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.


1

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) 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. 

APC 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. 

While it was apparent in the preamble that the EPA 

intended to allow EOR operations to continue under 

current Class II regulations, the rules left some 

ambiguity to that distinction. In order to operate a 

successful recovery project it is imperative that the oil 

and gas regulators continue to govern EOR 

operations. APC offers language in our comments 

that would make this more explicit. 

APC strongly supports the proposed approach and 

the absence of an economic test for oil and gas 

reservoir “depletion.” Recognizing though that EPA 

may face pressure to change its approach, APC 

offers language in our comments on the proposed 

rule for EPA’s consideration for differentiating 

between wells for EOR/EGR and sequestration. 

Additionally, APC, along with the Multi-Stakeholder 

Discussion Group, supports the creation of a 

subclass under Class II (e.g “Class IIB”) for storage 

operations in hydrocarbon formations. See 

proposed section 146.25. By utilizing this approach 

operators avoid the potential complexity of switching 

agencies in the middle of a project (this is especially 

important given the sometimes conflicting jurisdiction 

shown between various regulating agencies within a 

state). Also, this allows for the different risk-profile of 

sequestration in an oil and gas reservoir to be taken 

into account and a different set of regulating 

requirements to be utilized. 

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. 

APC strongly 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, APC, along with the MultiStakeholder Discussion Group, propose that they 

remain under the Class II program when transitioning 

from EOR to GS. Through the approach of two forms 

of sequestration, Class VI and Class II GS, the EPA 

would eliminate some of the future confusion 

regarding grandfathering of requirements. EOR wells 

will have proven their integrity and protection of 

USDWs during the operational phases of the flood 

through sound performance and MIT programs; and, 

therefore, the construction requirements proposed 

will not be necessary. 
2 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

In addition, many of the required well construction 

requirements, such as cement to surface, are truly 

not necessary. Industry has proven the 

successfulness of current well cement practices in 35 

plus years of CO2 injection for EOR with an excellent 

environmental, health, and safety record. Through 

keeping these projects in the same regulating agency 

that governed the EOR operations it ensures that 

those regulators the most knowledgeable for working 

in oil and gas reservoirs are overseeing the 

regulatory requirements. 

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. Projects that are 

being converted to sequestration projects will have a 

significantly larger base-line data set than those pure 

sequestration projects. This should be taken into 

account when considering grandfathering provisions 

and plan requirements. 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. 

APC opposes this restriction. Qualification of a 

formation for storage should be based on 

performance-based standards and site-specific 

considerations. It is more important to recognize that 

for those first pilot projects the Class V experimental 

well regulations may be better suited. However, if 

the data can be shown that USDW protection can be 

achieved through proper confining units and reservoir 

trapping mechanisms, injection into coal seams 

above the lowermost USDW should be allowed. 

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. 
3 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) 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. 

APC 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 in a GHG management and accounting 

system is beyond the scope of this regulation. 

More to the issue of “impurities”, APC objects to any 

mandated purity standards for CO2. The inclusion of 

impurities in stored CO2 should not be arbitrarily 

prohibited; however, it is recognized that the 

presence of those impurities at sufficient 

concentrations may trigger the applicability of other 

statutory limits or requirements. Determining the type 

and levels of impurities in the CO2 stream is – absent 

a compelling public or environmental health risk – 

best left to contractual negotiations between partners 

in a CCS value chain as opposed to an arbitrary 

regulatory determination. The contracting parties are 

best able to evaluate the types of impurities, their 

compatibility with the reservoir and equipment, and 

determine the acceptable levels of those impurities in 

the stored CO2. To the extent that there is an 

overriding public interest in limiting either the type or 

level of contaminants, principles of cost-effectiveness 

and risk-management should guide the decision 

making process. 

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 conjured up 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. 
4 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

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. 

APC 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 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 

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. 

By utilizing the definition of confining zone (a 

geologic formation, group of formations, or part of a 

formation stratigraphically overlying the injection 

zone that acts as a barrier to fluid movement) the 

EPA has provided necessary guidance to prevent 

movement of fluids from the injection zone which 

may potentially endanger a USDW. The director 

discretion does not provide for any additional 

protection level of USDWs but does create issues 

and uncertainty by allowing the director to require 

additional zones without scientific basis. 

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 a 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 and/or 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. Nor is it necessary to 

specify only one model as this would hinder the 

development of future models and techniques. 

Therefore, APC recommends that EPA provide 

flexibility in the rule to accommodate the use of future 

technologies and refrain from unnecessarily 

prescriptive measures. 

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 

It is critical to allow proprietary models to be used. 

EPA’s Confidential Business Information 

requirements should apply to any proprietary model 

used. APC recommends EPA allow the use of 

proprietary models and clearly state that CBI 
5 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

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. 

requirements will apply. 

While there has been concern raised on the current 

model’s ability to predict fluid flow in saline 

reservoirs, the development of technologies in this 

area will only progress when there is an economic 

driver that proprietary models will provide. In 

addition, being able to see the assumptions and 

equations of the model will provide the regulating 

authority the ability to assess the models accuracy. 

The currently proposed regulations also contain 

requirements to revisit these models when the actual 

site data no longer supports the models conclusions, 

or at a minimum of every 10 years, which APC 

believes is sufficient to ensure the viability of the 

models and data generated from their use. 

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 Comments to 

EPA Notice 43506 and 43507 above also.) 

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. 

Ten years is acceptable as long as reevaluation at 

this frequency is coupled with the ongoing duty to 

monitor for changes that would trigger an earlier 

reevaluation of the AoR. 

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. 

APC 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 remediating 

wells in an area that ultimately may not be affected 

by the storage project. 

Allowing a phased approach for corrective action is 

also imperative for economic success of many 

projects. The upfront capital cost for sequestration 

will be extensive, and requiring corrective action 

upfront may be economically unfeasible. For 

instance Anadarko has spent over $10 million 

addressing historic wells at one of our EOR 

operations; this site is significantly smaller than those 

that may be involved in large sequestration projects. 

Therefore, allowing corrective actions in a phased 

manner will provide the flexibility needed to address 

operational and economic issues. Beyond the 

potential for significant economic expenditure, the 

availability of work-over rigs may also provide a 

difficult time-delay for starting sequestration projects. 

Frequency of reevaluation should be based on site 

performance as noted in the prior comment. 
6 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

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 for other methods of protecting USDWs 

APC opposes the requirement for cementing the long 

string casing back to surface. Cementing 

requirements should focus on ensuring competent 

isolation and seal across the 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. 

Anadarko does not believe the construction 

requirements above current Class II standards are 

necessary (in particular cement to surface). 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. Class II EOR has proven 

successful at preventing contamination of USDWs. 

As mentioned in response to EPA Notice 43502, 

utilizing a sub-class of Class II (Class II GS) would 

provide a means to handle the additional monitoring 

requirements from sequestration applications. 

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.

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 a well 

established technology that can significantly reduce 

surface impacts of a GS project as well as improve 

injection rate of a well. Horizontal wells are currently 

being utilized in EOR operations and CO2 storage 

operations successfully. 
7 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

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. Wells cemented with basic cement that 

have been exposed to CO2 for several decades have 

demonstrated minimal degradation and have been 

protective of USDWs (Reference: Crow. CO2 

Capture Project Field Study of a Wellbore from a 

Natural CO2 Reservoir). 

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. Industry has demonstrated the ability to 

fracture injection zones without jeopardizing the 

integrity of the confining unit. There are computer 

simulators to predict fracture behavior so the impact 

on the confining zone can be anticipated and 

accounted for in designing any proposed operations 

involving fracturing. 

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 EPA Notice 43511. 

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. It 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 operator’s ability to perform 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 
8 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

overall project operations. 

To address EPA’s concerns while maintaining the 

necessary operational flexibility, APC recommends 

EPA allow for the 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 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 assurance regarding 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 above response to EPA Notice 43512. 

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 it exists today. 

Each aquifer exemption should be considered on a 

case-specific basis. However, there should also be 

no requirement that sequestration be below the 

lowest USDW (see comment to EPA Notice 43512 

above). 

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. 
9 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) 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 numerous 

members of the scientific community. 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 a plume. 

Tracers, in general, provide minimal diagnostic 

abilities and currently have few practical applications. 

This technology is still under development and as 

such should not be required. Currently, most tracers 

have the issue of providing false positives, have a 

significant supply time-delay, have greater 

environmental impacts than CO2 (PFCs for 

instance), and are very expensive. Radioactive 

tracers are utilized the most in operations and prove 

the most useful, but again, only for a limited radius of 

investigation. Other monitoring techniques are more 

reliable and operational-friendly for tracking the 

plume and determining CO2 migration. While certain 

tracers can be useful for near-well trouble-shooting 

application this technology on a whole is not ready 

for field-wide deployment and any regulation 

mandating their use should not be instituted. 

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. Anadarko 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 semiannual basis. As a guiding principle, the frequency of 

monitoring should be determined by the level of risk 

posed by the injection operation and should be set on 

a case-by-case basis at the permit approval stage 

taking into consideration the site-specific 

characteristics of the proposed project. 

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, APC 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 methods for 

detecting mechanical failures, managing those risks, 

and conducting MITs. 

 
10 

Rule Provisions EPA Rule Issue Anadarko Petroleum Corporation (APC) Response 

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 and should be set at the permit approval 

stage. 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, and EPA should provide regulatory 

flexibility to account for this. 

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 

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. 

Plume and pressure front are different concepts and 

should not be confused. They yield information on 

two different metrics. The former tells you about the 

remaining capacity of the storage formation and the 

latter describes the direction and movement of the 

CO2 plume. 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 which can only be obtained by 

drilling a well. 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. 

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 their effectiveness can be demonstrated. 

 
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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 plans is a good idea because it 

negates prescriptive regulation of the process. APC

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. 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. 

APC 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 APC. 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. The addition of 

this report would not produce any new pertinent 

information to the regulating agency; and, therefore, 

only increases their administrative burden on the 

agency and requires the generation of needless 

documents. In keeping with the provisions of the 

Paperwork Reduction Act, EPA should not require an 

annual report. Alternatively, if this report was to 

replace the other reporting requirements, there would 

be value to the proposal. 
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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. 

APC 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. (APC

offers such criteria in the 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. 

It is inappropriate to utilize a fixed period as this does 

not provide the flexibility to address site-specific 

issues; instead EPA should adopt a standard that is 

based on a demonstration of non-endangerment to 

determine when monitoring is no longer needed. 

Please see response to EPA 43519. 

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. 

It is inappropriate to utilize a fixed period; instead a 

demonstration of non endangerment is an 

appropriate means of deciding when monitoring is no 

longer needed. Please see response to EPA 43519.

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. 
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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 EPA Notice 43521. 

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 EPA Notice 43521. 

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 EPA Notice 43521. 

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 EPA Notice 43521. 
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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. The EPA should not 

require new technology for involving the public. As 

technological advancements happen at an ever 

increasing rate, current possibilities may be obsolete 

in a few years. In addition, there is still a vast 

population in the country that are not comfortable 

with the newer technologies. While in some areas of 

the country these may be beneficial, in other areas 

they may not provide enough public engagement (or 

more importantly not enough local engagement). 

The Class VI program should involve public 

participation but should not dictate the method in 

which that is performed. 

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. 

73 FR 43522-

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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. 

While public participation is critical, bringing in public 

review before the project details are worked out can 

create unnecessary complications. APC 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.

Primacy should be granted for Class VI and Class IIGS well classifications. In addition, the primacy for 

Class VI should be granted independently of other 

well classes allowing the states to determine the 

appropriate regulating agency (Class II-GS will 

obviously be part of the current Class II program). 

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. 

APC supports the implementation of partial primacy 

for Class VI separately from other classes of wells. 

The geologic variation across the country justifies 

partial primacy. 
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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. 

Please see the report submitted by API and prepared 

by ARI that discusses the cost modeling in greater 

detail. 

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. 

APC 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. 
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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 further comments and 
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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 beneaththe lowermost formation containing a USDW. 

Sections 144.6, and 146.5 – 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 subsurface geologic formations in which extraction of hydrocarbons has occurred, is occurring or is 

reasonably expected to occur 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.

The changes to (b) athat EOR can have stois consistent with EPAin the preamble an

meeting with EPA. It is CO2 based EOR caearly opportunity for cacorrectly recognizes, can have a significathrough capillary mechanisms. Additionally, there shprohibition concerniUSDW’s or at specespecially true given thin the definition of formations greater thmillion Total Dissorequirement is not protection of USDWs vast number of viconsideration. Industoperate CO2 injectiocontext without endanlocated below the injecexample is the Salt Wyoming, which has injection zone. Moreovrule, there are other provide real assurancand require operatortheir project will nomaking the lowermounnecessary. 
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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 necessathrough the end of the phase, which is consiclosure in the amended 

 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 

waste injection wells, Class II, Class III or 
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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 mustmaintain 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 of his/ her determination to the owner or 
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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:......(2) for enhanced recovery of oil or natural gas; (3) For EOR or EGR, and where geologic sequestration of a carbon dioxide stream is occurring during or in connection with EOR or EGR operations or activities; and (4) For storage of hydrocarbons....(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 subsurface geologic formations in which extraction of hydrocarbons has occurred, is occurring or is reasonably expected to occur 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 

See 144.6 
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or EGR are regulated under Class II.

