9and 

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 5-33
October 17, 2008

8

Nonetheless, this appears to be 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 technologies could potentially represent a significant percentage of the 

cumulative effort for reducing CO2 emissions worldwide.”

Moreover, the draft of the proposed GS rule goes on to say:

“Establishing a supporting regulatory framework 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 cost analyses 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 drafting 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 framework 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 standards aimed at protecting underground 

sources of drinking water (USDWs). 

API also appreciated EPA extending the comment period. During that time, API has 

Individual Response: EPA acknowledges the comment. EPA recognizes that the oil and gas 

industry has decades of experience injecting CO2 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 nature 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 regulatory approach, please see the final rule and 

preamble, including the discussion of the repermitting 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 sections of the proposed rule, including 

the lowermost USDW restriction, the 50-year post-injection site care 

requirement, the well construction and 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. Please see the remainder of EPA's 

responses to this letter for further details. 

Letter ID: 0170 Comment ID: 24119 Letter Lines: 84 to 91 

1
Comment 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, construction, 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 the 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 are not designed to provide the type of 

isolation envisioned by the EPA. 

Individual Response: After evaluating the risks and benefits of down-hole shut-off systems and 

considering additional research, EPA will not require automatic down-hole shut-off devices for 

onshore Class VI wells since it is not necessary in all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

warrant their use. However, the Agency believes that offshore Class VI wells present unique 

construction and operational conditions, including isolation from shorelines and the need to 

construct wells through the water column and the subsurface, which may delay response time in 

the event of well difficulties. The rule requires, at §146.88(e)(3), that owners or operators of 

offshore wells within State territorial waters install automatic down-hole shut-off systems. EPA 

believes that these requirements at §146.88(e) ensure that proper precautions are taken to prevent 

subsurface fluid movement and ensure protection of USDWs. 

EPA clarifies that down-hole shut-off devices are currently used in situations where loss of well 

integrity could result in damage to the well or harm to humans (e.g., near high-density population 

areas, or in onshore acid gas injection; IEA, 2003). EPA has identified examples of documented 

logging techniques, including ultrasonic and temperature logs, that 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 received. 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 conducted since most Class VI projects will 

2
not be oil and gas related and so would 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 available at the time the owner or operator develops their initial 

permit application. In response to comments and based on an evaluation of the proposed 

requirements at §146.82, the Agency revised this subpart so that the final regulation specifies 

separate requirements for information to be submitted with the permit application and before 

well construction is approved (at §146.82(a)) and information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

EPA believes that this revision of §146.82 addresses commenters' concerns regarding the timing 

of information to be submitted. In addition, section §146.82 in the final rule is similar to the 

permit application requirements for other injection well classes, which could help avoid 

confusion about how to meet the permitting requirements for Class VI wells. The requirements at 

§146.82(c) for information to be submitted before operation of the well is authorized are very 

similar to those for Class I wells, with modifications and additions that address the unique 

challenges and types of data collected for GS wells. 

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 formations 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 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. 

Individual Response: EPA acknowledges that there are limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. The final GS rule at §146.95 

establishes a process by which owners or operators can seek a waiver of the Class VI injection 

depth requirements for injection into non-USDW formations above and/or between USDWs. 

Additionally, the final GS rule does not categorically preclude or prohibit injection into any type 

of formation. 

EPA believes that these requirements will ensure USDW protection while providing flexibility to 

UIC program Directors and owners or operators who undertake CO2 injection for GS. The 

3
Agency believes this approach: 1) responds to concerns about local and regional geologic storage 

capacity limitations imposed by the proposed injection depth requirements; 2) allows for a more 

site-specific assessment of injection depth for GS projects; 3) accommodates injection into 

different formation types; 4) allows for injection of CO2 for GS into non-USDWs above and/or 

between USDWs when appropriate and where it can be demonstrated that USDWs will be 

protected; and 5) responds to concerns about the use of aquifer exemptions for GS. Finally, 

EPA’s approach to addressing injection depth variability through a waiver process responds to 

concerns about future drinking water resource availability and the need to ensure that highquality water remains available in sufficient quantities to supply drinking water needs. 

For additional information on the waiver approach, please see the final rule and preamble, as 

well as EPA's responses to comments on the Notice of Data Availability and Request for 

Comment. 

Letter ID: 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 proposed 50-year default period for 

post-injection site care. EPA offers no rationale for this arbitrarily-selected 

period of 50 years. Establishing a fixed and unusually long time period, even 

with the Director discretion provided, may create a significant barrier for 

operators considering 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 relative risk of the project. 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. 

A related concern is that EPA is proposing 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 estimated and assumed to be relatively 

accurate going forward. If not, financial assurance is no better than a guess, 

and serves only to introduce significant uncertainties into project economics 

and project finance. 

Individual Response: EPA disagrees that a post-injection site 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, industry reports, and existing environmental programs. This analysis 

was included in an EPA-prepared background document that is available in the federal docket, 

4
titled "Computational Modeling of Underground Injection of Carbon Dioxide for Determination 

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

assessed various default timeframes based on additional review of research studies and 

evaluation of public comments. While numerous commenters suggested that EPA shorten the 

monitoring timeframe, none of the commenters provided sufficient data or other evidence to 

warrant a change in the proposed timeframe. While the 10- or 30-year timeframe suggested by 

some of these commenters may be within the timeframe suggested in some studies, EPA believes 

that the potential risks of endangering USDWs will likely not decline within these timeframes 

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

timeframe. 

However, EPA recognizes that alternative timeframes may be appropriate under limited, specific 

circumstances. 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 during the PISC period based on site-specific data, pursuant to 

requirements at §146.93(b); or (2) affording the Director discretion to allow a Class VI well 

owner or operator to demonstrate, based on substantial data during the permitting process, that an 

alternative PISC timeframe may be appropriate if it ensures non-endangerment of USDWs 

pursuant to requirements at §146.93(c). 

EPA believes that a 50 year post-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. Furthermore, 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 challenges associated with assuring funding for activities that will 

occur far in the future. However, the Agency believes that in order to protect USDWs from 

endangerment under the SDWA, operators must demonstrate under §146.85 that financial 

resources are available to plug the injection well and provide post-injection site care at the point 

in time that the first CO2 is injected. 

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 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. 

5
Individual Response: EPA believes that many site-specific factors will influence the 

determination of when the CO2 plume and pressure front no longer pose a risk of endangerment 

to USDWs, and therefore is not defining the criteria in the final rule. It is for this reason that 

EPA believes that individual UIC Directors, in consultation with operators, will be in the best 

position to determine whether additional post-injection site care is needed. EPA expects this 

decision to be made based on relevant site data and in consultation with all potentially impacted 

parties. 

The post-injection site care requirements in the final GS rule incorporate a combination of a 

fixed timeframe 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 

site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion 

to allow a Class VI well owner or operator to demonstrate, during the permitting process based 

on substantial data, that an alternative PISC timeframe may be appropriate if it ensures 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 proposed well plugging plans and post-injection site 

care and site closure plans under 146.92 and 146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells; demonstrate 

the appropriateness of an alternative post-injection site care time frame; perform post-injection 

monitoring; demonstrate non endangerment; and perform site closure activities. The guidance 

will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 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 site care (seeking comment) 

Comment: A related concern is that EPA is proposing 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 estimated and assumed to be relatively 

accurate going forward. If not, financial assurance is no better than a guess, 

and serves only to introduce significant 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 available 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 

6
activities, thereby realizing greater flexibility and cost savings from this regulation. In the event 

that the owner or operator combines 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 adjust 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 adequate, as specified at §146.85(e). 

In order to assist owners or operators and financial institutions in achieving accurate cost 

estimates for all GS activities, EPA plans to issue financial responsibility guidance that will 

include a discussion of how to estimate costs, including 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. This 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 estimating methods are likely to change and improve 

as GS is deployed nationwide. However, EPA believes that past injection 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 responsibility 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 proposed well construction and operation 

requirements which are much more prescriptive 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 that EPA is proposing. The Class II EOR 

wells constructed for CO2 injection projects - and their operating practices - 

have an excellent record of mechanical integrity and protecting USDWs. Recent 

7
research by the University of Texas, Bureau of Economic Geology presented at the 

Department of Energy's Regional Partnership meeting in Pittsburgh, PA in October 

2008 demonstrates that 35 years of CO2 injection 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 introduce unintended risks. For example, 

cementing the longstring casing to surface seals off access to the annulus which 

could otherwise be used to monitor subsurface formations for potential leakage. 

Individual Response: EPA disagrees that the well construction standards for Class VI wells are 

too stringent. Instead, the construction requirements at §146.86 provide an appropriate and 

necessary level of protection from endangerment to USDWs that is based upon the existing UIC 

framework for deep wells. The new tailored approach was designed to address 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 buoyancy of CO2, its corrosivity in 

the presence of water, the potential presence of impurities in captured CO2, and its mobility 

within subsurface geologic formations). EPA adds that promoting GS or carbon management 

efforts is outside the scope of the GS rulemaking, which focuses on protecting USDWs from 

endangerment. 

EPA does not believe that the cementing requirements at §146.86 would prevent annulus 

monitoring. 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 and 

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 additional 

information. Additionally, EPA is developing guidance on the construction of Class VI wells. 

This guidance will be available on EPA’s website at 

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

Letter ID: 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 introduce 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 

8
operators of onshore Class VI wells install automatic surface shut-off devices. The rule affords 

Director's discretion to mandate automatic down-hole shut-off devices in onshore situations that 

may warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore 

wells within State territorial waters install automatic down-hole shut-off systems. 

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 introduce unintended risks. For example, 

cementing the longstring casing to surface seals off access to the annulus which 

could otherwise be used to monitor subsurface formations for potential leakage. 

Individual Response: EPA does not believe that the cementing 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 and 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 additional information. Additionally, EPA is developing 

guidance on the construction of Class VI wells. This guidance will be available on EPA’s 

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

Letter ID: 0170 Comment ID: 24128 Letter Lines: 161 to 190 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: Differentiating Applicability of Class II versus Class VI Permits 

API supports the concept embodied in the preamble 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 27th ,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 distinguishing Class II EOR "business as 

usual" from other activities (see §146.5(b){4)). API proposes that wells used 

9
for GS in oil and gas reservoirs that do not meet the criteria proposed for 

§144.6{b)(4) be regulated under the Class II program since it would facilitate 

EOR operations transitioning to GS under 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 edits 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 Class 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 criteria 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 which is consistent with suggestions API 

had developed before discussions with the 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 Class II Program. EPA recognizes that the oil and 

gas industry has decades of experience injecting CO2 for the purpose of EOR, and that sites used 

for ER may be suitable for GS and may be among the first GS sites. 

However, the Agency disagrees that wells injecting 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 therefore has developed new Class VI regulations to 

address these unique risks. For example, the volume 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 operations involving large volumes of CO2 and likely 

having higher pressures within their storage formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. For more information, please see the discussion on 

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

Letter ID: 0170 Comment ID: 24129 Letter Lines: 192 to 204 

Comment Code: 5610 2.11.1 Allowing partial primacy for Class VI wells (seeking comment) 

10
Comment: State Primacy 

API contends that states and tribes should 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 absence of primacy for other well classes 

(partial primacy). Numerous states have decades of experience regulating CO2 

injection through Class II programs, and those 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 and so may want to pass on obtaining 

primacy for this program. 

Individual Response: EPA agrees that states should be allowed to obtain primacy for Class VI 

wells independently of other well classes, and will allow independent primacy for Class VI wells 

under §145.1(i) of the final GS rule. In the past, EPA has not accepted UIC primacy applications 

for individual well classes under Section 1422 of SDWA. In other words, if a State wanted 

primacy for Class I wells, the State would also need to accept responsibility 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 (encompassing capture, transportation, and geologic 

sequestration) to be an important part of a national priority to address climate change, EPA 

believes that providing states the flexibility to obtain primacy for Class VI wells independently 

of other well classes can help foster effective management of CCS. EPA believes that allowing 

independent Class VI primacy may encourage states to take responsibility for implementation of 

Class VI regulations and provide for a more comprehensive approach to managing CCS projects 

by promoting the integration of GS activities under SDWA into a broader framework for 

managing CCS. Furthermore, GS operations involve ancillary activities (e.g., pipeline 

operations, pore space ownership, land use rights, and surface access) for which states can call 

upon other authorities that exist at the state level (but outside UIC authority) to provide a more 

comprehensive CCS management approach. 

EPA also believes that allowing states to apply only for Class VI primacy will shorten the 

primacy approval process for states. It is very important to note that this shift in policy allowing 

for Class VI primacy does not apply to any other well Class under Section 1422. EPA will 

continue to discourage applications for partial primacy for all other well types under Section 

1422. 

EPA recognizes that some states may not have appropriate geology for sequestering CO2, and 

these states should be able to retain primacy for other well classes without incurring the cost and 

burden of adopting primacy changes to address the new Class VI well requirements. 

EPA clarifies that states should be able to obtain primacy for Class VI wells independent of other 

11
well classes provided they develop regulations that are at least as stringent as the minimum 

Federal requirements (e.g., permitting, inspection, 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 will be able to develop a primacy application for 

Class VI wells under section 1422 of SDWA and ensure that their GS programs integrate into 

national climate change priorities and protect USDWs from endangerment. 

EPA also 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 acquiring the resources, personnel, 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 that 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 are 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/Modeling CO2 movement 

Comment: Definition of Geological Sequestration Project (GSP) and Area of Review (AoR) 

EPA's definitions of GSP and AoR require alignment. 

Currently the GSP and AoR definitions confusingly use different wording to 

describe similar concepts. It is API's view that these definitions should be 

essentially the same. API offers languages 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 endangered by the injection activity. The area of 

review is delineated using computational modeling that accounts for the physical and chemical 

properties of all phases of the injected CO2 stream and is based on available site 

characterization, monitoring, and operational data. The definition in the proposed rule accounted 

for the varying physical and chemical properties of the CO2, including free-phase and waterdissolved CO2. The definition in the final rule will continue to do so. 

EPA is developing guidance on AoR and corrective action at GS Class VI sites to assist owners 

or operators and Directors in evaluating requirements and proposed AoR and corrective action 

plans under 146.84. The guidance describes EPA's recommended approaches for the data to be 

considered in an initial AoR delineation, how to apply computational modeling to delineate the 

AoR, performing corrective action at GS sites, and, when appropriate, completing AoR 

12
reevaluations. 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: 24131 Letter Lines: 214 to 235 

Comment Code: 5460 2.9.2 Comments on transfer of liability 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 feels it is important to offer some 

comments on this topic. API believes long-term responsibility management for 

decommissioned carbon storage sites is an issue that should be defined early in 

the planning process for a carbon capture and storage (CCS) project. A 

management system that ensures the responsible 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 storage site owner or operator to hold 

responsibility during the operational phases of the project through a reasonable 

post-closure monitoring period. With adequate demonstration of site integrity 

and stability, responsibility for the long term stewardship of the site should 

be transferred to a public entity (government, public trust, or other competent 

authority). Prior to transfer of this responsibility the site owner or operator 

should demonstrate the following: 1) compliance with the requirements of all 

applicable regulations, permits, and approvals relevant to the long term 

integrity of the site and 2) site integrity by reasonable and proven surface and 

subsurface monitoring for an appropriate period of time after the completion of 

injection operations or any subsequent remediation operations. 

Individual Response: EPA agrees that the issue of long-term liability management for GS sites 

is outside the scope of this rulemaking. 