146.23(a) (3) When, on an annual basis, the field-wide average CO2 injection to withdrawal ratio is 

greater than 5.0 in an injection zone and the average reservoir pressure in the injection zone becomes greater than (a) the average original reservoir pressure in the injection zone at the time of discovery of the reservoir, or (b) the average design operating pressure during CO2 EOR or EGR, whichever is greater, the Director may require the operator of a CO2 EOR or EGR project permitted under Class II to provide additional information and data to the Director explaining the necessity to increase or maintain such pressure. If the Director determines, based on site-specific characteristics that the information provided fails to support the need to increase or maintain the average reservoir pressure in the injection zone above the average original reservoir pressure, or the average design operating pressure during CO2 EOR or EGR, the Director may require the operator to: (i) reduce or maintain the CO2 EOR or EGR project’s field-wide average injection to withdrawal ratio to a value such that the average reservoir pressure or average design operating pressure during CO2 EOR or EGR within the injection zone essentially remains constant; or 

(ii) apply to reclassify the CO2 EOR or EGR injection wells and injection zone covered under the Class II permit as a Geologic Sequestration project regulated under the applicable well class. If the operator fails to comply with any of the above requirements, the Director may revoke or modify the applicable Class II injection permit. 

A carbon dioxide streamay be injected into a EGR. When CO2 comdissolves into the oil, thless viscous and the suthe oil and the formatiopoint that the oil becominjection of CO2 also rathe formation to a desioperating pressure. If operating pressure will miscibility pressure of tAchieving sustained prmiscibility pressure wilmost efficient and effecresidual oil remaining iMiscibility pressures arproperties, carbon dioxand the reservoir tempmiscibility pressure maaverage original discovreservoir, or may be eqthe average original disreservoir. The propert(generally heavier crudmiscibility pressure of texcess of the average pressure of the reservogreater than the fractureservoir and/or the coOnce the reservoir predesigned or desired avpressure for the CO2 Einjections of CO2 (or Calternating gas CO2 EOmanaged such that the CO2 and water) being reservoir are generally greater than, the volumwithdrawn from the resaverage designed or d
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reservoir pressure remThe desired or designepressure may be alterethe process of raising tpressure, and then holreservoir pressure relasame. Therefore, except durinre-pressurization (i.e. tEOR project, or for a pdesigned or desired avoperating pressure is bof the injected volumes withdrawal volumes (Cnatural gas and water) than 1.5. All volumes sat average reservoir cominimum, at the same average pressures and In contrast, a GS projeafter a CO2 EOR projeGS project is a project but not necessarily onland store a CO2 streaof injected volumes (Cvolumes (CO2 + other be greatly in excess of likely an order of magnIn order to allow for reaand variations within Cinjection-withdrawal ramultiple of typical injecis recommended to disEOR and Geologic Stoinjection-withdrawal raover the applicable repunder the applicable peevaluated on a field-wiwell-by-well basis (whidevelopment). 
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146.25Geologic 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 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 except sections 146.86 and 146.87

Details of what would bIIB” wells are to be wodiscussions of the MultDiscussion Group (MSoffers this language whchanges APC had sugdiscussions with the MSection 146.81(c)). 

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. 

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. 
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 (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 supercriticalcarbon 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, lbecause it was added 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 Cla146.81(c) is no longer of 146.25. However, if EPA wer146.25, APC would revisions: (c) This subpart apoperators of permit or industrial, Class II wh

no longer continue EOactivities, or Class V 

dioxide injection projefor a Class VI geologfor their well or wdetermines that Uendangered, such weDirector’s discretion, 

cementing requiremen146.87(a)(1) throug

requirements. Class II injection and that have exempt from the reqand 146.87. The language allows foII wells to Class VI opshould be allowed to based on their history under the Class II proby MIT results. The la
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Director to exercise disClass 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 basCO2 plume and its asis a more direct appapproach offered by definition suggests tapproach defines the potential risks of the in

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, which will be injected in any physical state or dissolved, 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. 

Source of CO2 is not of defining the CO2 stto the injection of address the origins of is beyond the scopOriginal text would havCO2 from some source
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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 supercriticalcarbon dioxide stream in subsurface geologic formations. This term does not apply to its capture or transport. 

Suggest removing supercritical" as these the term "carbon dioxidto be modified by APC

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 concerning injection specific depths. Thnecessary for the prowould remove a vaformations from considshown that it can operin an EOR context USDWs that are locazone. An excellent exEOR project in Wyomibelow the injection zonproposed rule, there awould provide real aintegrity and require opthat their project will making the lowermounnecessary. 

Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient a real 

Injection zone means a geologic formation, group of formations, or part of a formation that is of sufficient a real extent, thickness, porosity, and 

Existing definition in thdoes not need to be cadding the sufficiency 
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extent, thickness, porosity, and permeability to receive carbon dioxide through a well or wells associated with a geologic sequestration project. 

permeability to receive carbon dioxide receiving 

fluids through a well or wells associated with a 

geologic sequestration project

definitional issue and 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” of it is not clear. Deleted USDW phincorporated in 146 req

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 or formation fluids into a USDW. 

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.

Clarification. 

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 cdefinitions. 

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 fosince there can be muinjection zone. Thtransmissivity is movdisplaced fluids beyond 

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: 
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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, if known or suspected. Only informationof public record is required to be included on this map; 

(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; 

Faults are not shown oa surface expression oare detailed in (d) beappears redundant. Known needs to be implication that an apstuides to determine currently documented 

 (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 where a well is alreadalign with requesting ipermit. 

 (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 

(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 

If the information is nreported. “Reservoir” and chantechnical corrections. Fractures generally cawell is drilled and evalfractures in the immwellbore can be identif
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interfere with containment; may transect the confining zone(s) in the area of 

review and a determination that they would not interfere with containment; 

 (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, and names and lithologic descriptions;  (5) Geomechanical informationon 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. 

 (3) Information on seismic history that have affected the proposed area of reviewincluding knowledge of previous seismic events and history of these 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 andcapillary 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 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 

Information on seismsome degree of relevaDeleted capillary preshard to measure outssidewall cores, it may capillary pressure. Adnot available until 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 of all wells artificial 

penetrations 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; 

Artificial penetrations is 

 (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 
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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 suinformation and to the zone immediately abowhich is the zones mofor potential CO2 leaka

 (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 injectionrate and volume of the carbon dioxide stream;  (2) Average and maximum surfaceinjection 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; 
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 (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 constructionprocedures that meet the requirements of § 146.86; 

 (n) A wellbore schematic or other appropriate drawings of the surface and of the 

subsurface construction details of the well and 

surface wellhead construction.

Technical clarification. 

 (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 naction will not have a c

146.82(u) (u) Proposed testing and 

monitoring plan required by § 146.90;  (v) Proposed injection well plugging plan required by § 146.92(b); 
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 (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. 

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 faultsor 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 claemphasis on the USDWs and limits thwhich is known or can 

 (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 creatadditional confining zoIt is also redundansections. 
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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 the injected carbon dioxide stream. 

(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. 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.

Edits make this provisdefinition of “Area orevised. 

 (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 themodel 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, periodicallyreevaluate 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 

(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.
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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 of review reevaluation; and 

(iii)(i) How monitoring and operational data (e.g., injection rate and pressure) will be used to inform an area 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 beguaranteed arranged for future corrective action. 

Future access cannot area in advance that mthe boundaries of the A

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 to characterize the injection zone, confining zoneand 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 

Clarification. 
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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. 

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, 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 

Changed for conslanguage. 

 (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 reviewidentified 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 supports the use omaterials that might definition of “corrosion 

 (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 specifies the notificainjection. APC suggelanguage as unnecess
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 (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: 

Clarification. 

 (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 modelingresults 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. 

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 
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site closure (that meets the requirements of § 146.93), and emergency andremedial 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 obligation until site cloThe Director should release the obligatioplugged. 

 (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 frequejustified. 

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 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). 

(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 

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) 

Clarification. 
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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 underground sources of drinking water, 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 chanendangerment standathe 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 standardsor 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 geologicould be different thaClass VI well design slife of the well. 

146.86(b)(1) (i) Depth to the injection zone; 

 (ii) Injection pressure, external pressure, internal pressure and axial loading; 
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 (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 “corrosiveness” of a relevant information is 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 zoneand be cemented to the surface. 

In some parts of the deep and this standard sequestration in these 

 (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 to create a 

cement bond through the injection and confining 

zone(s), 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. 

Cementing to surface protect USDWS, and consequences, as followould eliminate the pressures in this anflexibility of remedial oproposal would allow development of alternaAPI RP90 for desapproach for managiannular casing pressuwith CO2 EOR undedemonstrates the effcementing procedures
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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 program demonstrateexisting cementing maStandard API cemennumerous CO2 EOR adverse consequenceswithin EPA’s propose43533: Carey et al., (2008), and Meyer, J.P 

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 dioxide stream (chemical content, corrosiveness, temperature, and density); 

(ii) Composition of the carbon dioxide stream.(chemical content, corrosiveness, temperature, and density);

There is no method “corrosiveness” of a relevant information is CO2 stream. The costream is more relevtubing and packer syst
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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 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:

In well defined areas, tfrequently unnecessaryhave discretion to selerequirements necessabaseline data and inforFor example, in an arewells are being drilled, hole yields little useful In particular, this changDirector to reduce the multiple wells are insta
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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 d

evaluations are frequyield little new informaof where Director 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 due to uniformity of san example of where be appropriate. The proposed change to select the appropriadequate 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 requirements, howevenot be specified. Any the area should be dra

 (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. 

The proposed change to select the appropriadequate cement bond
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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

(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 grammaIn (iv), “if required unnecessary. 

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 samplesfrom nearby wells if the owner or operator can demonstrate that such data are representative of 

conditions in the wellbore. 

The information requirto properly describconfining 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 the fluid formation

temperature, formation fluid pH and conductivity, and reservoir pressure and the static fluid level of 

the injection zone(s). 

Technical correctionsand static fluid parameters. 
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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 pressure, the requireappear redundant to prior sections. Trequirement has be146.87(e) below. (2) and (3) are too vag

 (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 mustestimate fracture pressures of the injection and confining zones and conduct the following tests 

to verify hydrogeologic and geomechanical

characteristics of the injection zone, e.g., injectivity tests, estimates based on open-hole logging tools (e.g. mechanical properties logs), and other appropriate methods. (1) A pump test; or

(2) Injectivity tests.

Allows the use of infor

tests conducted during The results of a pump the well) have no relwell. Deletion of the injectivuse of non-destructive 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 submit any changes to the schedule 30 days

48 hours prior to the next scheduled test. 

The changes reflect thschedules and operatare fully consistent requirements and prathese issues on a daily 
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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 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) 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. 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)

Maintaining the integriis the critical paramete

 (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 target interval(s) showever, wording of clear as to which interAn absolute prohibitioannulus may also limit could be useful. 

 (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 maintainon 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 wprogram does not suppPositive annular presoperating injection prebecause a leak from not have the same imphazardous situation. 
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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. 

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 permittedranges 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 protectensuring compatibility 

material design streninjection (compressionshut-in devices are napplication. These devtubing string and are tyof the well. They’re tubing in the event of the wellhead. These little if any protection practicable to install ththe well (e.g. shortl

Additionally these dev

on running other tools well and therefore coability to do requdiagnostic work. Lastlperiodic testing and mrequire either pulling thby pulling the entire ton the type of devise inactivities would be disroverall project operatioA more appropriate installation of landing points in the tubing stuse of wireline retneeded. 

146.88 (f) If a down-hole automatic 

shutdown is triggered or a loss of mechanical integrity is discovered, the 

(f) If an down-hole automatic shutdown is 

triggered or a loss of mechanical integrity is discovered, the owner or operator must 

Technical clarification g
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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: 

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: 

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 

(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 

Technical clarification. 
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the annulus between tubing and long stem casing and annulus fluid volume as specified in § 146.88(e); 

pressure, rate, injected volumes, and pressure 

on the annulus between the tubing and long stemstring casing and annulus fluid volume as specified in §146.88 (e);

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 approach and allows use of new technoloavailable. Cement circnot necessary becauannulus above the regular monitoring of could indicate leakageNumber 3 was deleted tubing to be pulled at of uncontrolled release

 (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. 
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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.
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146.90 10. 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: 

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:

(a) Based on a site-specific assessment of the potential for fluid movement from the injection well or injection zone, and on the potential value of monitoring wells to detect such movement, 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 include a description of how the owner or operator will meet the requirements of this section; 

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) The testing and monitoring plan must, at a minimum, include: (a1) Analysis of the carbon dioxide stream with 

sufficient frequency to yield data representative of its chemical and physical characteristics; (b2) Installation and use, except during well 

workovers as defined in § 146.86(d), of continuous recording monitoring devices (including digital devices capturing periodic data)to monitor injection pressure, rate and volume; and to record at least daily the pressure on the annulus between the tubing and the long string 

§146.86(d) does §146.88(d) is what was There is concern regacontinuous monitoringregular monitoring of thby EPA is appropriateCO2 EOR strongly monitoring of most oadequate (exceptions site-specific basis). generally be done oreporting on a semi-
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casing; and the annulus fluid volume; 

(3) a demonstration of external mechanical integrity pursuant to §146.89(c) until the well is plugged; (4) monitoring of the pressure buildup in the injection zone annually, including at a minimum, a shutdown of the well for a time sufficient to conduct a valid observation of the pressure falloff curve at least once every five years; and (5) a quality assurance plan for all testing and monitoring requirements. (b) Installation and use, except during well workovers as defined in §146.88(d), of 

continuous 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; 

guiding principle, the fshould be determined posed by the injection 

(c) Where appropriate, the testing and monitoring plan shall also include: (1) Continuous monitoring for pressure changes in an appropriately porous and permeable formation overlying the confining zone. When a well is installed to enable such monitoring, the owner or operator shall, on a specified frequency or at specified times, sample the formation and analyze for constituents specified in the plan; (2) The use of indirect, geophysical techniques to determine the position of the CO2 stream front, the water quality in a designated formation, or to provide other site specific data; (3) Periodic monitoring of water quality in an appropriately porous and permeable formation overlying the injection zone; (4) Periodic monitoring of water quality in one or more USDWs; 

Drilling monitoring weconsidered since eapotential pathway for the cost of adding mua barrier to CCS devellimited information on CO2 stream. 
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(5) Corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting and other signs of corrosion performed and recorded at least quarterly 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: (i) Analyzing coupons of the well construction materials placed in contact with the carbon dioxide stream; or (ii) Routing the carbon dioxide stream through a loop constructed with the material used in the well and inspecting the materials in the loop; or (iii) Using an alternative method, materials, or time period approved by the Director; (6) Any additional testing and monitoring appropriate to support modeling the extent of the carbon dioxide plume and the position of the pressure front; and (7) Any additional testing and monitoring necessary to determine whether fluid movement is occurring into or between USDWs that would endanger a USDW. 

APC questions the monitoring of most since they will typically thus having no corrosexperience with prodand injection of dry Cthe non-corrosive natustream. 

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) 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:

See 146.90(5) 
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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 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;

See 146.90(5)(i-iii) 

146.90(d) (d) Periodic monitoring of the 

ground water quality and geochemicalchanges 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 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);

See 146.90(c)(1 thru 4 

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 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;

See 146.90(b)(3) See 146.90(b)(4) 
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 (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 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);

See 146.90(c)(1 thru 4 Monitoring outside oprovides little informatand monitoring the injeof how to test and moin the Preamble but nthe rule itself. 

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, surface air monitoring and/or soil gas monitoring to detect movement of carbon dioxide that could endanger a USDW.

In most situations soil not provide an effectivUSDWs. 

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 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;

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, 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.

See 146.90(c)(6) See 146.90(b)(5) 
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146.91 11. Reporting requirements. 

The owner or operator must, at aminimum, 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 data;  (2) Monthly average, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure; 

(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 prdecide that less report(1) Technical clarificabe determined by a stdata. Rules should rebe minor variations in 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 considthreshold on reporting reporting events that interest or consequenc

 (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 
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 (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, determine bottomhole reservoir pressure, and perform a final mechanical integrity test. 

(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. 

Many of the componenby an internal MIT aduring the plugging pro

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 

(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 componenby an internal MIT aduring the plugging pro
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stream; and  (6) The method of placement of the plugs. 

 (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 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 changsimplify and clarify believes is needlessly 

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 

Revisions here r§146.93(b)(3)
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performance based criteria described in 146.93(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;  (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); 

(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);

Revisions here r§146.93(b)(3) 

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 
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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 no longer poses an endangerment to USDWs. 

(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 endangerment to USDWs. pursuant to the 

performance based criteria described in §146.93(b)(3).

EPA should also recoyear default period for EPA offers no rationselected period of 50 fixed and unusually create a significant considering entry inCriteria for determinininjection site care shbased and a functiocharacteristics of a psize, geologic factors, project. APC offers sto §146.93(b)(3). 

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 pose an endangerment to USDWs. The owner or operator must demonstrate, basedon 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 

APC edits establish tcriteria for selecting the EPA should recognize set of site specific cocriteria may not be fullretain the ability to waicriteria described here 
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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. 

 (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 theDirector 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 g

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 

(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. 

after completion of all closure operations. The 

Once the site closure the Director, the opresponsibility for any f

At this point, EPA be

information for the proj
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the Director. The report must include:  (1) Documentation of appropriate injection and monitoring well plugging as specified in § 146.92 and paragraph (c) of this section. The owner or operator must provide a copy of a survey plat which has been submitted to the local zoning authority designated by the Director. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks. The owner or operator must also submit a copy of the plat to the Regional Administrator of the appropriate EPA 

Regional Office; 

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; 

 (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 
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to which it was submitted; and 

 (3) The volume of fluid injected, 

the injection zone or zones into which it was injected, and the period over which injection occurred.  (g) The owner or operator must retain for three years following site closure, records collected during the post-injection site care period. The owner or operator must deliver the records to the Director at the conclusion of the retention period, and the records must thereafter be retained at a location designated by the Director for that purpose. 

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 

(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; 

Technical clarificationsThere is a slight chceasing injection could on other aspects of the 
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hours; and  (4) Implement the emergency and remedial response plan approved by the Director. 

(3) Notify the Director or the designated representative within 24 hours of becoming aware of the endangerment; and 

 (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 workover. 

(d) The owner or operator must notify the Director prior to conducting any well workover in response to any case of endangerment.

In critical situations, approval could adversconduct operations or endangerment. 
Letter ID: 0200 

Commenter: Craig R. Walters 

Organization: Anadarko Petroleum Corporation 

Letter ID: 0200 Comment ID: 24563 Letter Lines: 23 to 30 

Comment Code: 1420 1.2.1.1 Support the GS rulemaking 

Comment: Anadarko Petroleum Corporation appreciates the opportunity to submit comments on 

the EPA's proposed regulations governing underground injection of carbon dioxide 

for geologic sequestration. Anadarko feels the EPA has done a very good job on 

many critical aspects of this very important rule including the ability to 

sequester CO2 under current Class II regulations during enhanced recovery and 

the protective nature of the current Class II operations. In addition, we would 

like to recommend several modifications based on our experiences with conducting 

Enhanced Oil Recovery (EOR). Currently, Anadarko operates two EOR projects that 

Individual Response: EPA believes that the creation of a new injection well class (VI) under the 

existing UIC Program is necessary to enable the use of GS as a climate change mitigation 

technology in a manner that protects USDWs from endangerment. EPA agrees that the UIC 

Program, under the authority of the SDWA, provides a strong framework for regulating injection 

of CO2 for GS and adds that the GS regulation tailors the UIC requirements to address the 

unique issues associated with large-scale GS 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 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. EPA also recognizes that a by-product of ER activities is that a certain percentage of the 

CO2 is trapped in the receiving formation. 

Also, since field experience and well construction, injection, and monitoring information 

relevant to GS comes from operations that inject acid gas or inject CO2 for ER, the Agency has 

conducted evaluations regarding these commercial field operations and continues to track GSrelevant developments in these commercial operations. Some of the research that informs the 

final GS rule was conducted at ER sites. 

Letter ID: 0200 Comment ID: 24564 Letter Lines: 47 to 55 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: Injection below the lowermost USDW: 

A prohibition on injection above the lowermost USDW is not necessary for the 

1
protection of USDWs. Injection operations currently take place above a USDW in 

multiple classes, including current EOR projects. This regulation would 

eliminate many excellent sequestration formation candidates, especially in the 

western region of the United States. In addition, the regulations already 

provide for protection of USDWs both above and below the injection zone. Through 

proper siting and well design, risks to any USDW can be minimized. 

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 

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

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

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

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

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

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

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

concerns about future drinking water resource availability and the need to ensure that high 

quality water remains available in sufficient quantities to supply drinking water needs. 

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

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

Letter ID: 0200 Comment ID: 24565 Letter Lines: 57 to 66 

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: Injection Well Class (Class II vs. Class VI): 

Anadarko was very pleased to see the EPA maintain the integrity of the Class II 

program by excluding injection operations for the purpose of enhanced recovery. 

Also, Anadarko is in full support of developing two classes of wells to better 

address the associated risks with sequestration. By creating a Class II-B for 

the exclusive purpose of sequestration in oil and gas bearing formations, many 

of the complications with grandfathering and regulatory jurisdiction are 

resolved. The details of this separate class will be further worked out during 

discussions with the Multi-Stakeholder Discussion Group. 

2
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. However, 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. 

EPA believes that there are significant differences between how projects are operated, as well as 

the risks posed by these different injection activities. The new tailored approach of the GS rule 

was designed to address the general risks deep injection may pose to USDWs and was tailored 

specifically to address the risks posed by long-term storage of CO2 (i.e., very large volumes, 

very long time-periods, and reservoir pressure conditions). 

EPA believes 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 allows 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). 

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: 0200 Comment ID: 24566 Letter Lines: 70 to 75 

Comment Code: 3800 2.3 Proposed Injection Well Construction Requirements (40 CFR 

146.86) 

Comment: The majority of the well construction and operating requirements appear to be 

built on the Class I Hazardous Waste program. Based on industry's excellent 

environmental and safety record with CO2 injection practices, Anadarko 

recommends the EPA reconsider the proposed regulations. Several misconceptions 

on well design have been recently addressed as further. research has been 

completed in the field. One of these misconceptions is the cementing 

Individual Response: Although the requirements are based on the existing regulatory 

framework for deep wells, including Class I wells, EPA believes that GS is sufficiently different 

3
from other injection operations to warrant the tailored requirements for Class VI wells at §146.86 

in order to protect USDWs from endangerment. 

EPA clarifies that the requirements for Class VI wells are not necessarily more stringent than 

those for Class I hazardous waste injection wells, rather they are different. For example, Class I 

hazardous well owners or operators are subject to requirements that are not applicable to Class 

VI wells, such as no migration petitions. 

Letter ID: 0200 Comment ID: 24567 Letter Lines: 75 to 83 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

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

Comment: completed in the field. One of these misconceptions is the cementing 

requirements; both the requirement to cement to surface as well as the use of 

corrosion-resistant cement. It has been demonstrated that a good cement job is 

more important than a resistant cement, and in certain cases, the resistant 

cements proved more susceptible to degradation than a basic well cement. Also, 

research performed at SACROC has demonstrated the effectiveness of the current 

Class II program's cementing requirements. Many of the requirements currently 

proposed do not afford any extra protection to USDWs and in many cases may 

actually present greater risk. 

Individual Response: EPA agrees that proper cement installation is critical to maintaining 

injection well integrity and clarifies that the requirement at §146.86(b)(5) is that cement and 

cement additives must be compatible with the CO2 stream and formation fluids and of sufficient 

quality and quantity to maintain integrity over the design life of the GS project. It should be 

noted that in Carey et al. (2007), their research on the ER- CO2 injection well at SACROC was 

unable to determine whether CO2 in the presence of water, dry CO2, or a CO2-brine mixture had 

caused the cement alteration observed. In Crow et al. (2008), the well materials studied were 

from a production well producing from a natural CO2 deposit that also produced associated 

water, so well materials were presumably exposed to CO2 in the presence of water. Meyer 

(2007) acknowledges the Carey study found no loss of hydraulic integrity after 30 years, but also 

mentions the use of acid-resistant cements in wells used for acid gas injection and where brine is 

encountered. 

EPA is unaware of studies showing that the resistant cements proved more susceptible to 

degradation than basic well cement. However, the Agency clarifies that the final rule requires at 

§146.86(b)(5) that cement and cement additives be compatible with the CO2 stream and 

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

the GS project. If certain cements have been shown to degrade, they may not be used in Class VI 

wells. 

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 

4
http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

EPA anticipates further findings in the use of acid-resistant cements, in particular the physical 

integrity of such modified cements in place. 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: 0200 Comment ID: 24568 Letter Lines: 106 to 112 

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

Comment: Rule Provisions: 73 FR 43497 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: APC 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 

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. 

5
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: 0200 Comment ID: 24569 Letter Lines: 114 to 143 

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 Provisions: 73 FR 43502 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: While it was apparent in the 

preamble that the EPA intended to allow EOR operations to continue under current 

Class II regulations, the rules left some ambiguity to that distinction. In 

order to operate a successful recovery project it is imperative that the oil and 

gas regulators continue to govern EOR operations. APC offers language in our 

comments that would make this more explicit. 

APC strongly supports the proposed approach and the absence of an economic test 

for oil and gas reservoir "depletion." Recognizing though that EPA may face 

pressure to change its approach, APC offers language in our comments on the 

proposed rule for EPA’s consideration for differentiating between wells for 

EOR/EGR and sequestration. 