Under the final GS rule, once an owner or operator has met all regulatory requirements under 

Part 146 for Class VI wells and the Director has approved site closure pursuant to requirements 

at §146.93, the owner or operator will generally no longer be subject to enforcement for 

regulatory noncompliance. Furthermore, 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 certain circumstances. For example, an owner or operator may be held liable for 

regulatory noncompliance even after site closure 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 regulatory compliance, an owner or operator may be 

13
subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner 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 present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner 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 operator may remain liable under tort and other 

remedies, or under other federal statutes including, 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 (performance-based standards) 

Comment: API shares the same goal as EPA: to develop rules that facilitate the safe, 

secure longterm storage of CO2. API is concerned though that by being overly 

restrictive in designing the new well class, the proposed rule will hinder the 

deployment of CCS and could have the unanticipated consequence of hindering the 

innovations that could improve both well security and performance. CCS is likely 

to be of one of the core technologies that could help to ensure that we can 

continue to produce the clean energy society 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 rule requires owners or operators to submit, and Directors to 

consider, extensive site-specific data, specified at §146.82, to demonstrate that a site is suitable 

for GS. Additionally, many of the permit requirements for GS wells are established through 

individualized site-specific plans for AoR and corrective action, 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 specific criteria to be met by the owner or operator and areas of 

Directorial discretion and considerations 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 providing 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 from endangerment. Encouraging investment in 

CCS projects and facilitating deployment are outside the scope of the GS rulemaking. 

14
Letter 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 injection 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 strikeout 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, GASES OR OTHER MEANS TO IMPROVE OR 

INCREASE 

EXTRACTION OF HYDROCARBONS. 

Rationale: The definition of EOR is necessary 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: typically, the process of injecting a fluid (e.g., water, brine, or CO2) 

into an oil or gas bearing formation to recover residual oil or natural gas. The injected fluid thins 

(decreases the viscosity) and/or displaces small amounts of extractable oil and 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 injection 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 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) 

15
OPERATING PRESSURES ARE NO HIGHER 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 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 Total Dissolved Solids. 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, 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 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 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. 

The Agency disagrees that wells injecting 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 therefore has developed new Class VI regulations to address 

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

storage is significantly greater than for ER operations. Reservoir pressure conditions will also be 

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

higher pressures within their storage formations than Class II ER projects. 

The final Class VI regulations require that any owner or operator injecting CO2 for the primary 

purpose of long term storage obtain a Class VI permit with some special consideration for the 

fact that they are transitioning from a well not originally designed to meet Class VI requirements. 

The Director has the authority to determine at what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

16
The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. For more information, please see the discussion on 

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

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

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

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

purpose is long-term storage of large volumes of CO2. The guidance describes the 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/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 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 Total Dissolved Solids. 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, 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: As described above, EPA agrees that it is not appropriate to set a 

minimum injection depth for GS projects and the Agency believes that a determination of sitesuitability for GS (i.e., that subsurface formations 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- 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 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/edits to rule language 

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

17
comment) 

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 Class 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 specifies that Class VI permits will be 

issued for the operating life of the facility and the post-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 modified, 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 operators’ iterative reevaluation of the project. Specifically, the final 

rule includes a requirement that the AoR be reevaluated 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 remedial response plan throughout 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 every 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 preventing 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 injection 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 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 

18
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) 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 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 disagrees 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 comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach 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 injection 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 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 

19
ARE NO HIGHER 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 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 

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 disagrees 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 comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach 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 circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs from endangerment, as long as 

appropriate protections are in place. However, EPA disagrees with the suggested addition to the 

regulation. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. It establishes: 1) requirements specifying information 

that owners or operators must submit, and Directors must consider, in consultation with PWSS 

Directors; 2) procedures for public notice of a waiver application and for Director-Regional 

Administrator communication; 3) the waiver issuance process; and, 4) additional requirements 

that apply to owners or operators of Class VI wells granted a waiver of the injection depth 

requirements to ensure USDW protection above and below the injection zone. 

Letter ID: 0170 Comment ID: 24139 Letter Lines: 364 to 382 

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

20
Comment Code: 2064 1.5.3.2 Grandfathering construction of Class II wells (seeking comment) 

Comment: Rule Provision: 146.25 GEOLOGIC SEQUESTRATION IN OIL OR GAS 

RESERVOIRS WITHOUT 

ENHANCED RECOVERY OF OIL OR NATURAL GAS 

API Comments: WELLS USED FOR GEOLOGIC 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, 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 

Rationale: 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). However, 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. 

Individual Response: As described above regarding the suggested edit at 144.6, EPA did not 

make the suggested change. The Agency disagrees 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 posed by GS while ensuring protection of USDWs 

from endangerment. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach 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/edits to rule language 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: API Comments: (b) This subpart applies to wells used to inject carbon dioxide 

21
EXCLUSIVELY 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 DIOXIDE MAY OCCUR DURING OR IN 

CONNECTION WITH 

EOR OR EGR OPERATIONS AND/OR ACTIVITIES. 

Rationale: See 144.6. Deleted "gaseous, liquid 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 disagrees 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 comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach 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/edits to rule language 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: 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 cementing requirements at §§ 146.86(b) and 

146.87(a)(1) through (3). 

Rationale: The reference to Class II wells 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 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 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). 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 program 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 Class II requirements. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach 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 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. 

SUBSURFACE THREE-DIMENSIONAL EXTENT OF THE CARBON DIOXIDE PLUME, 

ASSOCIATED 

PRESSURE FRONT, AS WELL AS THE OVERLYING FORMATIONS AND SURFACE 

AREA ABOVE THAT 

DELINEATED REGION. 

23
Rationale: 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 EPA. The EPA definition suggests 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 surface area and all subsurface 

formations below it that may potentially be impacted by injection activity. Acceptable 

delineation models will provide predictions of CO2 fate and transport, as well as changes in 

formation pressure in three dimensions as a function of time that can be used to delineate the 

subsurface storage site and the AoR. Although EPA 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 region surrounding the geologic sequestration project 

where USDWs may be endangered by the injection activity. The area of review is delineated 

using computational modeling that accounts for the physical and chemical properties of all 

phases of the injected CO2 stream and is based on available site characterization, monitoring, 

and operational data. EPA believes that this definition is sufficiently broad and describes both 

the intent of the computational modeling and the relationship of the AoR to areas that are subject 

to the risks associated 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 issues (seeking comment) 

Comment: Rule Provision: 146.81(d) [Definition - 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 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 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. 

Rationale: Source of CO2 is not an issue 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. 

Original text would have precluded injection of CO2 from some sources. 

Individual Response: The final GS rule retains the definition of a CO2 stream as proposed. The 

GS regulation applies to injection 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 

24
program’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 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. 

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 subsurface geologic formations. This term does not 

apply to carbon dioxide capture or transport.” 

The final definition of carbon dioxide stream also remains unchanged. Carbon dioxide stream is 

defined at §146.81(d) as: “[C]arbon 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 or 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.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 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 sequestration project means an injection well or wells 

used to emplace a carbon dioxide stream beneath the lowermost 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 surface area above that delineated region. 

25
Rationale: 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, 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 limited circumstances where injection 

above the lowermost USDW can be performed in a manner that protects USDWs from 

endangerment, as long as appropriate protections are in place. However, EPA disagrees with the 

suggested change. For additional information, please see the final rule at §146.95 and the 

preamble, as well as EPA's responses to comments on the Notice of Data 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 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 associated with a geologic sequestration project 

Rationale: 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. 

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 Class VI GS rule. Please see the 

final rule and preamble for additional information. 

26
Letter 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 discussion on EPA's final approach. EPA adds that the 

owner or operator must monitor as specified in the post-injection site care and site closure plan 

for at least 50 years or for the duration of the alternative timeframe approved by the Director 

pursuant to requirements in §146.93(c), unless the owner or operator can make a demonstration 

earlier that the geologic sequestration 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 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 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 formation fluids into a 

USDW.” 

Based on its evaluation of all public comments and input on the proposed rule and the NODA 

27
and Request for Comment, EPA has made many revisions to the Class VI GS rule. Please see the 

final rule and preamble for additional information. 

Letter ID: 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 point/time, 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. 

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 further 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 fracture 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 definition at §148.2, to address transmissive 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/edits to rule language 

28
Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

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 the applicable area of review. Within 

the area of review, the map must show the number, or name and location of all 

KNOWN injection wells, producing wells, abandoned wells, plugged wells or dry 

holes, deep STRATAGRAPHIC boreholes, State or EPA approved subsurface cleanup 

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

quarries, water wells and other pertinent surface features including structures 

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

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

included on this map; 

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 remove any implication that an applicant 

has to conduct studies to determine 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 evaluating permit requirements and applications under 

§146.82. The guidance provides recommendations regarding characterizing the regional geology 

and hydrogeology of a proposed GS site as well as performing the necessary 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/groundwater/uic/wells_sequestration.cfm. 

Please see the final rule and the discussion of geologic site characterization in the preamble for 

additional information. 

EPA acknowledges that some smaller fractures may not be detectable during the site 

characterization process, and clarifies that §146.82(a)(3)(ii) requires the owner or operator to 

submit data on known or suspected faults and fractures (i.e., not all fractures). Other 

requirements for GS injection wells and sites can mitigate the potential impacts of unidentified 

fractures. These include limitations on injection pressures to avoid propagation of existing 

fractures in the confining zone (§146.88(a)), collection and assessments of CO2 monitoring data 

at the site, and AoR reevaluations (§146.84(e)) to assess possible CO2 movement through high29
permeability 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 instance, 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 there is reason to believe 

that the incompleteness of available information 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/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(c) 

API Comments: (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 REVIEW 

Rationale: 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. 

Individual Response: EPA agrees that not all of the information listed at §146.82 of the 

proposed regulation will be available at the time the owner or operator develops their initial 

permit application. In response to comments and based on an evaluation of the proposed 

requirements at §146.82, the Agency revised this subpart so that the final regulation specifies 

separate requirements for information to be submitted with the permit application and before 

well construction is approved (at §146.82(a)) and information to be submitted before operation 

of the well is authorized (at §146.82(c)). 

The requirement to provide the final area of review based on modeling and data obtained during 

logging and testing is in the final GS rule at §146.82(c)(1). Please 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/edits to rule language 

Comment Code: 3130 2.1.3 Comments that operators should submit more (or different) 

geologic data than proposed 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

30
comment) 

Comment: Rule Provision: 146.82(d)(1) and (2) 

API Comments: (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 CONFINING 

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; 

Rationale: 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 with EPA. 

Rule Provision: 146.82(d)(3) 

API Comments: (3) Information on seismic history THAT HAVE AFFECTED THE 

PROPOSED 

AREA OF REVIEW, INCLUDING KNOWLEDGE OF PREVIOUS SEISMIC EVENTS, 

including the 

presence and depth of seismic sources and a determination that the seismicity 

would not interfere with containment; 

Rationale: Information on seismic history should have some degree of relevance 

to the project. This responsibility is best left with EPA. 

Rule Provision: 146.82(d)(4) 

API Comments: (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 

31
changes based on field data which may include geologic cores, outcrop data, 

seismic surveys, well logs, and names and lithologic descriptions; 

Rationale: Deleted capillary pressure because it is too hard to measure outside 

of the lab. Using sidewall cores, it may 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 process, and clarifies that §146.82(a)(3)(ii) requires the owner or 

operator to submit data on known or suspected faults and fractures (i.e., not all fractures). Other 

requirements for GS injection wells and sites can mitigate the potential impacts of unidentified 

fractures. These include limitations on injection pressures to avoid propagation of existing 

fractures in the confining zone (§146.88(a)), collection 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 authorized (at §146.82(c)). Final information on 

injection zone pressures would be required following drilling of the well, at §146.82(c)(4). 

EPA disagrees that information submitted with Class VI permit applications should be limited to 

known (i.e., previously available) data. Site-specific conditions may 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/edits to rule language 

Comment Code: 3100 2.1 Proposed Geologic Siting Requirements (40 CFR 146.83) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(e) 

API Comments: (e) A tabulation RECORD of all wells ARTIFICIAL 

32
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, location, depth, record 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 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; POTENTIOMETRIC (WATER LEVEL) 

SURFACE 

MAP(S) OF EXISTING AQUIFERS BEING UTILIZED AS PRIVATE 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. 

No rationale provided 

Rule Provision: 146.82(g) 

API Comments: (g) Baseline 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 monitored for potential CO2 leakage. 

Individual Response: As described above, EPA disagrees that the information that is submitted 

to support a Class VI permit application should be limited to known/available data. 

EPA believes that a thorough understanding of the hydrogeologic conditions of all USDWs in 

the AoR is necessary, and disagrees with the suggested edits because the GS rule, as written, 

affords flexibility to owners or operators and Directors to tailor the site characterization process 

to the unique features of the site. EPA encourages owners or operators and Directors to 

collaborate and consult during site characterization to discuss information needs and ensure that 

33
all appropriate data to assess the suitability of the site are collected. The Director has the 

authority to request additional hydrogeologic 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 all USDWs in the AoR, is appropriate and 

protective of USDWs. EPA believes that this data will support monitoring plan development, 

inform injectate fate and transport model development (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 baseline 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 are 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 subsurface 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/edits to rule language 

Comment Code: 3150 2.1.5 Comments on required permit information (40 CFR 146.82) 

Comment Code: 4710 2.7.1 Proposed submissions required for permit applications (seeking 

comment) 

Comment: Rule Provision: 146.82(h) 

API Comments: (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; 

Rationale: Technical clarifications. 

Rule Provision: 146.82(k) 

API Comments: (k) Proposed stimulation 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 the 

surface and of the subsurface construction details of the well AND SURFACE 

WELLHEAD CONSTRUCTION. 

34
Rationale: Technical clarification. 

Rule Provision: 146.82(q) 

API Comments: q) The ANY status of corrective action 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 support for parts of the requirements 

under 146.82. EPA disagrees with suggested technical 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 geologic 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/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0170 Comment ID: 24156 Letter Lines: 692 to 704 

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

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

trapping mechanism) 

Comment: Rule Provision: 146.83(a)(2) 

API Comments: (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 contain the injected carbon dioxide stream and displaced 

formation fluids and allow injection at proposed maximum pressures and volumes 

without initiating or propagating fractures in the confining zone(s); and OVER 

AN AREA SUFFICIENT TO PREVENT THE MOVEMENT OF INJECTED OR DISPLACED 

FLUIDS INTO 

A USDW; 

Rationale: 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. 

Individual Response: The Agency believes that the requirement 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 maximizes 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 

35
in the past. EPA adds that the Director must evaluate all geologic data on the site to ensure 

protection of USDWs from endangerment before approving a site for a GS project. 

Letter ID: 0170 Comment ID: 24157 Letter Lines: 706 to 715 

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

Comment Code: 3120 2.1.2 Need to identify additional confining and containment zones 

(seeking comment) 

Comment: Rule Provision: 146.83(b) 

API Comments: (b) At the Director‘s discretion, owners or operators of Class 

VI wells must identify and characterize additional zones that will impede 

vertical fluid movement, are free of faults and fractures that may interfere 

with containment, allow for pressure dissipation, and provide additional 

opportunities for monitoring, mitigation and remediation. 

Rationale: This paragraph creates a presumption that additional confining zones 

WILL be required. It is also redundant given the previous sections. 

Individual Response: EPA clarifies that secondary confining zones are not required for all GS 

sites. Rather, secondary confining zones are required when the Director 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 primary (i.e., lowermost) confining zone can 

improve USDW protection. These layers could further impede vertical fluid movement and 

allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and 

remediation. The Agency believes that providing the Director discretion will allow consideration 

of a range of sites for GS, based on site-specific conditions, and ensure USDW protection. EPA 

believes that requiring appropriate site characterization by the owner or operator (under §146.82) 

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

geologic data will afford the greatest protection of USDWs from endangerment. 

Letter ID: 0170 Comment ID: 24158 Letter Lines: 717 to 728 

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

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rule Provision: 146.84(a) 

API Comments: (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 

36
SUBSURFACE THREE-DIMENSIONAL EXTENT 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 consistent 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 CO2 fate and transport, as well as changes in 

formation pressure, in three dimensions as a function of time that can be used to delineate the 

subsurface storage site and the AoR. Although EPA 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 region surrounding the geologic sequestration project 

where USDWs may be endangered by the injection activity. The area of review is delineated 

using computational modeling that accounts for the physical and chemical properties of all 

phases of the injected CO2 stream and is based on available site characterization, monitoring, 

and operational data. EPA believes that this definition is sufficiently broad and describes both 

the intent of the computational modeling and the relationship of the AoR to areas that are subject 

to the risks associated with injection. 