Additionally, APC, along with the Multi-Stakeholder Discussion Group, supports 

the creation of a subclass under Class II (e.g "Class IIB") for storage 

operations in hydrocarbon formations. See proposed section 146.25. By utilizing 

this approach operators avoid the potential complexity of switching agencies in 

the middle of a project (this is especially important given the sometimes 

conflicting jurisdiction shown between various regulating agencies within a 

state). Also, this allows for the different risk-profile of sequestration in an 

oil and gas reservoir to be taken into account and a different set of regulating 

requirements to be utilized. 

6
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. However, 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. 

EPA believes that there are significant differences between how projects are operated, as well as 

the risks posed by these different injection activities. The new tailored approach of the GS rule 

was designed to address the general risks deep injection may pose to USDWs and was tailored 

specifically to address the risks posed by long-term storage of CO2 (i.e., very large volumes, 

very long time-periods, and reservoir pressure conditions). 

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

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

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

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

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

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

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

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

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

Letter ID: 0200 Comment ID: 24570 Letter Lines: 145 to 173 

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

Comment: Rule Provisions: 146.81(c) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: APC strongly 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 

7
can be used as a basis for conversion to the Class VI program. 

For Class II wells, APC, along with the Multi- Stakeholder Discussion Group, 

propose that they remain under the Class II program when transitioning from EOR 

to GS. Through the approach of two forms of sequestration, Class VI and Class II 

GS, the EPA would eliminate some of the future confusion regarding 

grandfathering of requirements. EOR wells will have proven their integrity and 

protection of USDWs during the operational phases of the flood through sound 

performance and MIT programs; and, therefore, the construction requirements 

proposed will not be necessary. 

In addition, many of the required well construction requirements, such as cement 

to surface, are truly not necessary. Industry has proven the successfulness of 

current well cement practices in 35 plus years of CO2 injection for EOR with an 

excellent environmental, health, and safety record. Through keeping these 

projects in the same regulating agency that governed the EOR operations it 

ensures that those regulators the most knowledgeable for working in oil and gas 

reservoirs are overseeing the regulatory requirements. 

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 disagrees that other requirements (e.g., MITs, siting, monitoring, operational, and AoR 

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 must 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: 0200 Comment ID: 24571 Letter Lines: 175 to 186 

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

Comment: Rule Provisions: 146.81(c) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: All components of the existing 

8
wells with a proven record of performance should be grandfathered unless there 

are specific USDW endangerment concerns identified by the Director. Projects 

that are being converted to sequestration projects will have a significantly 

larger base-line data set than those pure sequestration projects. This should be 

taken into account when considering grandfathering provisions and plan 

requirements. See Comment above. 

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). 

As described above, EPA disagrees that other requirements (e.g., MITs, siting, monitoring, 

operational, and AoR requirements) should also be grandfathered. Following re-permitting, these 

projects must be subject to the operational, MIT, monitoring, reporting, plugging, and postinjection 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: 0200 Comment ID: 24572 Letter Lines: 188 to 199 

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 Rule Issue: 5. EPA is proposing to preclude the injection of CO2 for longterm storage into coal seams where they are above the lowermost USDW. EPA 

requests comment on this proposed prohibition. EPA Notice 43503. 

Anadarko Petroleum Corporation (APC) Response: APC opposes this restriction. 

Qualification of a formation for storage should be based on performance-based 

standards and site-specific considerations. It is more important to recognize 

that for those first pilot projects the Class V experimental well regulations 

may be better suited. However, if the data can be shown that USDW protection can 

be achieved through proper confining units and reservoir trapping mechanisms, 

injection into coal seams above the lowermost USDW should be allowed. 

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 

9
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. 

Regarding the suggestion to allow experimental GS wells to continue to operate under Class V, 

EPA anticipates that some owners or operators will apply for Class V experimental technology 

permits for injection into formations including shallow basalts, coal seams, salt caverns, and 

shales. These formations may or may not be located above the lowermost USDW or between 

USDWs. To facilitate experimental injection for GS and to increase understanding of injection 

into these formation types, the Agency is amending the Class V experimental technology 

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

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. EPA acknowledges that the 

Class V experimental technology well sub-classification may be appropriate for these projects, 

provided they are experimental in nature. EPA expects that, following the final GS rule, a limited 

number of experimental injection projects testing GS technology will continue. EPA anticipates 

that these projects will be small-scale and involve limited CO2 volumes. However, if these 

projects become larger scale and are no longer experimental, they will need to be permitted as 

Class VI wells. The construction, operation, or maintenance of any non-experimental Class V GS 

well is prohibited, at §144.15. 

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: 0200 Comment ID: 24573 Letter Lines: 201 to 215 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: 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 

10
endanger USDWs, making the lowermost USDW restriction unnecessary. 

Individual Response: EPA agrees that it is not appropriate to set a minimum injection depth for 

GS projects and the Agency 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. 

Letter ID: 0200 Comment ID: 24574 Letter Lines: 217 to 248 

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 Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: APC 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 in a GHG management and 

accounting system is beyond the scope of this regulation. 

More to the issue of "impurities", APC objects to any mandated purity standards 

for CO2. The inclusion of impurities in stored CO2 should not be arbitrarily 

prohibited; however, it is recognized that the presence of those impurities at 

sufficient concentrations may trigger the applicability of other statutory 

limits or requirements. Determining the type and levels of impurities in the CO2 

stream is " absent a compelling public or environmental health risk " best left 

to contractual negotiations between partners in a CCS value chain as opposed to 

an arbitrary regulatory determination. The contracting parties are best able to 

evaluate the types of impurities, their compatibility with the reservoir and 

equipment, and determine the acceptable levels of those impurities in the stored 

CO2. To the extent that there is an overriding public interest in limiting 

either the type or level of contaminants, principles of cost-effectiveness and 

risk-management should guide the decision making process. 

11
Individual Response: EPA understands that many CO2 streams may be relatively pure, and 

research indicates that the estimated amounts of impurities in a CO2 stream are likely to be low. 

However, these estimates are based on limited information, and uncertainties remain about the 

expected concentrations of impurities from the various types of CO2 streams. The concentrations 

of minor and trace elements in CO2 streams for GS projects are likely to vary by facility, coal 

composition, plant operating conditions, and pollution removal technologies. 

The GS rule does not set generic purity standards for CO2 injectate streams (e.g., a percent 

CO2). Instead, the GS rule addresses the quality and quantity of impurities by requiring owners 

or operators to submit information on the source of the CO2 and its physical and chemical 

properties. Specifically, the GS rule requires the owner or operator to submit data about the site, 

including an analysis of the chemical and physical characteristics of the CO2 stream, as required 

at §146.82(a)(7)(iv), and information on the compatibility of the CO2 stream with fluids in the 

injection zone and minerals in both the injection and the confining zones and the materials used 

to construct the well, per §146.82(c)(3). This information can help the Director determine the 

potential for geochemical reactions between the injectate (CO2) and the host geologic 

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

minerals. 

Since the GS rule, at §146.81(d), prohibits CO2 streams that meet the definition of a hazardous 

waste under 40 CFR part 261, injection of a CO2 stream that is determined to be a hazardous 

waste may only occur in a Class I hazardous waste injection well. 

Letter ID: 0200 Comment ID: 24575 Letter Lines: 250 to 270 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: Rule Provisions: 73 FR 43504 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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 conjured 

up by future litigants seeking compensation for response and remediation costs 

incurred in the cleanup of releases from geologic sequestration injection zones. 

12
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: 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. 

Furthermore, EPA is promulgating the GS rule under the authority of the SDWA. To the extent 

the commenter is seeking interpretations of CERCLA and its related provisions, such as the 

definition of a federally permitted release, such interpretations are beyond the scope of this 

rulemaking. 

EPA agrees that proper site characterization and operation of a GS project is important for 

protecting USDWs from endangerment. The UIC program Director also has authority under the 

SDWA 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 

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. 

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: 0200 Comment ID: 24576 Letter Lines: 272 to 281 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: Rule Provisions: 73 FR 43504 

EPA Rule Issue: 9. EPA also requests comment on other considerations associated 

with the presence of impurities in the CO2 stream related to CERCLA. EPA Notice 

43504. 

Anadarko Petroleum Corporation (APC) Response: APC 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 to provide the clarity and assurance needed to 

13
promote continued research and development for GS projects. 

Individual Response: As described above, 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: 0200 Comment ID: 24577 Letter Lines: 283 to 305 

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

(seeking comment) 

Comment: Rule Provisions: 73 FR 43506 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: By utilizing the definition of 

confining zone (a geologic formation, group of formations, or part of a 

formation stratigraphically overlying the injection zone that acts as a barrier 

to fluid movement) the EPA has provided necessary guidance to prevent movement 

of fluids from the injection zone which may potentially endanger a USDW. The 

director discretion does not provide for any additional protection level of 

USDWs but does create issues and uncertainty by allowing the director to require 

dditional zones without scientific basis. 

Individual Response: EPA retains the requirement to identify additional containment/confining 

zones, if required by the Director, as proposed (§146.83(b)). EPA acknowledges that such 

additional zones may not be needed in all circumstances, and clarifies that this requirement is at 

the Director's discretion, based on his or her understanding of a particular site. 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's decision is supported 

by commenters representing states, water associations, and an electric utility who assert that 

these requirements promote a flexible, risk-based, site-specific approach to characterizing and 

14
permitting a site for GS projects, and are intended to improve understanding of the project as a 

whole and promote better modeling of the site. 

Letter ID: 0200 Comment ID: 24578 Letter Lines: 307 to 330 

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 Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: Modeling is a 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 and/or 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. 

Nor is it necessary to specify only one model as this would hinder the 

development of future models and techniques. Therefore, APC recommends that EPA 

provide flexibility in the rule to accommodate the use of future technologies 

and refrain from unnecessarily prescriptive measures. 

Individual Response: EPA agrees that the oil and gas industry has contributed to the state of 

modeling science, and anticipates that some industry-developed modeling products will be 

acceptable for models in the AoR for GS sites, as long as GS well operators clearly disclose, to 

the Director's satisfaction, the code assumptions, relevant equations, and scientific basis. 

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. 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). 

EPA encourages and expects owners or operators to use the most appropriate multiphase 

computational models available to determine the AoR. However, EPA does not believe that the 

15
most "complex" model will, in all cases, be the best available AoR delineation model. The 

requirements at §146.84(c)(1) are designed to allow the owner or operator to choose, in 

consultation with the Director, the modeling platform that is most appropriate for a particular GS 

project. 

EPA anticipates that modeling technology will continue to improve, and encourages and expects 

owners or operators to use the best available multiphase computational models to determine the 

AoR. Reliance on improved models will likely increase the accuracy and quality of the AoR 

characterization, resulting in increased protection of USDWs from endangerment. 

Letter ID: 0200 Comment ID: 24579 Letter Lines: 332 to 359 

Comment Code: 3350 2.2.1.5 Use of proprietary models for GS sites (seeking comment) 

Comment: Rule Provisions: 146.84 

EPA Rule Issue: 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 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. 

Anadarko Petroleum Corporation (APC) Response: It is critical to allow 

proprietary models to be used. EPA’s Confidential Business Information 

requirements should apply to any proprietary model used. APC recommends EPA 

allow the use of proprietary models and clearly state that CBI requirements will 

apply. 

While there has been concern raised on the current model’s ability to predict 

fluid flow in saline reservoirs, the development of technologies in this area 

will only progress when there is an economic driver that proprietary models will 

provide. In addition, being able to see the assumptions and equations of the 

model will provide the regulating authority the ability to assess the models 

accuracy. The currently proposed regulations also contain requirements to 

revisit these models when the actual site data no longer supports the models 

conclusions, or at a minimum of every 10 years, which APC believes is sufficient 

to ensure the viability of the models and data generated from their use. 

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 

16
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. Information including model assumptions and equations are used by 

the Director to inform his/her decision to issue the permit and ensure that the requirements are 

met and the GS well will not endanger USDWs. EPA adds that its Confidential Business 

Information requirements at 40 CFR 144.5 will apply to the use of proprietary models. 

EPA clarifies that the GS rule requires that the AoR be reevaluated (§146.84(e)) to verify that the 

CO2 plume is moving as predicted and to allow for necessary revisions to the AoR and 

corrective action plan. This process will also serve to validate the modeling approach, as the 

commenter suggests. 

Regarding the commenter’s concern about current modeling ability to predict fluid flow in saline 

reservoirs, EPA adds that throughout development of the proposed GS regulation, EPA 

conducted a number of technical workshops inviting expert advice regarding modeling, and 

evaluated peer-reviewed journal articles and performed critical reviews pertaining to 

computational modeling of CO2 injection. Information collected from these efforts assured the 

Agency that available complex computational models can effectively simulate CO2 transport, 

fate and changes in formation pressure in three dimensions as a function of time. However, EPA 

agrees with the commenter that modeling technology will evolve and improve over the coming 

years. The Agency plans, every six years, to 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: 0200 Comment ID: 24580 Letter Lines: 361 to 368 

Comment Code: 3330 2.2.1.3 Applicability /adequacy of computational models (seeking 

comment) 

Comment: Rule Provisions: 146.84 

EPA Rule Issue: 13. EPA seeks comment on the applicability of computational 

fluid flow models for delineating the AoR of GS sites. EPA Notice 43507. 