Letter ID: 0170 Comment ID: 24159 Letter Lines: 730 to 741 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 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 Director. As a part of the 

permit application, for approval by the Director the owner or operator must 

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

information: 

Rationale: Clarification. 

Individual Response: EPA disagrees with the suggested change, and is retaining the approach 

of setting a minimum fixed frequency for reevaluating the AoR but has, based on commenters' 

37
input, changed the frequency from ten years to at least every five years, as specified in 

§146.84(e). EPA agrees with commenters that site-specific information is an important factor in 

determining an appropriate AoR reevaluation frequency, and adds that the owner or operator's 

AoR and corrective action plan must describe the minimum fixed frequency for reevaluating the 

AoR and the site-specific conditions on which this frequency is based. EPA adds that the 

Director will evaluate the proposed plan in connection with a review of a vast amount of 

geologic and proposed operating data in determining whether to approve the plan. EPA is 

developing guidance describing recommended approaches to preparing all of the required GS 

project plans, which will address considerations for determining an appropriate AoR reevaluation 

schedule. The guidance will be available on EPA's web site at 

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

Letter ID: 0170 Comment ID: 24160 Letter Lines: 743 to 768 

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

Comment Code: 3500 2.2.3 Area of Review Reevaluation (seeking comment) 

Comment 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 exceed 10 years, the owner or operator 

proposes to reevaluate the area of review; 

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

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

determined by the minimum fixed frequency established in paragraph (b)(2)(i) of 

this section. 

(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 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. 

Rationale: Future access cannot be guaranteed for an area in advance that may 

not even be within the boundaries of the AOR/ project. 

38
Individual Response: EPA disagrees with the suggested changes. 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 from endangerment and address the uncertainties 

inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a 

deliberate effort is made to verify, based on monitoring and operational data, that the CO2 plume 

is moving within the subsurface as predicted. EPA believes that less frequent reevaluations may 

not be sufficient to appropriately model plume and pressure front movement, establish conditions 

for corrective action, and ensure protection of USDWs from endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

To the comment on site access, EPA clarifies that the purpose of the corrective action 

requirement at §146.84(d) is to ensure that all wells in the AoR that have the potential to cause 

the movement of CO2 or other fluids into or between USDWs receive appropriate corrective 

action. In general, to meet this requirement, the owner or operator will most likely need to obtain 

the right of access to wells that may require corrective action, and demonstrate they have done 

this in their proposed AoR and corrective action plan. The final rule retains the requirement as 

proposed. 

Letter ID: 0170 Comment ID: 24161 Letter Lines: 770 to 793 

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

Comment Code: 3300 2.2.1 Delineating the AoR/Modeling CO2 movement 

Comment: Rule Provision: 146.84(c)(1) 

API Comments: (1) Predict, using computational modeling, the projected lateral 

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

subsurface from the commencement of injection activities until the plume 

movement ceases, pressure differentials sufficient to cause the movement of 

injected fluids or formation fluids into a USDW are no longer present, or 

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, confining zone and any additional zones; 

and anticipated operating data, including injection pressures, rates and total 

volumes over the proposed life of the geological sequestration project THE 

DURATION OF INJECTION; (ii) Take into account any RELEVANT geologic 

39
heterogeneities, AND data quality, and 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 characterization, monitoring and operational data, and 

computational modeling, the projected lateral and vertical migration of the carbon dioxide plume 

and formation fluids in the subsurface from the commencement of injection activities until the 

plume movement ceases, until pressure differentials sufficient to cause the movement of injected 

fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time 

period as determined by the Director.” 

The final rule retains §146.84(c)(1)(ii) as proposed, except that it now requires owners or 

operators to take into account other discontinuities in addition to geologic heterogeneities when 

determining the AoR. 

EPA disagrees that only the injection and confining zones should be included in AoR modeling 

of GS sites. EPA believes that the modeling should also take into account the possibility of 

displaced fluids or brines caused by a lateral and/or vertical pressure plume, and therefore it may 

be necessary to include additional zones along with the confining/injection zones to ensure the 

integrity of the confining zone and ultimately protect a USDW from endangerment. 

Letter ID: 0170 Comment ID: 24162 Letter Lines: 795 to 805 

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

Comment Code: 3420 2.2.2.1 Scope of the inventory process (e.g., reliance on publicly 

available information, depth of wells) 

Comment: Rule Provision: 146.84(c)(2) 

API Comments: (2) Using methods approved by the Director, Identify 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 

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 additional information the Director may 

require; and 

Rationale: Changed for consistency with earlier language. 

Individual Response: EPA is retaining this requirement as proposed. EPA agrees with 

commenters that, for most GS sites, relying on database and other public records searches (i.e., 

40
of "known" artificial penetrations) will be sufficient to meet the requirements at §146.84(c)(2). 

However, the Agency recognizes that there may be situations where additional surveys or 

research to locate wells may be appropriate. For example, there may be cases where the Director 

may determine that ground or airborne surveys for wells are appropriate, e.g., if there is reason to 

believe, based on knowledge of the site or of available data, that the incompleteness of 

information on known wells could compromise USDW protection from endangerment. In order 

to preserve the Director's discretion to require an operator to supplement a records search, EPA 

did not make the suggested change. 

EPA clarifies that any well that penetrates the confining 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 modeling to delineate the AoR, performing corrective action at GS sites, 

and, when appropriate, completing AoR reevaluations. 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: 24163 Letter Lines: 807 to 814 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment: Rule Provision: 146.84(c)(3) 

API Comments: (3) Determine which abandoned 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 "associated fluids" as proposed in 

§146.84(c)(3) refers to formation fluids, other injectates, etc. that may be present in the 

subsurface and affect movement of the CO2 plume and/or pressure front. EPA believes this 

terminology would incorporate any fluids in the subsurface that could potentially move through 

artificial penetrations and affect USDWs. EPA has revised the language at §146.84(c)(3) to read, 

"... carbon dioxide or other fluids that may endanger USDWs..." EPA disagrees that deleting the 

term area of review is necessary and has retained 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/edits to rule language 

Comment Code: 3460 2.2.2.3 Acceptable corrective action techniques for GS sites (e.g., 

cements) 

41
Comment: Rule Provision: 146.84(d) 

API Comments: (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. 

Rationale: Experience with CO2 based EOR 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 require the use of materials that are 

"compatible with the carbon dioxide stream." EPA believes this language change addresses 

commenters' concerns and is also consistent 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/edits to rule language 

Comment Code: 3400 2.2.2 Corrective Action 

Comment: Rule Provision: 146.84(e) 

API Comments: (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. 

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 final rule now contains a provision in §146.91(c) 

that requires the owner or operator 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/edits to rule language 

Comment Code: 3530 2.2.3.1 AoR reevaluation frequency (seeking comment) 

42
Comment: 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 action plan, or When 

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 anomalous monitoring results. 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency is 

necessary to ensure protection of USDWs from endangerment and address the uncertainties 

inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a 

deliberate effort is made to verify, based on monitoring and operational data, that the CO2 plume 

is moving within the subsurface as predicted. EPA believes that less frequent reevaluations may 

not be sufficient to appropriately model plume and pressure front movement, establish conditions 

for corrective action, and ensure protection of USDWs from endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

Based on the comments received (including those by water associations, an energy company, 

associations, industries, states, and environmental groups), EPA has changed the minimum 

frequency for the AoR reevaluation from ten years to at least every five years. EPA believes that 

this revised frequency addresses commenters' concerns about the inherent uncertainties in 

modeling CO2 movement, the emerging nature of GS technology, risk-based targeting of 

monitoring activities, and the unique nature of CO2 GS. 

Letter ID: 0170 Comment ID: 24167 Letter Lines: 849 to 855 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 monitoring 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 

43
is 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/edits to rule language 

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

CFR 146.85) 

Comment: Rule Provision: 146.85(a)(1) 

API Comments: (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 

Rationale: Maintenance of the well plugging financial obligation until site 

closure is not necessary. The Director should 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, 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). 

Rationale: Updates more frequent than annual is not justified. 

Rule Provision: 146.85(c) 

API Comments: (c) The owner or operator must notify the Director of adverse 

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

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

Rationale: Clarification. 

Individual Response: Owners or operators have the flexibility to choose from a variety of 

financial instruments to meet their financial responsibility 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 allow 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-injection site care period rather than with the permit application). A 

demonstration of financial responsibility for all phases of the GS project will be required prior to 

the issuance of a Class VI permit (§146.85(a)(5)(i)). 

44
To ensure that financial resources are available to protect USDWs from endangerment, the GS 

rule (at §146.85) identifies qualifying financial instruments, the time frames over which financial 

responsibility must be maintained, procedures for estimating the costs of activities covered by 

the financial instruments, procedures for notifying the Director of adverse financial conditions, 

and requirements for adjusting cost estimates to reflect changes to the project plans. 

In addition, on an annual basis, the owner or operator must adjust the cost estimate for inflation, 

increase or decrease the value of the financial instrument to match the cost estimate, and provide 

any updated information related to their financial responsibility instrument(s), or at any other 

time deemed appropriate by the Director. These annual reviews provide a mechanism for 

revising cost estimates up or down to account for changes in the project, including the execution 

of environmental obligations as phases of a GS project are completed. 

Regarding the suggested edit at §146.85(a)(1), EPA clarifies that the financial instrument the 

owner or operator provided to meet the requirements 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 been met, pursuant to §146.85(b)(2) and §146.93. 

The GS rule, at §146.85(c), requires the owner or operator to have a detailed written estimate, in 

current dollars, of the cost of: performing corrective 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 activities and be based on the costs to the owner or 

operator of hiring a third party (who is neither a parent nor a subsidiary of the owner or operator) 

to perform the activities. However, EPA is not requiring independent third-party reviews of 

owner or operator cost estimates. 

EPA is developing guidance on financial responsibility for GS wells. 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 various 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) and (c), but did extensively 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/edits 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 operator must provide an adjustment of the cost estimate 

45
to 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) and post-injection site care 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 that the GS rule, at §146.85(e), 

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, and the 

PISC and site closure plan. See the final rule and preamble for further discussion 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/edits 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 the nonendangerment standard that is the 

basis of the UIC program. 

Individual Response: EPA disagrees that the proposed language 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 prevention of fluid movement between formations 

is paramount and the language as proposed meets 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 integrity of the well throughout the lifetime of a 

GS project. This is the foundation of the requirements for construction and pre-operational 

testing of Class VI wells at §§146.86 and 146.87. 

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. Please see the final rule and 

preamble for additional information. 

46
Letter ID: 0170 Comment ID: 24171 Letter Lines: 907 to 923 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 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 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 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: 

Rationale: The life of a geologic sequestration project could be different than 

the life of the well. Class VI well design 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 rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through the post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

Letter ID: 0170 Comment ID: 24172 Letter Lines: 925 to 931 

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: Rule Provision: 146.86(b)(1) 

API Comments: (v) Corrosiveness COMPOSITION of the carbon dioxide stream and 

formation fluids; 

47
Rationale: 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 corrosiveness 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/edits to rule language 

Comment Code: 3860 2.3.3 Well component degradation 

Comment: Rule Provision: 146.86(b)(1) 

API Comments: (vi) Down-hole temperatures AND PRESSURES; 

(viii) Type or grade of cement AND ADDITIVES; and 

Rationale: Technical 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 information on down-hole pressures is required 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/edits 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 extend through the base of the lowermost 

USDW ABOVE THE INJECTION ZONE and be cemented to the surface. 

Rationale: In some parts of the US the USDW is very deep and this standard may 

preclude geologic sequestration in these areas. 

Individual Response: EPA disagrees with the suggested edit or that the surface casing 

requirements in the GS rule preclude injection below deep USDWs. The final GS rule at 

§146.86(b)(2) requires that surface casing extend through the base of the lowermost USDW and 

be cemented to the surface through the use of single or multiple strings of casing and cement. It 

does not, however, specify how cementing must be accomplished, and gives flexibility to the 

48
owner 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 regarding construction of Class VI wells where the lowermost USDW 

is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 

includes requirements for owners or operators that seek a waiver of the injection depth 

requirements. Owners or operators of wells operating under injection depth waivers must comply 

with additional construction requirements to ensure that wells used to inject above or between 

USDWs are protective. See the discussion of the waiver 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/edits 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 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 

surface 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 USDWS. 

Rationale: Cementing to surface is 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 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 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. 

49
Rationale: Same as above 

Individual Response: EPA disagrees with the suggested edits. EPA believes that the 

requirements for long-string casing are appropriate and offer appropriate flexibility: 

§146.86(b)(3) requires that the long-string casing extend to the injection zone and be cemented 

by circulating cement to the surface in one or more stages. It does not, however, specify how 

cementing would be accomplished, and gives flexibility to the owner or operator to propose 

alternate methods to provide a sufficient amount of cement to meet the standard that USDWs are 

protected from endangerment, subject to the approval of the Director. 

EPA stresses that protection of USDWs is the primary mission and mandate of the UIC program 

and the purpose of all requirements for injection wells. Any injection activity must be 

demonstrated to not endanger USDWs, regardless of their depth, and if such non-endangerment 

cannot be shown, 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 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 and 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 additional information. Additionally, EPA is developing 

guidance on the construction of Class VI wells. This guidance will be available on EPA’s 

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

Letter ID: 0170 Comment ID: 24176 Letter Lines: 977 to 991 

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

Comment Code: 3864 2.3.3.2 Use of corrosion-resistant cements (seeking comment) 

Comment: Rule Provision: 146.86(b)(5) 

API Comments: (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. 

50
Rationale: Experience with CO2 EOR under the Class 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). 

Individual Response: EPA disagrees that the casing, cement, or other materials should only be 

designed for the period of the injection process rather than the life of the sequestration project. 

GS projects are anticipated to have long life spans in comparison to other types of deep injection 

wells. Not only must Class VI wells be able to function safely and properly over the lifespan of 

the GS project, but they must be constructed such that USDWs remain protected after well 

plugging. The requirements at §146.86 will ensure that the well can maintain integrity 

throughout the proposed life span of the project, including after the injection well is plugged and 

through the post-injection site care period and beyond. While the risk profile of a GS site will 

decrease following cessation of injection, EPA believes that Class VI wells must be designed to 

protect USDWs from endangerment for the life of the project. Furthermore, rigorous casing and 

cementing help ensure that the Class VI well will not serve as a conduit for movement of fluids 

associated with future injection operations. 

EPA recognizes that the oil and gas industry has decades of experience injecting CO2 and has 

demonstrated the effectiveness of existing cementing 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 International, or comparable standards acceptable to 

the Director. This requirement invokes the expertise of these bodies to ensure that the 

requirements for construction of Class VI wells reflect the state of the art in well construction 

technology. See the discussion of Class VI well construction requirements in the preamble to the 

final GS rule for additional information. Additionally, EPA is developing guidance on the 

construction of Class VI wells. This guidance will be available on EPA’s website at 

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

Letter ID: 0170 Comment ID: 24177 Letter Lines: 993 to 1010 

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

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: 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. 

51
Rule Provision: 146.86(c)(2) 

API Comments: (iii) MAXIMUM PROPOSED Injection temperature and pressure; 

(iv) MAXIMUM PROPOSED Annular pressure; 

(v) MAXIMUM PROPOSED Injection rate (intermittent 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 density. The suggested revision to refer to CO2 

"composition" would be less precise. EPA clarifies that, although corrosiveness 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. 