Anadarko Petroleum Corporation (APC) Response: While computational fluid flow 

models can inform the delineation of the AoR, modeling shouldn’t be the sole 

criteria for determining AoR. (See Comments to EPA Notice 43506 and 43507 above 

also.) 

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 

17
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 

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: 0200 Comment ID: 24581 Letter Lines: 370 to 378 

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

Comment: Rule Provisions: 146.84 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: Ten years is acceptable as long 

as reevaluation at this frequency is coupled with the ongoing duty to monitor 

for changes that would trigger an earlier reevaluation of the AoR. 

Individual Response: Based on evaluation of the public comments on this topic, EPA has 

changed the minimum frequency for the AoR reevaluation at §146.84(e) from ten years to at 

least every five years. EPA believes that this revised frequency addresses concerns raised by 

commenters representing water associations, an energy company, associations, industries, states, 

and environmental groups 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. 

The five-year reevaluation frequency, particularly during early stages of GS deployment, will 

also support EPA's adaptive approach to the GS rulemaking. EPA is using an adaptive approach 

to regulating GS. The Agency plans, every six years, to 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. 

18
Letter ID: 0200 Comment ID: 24582 Letter Lines: 380 to 406 

Comment Code: 3630 2.2.4.1 Comments in favor of allowing phased corrective action 

Comment: Rule Provisions: 146.84(f) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: APC 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 remediating 

wells in an area that ultimately may not be affected by the storage project. 

Allowing a phased approach for corrective action is also imperative for economic 

success of many projects. The upfront capital cost for sequestration will be 

extensive, and requiring corrective action upfront may be economically 

unfeasible. For instance Anadarko has spent over $10 million addressing historic 

wells at one of our EOR operations; this site is significantly smaller than 

those that may be involved in large sequestration projects. Therefore, allowing 

corrective actions in a phased manner will provide the flexibility needed to 

address operational and economic issues. Beyond the potential for significant 

economic expenditure, the availability of work-over rigs may also provide a 

difficult time-delay for starting sequestration projects. 

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 

19
plume is moving within the subsurface as predicted. 

Letter ID: 0200 Comment ID: 24587 Letter Lines: 429 to 450 

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

Comment: Rule Provisions: 146.81(c) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: Anadarko does not believe the 

construction requirements above current Class II standards are necessary (in 

particular cement to surface). 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. Class II EOR has proven 

successful at preventing contamination of USDWs. As mentioned in response to EPA 

Notice 43502, utilizing a sub-class of Class II (Class II GS) would provide a 

means to handle the additional monitoring requirements from sequestration 

applications. 

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. 

Individual Response: EPA agrees that many Class II 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). The final 

Class VI regulations require that any owner or operator injecting CO2 for the primary purpose of 

long term storage obtain a Class VI permit with some special consideration for the fact that they 

are transitioning from a well not originally designed to meet Class VI requirements. The Director 

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

are transitioning from the primary purpose of EOR to long term storage of CO2. The final 

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

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

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

while allowing for site-specific flexibility. EPA adds that, 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. 

20
Letter ID: 0200 Comment ID: 24588 Letter Lines: 452 to 461 

Comment Code: 3840 2.3.2 Horizontal well drilling techniques (seeking comment) 

Comment: Rule Provisions: 146.86 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: Drilling of directional and 

horizontal wells is a well established technology that can significantly reduce 

surface impacts of a GS project as well as improve injection rate of a well. 

Horizontal wells are currently being utilized in EOR operations and CO2 storage 

operations successfully. 

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 

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: 0200 Comment ID: 24589 Letter Lines: 463 to 480 

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 Rule Issue: 19. EPA seeks comment regarding requirements for degradationresistant well construction materials, such as acid-resistant cements and 

corrosion resistant casing. EPA Notice 43510. 

Anadarko Petroleum Corporation (APC) 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. Wells cemented with basic 

cement that have been exposed to CO2 for several decades have demonstrated 

minimal degradation and have been protective of USDWs (Reference: Crow. CO2 

Capture Project Field Study of a Wellbore from a Natural CO2 Reservoir). 

Industry experience over the past 35 years has led to the development of 

21
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 individual 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. 

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: 0200 Comment ID: 24590 Letter Lines: 482 to 494 

Comment Code: 4130 2.4.1.3 Appropriateness of using fracturing for well stimulation (seeking 

comment) 

Comment: Rule Provisions: 146.88(a) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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. Industry has demonstrated the 

ability to fracture injection zones without jeopardizing the integrity of the 

confining unit. There are computer simulators to predict fracture behavior so 

the impact on the confining zone can be anticipated and accounted for in 

designing any proposed operations involving fracturing. 

Individual Response: EPA agrees that hydraulic fracturing may be appropriate 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 

22
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: 0200 Comment ID: 24591 Letter Lines: 496 to 501 

Comment Code: 4120 2.4.1.2 Allowing hydraulic fracturing during GS (seeking comment) 

Comment: Rule Provisions: 73 FR 43511 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: See response to EPA Notice 43511. 

Individual Response: As described above, the final rule allows fracturing only during 

stimulation and where the Director approves such action. 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: 0200 Comment ID: 24592 Letter Lines: 503 to 526 

Comment Code: 4200 2.4.2 Down-hole shut-off valves in GS wells (seeking comment) 

Comment: Rule Provisions: 146.88(e) 

EPA Rule Issue: 22. EPA seeks comment on the merits of requiring down-hole shutoff valves in GS wells. EPA Notice 43511. 

Anadarko Petroleum Corporation (APC) 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. It 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 

23
logging tools in the well and therefore could limit an operator’s ability to 

perform 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. 

To address EPA’s concerns while maintaining the necessary operational 

flexibility, APC recommends EPA allow for the 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 the well. 

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. 

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. 

Letter ID: 0200 Comment ID: 24593 Letter Lines: 528 to 546 

Comment Code: 4410 2.4.4.3.1 Comments in favor of allowing injection above/between 

24
USDWs in certain circumstances 

Comment: Rule Provisions: 144.6(f), 146.5, 146.81 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: 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 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 assurance regarding formation 

integrity and require operators to demonstrate that their project will not 

ndanger 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, 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: 0200 Comment ID: 24594 Letter Lines: 548 to 556 

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 Rule Issue: 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) 

25
exist that will prevent fluid movement into adjacent USDWs. EPA Notice 43512. 

Anadarko Petroleum Corporation (APC) Response: See above response to EPA Notice 

43512. 

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: 0200 Comment ID: 24595 Letter Lines: 558 to 567 

Comment Code: 4460 2.4.4.4.1 Comments in favor of allowing aquifer exemptions in certain 

circumstances 

Comment: Rule Provisions: 73 FR 43512 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: There should be no changes to the 

aquifer exemption requirements in the UIC program as it exists today. Each 

aquifer exemption should be considered on a case-specific basis. However, there 

should also be no requirement that sequestration be below the lowest USDW (see 

comment to EPA Notice 43512 above). 

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. 

EPA clarifies that all decisions regarding 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. 

26
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. 

Letter ID: 0200 Comment ID: 24596 Letter Lines: 569 to 580 

Comment Code: 4344 2.4.4.2.2 Comments opposed to setting a minimum injection depth 

Comment: Rule Provisions: 73 FR 43512 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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: 0200 Comment ID: 24597 Letter Lines: 582 to 604 

27
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 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: EPA should not mandate the use of 

tracers. The value of tracers has been questioned by numerous members of the 

scientific community. 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 a plume. 

Tracers, in general, provide minimal diagnostic abilities and currently have few 

practical applications. This technology is still under development and as such 

should not be required. Currently, most tracers have the issue of providing 

false positives, have a significant supply time-delay, have greater 

environmental impacts than CO2 (PFCs for instance), and are very expensive. 

Radioactive tracers are utilized the most in operations and prove the most 

useful, but again, only for a limited radius of investigation. Other monitoring 

techniques are more reliable and operational-friendly for tracking the plume and 

determining CO2 migration. While certain tracers can be useful for near-well 

trouble-shooting application this technology on a whole is not ready for fieldwide deployment and any regulation mandating their use should not be instituted. 

Individual Response: EPA agrees that tracer use is not appropriate in all situations. Some 

tracers may have the potential to cause harm to people or the environment. Nevertheless, there 

are many different types of tracers and not all are problematic; research is being done to 

overcome problems with existing tracers. EPA believes that tracers have been used safely and 

successfully in other applications. For this reason, EPA does not require the use of tracers at all 

GS sites; rather, 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 has been following new and ongoing research on the safety and efficacy of tracers, and 

believes that, in some circumstances, tracers can be an effective part of monitoring GS projects. 

EPA will continue to track research related to tracer use and 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: 0200 Comment ID: 24598 Letter Lines: 606 to 623 

28
Comment Code: 4520 2.5.1 Continuous internal mechanical integrity monitoring (seeking 

comment) 

Comment: Rule Provisions: 146.89(b) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: There is concern regarding what 

constitutes continuous monitoring. Anadarko 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 semiannual basis. As a 

guiding principle, the frequency of monitoring should be determined by the level 

of risk posed by the injection operation and should be set on a case-by-case 

basis at the permit approval stage taking into consideration the site-specific 

characteristics of the proposed project. 

Individual Response: EPA believes that continuous pressure monitoring to demonstrate internal 

mechanical integrity of Class VI wells (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 

practicable, available, and is currently in fairly wide use. 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 commercialscaled 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. 

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. 40 CFR §146.91(a)(2) requires that monthly averages of the 

continuous annulus monitoring be reported on a semiannual basis. For additional information, 

please see the discussion of MITs in the final rule preamble. 

Letter ID: 0200 Comment ID: 24599 

Comment: Individual Response: 

29
Letter ID: 0200 Comment ID: 24600 Letter Lines: 642 to 655 

Comment Code: 4650 2.6.5 CO2 plume and pressure front tracking (seeking comment) 

Comment: Rule Provisions: 146.90 

EPA Rule Issue: 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 

Anadarko Petroleum Corporation (APC) Response: The frequency of monitoring 

should be dictated by site-specific operational and geologic conditions combined 

with the results of monitoring with model predictions and should be set at the 

permit approval stage. 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, and EPA should provide regulatory flexibility to 

account for this. 

Individual Response: EPA clarifies that all of the monitoring requirements in the GS rule are 

for the purpose of ensuring containment so that USDWs are protected from endangerment. EPA 

believes that knowing the extent of the CO2 plume and pressure front is necessary to make such 

a determination. 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. 

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. 

EPA adds that all monitoring will be conducted pursuant to the approved testing and monitoring 

plan, which should be based on site-specific information about the site and planned operations. 

30
Letter ID: 0200 Comment ID: 24601 Letter Lines: 657 to 667 

Comment Code: 4640 2.6.4 Pressure fall-off testing (seeking comment) 

Comment: Rule Provisions: 146.90(f) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: 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: 0200 Comment ID: 24602 Letter Lines: 669 to 685 

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 Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: Plume and pressure front are 

different concepts and should not be confused. They yield information on two 

different metrics. The former tells you about the remaining capacity of the 

storage formation and the latter describes the direction and movement of the CO2 

plume. 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 which can only be obtained by drilling a well. Modeling can 

31
estimate the movement of a pressure front. Those estimations are limited by the 

accuracy of the model and its iterative adjustments as previously mentioned. 

Individual Response: EPA acknowledges that monitoring the plume and pressure front are 

different issues and 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. 

Letter ID: 0200 Comment ID: 24603 Letter Lines: 687 to 704 

Comment Code: 4670 2.6.7 Surface air monitoring and/or soil gas monitoring (seeking 

comment) 

Comment: Rule Provisions: 73 FR 43517 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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 their effectiveness can be demonstrated. 

Individual Response: EPA acknowledges that air and soil gas monitoring to ensure USDW 

32
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 sitespecific. 

The Agency believes that surface air and soil gas monitoring, when coupled with subsurface 

monitoring, may be appropriate at some GS projects to ensure USDW protection. EPA also 

acknowledges that surface air and soil gas measurements 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. The decision to use surface monitoring and 

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. 

In the final rule, at §146.90(h), the decision to require such monitoring as an additional measure 

to ensure USDW protection rests with 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). 

Letter ID: 0200 Comment ID: 24604 Letter Lines: 706 to 728 

Comment Code: 4610 2.6.1 Testing and monitoring plan requirement (seeking comment) 

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 Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: The development of plans is a 

good idea because it negates prescriptive regulation of the process. APC 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. 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 

33
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 

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 

34
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: 0200 Comment ID: 24605 Letter Lines: 730 to 737 

Comment Code: 4760 2.7.6 Proposed reporting frequency (seeking comment) 

Comment: Rule Provisions: 146.91 

EPA Rule Issue: 35. EPA seeks comment on the frequency of all proposed reporting 

requirements. EPA Notice 43517 

Anadarko Petroleum Corporation (APC) 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 is retaining the semi-annual reporting requirements as proposed at 

§146.91(a). These requirements ensure the Director has the information needed to take 

preventive action in a timely manner to protect USDWs from endangerment. 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. For additional information, please see the final rule and the preamble for a 

discussion of EPA's final approach to recordkeeping and reporting. 