See the discussion of Class VI well construction requirements in the preamble to the final GS 

rule for additional information. Additionally, EPA is developing guidance on the construction of 

Class VI wells. This guidance will be available on EPA’s website at 

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

EPA has revised §146.86(c)(3)(iii) and (iv) to reference the maximum proposed injection 

pressure and maximum proposed annular pressure, respectively. EPA has revised 

§146.86(c)(3)(v) to read "proposed injection rate (intermittent or continuous), and volume and/or 

mass of the carbon dioxide stream." EPA believes that reference to the continuous 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/edits 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 appropriate logs, surveys and tests to 

determine or verify the depth, thickness, porosity, permeability, and lithology 

of, and the salinity of any formation fluids in, all relevant geologic 

formations to assure 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 minimum, such logs and tests must include: THE DIRECTOR MAY REQUIRE 

52
SUCH LOGS AND TESTS AS MAY BE NEEDED 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 WELL PROGRESSES AND THESE MAY INCLUDE THE 

FOLLOWING: 

Rationale: Obtaining the geologic information will not assure conformance 

with well construction requirements, just measure or evaluate it. 

In well defined areas, these evaluations 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 drilled, the logging of surface hole yields 

little useful additional information. 

In particular, this change would allow the Director to reduce the requirements 

when multiple wells are installed 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 injection and confining zones and ensure that the well 

is being drilled and cased as approved, and has mechanical integrity. This information is needed 

to demonstrate that the well can be operated and tested in a manner that protects USDWs from 

endangerment. While the tests do provide information on some of the same items, each test 

provides unique pieces of information that build on each other and allow for interpretations not 

possible with a single test. 

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods 

that provide equivalent or better information, and the Director 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 question and core retrieval is not 

possible, as specified at §146.87(b). EPA believes that logs and tests must be performed on each 

well drilled regardless of existing information 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 needed for site-specific well design and 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/edits to rule language 

Comment Code: 4110 2.4.1.1 Injection pressure limitations 

Comment: Rule Provision: 146.88(a) 

53
API Comments: (a) Except during stimulation, 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 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. (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 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 INJECTION 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. First, 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 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 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 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 where 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. 

Individual Response: EPA notes that because determination of the injection pressure limit is 

54
based on the fracture pressure of the injection zone, the limit is site-specific and not arbitrary. 

EPA emphasizes that injection pressure limits are important to protect against fracturing of the 

confining zone, and that the requirement at §146.88(a) that the pressure in the 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 Director determines, based on a review of the 

information collected as part of site characterization, that a lower injection pressure 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 process, owners or operators must submit data 

about the geology of the site, as specified at §146.82(a), including data on known or suspected 

faults and fractures and geomechanical information on fractures, stress, ductility, rock strength, 

and in situ fluid pressures within the confining zone. The Director 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 requirement for the owner or operator to submit data on 

known or suspected faults and fractures and information on the seismic history of the site will 

inform the determination of an appropriate pressure 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 approaches for characterizing the regional geology and 

hydrogeology of a proposed site and performing the necessary geochemical, geomechanical, and 

geophysical analyses of the injection and confining zone. EPA is also developing guidance for 

primacy agencies that will include recommended approaches for evaluating owner or operatorsubmitted data in setting permit conditions. 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: 24181 Letter Lines: 1217 to 1221 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 into this annulus may also limit diagnostic options that could be 

useful. 

55
Individual Response: EPA retains the provision as proposed, 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/edits 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 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. 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 the operating injection pressure is not 

necessary because a leak from tubing to annulus does not have the same 

implications as in a Class 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 believes this requirement is appropriate for Class 

VI wells given the potential high volumes and supercritical 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/edits 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 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 between the tubing and the long 

string casing and annulus fluid volume and. THE OWNER OR OPERATOR must 

56
install 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 other parameters approved by the Director 

diverge beyond ranges and/or gradients specified in the permit; 

Rationale: Over-pressure protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength 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 tubing 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 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 landing 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. EPA 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 systems, as required at §146.88(e), is necessary 

to ensure protection of USDWs from endangerment from the risks associated 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 believes, 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 require getting the device to the site, setting up a 

rig, and deploying the device down the well, a significant 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 all cases to ensure protection of USDWs from 

endangerment. Instead, the final rule, at §146.88(e)(2), requires that owners or operators of 

onshore Class VI wells install automatic surface shut-off devices. The rule affords Director's 

discretion to mandate automatic down-hole shut-off devices in onshore situations that may 

57
warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore wells 

within State territorial waters install automatic down-hole shut-off systems. EPA 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/edits 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 expeditiously as possible the cause of the 

shutoff. If, upon such investigation, the well appears to be lacking 

mechanical integrity, or if monitoring required under paragraph (e) of this 

section otherwise indicates that the well may be lacking mechanical integrity, 

the owner or operator must: 

Rationale: Technical clarification 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 automatic surface shut-off devices. The rule affords 

Director's discretion to mandate automatic down-hole shut-off devices in onshore situations that 

may warrant their use. The rule requires, at §146.88(e)(3), that owners or operators of offshore 

wells within State territorial waters install automatic down-hole shut-off systems. 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/edits to rule language 

Comment Code: 4000 2.4 Proposed Injection Well Operating Requirements (40 CFR 146.88) 

Comment: Rule Provision: 146.88(f)(3) 

API Comments: (3) Notify the Director 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 triggered or a loss of mechanical integrity is discovered." Therefore the 

notice required at §146.88(f)(3) must be provided within 24 hours of an automatic shut-off 

58
device being triggered or a loss of mechanical integrity being discovered. EPA believes this 

provision is necessary to ensure timely response to potential USDW endangerment. 

Letter ID: 0170 Comment ID: 24186 Letter Lines: 1288 to 1297 

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

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.89(b) 

API Comments: (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 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 specified in §146.88 (e); 

Rationale: Technical clarification. 

Individual Response: EPA agrees with the commenter regarding the importance of 

demonstrating internal mechanical integrity (MI), 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 report volumes of packer fluid injected or removed. 

EPA agrees with the commenter that recording annulus fluid volume may not be appropriate. 

EPA believes that knowing annulus fluid volume (146.88(e)) is a necessary component of 

monitoring well mechanical integrity, but believes that knowing the annulus fluid volume added 

is sufficient to meet the intent of the requirement. The final GS rule requires that owners or 

operators use continuous recording 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 fluid 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. 

59
Letter ID: 0170 Comment ID: 24188 Letter Lines: 1320 to 1336 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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, except during well workovers as defined 

in §146.868(d), of continuous recording MONITORING devices (INCLUDING DIGITAL 

DEVICES CAPTURING PERIODIC DATA) to monitor injection pressure, rate and volume; 

AND RECORD AT LEAST DAILY the pressure on the annulus between the tubing and the 

long string casing; and the annulus fluid volume; 

Rationale: §146.86(d) does not exist; perhaps §146.88(d) is what was apparently 

intended. 

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 strongly shows that daily monitoring of 

most of these parameters is adequate (exceptions to this would be on a sitespecific basis). Recording should generally be done on a daily basis and 

reporting on a semi-annually basis. 

Individual Response: EPA believes that a monitoring regime that includes continuous pressure 

monitoring of GS wells, as required 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 continuous monitoring, EPA expects that Class VI 

injection wells under §146.88(e) will be equipped with dedicated computer-based continuous 

pressure monitoring devices (in concert with the 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 the final rule, however. 

EPA adds that the final GS rule references §146.88(e), as the commenter suggests. 

Letter ID: 0170 Comment ID: 24189 Letter Lines: 1338 to 1353 

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

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: Rule Provision: 146.90(c) 

API Comments: (c) WHERE CONDITIONS WARRANT, corrosion monitoring of the well 

materials for loss of mass, thickness, cracking, pitting and other signs of 

60
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 to ensure 

that the well components meet the minimum 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 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. 

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 potential for corrosion of well materials down-hole, where the 

injectate can potentially mix with water in the target formation, must be considered. 

Several laboratory studies and a limited number of field studies have investigated and 

characterized the effects of carbonic acid on well materials. Laboratory studies (e.g., Kutchko et 

al., 2007; Kutchko et al., 2008) consistently identify alterations (typically carbonation) of cement 

as the result of interactions between cement and CO2-saturated brine. 

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

contact with CO2 in actual field (down-hole) conditions. Evaluation of cement from a well at the 

Scurry Area Canyon Reef Operators Committee (SACROC) site showed alteration, but did not 

show degradation that compromised the structural integrity of the cement (Carey et al., 2007). In 

another study, cement samples were collected and analyzed from a CO2 production well in a 

natural CO2 reservoir in Colorado exposed to a CO2-water down-hole environment for 30 years 

(Crow et al., 2008). The study found evidence of reaction between the CO2-rich water and the 

cement. 

Oil industry research also addresses the effects of corrosion of steel tubing and pipes. Lopez et 

al. (2003) noted that 60 percent of oilfield failures are related to the effects of carbonic acid from 

produced brines on carbon and low alloy steels. 

Laboratory investigation of cement alteration/degradation is an ongoing research area. Few fieldbased studies have been completed to date. The laboratory and field studies currently available 

suggest that corrosion problems can be managed; however, there is not a large enough body of 

research to rule out potential corrosion problems of steel components of injection wells. The 

IPCC (2005) report on carbon dioxide capture and storage reviewed oil and gas industry 

experience with gas injection wells, close industry analogues to CO2 injection wells. The report 

stated that while the design of CO2 injection wells will be very similar to gas injection wells, 

61
most down-hole components of the CO2 injection wells will “need to be upgraded for higher 

pressure ratings and corrosion resistance.” Given the pressure and corrosion considerations, 

anticipated long lifespan of a GS well, and the difficulties that would be associated with a 

corrosion-related well failure, EPA believes that corrosion monitoring in the down-hole 

environment is justified. For these reasons, the final rule requires quarterly corrosion monitoring 

(at §146.90(c)). 

Letter ID: 0170 Comment ID: 24190 Letter Lines: 1355 to 1364 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 INSPECTING 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 further 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/edits 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 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 

62
be based on GEOLOGICAL, geochemical AND GEOPHYSICAL 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); 

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 suggested 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 confining layer itself. Monitoring above the 

confining layer will provide an indication of upward movement of CO2 that might endanger a 

USDW. The exact number of formations to be tested must, however, be based on site-specific 

characteristics and vulnerabilities and described in the Director-approved testing and monitoring 

plan. 

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 believes, however, 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 and USDWs or other layers above the confining zone. 

Such construction technologies exist 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 CO2 remains confined in the injection zone and that 

pressure changes are not causing movement or formation 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 construction that will include recommendations for monitoring well 

construction. The guidance will be available on EPA’s website at 

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

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

63
website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA acknowledges the commenters' concern about the cost of monitoring. However, EPA 

believes that monitoring is essential for protection of USDWs at GS sites. Although a significant 

cost in absolute terms, monitoring costs are expected to be a small fraction of site operating 

costs, according to EPA's cost analysis for the GS rulemaking (which is available in the docket). 

Letter ID: 0170 Comment ID: 24192 Letter Lines: 1299 to 1318 

Comment Code: 1240 1.1.1.3 Suggested changes/edits 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 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. 

Rationale: Revised text supports a performance-based approach and allows the 

development and use of new technologies as they become available. 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 it requires the tubing to be pulled at 

significant cost and risk of uncontrolled releases. 

Individual Response: EPA believes that the MITs described in §146.89(c) of the rule (e.g., an 

approved tracer log or temperature or noise logs) are effective methods to demonstrate external 

MI, provide an important early warning of potential 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 that the regulations do provide the Director the 

flexibility at §146.89(e) to approve the 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 has revised the final GS rule to require that 

64
the frequency of the casing inspection 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/edits 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 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 DYNAMICS 

at least once 

every five years unless more frequent testing is required by the Director based 

on site specific information; 

Rationale: Technical clarifications. 

Individual Response: Regarding pressure testing, EPA believes 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 decline 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. Therefore, EPA is requiring that pressure fall-off 

testing be conducted every five years at a minimum, 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 testing) to ensure safe and effective operations. 

EPA disagrees that the rule should provide specifics of the test at the degree suggested, however. 

Based on its evaluation of all public comments and input on the proposed rule and NODA and 

Request for Comment, EPA has made many revisions to the GS Rule. See the final rule and 

preamble for further discussion on EPA's final approach. 

Letter ID: 0170 Comment ID: 24194 Letter Lines: 1398 to 1410 

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

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment: Rule Provision: 149.90(g) 

API Comments: (g) Testing and monitoring AS APPROPRIATE TO SUPPORT THE MODEL 

FOR 

65
to trackING 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); 

Rationale: 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. 

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 operators 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 movement 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 detect movement of the pressure front unless a breach of the 

confining zone occurs. EPA believes that monitoring using wells in the injection zone (i.e., that 

penetrate the confining zone) can be safely performed if the wells are constructed to prevent flow 

between the injection zone and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used 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 performing additional pressure monitoring in wells that are above the 

confining zone (e.g., in the same wells used to perform ground water quality monitoring required 

at §146.90(d)) to provide additional verification that no pressure changes are occurring above the 

confining zone due to CO2 leakage. Monitoring also identifies needed remedial actions, provides 

inputs for AoR reevaluation modeling, and targets additional geochemical 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 appropriate actions to address any 

indication that USDWs may be endangered. 

EPA acknowledges that, at certain sites, there may be a need for more or different monitoring 

schemes (which may include monitoring in the confining 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 could serve as conduits for fluid migration. EPA 

expects site-specific testing and monitoring plans to describe the proposed monitoring regime, 

which must be approved by the Director. 

Flexibility is also provided regarding how to monitor for the specific data required by the final 

rule. The testing and monitoring plan is developed by the owner or operator in consultation with 

the Director and is designed to ensure that a detailed, Director-approved document describing 

how monitoring will be conducted during the lifetime of the project exists. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

66
Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. 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: 24195 Letter Lines: 1412 to 1419 

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

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: Rule Provision: 146.90(h) 

API Comments: (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. 

Rationale: In most situations soil and air monitoring does not provide an 

effective method of protecting USDWs. 

Individual Response: EPA clarifies that subsurface geochemical and pressure monitoring in the 

subsurface formations are the first line of monitoring that would allow detection of potential 

endangerment to USDWs from GS activities (this is required at all GS sites, as described at 

§146.90(d)). The Agency also believes that surface air and soil gas monitoring, when coupled 

with subsurface monitoring, may be appropriate at some GS projects to ensure USDW 

protection. 

The final rule at §146.90(h) retains the allowance for surface air and soil gas monitoring at the 

discretion of the Director as a means of identifying leaks that may pose a risk to USDWs and 

informing emergency notification of a Class VI owner or operator and UIC Director in the event 

of a USDW endangerment, pursuant to requirements at §146.91(c). 

The selection of monitoring methods will be site-specific (e.g., may be influenced by geology, 

injection depth, and operational conditions) and must be based on potential risks to USDWs 

within the AoR. 

Letter ID: 0170 Comment ID: 24196 Letter Lines: 1421 to 1427 

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

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

Comment: Rule Provision: 146.90(h)(1) 

67
API Comments: (1) The testing and monitoring plan must be based on potential 

vulnerabilities SITE-SPECIFIC GEOLOGIC FACTORS, MODELING, AND RISKASSESSMENT 

within the area of review; 

Rationale: Technical 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 discussion on EPA's final approach. EPA anticipates that 

the testing and monitoring plan will address site-specific geologic factors, modeling, and riskassessment. EPA is developing guidance on how best to develop the various required project 

plans, including the testing and monitoring plan. 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/edits 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 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 

Rationale: Technical 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 discussion on EPA's final approach. EPA agrees that any 

additional monitoring requirements would be based on site-specific geologic factors, modeling, 

and risk-assessment. EPA is developing guidance for directors that provides recommended 

approaches when exercising discretion to require 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/edits to rule language 

Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.91(a) 

68
API Comments: (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 

characteristics of the carbon dioxide stream 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 recognize that there will be minor variations 

in many data sets over time. 

Rule Provision: 146.91(a) 

API Comments: (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 SIGNIFICANT event which triggers a shutdown device 

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

Rationale: EPA should consider some significance 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 semi-annual reporting is 

appropriate and necessary for Class VI wells during the operational phase of the project. EPA 

believes that the potentially large injection volumes and injection pressures associated with GS 

warrant more frequent reporting than for other well classes. See the final rule and preamble for 

further discussion on EPA's final approach 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 to 

consistently 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 appropriate 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/edits to rule language 

69
Comment Code: 5100 2.8.1 Injection well plugging activities (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 buffer fluid, determine bottomhole reservoir 

pressure, and perform a final EXTERNAL mechanical integrity test OF ANY RELEVANT 

WELLBORE MATERIALS REMAINING. 

Rationale: Many of the components that would 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 operators 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/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: Rule Provision: 146.92(b)(2) 

API Comments: (2) Appropriate testing methods to ensure FINAL EXTERNAL 

mechanical integrity as specified in §146.89(C); 

Rationale: Many of the components that would 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 operators 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/edits to rule language 

Comment Code: 5100 2.8.1 Injection well plugging activities (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 FOR USE with the carbon dioxide stream; 

70
and 

No rationale provided 

Individual Response: EPA believes, considering the potentially corrosive nature of CO2 when 

it is in contact with water, that the requirement that the material must be compatible with the 

CO2 stream is appropriate. The final rule retains this requirement. 

Letter ID: 0170 Comment ID: 24202 Letter Lines: 1491 to 1501 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5100 2.8.1 Injection well plugging activities (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 

must be submitted within 60 days after plugging. The report must be certified 

as accurate by the owner or operator and by the person who performed the 

plugging operation (if other than the owner or operator.) 

Rationale: The proposed changes are suggested 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/edits 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 operator must submit the postinjection site 

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

the Director. SHALL CONTINUE TO CONDUCT MONITORING 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). 

71
Rationale: Revisions here reflect changes to §146.93(b)(3) 

Individual Response: EPA disagrees with the suggested changes, and disagrees that the postinjection monitoring period should be strictly performance-based. The Agency agrees that there 

will be limited 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, 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 ensures the protection of USDWs. However, EPA 

anticipates that a default timeframe for post-injection 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 based 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 provision that the Director may, at his or her 

discretion, shorten the post-injection site care timeframe if the owner or operator can 

demonstrate that the GS project does not pose an endangerment to USDWs, as specified in 

§146.93(b)(2). Such a demonstration will be site-specific, 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-endangerment of USDWs will be demonstrated 

throughout the post-injection site care period. 

Letter ID: 0170 Comment ID: 24204 Letter Lines: 1513 to 1527 

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

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: 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 between preinjection and predicted post-injection 

pressures in the injection zone; 

(ii) The predicted position of the carbon dioxide plume and associated pressure 

front at site closure as demonstrated in the area of review evaluation required 

under § 146.84(b); 

(iii) A description of post-injection monitoring location, methods, and proposed 

frequency; and 

(iv) A proposed schedule for submitting post-injection site care monitoring 

results to the Director. 

Rationale: Revisions here reflect changes to §146.93(b)(3) 

Individual Response: Based on its evaluation of all public comments and input on the proposed 

72
rule and NODA and Request for Comment, EPA has made many revisions to the GS Rule. See 

the final rule and preamble for further discussion on EPA's final approach. 

Letter ID: 0170 Comment ID: 24205 Letter Lines: 1529 to 1535 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: 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 approval 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 projected, and there may be a need to amend 

the post-injection site care and site closure plan. EPA is requiring that upon the cessation of 

injection, the owner or operator submit an amended post-injection site 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 requiring formal periodic review and 

updates to the PISC and site closure plan throughout the injection phase. EPA does not expect 

that changes to this plan would be implemented until injection operations cease. EPA envisions 

that owners or operators would take into account similar considerations that guide updates to 

other project plans, e.g., monitoring and operational data and results 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 expected to amend the plan accordingly. 

EPA adds that, in the final rule, it has revised the text at §146.93(a)(4) as follows: "At any time 

during the life of the geologic sequestration project, the owner or operator may modify and 

resubmit the post-injection site care and site closure plan for the Director’s approval within 30 

days of such change." 

EPA is issuing guidance on development and updating 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/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0170 Comment ID: 24206 Letter Lines: 1537 to 1585 

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

73
Comment 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 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 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 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 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, believes 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 counterproductive. A 

straight performance standard is preferable to this or any other fixed time 

period because 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. Cessation of plume movement is not necessarily 

essential to show that a 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 what the operator must show. 

API, in concert with the MSDG, recommends 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 the requisite information to make the 

appropriate determination. The advantage of this approach is that it establishes 

clear criteria that an operator must demonstrate 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 

74
fixedduration. Furthermore, it is more stringent than a purely discretionary 

approach 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. 

Individual Response: EPA disagrees with the suggested changes. As noted above, EPA 

disagrees that a post-injection site care timeframe of 50 years 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 exaggerate the risks associated with GS, is 

consistent with other environmental programs, 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 during the PISC period based on site-specific data, 

pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class 

VI well owner or operator to demonstrate, based on substantial data during the permitting 

process, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment 

of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a 50 year post-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. Furthermore, 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 proposed well plugging plans and 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, demonstrate the appropriateness of an 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: 24207 Letter Lines: 1572 to 1585 

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: API, in concert with the MSDG, recommends the standard in the proposed 

alternative language for section 146.93(b) below because it sets forth detailed 

75
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 the requisite information to make the 

appropriate determination. The advantage of this approach is that it establishes 

clear criteria that an operator must demonstrate 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 

fixedduration. Furthermore, it is more stringent than a purely discretionary 

approach 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. 

Individual Response: EPA believes that many site-specific factors will influence the 

determination of when the CO2 plume and pressure front no longer pose a risk of endangerment 

to USDWs, and therefore is not defining the criteria in the final rule. It is for this reason that 

EPA believes that individual UIC Directors, in consultation with operators, will be in the best 

position to determine whether additional post-injection site care is needed. EPA expects this 

decision to be made based on relevant site data and in consultation with all potentially impacted 

parties. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells, perform 

post-injection monitoring, demonstrate non-endangerment, and perform site closure activities. 

The guidance will be available at 

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

Letter ID: 0170 Comment ID: 24208 Letter Lines: 1587 to 1622 

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

Comment Code: 5280 2.8.2.4 USDW non-endangerment demonstrations 

Comment: Rule Provision: 146.93(b)(3) 

API Comments: (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-specific 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 

76
OWNER 

OR OPERATOR DEMONSTRATES, BASED 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 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 ZONE 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. 

Rationale: 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. 

Rule Provision: 146.93(b)(4) 

API Comments: (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 postinjection 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 closure plan. EPA also 

believes that periodic reviews and updates, where 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 appropriate. The post-injection site care requirements in the final GS 

77
rule incorporate a combination of a fixed timeframe 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 site-specific data, pursuant to requirements at §146.93(b); or (2) 

affording the Director discretion to allow a Class VI well owner or operator to demonstrate, 

during the permitting process based on substantial data, that an alternative PISC timeframe may 

be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at 

§146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans under §146.92 and §146.93. The guidance describes recommended 

approaches for how an owner or operator could plug injection and monitoring wells, perform 

post-injection monitoring, demonstrate the appropriateness of an alternative post-injection site 

care time frame, demonstrate non-endangerment, and perform site closure activities. The 

guidance will be available at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0170 Comment ID: 24209 Letter Lines: 1615 to 1622 

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

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

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Rule Provision: 146.93(b)(4) 

API Comments: (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 postinjection 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-injection site care is necessary in most cases. A 50-

year post-injection site care timeframe represents a reasonable and protective monitoring period 

for most GS projects based on a review of research studies, industry reports, and existing 

environmental programs, and evaluation of public comments. However, EPA recognizes that 

78
alternative 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 discretion to shorten or lengthen the PISC timeframe 

during the PISC period based on site-specific data, pursuant to requirements at §146.93(b); or (2) 

affording the Director discretion to allow a Class VI well owner or operator to demonstrate, 

based on substantial data during the permitting process, that an alternative PISC timeframe may 

be appropriate if it ensures non-endangerment of USDWs pursuant to requirements at 

§146.93(c). 

Letter ID: 0170 Comment ID: 24210 Letter Lines: 1624 to 1641 

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

Comment Code: 4730 2.7.3 Reporting associated with closure and post-injection site care 

Comment Code: 5300 2.8.3 Site closure activities (40 CFR 146.93) 

Comment: Rule Provision: 146.93(e) 

API Comments: (e) Once the Director has authorizeSd site closure, the 

owner or operator must submit a site closure report within 90 days that must 

thereafter be retained at a location designated by the Director. 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 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(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; 

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 operator should not be responsible for 

record retention such as site closure reports. EPA believes that the requirements that the owner or 

operator retain, for ten years following site closure, records collected during the post-injection 

site care period at §146.93(f) and §146.93(h) are appropriate for the post-injection and site 

closure period to ensure that data are available to support non-endangerment demonstrations and 

to address any concerns that may arise following site closure. This data will also support EPA's 

review of project data as part of the adaptive rulemaking approach. 

Letter ID: 0170 Comment ID: 24211 Letter Lines: 1643 to 1659 

79
Comment Code: 1240 1.1.1.3 Suggested changes/edits to rule language 

Comment Code: 5800 2.13 Comments on emergency and remedial 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 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 

BECOMING AWARE OF THE ENDANGERMENT; and 

Rationale: Technical clarifications. 

There is a slight change that immediately 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 clarifies that the pressure 

front, as defined in §146.81, is a zone where the pressure differential is sufficient to cause the 

movement of injected fluids or formation fluids into a USDW. Therefore, displaced formation 

fluids are implicitly included in the requirements for §146.94. EPA also 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 USDWs, as required under §1421 of the SDWA, EPA 

expects the owner or operator to act preemptively and not wait until endangerment has occurred. 

This language is consistent with existing UIC requirements for 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 injection. 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 encouraged to discuss with the Director 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 obtains 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/edits to rule language 

Comment Code: 5800 2.13 Comments on emergency and remedial response (40 CFR 146.94) 

80
Comment: 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 maintenance-type workover. For maintenance-type 

workovers (i.e., those that are scheduled in advance), the owner or operator must notify and gain 

approval from the Director prior to beginning the workover. In the final GS regulation, EPA has 

moved this requirement to the reporting requirements at §146.91(d) to clarify its intent. 

Regarding concerns that notification could delay responses, EPA clarifies that the GS rule, at 

§146.94(b), describes procedures owners or operators must take in emergency situations. 

Specifically, upon determining that there is a problem with the well that may endanger a USDW, 

the owner or operator must first cease injection, then take all steps reasonably necessary to 

identify and characterize any release, notify the Director, and implement the approved 

emergency and remedial response plan, which may include a well workover. EPA believes that 

ceasing injection (which the owner 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 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 Response: API supports the implementation 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 the final GS rule. Given the potential for CCS 

(encompassing capture, transportation, and geologic sequestration) to be an important part of a 

national priority to address climate change, EPA believes that providing states the flexibility to 

obtain primacy for Class VI wells independently of other well classes can help foster effective 

management of CCS. EPA believes that allowing independent Class VI primacy may encourage 

81
states to take responsibility for implementation of Class VI regulations and provide for a more 

comprehensive approach to managing CCS projects by promoting the integration of GS activities 

under SDWA into a broader framework for managing CCS. Furthermore, GS operations involve 

ancillary activities (e.g., pipeline operations, pore space ownership, land use rights, and surface 

access) for which states can call upon other authorities that exist at the state level (but outside 

UIC authority) to provide a more comprehensive CCS management approach. 

The Agency believes that it is important for states to use their unique efficiencies to promote 

adoption of this burgeoning and important technology, while assuring that USDWs are protected 

from endangerment through the UIC regulatory framework. EPA believes that, due to the 

importance of implementing an effective, comprehensive, and seamless CCS program, States 

should be provided the flexibility to obtain primacy for Class VI only. 

EPA also believes that allowing states to apply only for Class VI primacy will shorten the 

primacy approval process for states. EPA's willingness to accept independent primacy 

applications for Class VI wells represents a shift in its longstanding policy of discouraging 

"partial primacy." It is very important to note that this shift in policy allowing for Class VI 

primacy does not apply to any other well Class under Section 1422. EPA will continue to 

discourage applications for partial primacy for all other well types under Section 1422. 

EPA clarifies that states should be able to obtain primacy for Class VI wells independent of other 

well classes provided they develop regulations that are at least as stringent as the minimum 

Federal requirements (e.g., permitting, inspection, operation, monitoring, and recordkeeping 

requirements) provided in the final GS rule. EPA believes that existing programs can adapt their 

expertise to the new requirements for Class VI wells and will be able to develop a primacy 

application for Class VI wells under section 1422 of SDWA and ensure that their GS programs 

integrate into national climate change priorities and protect USDWs from endangerment. 

Letter ID: 0170 Comment ID: 24214 Letter Lines: 1687 to 1700 

Comment Code: 2046 1.5.2.3 Continuing to classify CO2 injection for EOR/EGR as Class II/ 

dividing line between Class II and Class VI (seeking comment) 

Comment: EPA Preamble Question: 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. EPA Notice 43502. 

API Response: 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 EOR continues to be handled under the Class II program. 

Additionally, API supports the creation of a subclass under Class II (e.g "Class 

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IIB") 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 Class II Program. EPA recognizes that the oil and 

gas industry has decades of experience injecting CO2 for the purpose of ER, and that sites used 

for ER may be suitable for GS and may be among the first GS sites. 

However, the Agency disagrees that wells injecting CO2 for the primary purpose of long-term 

storage should be regulated under Class II requirements (e.g., the Class IIB category suggested 

by the commenter). The Agency believes that the nature and risks of CO2 injection for the 

primary purpose of long-term storage poses different risks than injection for the primary purpose 

of ER, and therefore has developed new Class VI regulations to address these unique risks. For 

example, the volume of CO2 anticipated to be injected for long term storage is significantly 

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

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

within their storage formations than Class II ER projects. 

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

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

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

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

available for the Director to evaluate changes 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/groundwater/uic/wells_sequestration.cfm. For more information, 

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

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 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 Response: 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 proposes that they remain under the Class II program 

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when transitioning from EOR to GS. 

Individual Response: EPA agrees that many Class I, Class 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 engineered and constructed 

to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements 

at §146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are 

grandfathered and that all other Class VI requirements (reporting, monitoring, mechnical 

integrity testing, etc.) must be met following a determination under §146.81(c). 

EPA disagrees that wells transitioning from ER to GS should be regulated as Class II wells. 

During and following this transitional phase, many of the unique factors of GS sites (e.g., 

increased reservoir pressures associated with large volumes of stored CO2 and the corrosivity of 

CO2 in the presence of water) 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 what point a Class VI permit is required for those 

projects that are transitioning from the primary purpose of EOR to long term storage of CO2. 

The final regulation provides a set of technical factors for the Director to evaluate in making this 

determination, at §144.19. EPA believes that this approach provides sufficient protection of 

USDWs when there is an increased risk to USDWs as compared to traditional Class II operations 

while allowing for site-specific flexibility. 

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

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

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

purpose is long-term storage of large volumes of CO2. The guidance describes 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 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: 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 existing wells with a proven record of 

performance should be grandfathered unless there are specific USDW endangerment 

concerns identified by the Director. See Comment above. 

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Individual Response: EPA agrees that many Class I, Class 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 engineered and constructed 

to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu of requirements 

at §146.86(b) and §146.87(a). EPA clarifies that only the construction requirements are 

grandfathered and that all other Class VI requirements (reporting, monitoring, mechanical 

integrity testing, etc.) must be met following a determination under §146.81(c). 

EPA disagrees that other requirements should also 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 and the corrosivity of CO2 in the presence of 

water) will result in an increased risk profile, warranting 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, and post-injection site care and site closure 

requirements in the final GS rule. See the discussion 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 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 Response: API opposes this restriction. Qualification of a formation for 

storage should be based on performance-based standards and site-specific 

considerations. 