EPA agrees that some monitoring types and frequencies (e.g., associated with ground water 

monitoring and plume tracking) will be site-specific. These activities must be established in the 

approved testing and monitoring plan, which will be incorporated as a condition of the Class VI 

permit. 

Letter ID: 0200 Comment ID: 24606 Letter Lines: 739 to 749 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: Rule Provisions: 146.91(c) 

EPA Rule Issue: 36. EPA seeks comment on the requirement for electronic 

reporting in its proposed rule. EPA Notice 43518. 

Anadarko Petroleum Corporation (APC) Response: APC 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 APC. Until these 

35
concerns related to electronic reporting are resolved, such reporting may be 

encouraged but should not be required. 

Individual Response: EPA 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 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: 0200 Comment ID: 24607 Letter Lines: 751 to 766 

Comment Code: 4750 2.7.5 Comments on the merit of annual reports (seeking comment) 

Comment: Rule Provisions: 73 FR 43518 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: An Annual report is not necessary 

given the other reporting requirements in the Rule. The addition of this report 

would not produce any new pertinent information to the regulating agency; and, 

therefore, only increases their administrative burden on the agency and requires 

the generation of needless documents. In keeping with the provisions of the 

Paperwork Reduction Act, EPA should not require an annual report. 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 

and 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 

36
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. For 

additional information, please see the final rule and the preamble for a discussion of EPA's final 

approach to recordkeeping and reporting. 

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. 

Letter ID: 0200 Comment ID: 24608 Letter Lines: 768 to 790 

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

Comment: Rule Provisions: 73 FR 43519-20, 146.93(b) 

EPA Rule Issue: 38. EPA is proposing using a combination of fixed timeframe and 

a performance standard as described above. EPA is tentatively proposing a postinjection 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. 

Anadarko Petroleum Corporation (APC) Response: APC 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. (APC offers such criteria in the 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 a post-injection site care timeframe of 50 years is 

excessive in most cases or 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, 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 

37
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 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. 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 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. 

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. 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. 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. This 

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

Letter ID: 0200 Comment ID: 24609 Letter Lines: 792 to 801 

Comment Code: 5200 2.8.2 Post injection site care (seeking comment) (40 CFR 146.93) 

Comment: Rule Provisions: 146.93 

38
EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: It is inappropriate to utilize a 

fixed period as this does not provide the flexibility to address site-specific 

issues; instead EPA should adopt a standard that is based on a demonstration of 

non-endangerment to determine when monitoring is no longer needed. Please see 

response to EPA 43519. 

Individual Response: EPA agrees with commenters that there will be circumstances where it 

can be demonstrated in less than 50 years that the plume and pressure front no longer pose a risk 

of endangerment to USDWs. For this reason, the final GS regulation includes a provision that the 

Director may, at his 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). 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). 

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 believes, however, 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 

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

timeframe. This determination is based on a review of research studies, industry reports, existing 

39
environmental programs, and evaluation of public comments. 

Letter ID: 0200 Comment ID: 24610 Letter Lines: 803 to 812 

Comment Code: 5260 2.8.2.3 Adjusting the post-injection timeframe (seeking comment) 

Comment: Rule Provisions: 146.93(b)(2) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: It is inappropriate to utilize a 

fixed period; instead a demonstration of non endangerment is an appropriate 

means of deciding when monitoring is no longer needed. Please see response to 

EPA 43519. 

Individual Response: EPA agrees 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 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 however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The default 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. 

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. 

Letter ID: 0200 Comment ID: 24611 Letter Lines: 814 to 828 

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

CFR 146.85) 

Comment: Rule Provisions: 144.36 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: 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. 

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

financial instruments to meet their financial responsibility obligations. 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)). 

The allowable instruments are identified at §146.85(a). See the final rule and preamble for 

further discussion of EPA's final approach to financial responsibility. 

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, including trust funds, 

surety bonds, letters of credit, insurance, self insurance, escrow accounts, or any other 

instrument(s) satisfactory to the Director. 

Given that the practice of GS is fairly new and EPA does not have enough information in 

supporting future prediction, EPA plans, every six years, to 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: 0200 Comment ID: 24612 Letter Lines: 830 to 841 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

41
Comment: Rule Provisions: 73 FR 43521 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: See response to EPA Notice 43521. 

Individual Response: As described above, owners or 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: 0200 Comment ID: 24613 Letter Lines: 843 to 851 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: Rule Provisions: 73 FR 43522 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: See response to EPA Notice 43521. 

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 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. 

42
Letter ID: 0200 Comment ID: 24614 Letter Lines: 853 to 860 

Comment Code: 5432 2.9.1.1 Need to adjust financial responsibility mechanisms (seeking 

comment) 

Comment: Rule Provisions: 146.85 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: See response to EPA Notice 43521. 

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 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: 0200 Comment ID: 24615 Letter Lines: 862 to 867 

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 Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: See response to EPA Notice 43521. 

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 prevent endangerment of USDWs 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. 

EPA agrees that it is appropriate to allow a flexible approach for financial responsibility. Under 

the final GS rule, owners or operators may choose from a variety of financial instruments to meet 

their financial responsibility needs, provided the Director determines that the owner or operator's 

proposed financial responsibility demonstration is adequate to pay for each activity for which 

financial responsibility must be demonstrated, including corrective action on wells in the AoR, 

43
injection well plugging, PISC and site closure, and emergency and remedial response. The 

permitted methods are specified at §146.85(a)(1). EPA is developing guidance to help owners or 

operators, permitting authorities, and third parties choose and evaluate appropriate financial 

methods, and states may set more specific financial responsibility requirements if they so choose. 

This guidance will be available on EPA's website at 

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

Letter ID: 0200 Comment ID: 24617 Letter Lines: 869 to 889 

Comment Code: 5540 2.10.2 Need for additional public participation requirements/ use of new 

information technology (seeking comment) 

Comment: Rule Provisions: 73 FR 43523 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: The current provisions in Parts 

25 and 124 are sufficient to inform the public. The EPA should not require new 

technology for involving the public. As technological advancements happen at an 

ever increasing rate, current possibilities may be obsolete in a few years. In 

addition, there is still a vast population in the country that are not 

comfortable with the newer technologies. While in some areas of the country 

these may be beneficial, in other areas they may not provide enough public 

engagement (or more importantly not enough local engagement). The Class VI 

program should involve public participation but should not dictate the method in 

which that is performed. 

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. GS permitting 

authorities must follow the existing public participation requirements for UIC permits as 

specified in 40 CFR Part 124. These regulations lay out the procedures for decision making and 

include requirements such as requiring 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. 

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, project specific 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 

44
the public's concerns before the permitting process is complete. 

EPA is not requiring the use of new information technologies. EPA encourages GS operators to 

use new information technologies whenever possible to keep the public informed of GS projects. 

The Agency believes that flexibility is important and does not want to limit use of public 

participation and notification technologies developed in the future. 

Letter ID: 0200 Comment ID: 24618 Letter Lines: 891 to 902 

Comment Code: 5560 2.10.3 Enhancing the public participation process (seeking comment) 

Comment: Rule Provisions: 73 FR 43522- 23 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: While public participation is 

critical, bringing in public review before the project details are worked out 

can create unnecessary complications. APC 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. 

45
Letter ID: 0200 Comment ID: 24619 Letter Lines: 904 to 919 

Comment Code: 5600 2.11 Comments related to UIC Program primacy for Class VI wells 

Comment: Rule Provisions: 73 FR 43523 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: Primacy should be granted for 

Class VI and Class II GS well classifications. In addition, the primacy for Class 

VI should be granted independently of other well classes allowing the states to 

determine the appropriate regulating agency (Class II-GS will obviously be part 

of the current Class II program). 

EPA should ensure that adequate funding is provided for the delegated 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 also had to accept responsibility for Class III, IV, and V 

wells. This policy has been in place since the initiation of the UIC Program in the early 1980s 

and 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. EPA's willingness to accept independent primacy 

applications for Class VI wells represents a shift in its longstanding policy of discouraging 

46
"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. 

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 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: 0200 Comment ID: 24620 Letter Lines: 921 to 933 

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 Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) Response: APC 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 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. 

47
Letter ID: 0200 Comment ID: 24621 Letter Lines: 935 to 943 

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

comment) 

Comment: Rule Provisions: 144.36(a) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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)). However, 

it 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. 

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. 

Letter ID: 0200 Comment ID: 24622 Letter Lines: 945 to 961 

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

comment) 

Comment: Rule Provisions: 73 FR 43527 

EPA Rule Issue: 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 

48
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. 

Anadarko Petroleum Corporation (APC) 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. 

Please see the report submitted by API and prepared by ARI that 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). 

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

requirements, please see the final rule and preamble. 

Letter ID: 0200 Comment ID: 24623 Letter Lines: 963 to 973 

Comment Code: 7700 4.7 Executive Order 13045: Children's Health Protection 

Comment: Rule Provisions: 73 FR 43531 

EPA Rule Issue: 52. The public is invited to submit comments or identify peer49
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. 

Anadarko Petroleum Corporation (APC) Response: APC 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, 

50
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 

collected, and to determine if modifications to the requirements are appropriate or necessary. 

Letter ID: 0200 Comment ID: 24624 Letter Lines: 984 to 991 

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: Rule Provision: 144.3 

Anadarko Petroleum Corporation (APC) 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 includes the following definition of 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: 0200 Comment ID: 24625 Letter Lines: 993 to 1032 

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 and 146.5 

Anadarko Petroleum Corporation (APC) 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 

51
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 SUBSURFACE GEOLOGIC FORMATIONS IN 

WHICH 

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS 

REASONABLY EXPECTED 

TO OCCUR 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: The changes to (b) and (f) are to recognize that EOR can have storage 

component, which is consistent with EPA’s intent as expressed in the preamble 

and API’s October 27th meeting with EPA. It is widely recognized that CO2 based 

EOR can provide a significant early opportunity for carbon storage. As EPA 

correctly recognizes, CO2 EOR operations can have a significant storage 

component through capillary trapping or other mechanisms. 

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 edits. EPA 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 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. 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 also recognizes that a 

by-product of ER activities is that a certain percentage of the CO2 is trapped in the receiving 

52
formation. 

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. 

Regarding injection into basalts, coal seams, and salt domes, EPA clarifies that the GS rule does 

not preclude injection of CO2 into any non-USDW formation types. The purpose of the GS rule 

is to ensure protection of USDWs from endangerment, and the rule requires that owners or 

operators demonstrate that wells are sited in suitable systems with geologic formations to receive 

and confine injected CO2, as required at §146.83 of the GS rule. The Class VI siting, well 

construction and operation, monitoring and testing, and post-injection site care and site closure 

requirements are designed to ensure that injected CO2 remains within the target formation. If an 

owner or operator can demonstrate to the Director's satisfaction that GS in coal seams, basalts, 

salt domes, or shales can be accomplished in a manner that protects USDWs and meets all of the 

requirements of the GS rule, the project may be permitted as a Class VI well. 

EPA acknowledges that there may be unknown risks associated with GS, particularly regarding 

GS into formations such as coal seams, basalts, and salt domes, which have been the subject of 

limited experimental projects in the past. EPA anticipates that in the short-term, GS into these 

types of formations will continue to be experimental (i.e., to test GS technologies and collect 

data), and will likely be permitted as Class V experimental technology wells subject to UIC 

Program Guidance #83. 

EPA is preparing an addendum to UICPG #83 that describes the use of the Class V experimental 

technology well classification to clarify permitting for Class V wells. This addendum will 

address shifting of Class V experimental projects to full-scale GS projects and the future use of 

the Class V experimental technology well subclass for research and testing of new GS 

technologies. 

EPA acknowledges that there are limited circumstances where injection above the lowermost 

USDW can be performed in a manner that protects USDWs. 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. The waiver approach requires the submission of extensive, site-specific 

information (in conjunction with the permit application submittal) to demonstrate that injection 

of CO2 into a formation that is above or between USDWs can be done in a manner that is 

protective of USDWs. The requirements are designed to ensure 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. 

53
Letter ID: 0200 Comment ID: 24626 Letter Lines: 1021 to 1032 

Comment Code: 4324 2.4.4.1.2 Comments opposed to requiring injection below the lowermost 

USDW 

Comment: 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: 0200 Comment ID: 24627 Letter Lines: 1034 to 1044 

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 

comment) 

Comment: Rule Provision: 144.36(a) 

Anadarko Petroleum Corporation (APC) 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 

54
issued for the operating life of the facility and the post-injection site care period (144.36(a)). 

However, it 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. 