Individual Response: The final GS rule does not categorically preclude or prohibit injection 

into any type of formation, including coal seams. Instead, the requirements are designed to 

ensure protection of USDWs from endangerment 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 seams and basalts, are typically 

shallow and above the lowermost USDW. EPA expects 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 demonstrate that such injection can be performed in a manner that 

protects USDWs, as long as appropriate protections are in place. The Class V experimental 

technology well classification may, in some instances, be an appropriate permitting alternative. 

This decision should be informed through a discussion between the injection well owner or 

operator and the Director to determine the purpose and proper design of the well. 

85
For additional information on the waiver approach and aquifer exemptions for Class VI wells, 

please see the final rule and preamble, as well as EPA's responses to comments on the Notice of 

Data Availability and Request for Comment. 

Letter ID: 0170 Comment ID: 24219 Letter Lines: 1752 to 1769 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; 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 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 VI 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 Response: API agrees with the concept that Class VI wells should not be 

injecting hazardous wastes but is 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 

original 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 

management and accounting system is beyond the scope of this regulation. 

Individual Response: EPA agrees; the GS regulation applies to injection 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 program’s authority under the SDWA is limited to 

ensuring that GS projects are sited, constructed, operated, and closed 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 characteristics of the CO2 stream because the 

concentrations of minor and trace elements in CO2 streams for GS projects are likely to vary by 

facility, coal composition, plant operating conditions, and pollution removal technologies. 

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 "authorize" inappropriate 

86
hazardous 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 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 CO2 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. 

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 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 that may apply. 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 substance 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 the composition of the specific CO2 stream and the environmental 

media in which it is stored (e.g., soil or ground water). CERCLA exempts from liability, under 

CERCLA section 107, 42 U.S.C. 9607, certain "federally 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 well 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 USDWs. 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 event that a remedial response is 

necessary. Although EPA anticipates that the need for emergency or remedial actions at GS sites 

will be rare, the GS rule requires, at §146.94, that emergency and remedial response plans be 

87
developed and updated to address such events and that owners or operators demonstrate that 

financial resources are set aside to implement the plans if necessary, per §146.85. 

Regarding long term liability, once an owner or operator has met all regulatory requirements 

under Part 146 for Class VI wells and the Director has approved site closure pursuant to 

requirements at §146.93, the owner or operator will generally no longer be subject to 

enforcement for regulatory noncompliance. Furthermore, 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 certain circumstances. For example, an owner or operator may be 

held liable for regulatory noncompliance even after site closure 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 regulatory compliance, an owner or operator may be 

subject to a §1431 response order even after proper site closure is approved under §146.93. 

Under §1431 the Administrator may require an owner 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 present an imminent and substantial endangerment 

to the health of persons, and the appropriate State and local authorities have not acted to protect 

the health of such persons. The action may include issuing administrative orders or commencing 

a civil action for appropriate relief against the owner 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 operator may remain liable under tort and other 

remedies, or under other federal statutes including, 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. 

EPA adds that promoting the use of GS is outside the scope of the GS rule. Rather, the purpose 

of the GS regulation is to ensure that, where deployed, GS is conducted 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 requests 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 potential CERCLA liabilities will have the 

88
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. 

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 that may apply. To the extent the commenter is 

seeking interpretations of CERCLA, such interpretations 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 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 

pressure dissipation. EPA says that these layers could provide additional sites 

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 proposed GS site. EPA specifically 

seeks comment on the merits of requiring the identification of these additional 

zones. EPA Notice 43506. 

API Response: API holds that secondary containment is not mandatory. There are 

many areas where a single confining zone can be shown 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. 

Individual Response: EPA clarifies that secondary confining zones are not required for all GS 

sites. Rather, secondary confining zones are required when the Director 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 primary (i.e., lowermost) confining zone can 

improve USDW protection. These layers could further impede vertical fluid movement and 

89
allow 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 provides 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 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 of 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. 

API Response: 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 sole basis for 

determining the AoR. Other technologies such 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 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. 

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 characterization, monitoring and operational data, and 

computational modeling, the projected lateral and vertical migration of the carbon dioxide plume 

and formation fluids in the subsurface from the commencement of injection activities until the 

plume movement ceases, until pressure differentials sufficient to cause the movement of injected 

fluids or formation fluids into a USDW are no longer present, or until the end of a fixed time 

period as determined by the Director.” 

EPA clarifies that the model inputs must include actual 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 

90
requirements of §146.82(a). Models will be revised and recalibrated during subsequent AoR 

reevaluations, which must account for all available 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, owners 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 may prevent full evaluation 

of model results (e.g., NRC, 2007). Several popular codes in the petroleumreservoir engineering discipline are proprietary 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 should 

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. 

API Response: Use of proprietary models should be allowed. EPA’s Confidential 

Business Information requirements should apply to any proprietary model used. 

Individual Response: EPA agrees that some of the available 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 satisfaction, the code assumptions, relevant equations, and scientific 

basis. EPA acknowledges that several proprietary models have been used by petroleum-reservoir 

engineering professionals as well as in peer-reviewed studies to model CO2 sequestration. EPA 

adds that its Confidential Business Information 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 delineating the AoR of GS sites. EPA Notice 

43507. 

API Response: While computational fluid flow models can inform the delineation 

91
of the AoR, modeling shouldn’t be the sole criteria for determining AoR. (See 

Comment # above also.) 

Individual Response: As described above, 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, specifying that site characterization, monitoring, and operational 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 frequency (seeking comment) 

Comment: Rule Provisions: 146.84 

EPA Preamble Question: 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. 

API Response: 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. 

Individual Response: EPA believes that periodic AoR reevaluation at a set frequency is 

necessary to ensure protection of USDWs from endangerment and address the uncertainties 

inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure that a 

deliberate effort is made to verify, based on monitoring and operational data, that the CO2 plume 

is moving within the subsurface as predicted. EPA believes that less frequent reevaluations may 

not be sufficient to appropriately model plume and pressure front movement, establish conditions 

for corrective action, and ensure protection of USDWs from endangerment. 

EPA clarifies that if site monitoring data agrees with the existing AoR delineation, a model 

recalibration may not be necessary, and the AoR reevaluation may consist of a demonstration 

that the current AoR delineation is adequate based on site monitoring data. 

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 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 to 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 

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AoR as well as the phased corrective action approach for GS wells. EPA Notice 

43508. 

API Response: 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. 

Individual Response: EPA acknowledges the commenter’s support 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, avoiding delays in project start-up, allowing for use 

of future, improved corrective action 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 frequency 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 protection of USDWs from endangerment and address the 

uncertainties inherent in predictive modeling. Periodic AoR reevaluations at §146.84(e) ensure 

that a deliberate effort is made to verify, based on monitoring and operational data, that the CO2 

plume is moving within the subsurface as predicted. 

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 opposite a cemented interval. EPA Notice 

43509. 

API Response: 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 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 the long-string casing extend to the 

injection zone and be cemented by circulating cement to the surface in one or more stages. It 

does not, however, specify how cementing would be accomplished, and gives flexibility to the 

owner or operator to propose alternate methods to provide a sufficient amount of cement to meet 

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the standard that USDWs are protected from endangerment, subject to the approval of the 

Director. EPA notes that there are many potential ways to meet the requirement in deep wells, 

such as the use of staged cementing. See the discussion of Class VI well construction 

requirements in the preamble to the final GS rule for additional information. Additionally, EPA 

is developing guidance on the construction of Class VI wells. This guidance will be available on 

EPA’s website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA adds that cementing of deep wells has been performed successfully in the past, for example, 

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 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 provision, saying that it provides, at a reasonable cost, corrosion 

protection of the casing; prevents undesirable migration of fluids behind the casing; provides 

support to the casing; and provides multiple barriers against endangerment of USDWs. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

is very deep. To further address comments on deep injection wells, the final GS rule at §146.95 

includes requirements for owners or operators that seek a waiver of the injection depth 

requirements. Owners or operators of wells operating under injection depth waivers must comply 

with additional construction requirements to ensure that wells used to inject above or between 

USDWs are protective. See the discussion of the waiver 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 wells (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 demonstrated 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 deemed to meet the requirements of 

146.86 and 146.87 upon notification. The purpose of grandfathering 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 under the Class II program. 

Individual Response: The final Class VI regulations require that any owner or operator 

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injecting CO2 for the primary purpose of long term storage obtain a Class VI permit with some 

special consideration for the fact that they are transitioning from a well not originally designed to 

meet Class VI requirements. The Director has the authority to determine at what point a Class VI 

permit is required for those projects that are transitioning from the primary purpose of EOR to 

long term storage of CO2. The final regulation provides a set of technical factors for the Director 

to evaluate in making this determination, at §144.19. EPA believes that this approach provides 

sufficient protection of USDWs when there is an increased risk to USDWs as compared to 

traditional Class II operations while allowing for site-specific flexibility. 

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

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

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

long-term storage of large volumes of CO2. The guidance describes recommended methods the 

Director may use to 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/groundwater/uic/wells_sequestration.cfm. 

In response to the comment that GS wells should 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 warrants tailored requirements. For example, the volume of CO2 anticipated 

to be injected in Class VI wells is significantly greater than for Class II wells. Reservoir pressure 

conditions will also be different, with Class VI injection operations involving large volumes of 

CO2 and likely having higher pressures within their storage formations than Class II ER projects, 

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 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 43509. 

API Response: Drilling of directional and 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 horizontal or have horizontal 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 appropriateness of horizontal drilling techniques 

for Class VI wells, and commenters representing energy companies, electric utilities, the oil and 

gas industry, CCS associations, states, and the public, unanimously supported the concept and 

provided many reasons why horizontal wells could be beneficial at GS sites. Based on an 

evaluation of these comments and additional research by EPA, the Agency has concluded that 

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horizontal wells that are properly constructed, logged, and tested for mechanical integrity (i.e., to 

meet the requirements of the GS rule) can ensure the protection of USDWs 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 resistant 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 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. 

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

injecting CO2 for the purpose of enhanced recovery, 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 flexibility: it does not specify materials to be used; 

rather, it provides owners or operators with the flexibility 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 described by the owner or operator and will be 

evaluated by the Director and must 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/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0170 Comment ID: 24235 Letter Lines: 1960 to 1969 

Comment Code: 4130 2.4.1.3 Appropriateness of using fracturing for well stimulation (seeking 

comment) 

Comment: Rule Provisions: 146.88(a) 

EPA Preamble Question: 20. EPA is requesting comment on the extent and scope to 

96
which hydraulic fracturing should be allowed 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 confining unit that would result in endangerment 

of USDWs. There are computer simulators to predict fracture behavior so the 

impact on the confining zone 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 sites, where approved by the Director. 

Hydraulic fracturing is one of several stimulation technologies available to improve wellbore and 

formation injectivity. EPA clarifies that fracturing is permitted during stimulation, but not during 

injection. During injection, the injection pressure must not exceed 90 percent of the fracture 

pressure, as specified in §146.88(a). 

All stimulation, including hydraulic fracturing, must be approved by the 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 will 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 possible 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, will inform the Director's decision on whether 

hydraulic fracturing is acceptable 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 requesting 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 rule 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) 

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Comment: 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 protection is best achieved by ensuring 

compatibility of the casing/tubing material design strength 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 tubing 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 pulling the devise 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 landing 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 install automatic surface shut-off devices. The rule 

affords Director's discretion to mandate automatic down-hole shut-off devices in onshore 

situations that may warrant their use. The rule requires, at §146.88(e)(3), that owners or 

operators of offshore wells within State territorial waters install automatic down-hole shut-off 

systems. 

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 aware that the proposed requirement of 

injecting CO2 below the lowermost USDW may preclude injection 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 lowermost USDW, and thus potentially 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 below the injection formation. Retaining 

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the restriction would remove a significant 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, 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: As described above, EPA acknowledges that there are limited 

circumstances where injection above the lowermost USDW can be performed in a manner that 

protects USDWs from endangerment, as long as appropriate protections are in place. The final 

GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the 

Class VI injection depth requirements for injection into non-USDW formations above and/or 

between USDWs. 

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 soliciting comment on whether CO2 injection 

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

API Response: See response to #23. CO2 injection 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 lowermost USDW can be performed in a manner that 

protects USDWs from endangerment, as long as appropriate protections are in place. The final 

GS rule at §146.95 establishes a process by which owners or operators can seek a waiver of the 

Class VI injection depth requirements for injection into non-USDW formations above and/or 

between USDWs. 

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 

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EPA Preamble Question: 25. EPA is also requesting comments on whether aquifer 

exemptions should be allowed for the purpose of Class VI injection, and under 

what conditions should such aquifer exemptions 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 limited 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 exemption 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 for GS projects must meet all of the tailored 

requirements for GS wells in the final GS rule, including the requirements at §146.83 for site 

criteria. EPA believes that, in most cases, the injection 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 whether 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 permit 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 zone are protected from endangerment. 

This approach is designed to ensure that the differences between traditional Class II EOR/EGR 

operations and Class VI operations are considered during the aquifer exemption application 

process and the Class VI permitting process. These 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 Agency believes that this process will encourage 

owners or operators and Directors to consider the use of alternative 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 Class 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 Data Availability and 

Request for Comment. 

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Letter 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 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. 

API Response: There should be no minimum depth 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. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects or require that the CO2 be injected in a supercritical state. EPA believes that a 

determination of site-suitability for GS (i.e., that subsurface formations 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- 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 that USDWs will be protected from endangerment. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs, as long as appropriate protections 

are in place. The final GS rule at §146.95 establishes a process by which owners or operators can 

seek a waiver of the Class VI injection depth requirements for injection into non-USDW 

formations above and/or between USDWs. The waiver approach requires the submission of 

extensive, site-specific information (in conjunction with the permit application submission) to 

demonstrate that injection of CO2 into a non-USDW that is above or between USDWs can be 

done in a manner that is protective of USDWs. The requirements are designed to ensure that the 

owner or operator, the Director, and the Regional Administrator consider, on a site specific basis, 

the implications, benefits, and challenges associated 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 impact on human health or ecosystems 

(seeking comment) 

Comment: Rule Provisions: 73 FR 43513-15 

101
EPA 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 ecosystems 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 use 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 Experiment site (Dayton, TX) used various types of 

tracers, including perfluorocarbon tracers (PFTs), sulfur hexafluoride, and the noble gases 

krypton, neon, and xenon. These studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; 

McCallum et al., 2005) found that tracers can provide useful CO2 monitoring information at 

injection wells at depth and at near-surface locations. At Frio, tracers enabled quantification of 

CO2 plume behavior and provided a technique for model validity testing (McCallum et al., 

2005). EPA will continue to track research 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 determine whether the appropriate amount and types of 

information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 

Letter ID: 0170 Comment ID: 24243 Letter Lines: 2066 to 2081 

Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: Rule Provisions: 146.89(b) 

EPA Preamble Question: 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. 

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API 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 strongly shows that daily monitoring of 

most of these parameters is adequate (exceptions to this would be on a sitespecific basis). Recording should generally 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 level 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 materials, 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 fairly wide use. EPA anticipates that Class VI 

injection wells will 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. 40 CFR 146.91(a)(2) requires that monthly averages of the 

continuous annulus monitoring be reported on a semiannual basis. 

At least one commenter indicated that the technology required for continuous monitoring is 

currently available and should not present an undue cost burden. Continuous annulus monitoring 

is also conducted at the commercial-scale carbon capture and geologic sequestration 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 needed and is using an adaptive approach to 

regulating GS. The Agency plans to collect and review data every six years on GS projects to 

determine whether the appropriate amount and types of information and appropriate 

documentation are being collected, and to determine if modifications to the requirements are 

appropriate or necessary. 

Letter ID: 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) 

103
Comment: Rule Provisions: 146,89(c), 146,90(e) 

EPA Preamble Question: 29. EPA seeks 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. 

API Response: Timing for conducting MITs, 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 external MIT is appropriate. The final GS 

regulation retains the requirement that owners or operators of Class VI wells must demonstrate 

injection well external mechanical integrity at least once annually under §146.89(c). 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 protection of USDWs from endangerment given the unique nature of 

CO2 GS relative to other injection operations, including the potential corrosive impact of CO2 in 

the presence of water and impurities on well materials, the potential geomechanical impacts to 

well integrity due to CO2 phase changes, the temperature and pressure effects associated with 

injecting supercritical CO2, and the buoyant nature of the injected CO2. Because of the unknown 

long-term effects of CO2 GS, EPA chose a more conservative initial approach in the early stages 

of deployment for GS. 

In addition, a comprehensive review conducted by EPA of MIT results from 1993 to 1998 found 

that Class I wells injecting corrosive fluids fail MITs at rates two to three times higher than those 

that inject non-corrosive fluids (USEPA 1999). Given the potential for CO2 to be corrosive (e.g., 

in the presence of water or aqueous formation fluids), there is a potential risk factor for MIT 

failure and, for this reason, EPA believes that the tailored MIT requirements in the final GS rule 

are appropriate. 

EPA adds that it is using an adaptive approach to regulating GS. The Agency plans to collect and 

review data every six years on GS projects, including MIT data, to determine whether the 

appropriate amount and types of information and appropriate documentation are being collected, 

and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 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 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 flexibility in selecting the 

appropriate methods for their specific situation. API RP90 provides good 

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examples of various methods for detecting mechanical failures, managing those 

risks, and conducting MITs. 

Individual Response: EPA believes that the MITs described 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 problems 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 the owner or operator to prepare and gain approval 

for a project-specific testing and monitoring plan that includes MITs under §146.90. EPA 

clarifies that the regulations allow the Director to require additional methods or, with the 

Administrator's approval, to approve the use of alternative MIT methods 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 Agency plans to collect 

and review data every six years on GS projects to determine whether the appropriate amount and 

types of information and appropriate documentation are being collected, and to determine if 

modifications to the requirements are appropriate or necessary. 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 front tracking (seeking comment) 

Comment: Rule Provisions: 146.90 

EPA Preamble Question: 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 

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 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 relatively 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, modeling, and AoR reevaluation is 

appropriate to verify that the CO2 plume and pressure front are moving through the subsurface 

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as predicted, verify the accuracy of the delineation model (or identify needed changes), and 

refine testing and monitoring activities to ensure 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 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. 

API Response: 31. 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 operational injection. 

Following the first year, the frequency should be at the discretion of the Director 

but the frequency should be aligned with 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 appropriate 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 project, if necessary based on sitespecific circumstances. Pressure fall-off tests may be conducted in conjunction with other well 

performance tests (i.e., mechanical integrity testing) to ensure safe 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 front 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 information evaluated to date, EPA believes 

that tracking the 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 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 front will be more difficult since that requires data 

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from the injection formation 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. 

Individual Response: EPA believes that direct pressure measurements 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 track the extent of the CO2 plume and pressure 

front. The owner or operator must use direct methods to monitor for pressure changes in the 

injection zone. Indirect methods (e.g., seismic, electrical, gravity, or electromagnetic surveys 

and/or down-hole CO2 detection tools) are also required unless the Director determines, based 

on site-specific geology, that such methods are not appropriate. 

EPA believes that pressure monitoring in the injection zone is necessary 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 modeling, evaluate predictions of 

plume movement, and target additional geochemical 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 appropriate 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 prove to be useful. Such methods may be an 

important component of plume tracking at some GS sites. For this reason, the final rule (at 

§146.90(g)) requires the use of indirect methods (e.g., seismic, electrical, gravity, or 

electromagnetic surveys and/or down-hole CO2 detection tools) unless the Director determines, 

based on site-specific geology, that such methods are not appropriate. 

EPA is developing guidance on testing and monitoring to assist owners 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, MITs, injection well testing 

during operation, groundwater quality monitoring, tracking the CO2 plume and pressure front, 

and soil gas and surface air monitoring which may be required by the UIC Director for specific 

GS projects. The guidance can be found on EPA’s website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. In addition, in January 2009, 

DOE published a best practices manual entitled "Monitoring, Verification, and Accounting of 

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CO2 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 comment on the appropriate amount and 

types 

of monitoring that should be conducted at a GS site. Specifically, EPA seeks 

comment regarding the usefulness 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. 

API Response: Monitoring techniques and frequency should be determined 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 does not add value to the protection of USDWs. Many of 

the surface 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 defer on using 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 not necessary at all GS sites and agrees that the decision to use 

surface monitoring and the selection of monitoring methods for the purpose of USDW protection 

will be site-specific. 

EPA acknowledges that air and soil gas monitoring are subject to variability and may not be 

suitable in all settings as a method to ensure USDW protection. However, EPA does not believe 

that this should entirely preclude their use. For example, if a leak to the surface is suspected, 

surface monitoring could provide vital information on its location and magnitude to assist 

owners and operators in identifying what USDWs may have been impacted by a leak. EPA 

clarifies that the various air and soil gas monitoring methods (e.g., chambers, eddy covariance, 

hyperspectral imaging) all have different capabilities that may prove useful in specific GS 

projects (Miles et al., 2005; Pickles and Cover, 2005; IPCC, 2005; Menzies et al., 2001). The 

occurrence of false positives will be reduced by comparing monitoring data to baseline data 

collected prior to injection or from a nearby area away from the GS project. 

Letter ID: 0170 Comment ID: 24251 Letter Lines: 2163 to 2184 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

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Comment 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 proposing 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. 

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. API is concerned that every modification 

of a plan may trigger a major permit 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. 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 monitoring plan at the start of the project, 

particularly considering that these activities 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 part of assuring that a GS project is operating properly and is 

crucial for the early detection of potential endangerment 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. EPA clarifies that the final GS 

regulation includes a requirement that the AoR be reevaluated at least every five years, and it 

specifies at §146.90(j) that the operator revise the testing and monitoring plan to incorporate the 

results of the most recent AoR reevaluation 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 and USDWs or other layers above the confining zone. Such 

construction technologies exist and have been used in the oil and gas industry for years. The 

testing and monitoring plan must describe how the owner or operator plans to site and construct 

monitoring wells. EPA is developing guidance on well construction that will include 

recommendations for monitoring well construction. The guidance will be available on EPA’s 

website at http://water.epa.gov/type/groundwater/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 regulation at 40 CFR 144.39(a) identifies causes for 

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modification of permits that would invoke the public notification procedures at 40 CFR 124. In 

the final rule, EPA added text to §144.39(a)(5) that permit modifications would be required if the 

Director determines that a modification is necessary 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 for minor modifications of permits (which do 

not require following the procedures 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, plugging plan, post-injection site care 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 monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90. The guidance can be found on EPA’s 

website at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. In addition, in 

January 2009, DOE published a best practices manual entitled "Monitoring, Verification, and 

Accounting of CO2 Stored in Deep Geologic 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-injection site care and site closure plan. 

EPA also believes that it is appropriate to require owners and operators to submit all plans, 

including the injection well plugging and post-injection site care and site closure plans, at the 

time of permit application. EPA believes that the Director needs a satisfactory level of assurance 

that the owner or operator has planned for these events before injection commences and that the 

owner or operator has ensured that appropriate financial resources 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 comment on the frequency of all proposed 

reporting requirements. EPA Notice 43517 

API Response: 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 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 within 30 days of the test. EPA clarifies that some 

monitoring frequencies (e.g., associated with ground 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 of these tests will be determined based on site110
specific information. For additional information, please see the final rule and the preamble for a 

discussion of EPA's final approach to recordkeeping and reporting. 

EPA disagrees that reporting should 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 reporting on all wells in a GS project at the same 

time; however, data for each well must be reported 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 comment on the requirement for electronic 

reporting in its proposed rule. EPA Notice 43518. 

API Response: API strongly supports the concept of electronic reporting. 

Industry’s objections to prior proposals for electronic reporting 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 

electronic reporting are resolved, such reporting may be encouraged but should 

not be required. 

Individual Response: EPA agrees and believes that electronic formatting is the most appropriate 

format for submitting Class VI project information to the Director, and requires this at 

§146.91(e). Based on comments received on the proposed 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 activities and provides recommended guidelines on 

the types of data to be collected for tracking GS projects, reporting 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 annual reports (seeking comment) 

Comment: Rule Provisions: 73 FR 43518 

EPA Preamble Question: 37. In addition to the above recordkeeping and reporting 

requirements, EPA considered a requirement for owners or operators of GS sites 

to provide an annual report during the lifetime of the project, including the 

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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 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 would 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 annual report. Instead, EPA believes that periodic 

reevaluation of the AoR, as required at §146.84(e), along with any revisions 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 operators to review and update the AoR and 

corrective action plan, the testing and monitoring plan, and the emergency and remedial response 

plan throughout the life of the project. Owners or operators must review each plan and identify 

necessary amendments to the plan or demonstrate 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 addition of monitoring or injection wells), or when 

required by the Director. In no case can reviews occur less often than once every five years. See 

the final rule and preamble for further discussion 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-annual report in conjunction with the continued 

dialogue associated with AoR reevaluations and periodic updates to the plans is a preferred 

approach to an annual report. 

EPA encourages and expects owners and operators to share monitoring and operating data with 

the public voluntarily, however (e.g., through the Internet). Providing 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 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 shorten 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. 

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API Response: API strongly objects to the use of a 50-year 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 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 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. 

Individual Response: EPA disagrees that the post-injection monitoring period is arbitrary. In 

determining the post-injection site care-timeframe for the proposed regulation, EPA reviewed 

industry reports, existing environmental programs, and initial GS research studies. EPA provided 

a synthesis of pertinent results from GS modeling studies in the preamble to the proposed 

regulation. Further explanation of this analysis was included in an EPA-prepared background 

document that is available in the federal docket, titled "Computational Modeling of Underground 

Injection of Carbon Dioxide for Determination of Area-of-Review and Potential Risk to 

Underground Sources of Drinking Water." Based on review of these studies, modeling results 

indicate that the CO2 plume stabilization may occur on the timeframe of 10-100 years after the 

cessation of injection. EPA believes that a 50-year default post-injection site care timeframe is a 

reasonable midpoint for most GS projects and available data, including data submitted by 

commenters, do not support a different default timeframe, and has retained this in the final 

regulation. 

However, EPA recognizes that there may be sites 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 offers owners or operators flexibility regarding 

the duration of the PISC timeframe by: (1) allowing the Director discretion to shorten or 

lengthen the PISC timeframe during the post-injection period based on site-specific data, 

pursuant to requirements at §146.93(b); or (2) affording the Director discretion to allow a Class 

VI well owner or operator to demonstrate, during the permitting process based on substantial 

data, that an alternative PISC timeframe may be appropriate if it ensures non-endangerment of 

USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

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EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of 146.92 and 146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans 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, demonstrate the appropriateness of an 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: 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 requesting comments on the proposed 

requirements for well plugging, post-injection site care, and site closure, 

including the proposed requirements for the post-injection time period. EPA 

Notice 43520. 

API Response: See question 38 above regarding 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 plume and pressure front no longer 

pose a risk of endangerment to USDWs. For this reason, the final GS regulation includes a 

provision that the Director may, at his/her discretion, shorten the post-injection site care 

timeframe if the owner or operator can demonstrate that the GS project does not pose a risk to 

USDWs, as specified in §146.93(b)(2). Such a demonstration will be site-specific, and based on 

pressure monitoring and USDW impacts. Alternatively, the final rule at §146.93(c), also allows 

the Director to approve an alternative post-injection site care timeframe where an owner or 

operator can demonstrate during the permitting process that an alternative post-injection site care 

timeframe, other than the 50 year default, is appropriate and ensures non-endangerment of 

USDWs. The demonstration must be based on site-specific information, including the results of 

site-specific computational modeling; the predicted timeframe for pressure decline; the predicted 

rate of carbon dioxide plume migration; site-specific chemical processes that will result in 

carbon dioxide trapping; the predicted rate of carbon dioxide trapping; characterization of the 

confining zone(s); laboratory analyses or studies to verify the information on trapping; the 

presence of potential conduits for fluid movement and the quality of abandoned well plugs 

within the AoR; the distance between the injection zone and the USDWs above and/or below the 

injection zone; and any additional site-specific factors determined by the Director. The 

demonstration must meet the criteria at §146.93(c)(2) for ensuring the quality and accuracy of 

the data and models on which the demonstration 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 required at §146.82(a)(17). 

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EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of §146.92 and §146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans 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, demonstrate the appropriateness of an 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: 24257 Letter Lines: 2249 to 2255 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Rule Provisions: 146.93(b)(2) 

EPA Preamble Question: 40. In addition, EPA seeks comment on whether the 

Director should be allowed to shorten the timeframe based on performance 

information, and whether EPA should require a shorter or longer post injection 

period if data suggests the time frame should be adjusted. EPA Notice 43520. 

API Response: See question 38 above regarding post closure time periods. 

Individual Response: As described above, EPA recognizes that there may be sites where the 50 

year post injection site care timeframe may be either not appropriate or more burdensome than 

necessary based on site-specific conditions. For this reason, the GS rule offers owners or 

operators flexibility regarding the duration of the PISC timeframe by: (1) allowing the Director 

discretion to shorten or lengthen the PISC timeframe during the post-injection period based on 

site-specific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion 

to allow a Class VI well owner or operator to demonstrate, during the permitting process based 

on substantial data, that an alternative PISC timeframe may be appropriate if it ensures nonendangerment of USDWs pursuant to requirements at §146.93(c). 

EPA believes that a default post-injection site care timeframe of 50 years, with flexibility to 

adjust the timeframe for a limited number of GS projects during the permitting process where 

substantial data exists to demonstrate that an alternative timeframe would be protective of 

USDWs, or based on data collected during the PISC period, is appropriate to address the range of 

115
sites where GS is anticipated to occur, to accommodate site-specific circumstances and various 

geologic conditions, and addresses commenters’ concerns, while ensuring USDW protection. 

Both approaches will utilize site-specific data, and be based on pressure monitoring and USDW 

impacts. 

EPA is developing guidance to assist owners or operators in evaluating well plugging, postinjection site care, and site closure requirements of 146.92 and 146.93. Additionally, the 

guidance will assist Directors in evaluating proposed well plugging plans and post-injection site 

care and site closure plans 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, demonstrate the appropriateness of an 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 financial responsibility requirements (40 

CFR 146.85) 

Comment: Rule Provisions: 144.36 

EPA Preamble Question: 41. Current UIC guidance describes trust funds as a form 

of financial 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 period 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, consistent with other similar 

programs in the Agency. EPA Notice 43521. 

API Response: Industry should have a variety of options for meeting financial 

assurance based upon the companies’ discretion. Options should include selfinsurance, insurance, surety bonds or other 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 responsibility instruments that 

may be used to demonstrate compliance with the financial responsibility provisions, including 

trust funds, surety bonds, letters of credit, insurance, self insurance, escrow accounts, or any 

other instrument(s) provided the Director determines 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 activities, thereby realizing greater flexibility and cost savings from 

this regulation. In the event that the owner or operator combines more than one instrument for a 

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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), for 

example 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. 

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 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 guidance 

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. 

API Response: See response to 41 

Individual Response: As described above, owners or operators may choose from a variety of 

financial instruments listed in §146.85(a) to meet 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 responsibility must be demonstrated, including 

corrective action on wells in the AoR, injection well plugging, PISC and 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 assessing whether a financial ratings 

threshold for all companies 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 current rating threshold established 

under the UIC regulations) is appropriate for GS wells. EPA Notice 43522. 

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API Response: See response to 41 

Individual Response: As described above, owners or operators may choose from a variety of 

financial instruments listed in §146.85(a) to meet 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 responsibility must be demonstrated, including 

corrective action on wells in the AoR, injection well plugging, PISC and 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 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. 

API Response: See response to 41 

Individual Response: As described above, owners or operators may choose from a variety of 

financial instruments listed in §146.85(a) to meet 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 responsibility must be demonstrated, including 

corrective action on wells in the AoR, injection well plugging, PISC and 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 site care (seeking comment) 

Comment: Rule Provisions: 73 FR 43522 

EPA Preamble Question: 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. 