EPA believes that the iterative process of developing and executing the various plans required of 

GS well operators in the final rule (e.g., for AoR and corrective action, testing and monitoring, 

well plugging, and 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). This is preferable to a periodic permit 

reapplication. 

Letter ID: 0200 Comment ID: 24628 Letter Lines: 1046 to 1080 

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 

Anadarko Petroleum Corporation (APC) Comments: (b) Class II. Wells which inject 

fluids:........(2) for enhanced recovery of oil or natural gas; (3) FOR EOR OR 

EGR, AND WHERE GEOLOGIC SEQUESTRATION OF A CARBON DIOXIDE STREAM 

IS OCCURRING 

DURING OR IN CONNECTION WITH EOR OR EGR OPERATIONS OR ACTIVITIES; and 

(4) For 

storage of hydrocarbons.... 

(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 

55
Rule Provision: 146.5 

Anadarko Petroleum Corporation (APC) 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 ARE NO HIGHER THAN REASONABLY 

NECESSARY 

TO PRODUCE SUCH VOLUMES OR RATES; AND 

(5) FOR GEOLOGIC SEQUESTRATION IN SUBSURFACE GEOLOGIC FORMATIONS IN 

WHICH 

EXTRACTION OF HYDROCARBONS HAS OCCURRED, IS OCCURRING OR IS 

REASONABLY EXPECTED 

TO OCCUR 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 in the response to comment 24625 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. 

As described above, 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 nonUSDW formations above and/or between USDWs. 

56
Letter ID: 0200 Comment ID: 24629 Letter Lines: 1082 to 1163 

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: 146.23(a) 

Anadarko Petroleum Corporation (APC) Comments: (3) WHEN, ON AN ANNUAL BASIS, 

THE 

FIELD-WIDE AVERAGE CO2 INJECTION TO WITHDRAWAL RATIO IS GREATER 

THAN 5.0 IN AN 

INJECTION ZONE AND THE AVERAGE RESERVOIR PRESSURE IN THE INJECTION 

ZONE BECOMES 

GREATER THAN (A) THE AVERAGE ORIGINAL RESERVOIR PRESSURE IN THE 

INJECTION ZONE 

AT THE TIME OF DISCOVERY OF THE RESERVOIR, OR (B) THE AVERAGE DESIGN 

OPERATING 

PRESSURE DURING CO2 EOR OR EGR, WHICHEVER IS GREATER, THE DIRECTOR 

MAY REQUIRE 

THE OPERATOR OF A CO2 EOR OR EGR PROJECT PERMITTED UNDER CLASS II TO 

PROVIDE 

ADDITIONAL INFORMATION AND DATA TO THE DIRECTOR EXPLAINING THE 

NECESSITY TO 

INCREASE OR MAINTAIN SUCH PRESSURE. 

IF THE DIRECTOR DETERMINES, BASED ON SITE-SPECIFIC CHARACTERISTICS 

THAT THE 

INFORMATION PROVIDED FAILS TO SUPPORT THE NEED TO INCREASE OR 

MAINTAIN THE 

AVERAGE RESERVOIR PRESSURE IN THE INJECTION ZONE ABOVE THE AVERAGE 

ORIGINAL 

RESERVOIR PRESSURE, OR THE AVERAGE DESIGN OPERATING PRESSURE 

DURING CO2 EOR OR 

EGR, THE DIRECTOR MAY REQUIRE THE OPERATOR TO: 

(I) REDUCE OR MAINTAIN THE CO2 EOR OR EGR PROJECT’S FIELD-WIDE 

AVERAGE INJECTION 

TO WITHDRAWAL RATIO TO A VALUE SUCH THAT THE AVERAGE RESERVOIR 

PRESSURE OR 

AVERAGE DESIGN OPERATING PRESSURE DURING CO2 EOR OR EGR WITHIN THE 

INJECTION 

ZONE ESSENTIALLY REMAINS CONSTANT; OR 

(II) APPLY TO RECLASSIFY THE CO2 EOR OR EGR INJECTION WELLS AND 

INJECTION ZONE 

57
COVERED UNDER THE CLASS II PERMIT AS A GEOLOGIC SEQUESTRATION 

PROJECT REGULATED 

UNDER THE APPLICABLE WELL CLASS. 

IF THE OPERATOR FAILS TO COMPLY WITH ANY OF THE ABOVE REQUIREMENTS, 

THE DIRECTOR 

MAY REVOKE OR MODIFY THE APPLICABLE CLASS II INJECTION PERMIT. 

Rationale: A carbon dioxide stream or carbon dioxide may be injected into a 

reservoir for EOR or EGR. When CO2 comes in contact with oil it dissolves into 

the oil, the oil swells, becomes less viscous and the surface tension between 

the oil and the formation is reduced to such a point that the oil becomes 

mobile. The injection of CO2 also raises the pressure in the formation to a 

desired or designed operating pressure. If achievable, the desired operating 

pressure will be above the miscibility pressure of the oil and CO2. Achieving 

sustained pressures at or above the miscibility pressure will generally allow 

the most efficient and effective recovery of the residual oil remaining in the 

formation. Miscibility pressures are dependent on the oil properties, carbon 

dioxide stream properties and the reservoir temperature. Thus, miscibility 

pressure may be less than the average original discovery pressure of the 

reservoir, or may be equal to or greater than the average original discovery 

pressure of the reservoir. The properties of some oils (generally heavier 

crudes) are such that the miscibility pressure of the oil and CO2 is far in 

excess of the average original discovery pressure of the reservoir and can even 

be greater than the fracture pressure of the reservoir and/or the confining 

zone. 

Once the reservoir pressure reaches the designed or desired average reservoir 

pressure for the CO2 EOR project, the injections of CO2 (or CO2 and water in 

water alternating gas CO2 EOR projects) are managed such that the volumes of CO2 

(or CO2 and water) being injected into the reservoir are generally equal to, or 

slightly greater than, the volumes of fluids being withdrawn from the reservoir 

such that the average designed or desired operating reservoir pressure remains 

relatively constant. The desired or designed operating reservoir pressure may be 

altered from time to time, but the process of raising the average reservoir 

pressure, and then holding the average reservoir pressure relatively constant, 

is the same. 

Therefore, except during periods of reservoir re-pressurization (i.e. the 

beginning of a CO2 EOR project, or for a period of time when the designed or 

desired average reservoir operating pressure is being raised), the ratio of the 

injected volumes (CO2 + water) to the withdrawal volumes (CO2, oil, associated 

natural gas and water) will most likely be less than 1.5. All volumes should be 

determined at average reservoir conditions, or, at a minimum, at the same 

conditions (i.e. same average pressures and temperatures). 

58
In contrast, a GS project whether occurring after a CO2 EOR project or as a 

standalone GS project is a project in which the primary, but not necessarily 

only, purpose is to inject and store a CO2 stream. Therefore, the ratio of 

injected volumes (CO2) to the withdrawal volumes (CO2 + other formation fluids) 

should be greatly in excess of 1.5 and more than likely an order of magnitude 

greater. 

In order to allow for reasonable fluctuations and variations within CO2-EOR 

projects an injection-withdrawal ratio of 5.0 (3 to 4 times multiple of typical 

injection-withdrawal ratios) is recommended to distinguish between CO2- EOR and 

Geologic Storage projects. The injection-withdrawal ratio should be measured 

over the applicable reporting period required under the applicable permit and 

will be evaluated on a field-wide basis compared to a well-by-well basis (which 

will allow for phased development). 

Individual Response: As described above in the response to comment 24625 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 

to ensure 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: 0200 Comment ID: 24630 Letter Lines: 1165 to 1181 

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: Rule Provision: 146.25 GEOLOGIC SEQUESTRATION IN OIL OR GAS 

RESERVOIRS WITHOUT 

ENHANCED RECOVERY OF OIL OR NATURAL GAS 

Anadarko Petroleum Corporation (APC) 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 EXCEPT SECTIONS 146.86 AND 

146.87. 

(B) NEW WELLS MUST MET THE CONSTRUCTION REQUIREMENTS OF SECTION 

59
146.22 AND ARE 

SUBJECT TO PART 146, SUBPART H 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, APC offers this language which is consistent with changes APC 

had suggested before discussions with the MSDG began (see Section 146.81(c)). 

Individual Response: As described above in the response to comment 24625 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: 0200 Comment ID: 24631 Letter Lines: 1182 to 1197 

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(b) 

Anadarko Petroleum Corporation (APC) Comments: (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. 

Rationale: See 144.6 

Deleted "gaseous, liquid or supercritical" because it was added to the 

60
definition of CO2 stream. 

Individual Response: As described above in the response to comment 24625 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: 0200 Comment ID: 24632 Letter Lines: 1199 to 1230 

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) 

Anadarko Petroleum Corporation (APC) 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, APC 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 

61
§§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 in the response to comment 24625 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. 

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

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

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

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

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

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

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

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

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

Letter ID: 0200 Comment ID: 24633 Letter Lines: 1232 to 1245 

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] 

Anadarko Petroleum Corporation (APC) 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. 

62
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: 0200 Comment ID: 24634 Letter Lines: 1247 to 1261 

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] 

Anadarko Petroleum Corporation (APC) Comments: Carbon dioxide stream means 

carbon dioxide, WHICH WILL BE INJECTED IN ANY PHYSICAL STATE OR DISSOLVED, 

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 

63
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. 

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

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

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

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

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

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

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

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

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

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

Letter ID: 0200 Comment ID: 24635 Letter Lines: 1263 to 1282 

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 Code: 4400 2.4.4.3 Allowing injection above or between USDWs (seeking comment) 

Comment: Rule Provision: 146.81(d) [Definition - Geologic sequestration] 

Anadarko Petroleum Corporation (APC) 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. 

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 

64
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 has revised the definition of a geologic sequestration project to 

account for the new requirements to include “wells used for geologic sequestration of carbon 

dioxide that have been granted a waiver of the injection depth requirements pursuant to 

requirements at §146.95.” 

Letter ID: 0200 Comment ID: 24636 Letter Lines: 1284 to 1294 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Injection zone] 

Anadarko Petroleum Corporation (APC) Comments: 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 

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) is 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. 

Letter ID: 0200 Comment ID: 24637 Letter Lines: 1296 to 1304 

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] 

Anadarko Petroleum Corporation (APC) 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 

65
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 all 

post-injection site care must be performed pursuant to the post-injection site care and site closure 

plan, which must be approved by the Director and demonstrated to include monitoring activities 

that protect USDWs from endangerment. 

Letter ID: 0200 Comment ID: 24638 Letter Lines: 1306 to 1315 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

Comment: Rule Provision: 146.81(d) [Definition - Pressure front] 

Anadarko Petroleum Corporation (APC) 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) is 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 

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: 0200 Comment ID: 24639 Letter Lines: 1317 to 1324 

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] 

Anadarko Petroleum Corporation (APC) Comments: Site closure MEANS the 

66
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: 0200 Comment ID: 24640 Letter Lines: 1326 to 1335 

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] 

Anadarko Petroleum Corporation (APC) 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 has retained the proposed definition, 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: 0200 Comment ID: 24641 Letter Lines: 1337 to 1356 

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 

comment) 

Comment: Rule Provision: 146.82(b) 

Anadarko Petroleum Corporation (APC) 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 

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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. 

Known needs to be added to remove any implication that an applicant has to 

conduct stuides to determine wells that are not currently documented in some 

fashion. 

Individual Response: Regarding the comment that EPA delete mention of faults on surface 

maps, EPA believes that if faults have surface expressions, they should be presented on maps 

submitted; this information would 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. 

EPA disagrees that the information that is submitted to support a Class VI permit application 

should be limited to known/available data. The Agency believes that the site characterization 

requirements at §146.82, including geomechanical information and geologic and topographic 

maps and cross sections, are essential to proper siting of a GS well and are the foundation for a 

detailed understanding of the local and regional geology, and that the owner or operator should 

collect this information, regardless of whether it is known in advance of the siting process. 

Collecting and evaluating this data supports important evaluations regarding the suitability of the 

site to receive and contain injected CO2. 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 highpermeability regions (i.e., faults and/or fractures) not detected in the initial site characterization. 

EPA also believes that a determination about whether or what information may be necessary (for 

68
a specific GS project) is outside of the public record 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: 0200 Comment ID: 24642 Letter Lines: 1358 to 1367 

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) 

Anadarko Petroleum Corporation (APC) 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 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. 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). 

In the final rule, the requirement for the final AoR based on modeling, including data obtained 

during logging and testing, can be found 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: 0200 Comment ID: 24643 Letter Lines: 1369 to 1390 

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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 

comment) 

Comment: Rule Provision: 146.82(d) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: EPA believes that all of the site characterization requirements at 146.82, 

including information on faults and fractures, are essential to proper siting of a GS well and are 

the foundation for a detailed understanding of the local and regional geology, and that the owner 

or operator should collect this information, regardless of whether it is known in advance of the 

siting process. Collecting and evaluating this data supports important evaluations regarding the 

suitability of the site to receive and contain injected CO2. 

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 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 

70
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. 