API Response: See response to 41 

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Individual Response: As described above, owners and operators may choose from a variety of 

financial instruments to meet their financial responsibility obligations under the rule, provided 

the Director determines that the operator's proposed financial responsibility demonstration is 

adequate to protect USDWs from endangerment, which means the ability of the owner or 

operator to pay for each activity for which financial responsibility must be demonstrated, 

including corrective action on wells in the AoR, injection well 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 financial responsibility instruments. See the 

final rule and preamble for further discussion of EPA'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 public 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 gathering information. Such tools include 

cable networks, the Internet, and other 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 programs. 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 public participation requirements as 

specified in 40 CFR 25 and 40 CFR 124 are appropriate for GS projects. In addition, because of 

the unique nature of GS projects, and the anticipated level of public interest in GS projects, EPA 

encourages early public involvement in GS projects. Providing the public with accurate, projectspecific information in the early stages of each GS project can help clarify project details and 

avoid public misperceptions about the nature and safety of GS projects, and 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 participation 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 

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Comment Code: 5560 2.10.3 Enhancing the public participation process (seeking comment) 

Comment: Rule Provisions: 73 FR 43522-23 

EPA Preamble Question: 47. EPA also requests comment on ways to enhance the 

public participation process, including engaging communities in the site 

characterization process as soon as candidate 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 characterized in the process of winnowing down 

the portfolio of potential sites. 

Individual Response: The Agency believes that public participation is an important part of the 

UIC permitting process and wants to ensure wide access to decision-making processes and 

information on projects that may affect the public. GS permitting authorities must follow the 

existing public participation 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 require 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 perceive potential environmental, economic, or 

health effects. 

Furthermore, the Agency recognizes that the initial phases of site evaluation and site selection 

may begin in advance of permit application submission. The public may become aware of these 

activities and begin to have questions or concerns 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 avoid public misperceptions about the nature and 

safety of GS projects. This may also benefit 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 authority 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, 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. 

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API Response: 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 

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 acquiring 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 demonstrate 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 wells 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 penalties on owners and operators for non-compliance 

with regulatory requirements; and demonstrate sufficient/appropriate technical capacity (e.g., 

personnel, infrastructure, and technical expertise) to implement 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 that 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 are 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 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 Response: API supports the implementation 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 

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allowed to obtain primacy for Class VI wells independently of other well classes, and will allow 

independent primacy for Class VI wells under §145.1(i) of the final GS rule. 

Letter ID: 0170 Comment ID: 24267 Letter Lines: 2365 to 2373 

Comment Code: 5700 2.12 Comments on the proposed duration of Class VI permits (seeking 

comment) 

Comment: Rule Provisions: 144.36(a) 

EPA Preamble Question: 50. EPA proposes that Class VI injection well permits 

would be issued for the operating life of the GS project including the postinjection site care period. EPA seeks comment 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 would yield administrative burden without 

commensurate benefits. 

Individual Response: EPA agrees with commenters that Class VI permits should be issued for 

the operating life of the GS project. The final rule maintains the lifetime permit provision and 

clarifies that the permit extends through the post-injection site care period (144.36(a)). EPA 

believes that the iterative process of developing and executing the various plans required of GS 

well operators under the final rule (e.g., for AoR and corrective action, testing and monitoring, 

injection well plugging, post-injection site care, and emergency and remedial response) is 

tailored to the unique aspects of—and is more appropriate for–GS than establishing a finite 

permit duration (e.g., five years as suggested by some commenters). EPA adds that the required 

reviews of the AoR and corrective action plan, the testing and monitoring plan, and the 

emergency and remedial response plan throughout the life of the project are preferable to a 

periodic permit reapplication. The iterative process and subsequent plan reevaluations ensure that 

time and resources are committed to the most critical aspects of the permit in preventing 

endangerment to USDWs. EPA notes that the final rule 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 estimating 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 represent a significant component of the 

Cost Analysis, the Agency acknowledges that this factor may be significant in 

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the overall uncertainty of the Cost Analysis. 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 characteristics 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 monitoring wells associated with GS 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

presented in Exhibit 5.2 of the Cost Analysis. 

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

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

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

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

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

Exhibit 5.26 of the Cost Analysis). 

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

used at GS sites. 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: Children'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 assess the effects of early life exposure to 

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changes in drinking water quality that may be caused by geologic sequestration 

of carbon dioxide. EPA Notice 43531. 

API Response: 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. 

Individual Response: EPA is funding research related to the potential for USDW contamination 

associated with GS projects. In addition, the Agency 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 Availability (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 native mineral species that could potentially be 

mobilized by the intrusion of CO2 and the potential ground water concentrations that could result 

to determine the potential for drinking water standards to be exceeded. EPA has also examined 

potential methods for conducting treatment of water 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 investigate the fate of dissolved CO2 in underground 

geologic formations and to determine possible risks 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 Design, 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 protect USDWs from endangerment through 

permitting, siting, construction, operation, injection, and 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 risks to all populations, including children. The "Risk and Occurrence 

Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, 

presents a broad discussion of risks to human health 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 approach, EPA plans to collect and review available 

information, such as the research described above, and data every six years on early GS projects, 

including impacts to USDWs and drinking water quality that may affect the health of children, to 

determine whether the appropriate amount and types of information and documentation are being 

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collected and to determine if modifications to the requirements are appropriate 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 assumptions for what is required to comply 

with the new requirements in the cost analyses seem far less comprehensive than 

what appears to be 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 examples 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 

requires. The rule contains over four pages worth of fairly detailed 

requirements for GS site selection and approval, including the following for 

owners or operators to prepare and submit: 

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

“ Demonstration that the injection zone is: (1) sufficiently porous to receive 

the CO2 without fracturing and (2) extensive enough to receive 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 demonstrate the lateral extent and thickness, 

strength, capacity, porosity, and permeability of subsurface formations. They 

must demonstrate that the injection zone 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 displacing 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 "pinchouts" (i.e., thinning or tapering 

out) can affect storage potential, would need to be examined. 

“ Data on the local geologic structure, including information on the presence of 

any faults and fractures that transect the confining zone and a demonstration 

that they would not interfere with containment. These data are to support 

determinations about whether these features, 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, 

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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. 

Information on insitu 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 techniques 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 subsurface 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 pressure 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 CO2 and displaced brines. 

“ Demonstration of the maximum sustainable injection pressures that will not 

cause unpermitted fluid movement, in order to assure that owners or operators 

not exceed an injection pressure that would initiate or propagate fractures in 

the confining zone. This should be based on geomechanical studies of fault 

stability and rock 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, 

“ Information on the geochemistry of formation 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 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. Owners or operators are 

to submit geochemical data on a) the injection zone, b) the confining zones, c) 

containment zones above the confining zones 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 proposed monitoring program. 

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-months 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 

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the International 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.[FN2] 

[FN2: Advanced Resources International, Remediation 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 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. No 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 

permitting 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. 

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 place 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 value calculations) and allows for comparison of 

costs across rules that are incurred on various timelines. These factors result in the presentation 

of costs that are much lower than the 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 simulation 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 

127
projects were not increased, based on the assumption that ER sites would already have a 

significant amount of data available 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 estimates that are incremental changes in cost 

relative to the baseline), is consistent with EPA Guidelines for Preparing Economic Analyses 

(September 2000) and with other major rulemakings under SDWA. 

EPA clarifies that it included costs of delineation wells under the category 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, monitoring 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 the baseline (based on Class I nonhazardous well 

requirements) includes burden for completing basic monitoring and testing plans, corrective 

action plans, and well failure contingency plans, as required at 40 CFR 146.14(a). A well 

plugging plan is also required under the baseline at §146.14(c). The incremental burden 

associated with writing these plans under the final 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 information needed to complete the more detailed plans 

now required under the final rule and to compile this information into the plans is addressed in 

sections 5.4.3 (AoR and Corrective Action) and 5.4.7 (Monitoring). 

For additional information on the final costing approach, 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/edits 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 

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Rationale: 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 discretion 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 flexibility to select the appropriate log to 

demonstrate adequate cement bond. 

Rule Provision: 146.87(a)(3)(i) 

API Comments: Resistivity, spontaneous potential, porosity, caliper, gamma ray, 

fracture finder logs and any other logs the Director requires BASED ON SITE 

SPECIFIC CONDITIONS AND RISK-BASED FACTORS 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 information 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 with 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 

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

(a) 

Rule Provision: 146.87(a)(5) 

API Comments: (5) Any alternative 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 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. 

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 injection and confining zones and ensure that the well 

is being drilled and cased as approved, and has mechanical integrity. This information is needed 

to demonstrate that the well can be operated and tested in a manner that protects USDWs from 

endangerment. While the tests do provide information on some of the same items, each provides 

unique data that build on each other and allow for interpretations not possible with a single test. 

EPA notes that the Director has the discretion at §146.87(a)(5) to approve alternative methods 

that provide equivalent or better information. EPA believes that logs and tests must be performed 

on each well drilled regardless of existing information 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 needed for site-specific well 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 disagrees 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 surveys in evaluating mechanical integrity has been 

proven over time. EPA clarifies that a tracer survey is one of the mechanical integrity tests that 

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may be required by the Director or used by the owner or operator. EPA agrees with the 

commenter about the wording of the casing inspection log requirement and made the suggested 

change to improve clarity. In the final regulation, §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 confining system and formation fluid samples from the 

injection zone(s), and must submit to the Director a detailed report prepared by a log analyst that 

includes: well log analyses (including well logs), core analyses, and formation fluid sample 

information...." 

Letter ID: 0170 Comment ID: 29200 Letter Lines: 1117 to 1177 

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

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

Comment: Rule Provision: 146.87(c) 

API Comments: (c) PRIOR TO INJECTION WELL OPERATION, the owner or operator 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). 

Rationale: 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. 

Rule Provision: 146.87(d) 

API Comments: (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. 

Rationale: With the exception of calculating fracture pressure, the requirements 

of this section appear redundant to other requirements of prior sections. The 

fracture pressure requirement has been added to section 146.87(e) below. (2) and 

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(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 SHOULD BE BASED ON REPRESENTATIVE 

HYDROGEOLOGIC 

AND GEOMECHANICAL CHARACTERISTICS OF THE INJECTION ZONE. 

Rationale: Allows the use of information such as leak off tests conducted during 

the drilling operation. 

The 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 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 realities 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. 

Individual Response: EPA disagrees that "reservoir pressure" 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 always be identical to the reservoir pressure. 

Additionally, measuring the static fluid level provides 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 injection and confining zones in 

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§146.87(d) is warranted, and that the rule provides 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 disagrees that pump tests are irrelevant to determining 

injection zone properties. Depending on the characteristics or depth of knowledge of the 

confining and injection zone formations, pump tests may be necessary to prove that no hydraulic 

connection exists between the injection zone and a USDW. Additionally, EPA disagrees that the 

wording at §146.87(d) would lead the owner or operator to employ destructive testing methods 

for determination of fracture pressure. The wording "determined or calculated" allows for 

calculations to be performed based on non-destructive methods. 

EPA disagrees that the 30-day notification requirement is unreasonable. Acknowledging the 

developing nature of CO2 GS, EPA believes that involvement by the permitting authority in each 

project will provide much needed field data for assurance of USDW protection from 

endangerment and will help update and refine the permitting process. Adequate timing of 

notification will ensure the Director's ability to be involved. 

Letter ID: 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 opposite a cemented interval. EPA Notice 

43509. 

API opposes the requirement for cementing 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 operators ability to 

monitor for leakage or conduct remedial operations. 

Individual Response: As described above, EPA believes that the requirements for long-string 

casing are appropriate and offer appropriate flexibility. EPA does not believe that the cementing 

requirements at §146.86 would prevent monitoring, operation, and remediation of GS 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 and 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 additional information. 

Additionally, EPA is developing guidance on the construction of Class VI wells. This guidance 

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will 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 opposite a cemented interval. EPA Notice 

43509. 

Regarding packer setting depth, the director should retain discretion for 

allowing variation from this requirement. 

Individual Response: EPA clarifies that the rule does allow some Director's discretion in 

approving the owners or operators proposed well construction plan. The Director will evaluate 

the appropriateness of the proposed construction based on site-specific information about the 

injection project. EPA believes that 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 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 rule 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 some 

discussion of the uncertainty associated with these costs, and the potential 

implications associated with this uncertainty on EPA’s conclusions, at a 

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minimum, 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 probability of site failure and remediation of the 

site, which is included as a separate item and defined as a low percentage of capital expenditures 

on an annual basis. EPA included in the cost analysis 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 project-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 approach, 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 saline 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 characterization (cross sections, performing inter-well 

seismic, 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 often 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 EPA 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, while the 

engineer’s hourly labor rate was assumed to be $53.52 per hour. Assuming 2,080 

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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 year, and a "representative" engineer’s salary of $44,000 to 

$56,000 per year. 

The American Association of Petroleum Geologists (AAPG) performs 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 reasonable. However, it is important to 

note that in the last 3 years, these salaries have risen by 35%. 

[FN3: http://www.aapg.org/explorer/salarysurvey.cfm] 

Because of the similarities in the engineering tasks associated 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. 

The Society of Petroleum Engineers also performs an annual survey of its 

members, the last one conducted in September 2007.[FN4] The result 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 types of activities) where the 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, perhaps 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 engineers in EPA’s assessment, this could 

have a substantial impact on their overall cost impact characterization, perhaps 

on the order of about $60,000 per GS site. 

[FN5: http://www.bls.gov/oco/ocos027.htm#projections_data] 

[FN6: http://www.payscale.com/research/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 increase of 115% in the rate for engineers. EPA 

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believes the updated labor rates are consistent with those in the field and representative of labor 

costs for GS projects. 

Using industry survey data from AAPG and SPE as presented in the 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 rates in the final rule cost analysis are $107.23 

and $110.62 in 2008$ for engineering geologists and 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 approach, 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, importantly, the situation where demand for well 

drilling services in the GS industry expands 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. 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 

costs associated with well drilling and completion increases the range to from 

$280 to $320 per foot for a 9,000 foot well. 

According to the latest drilling cost survey by the American Petroleum Institute 

(for 2006):[FN7] 

“ The average costs of drilling and completing 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. 

[FN7 American Petroleum Institute, 2006 Joint Association Survey on Drilling 

Costs, April 2008] 

As another point of reference, Advanced Resources has drilled a GS well 

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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 to 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 CO2, today’s proposal includes enhancements to typical 

deep well construction procedures to provide 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 location 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. 

138
EPA appears not to consider the costs of surface equipment associated with CO2 

injection operations 

In addition to the Injection wells, additional surface equipment can often be 

associated with CO2 injection operations. These costs include CO2 storage 

vessels, high pressure pumps and vaporizers, distribution/production headers, 

and CO2 distribution lines when multiple injection wells are needed. It is not 

apparent that all of these costs are included 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 extensive 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 costs, EPA acknowledges that the proposal 

cost analysis underestimated the necessary surface casing lengths, which must be long enough to 

be set through the base of the 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 Director’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 approach, 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 anticipated level of GS activity in the 

United States under the existing regulatory conditions, as per EPA guidelines on 

139
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 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 regional incentive programs.[FN8] 

[FN8: 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)] 

EPA does recognize that alternative assumptions 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 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 technologies could potentially represent a significant percentage of the 

cumulative effort for reducing CO2 emissions worldwide." 

Moreover, the draft of the proposed GS rule goes on to say: 

"Establishing a supporting regulatory framework 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 cost analyses 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. 

Individual Response: EPA clarifies that addressing climate change is outside the scope of the 

GS rulemaking. Rather, the purpose of the GS regulation is to ensure that GS is conducted in a 

140
141

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 using a survey conducted with regional partners in 

2010 from DOE and additional projects from industry knowledge and publicly available data. 

Using a costing baseline that is based on current legislation only, and that does not take into 

account predictions of future legislation, is also consistent with 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 deployment, and did conduct a supplemental analysis 

that considered an alternative legislative 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 risk 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 approach, please see the final cost analysis and 

technology and cost document in the final rule docket.