Letter ID: 0200 Comment ID: 24644 Letter Lines: 1392 to 1401 

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 

comment) 

Comment: Rule Provision:146.82(d)(3) 

Anadarko Petroleum Corporation (APC) Comments: (3) Information on seismic 

history THAT HAVE AFFECTED THE PROPOSED AREA OF REVIEW INCLUDING 

KNOWLEDGE OF 

PREVIOUS SEISMIC EVENTS AND HISTORY OF THESE 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. 

Individual Response: EPA believes that consideration of local and regional seismicity is 

important and this type of review is relevant to every project. The site characterization provisions 

in the GS rule, including a review of the local and regional geology, and detailed review of any 

known or potential seismically active terrain in the vicinity of a proposed GS site are necessary 

to minimize the potential for induced seismic events or the reactivation of faults, which are a 

known potential risk associated with injection and are addressed in all aspects of the UIC 

regulations. 

Letter ID: 0200 Comment ID: 24645 Letter Lines: 1403 to 1419 

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 

comment) 

71
Comment: Rule Provision: 146.82(d)(4) & (5) 

Anadarko Petroleum Corporation (APC) 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 changes based on field data which may 

include geologic cores, outcrop 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 

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. 

Individual Response: EPA acknowledges the comment but did not make the suggested edits. 

The Agency believes that the site characterization requirements at §146.82, including 

geomechanical information and geologic and topographic maps and cross sections, are essential 

to proper siting of a GS well and are the foundation for a detailed understanding of the local and 

regional geology, and that the owner or operator should collect this information, regardless of 

whether it is known in advance of the siting process. Collecting and evaluating this data supports 

important evaluations regarding the suitability of the site to receive and contain injected CO2. 

EPA acknowledges that laboratory methods are standard for determining capillary pressures 

regardless of formation permeability and that in situ measurements would require drilling of a 

well. However, EPA also anticipates that test wells will be drilled to support geologic site 

characterization of the proposed GS sites and can be used to collect subsurface samples (for 

laboratory determination of capillary pressure) and take other necessary measurements. 

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 believes that information on capillary entry pressure is necessary and appropriate. Capillary 

entry pressure measurements on core samples can quantify the amount of buoyant force the 

confining zone can maintain before failure (World Resources Institute, 2008). 

Letter ID: 0200 Comment ID: 24646 Letter Lines: 1421 to 1429 

72
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) 

Anadarko Petroleum Corporation (APC) Comments: (e) A tabulation of all wells 

ARTIFICIAL PENETRATIONS 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; 

Rationale: Artificial penetrations is a more inclusive term. 

Individual Response: EPA agrees that all artificial penetrations must be identified and evaluated 

during site characterization. However the final rule retains the proposed text to be consistent with 

similar requirements for other well classes and to support the corrective action requirements. 

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 can be found on EPA’s website at 

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

Letter ID: 0200 Comment ID: 24647 Letter Lines: 1431 to 1443 

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(f) 

Anadarko Petroleum Corporation (APC) 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. 

73
No rationale provided 

Individual Response: The Agency acknowledges the suggested edits but has retained the 

language as proposed. EPA believes that a thorough understanding of the hydrogeologic 

conditions of all USDWs in the AoR is necessary to protect USDWs from endangerment, 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 geologic features 

of the site. The final requirements will allow for submittal of information similar to or the same 

as that which was suggested by the commenter. EPA encourages owners or operators and 

Directors to consult during site characterization to discuss information needs and ensure that all 

appropriate data necessary to assess the suitability of the site are collected. The Director may 

request additional hydrogeologic data or other data on USDWs as well, as provided in 

§146.82(a)(21). 

Letter ID: 0200 Comment ID: 24648 Letter Lines: 1445 to 1454 

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(g) 

Anadarko Petroleum Corporation (APC) 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 submitted to available information and to the 

injection zone and the zone immediately above the confining zone which is the 

zones most likely to be monitored for potential CO2 leakage. 

Individual Response: The Agency acknowledges the suggested edits but has retained the 

language as proposed. 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 consult during site characterization to discuss information needs and ensure that 

all appropriate data necessary 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 

74
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: 0200 Comment ID: 24649 Letter Lines: 1456 to 1463 

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) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: EPA disagrees that the suggested technical clarifications are necessary. 

EPA adds that it is developing guidance for owners or operators on the geologic site 

characterization process. The guidance will provide recommendations for owners and operators 

to consider when completing a permit application. The guidance can be found on EPA’s website 

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

Letter ID: 0200 Comment ID: 24650 Letter Lines: 1465 to 1471 

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(n) 

Anadarko Petroleum Corporation (APC) Comments: (n) A WELLBORE schematic or 

other appropriate drawings of the surface and of the subsurface construction 

75
details of the well AND SURFACE WELLHEAD CONSTRUCTION. 

Rationale: Technical clarification. 

Individual Response: EPA disagrees that the suggested technical clarifications are necessary. 

EPA adds that it is developing guidance for owners or operators on the geologic site 

characterization process. The guidance will provide recommendations for owners and operators 

to consider when completing a permit application. The guidance can be found on EPA’s website 

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

Letter ID: 0200 Comment ID: 24651 Letter Lines: 1473 to 1479 

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(q) 

Anadarko Petroleum Corporation (APC) 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 disagrees that the suggested technical clarifications are necessary. 

EPA adds that it is developing guidance for owners or operators on the geologic site 

characterization and AoR and corrective action process. The guidance documents will provide 

recommendations for owners and operators to consider when completing a permit application. 

The guidance can be found on EPA’s website at 

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

Letter ID: 0200 Comment ID: 24652 Letter Lines: 1481 to 1493 

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) 

Anadarko Petroleum Corporation (APC) 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 

76
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 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. EPA believes that 

the text regarding propagation of faults and fractures is important to avoid the potential for fluid 

movement and to ensure that injection is at appropriate pressures. 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 in the past. While core 

samples obtained through drilling and hydraulic testing are direct methods to obtain such 

information, geophysical techniques such as seismic or electromagnetic surveys can also be used 

in many geologic settings to demonstrate the absence of or identify and characterize the presence 

of faults or fractures. 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: 0200 Comment ID: 24653 Letter Lines: 1495 to 1505 

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) 

Anadarko Petroleum Corporation (APC) 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 

77
allow for pressure dissipation, and also provide additional sites for monitoring, mitigation, and 

remediation. 

Letter ID: 0200 Comment ID: 24654 Letter Lines: 1507 to 1518 

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) 

Anadarko Petroleum Corporation (APC) 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. 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: 0200 Comment ID: 24655 Letter Lines: 1520 to 1531 

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) 

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Anadarko Petroleum Corporation (APC) 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 changes and believes the proposed text 

is clear as written. EPA believes that review and approval of the AoR and corrective action plan, 

including the reevaluation frequency of at least every five years, by the Director (and in the 

context of all information submitted by the owner or operator with the permit application) is 

important to ensuring USDW protection. 

Letter ID: 0200 Comment ID: 24656 Letter Lines: 1533 to 1547 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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 

Individual Response: 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 

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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: 0200 Comment ID: 24657 Letter Lines: 1549 to 1560 

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

Comment Code: 3400 2.2.2 Corrective Action 

Comment Code: 3700 2.2.5 Comments on the requirement for an AoR and corrective action 

plan 

Comment: Rule Provision: 146.84(b)(2)(iv) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: 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: 0200 Comment ID: 24658 Letter Lines: 1562 to 1572 

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) 

Anadarko Petroleum Corporation (APC) 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 

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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 

Individual Response: Based on an evaluation of all comments received, EPA has clarified this 

language in the final rule at 146.84(c)(1). 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.” 

Letter ID: 0200 Comment ID: 24659 Letter Lines: 1574 to 1585 

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)(i) & (ii) 

Anadarko Petroleum Corporation (APC) Comments: (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 the proposed life of the geological 

sequestration project THE DURATION OF INJECTION; 

(ii) Take into account any RELEVANT geologic heterogeneities, AND data 

quality, and their possible impact on model predictions; and 

Rationale: Clarification. 

Individual Response: EPA agrees that detailed geologic data is invaluable to modeling an 

accurate AoR. EPA clarifies that owners or operators may use existing data as well as data 

collected during site characterization to predict the AoR. The final rule retains the language in 

§146.84(c)(1)(i) as proposed, and modifies §146.84(c)(1)(ii) slightly to require owners or 

operators to take into account “other discontinuities” in addition to geologic heterogeneities 

when predicting 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. 

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Letter ID: 0200 Comment ID: 24660 Letter Lines: 1587 to 1596 

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) 

Anadarko Petroleum Corporation (APC) Comments: (2) Using methods approved by the 

Director, identify all KNOWN ARTIFICIAL penetrations INTO THE CONFINING ZONE, 

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 

Rationale: Changed for consistency with earlier language. 

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

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

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 adds that all corrective action must be performed 

pursuant to the approved AoR and corrective action plan, which affords the Director the 

discretion to require any additional information needed (including information that is not 

publically available) to ensure that all necessary corrective action is performed. 

Letter ID: 0200 Comment ID: 24661 Letter Lines: 1598 to 1605 

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) 

Anadarko Petroleum Corporation (APC) 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. 

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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: 0200 Comment ID: 24662 Letter Lines: 1607 to 1619 

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) 

Comment: Rule Provision: 146.84(d) 

Anadarko Petroleum Corporation (APC) 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: 0200 Comment ID: 24663 Letter Lines: 1621 to 1629 

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) 

Anadarko Petroleum Corporation (APC) 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 if §146.94 already specifies the notification and 

83
cessation of injection. APC 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: 0200 Comment ID: 24664 Letter Lines: 1631 to 1638 

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) 

Comment: Rule Provision: 146.84(f) 

Anadarko Petroleum Corporation (APC) 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: Clarification. 

Individual Response: EPA did not make the suggested change, but agrees that AoR 

reevaluations must take place as specified in approved AoR and corrective action plan. EPA 

clarifies that owners or operators must develop, implement, and update a Director-approved AoR 

and corrective action plan as required under §146.84(b). EPA is developing guidance for owners 

or operators on how to prepare the required GS project plans. The guidance will be available on 

EPA's web site, at http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm. 

Letter ID: 0200 Comment ID: 24665 Letter Lines: 1640 to 1647 

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) 

Anadarko Petroleum Corporation (APC) 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. 

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Individual Response: EPA disagrees with the suggested change and believes the proposed text 

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: 0200 Comment ID: 24666 Letter Lines: 1649 to 1658 

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) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: EPA will allow owners or operators to use separate financial 

responsibility instruments for different GS activities as long as they are able to demonstrate that 

their instruments will protect USDWs from endangerment. This means that owners or operators 

must demonstrate adequate financial responsibility for all required activities, including well 

plugging, with their permit application, per §146.82(a)(14). 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 owner or operator may be 

released from a financial instrument when the phase of the project for which the instrument was 

required is complete and all financial obligations for that instrument have been met, as specified 

in §146.85(b)(2). For example, when the injection well is plugged to the Director's satisfaction, 

the owner or operator's financial instrument will be released if it was not used. 

EPA is developing guidance on financial responsibility for Class VI wells. The guidance will 

include a discussion on how best to estimate costs to assist GS 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. 

85
Letter ID: 0200 Comment ID: 24667 Letter Lines: 1660 to 1669 

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(b) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: Cost estimates must be reevaluated after amendments to the area of 

review and corrective action plan, prior to well plugging or site closure, after amendments to the 

emergency and remedial response plan, or at any other time deemed appropriate by the Director. 

The rule will also require annual adjustments to the cost estimates for inflation, as specified in 

§146.85(c)(2). 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. 

EPA did not make the proposed edits at §146.85(b), 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: 0200 Comment ID: 24668 Letter Lines: 1671 to 1678 

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(c) 

Anadarko Petroleum Corporation (APC) 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: EPA did not make the proposed edits at §146.85(c), but did extensively 

revise and clarify the financial responsibility requirements. EPA believes that the Director must 

86
be notified of bankruptcy specifically, among other adverse financial conditions, because it 

affects the use of financial instruments. See the final GS rule and preamble for additional 

information on EPA's final approach. 

Letter ID: 0200 Comment ID: 24669 Letter Lines: 1680 to 1688 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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 RECENT demonstration is no longer adequate to 

cover the cost of injection well plugging (as required by §146.92) and postinjection 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. 

Letter ID: 0200 Comment ID: 24670 Letter Lines: 1690 to 1699 

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) 

Anadarko Petroleum Corporation (APC) Comments: (1) Prevent the movement of fluid 

into or between USDWs or into any unauthorized zones; CONTAINING ANY 

CONTAMINANT INTO UNDERGROUND SOURCES OF DRINKING WATER, 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. 

87
Individual Response: EPA disagrees that the language provided in § 146.86(a)(1) does not meet 

the non-endangerment standard provided under the SDWA. In fact, EPA believes that protection 

of USDWs from endangerment and prevention of fluid movement between formations is 

paramount and believes that the language as proposed meets the non-endangerment standard. 

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. 

Letter ID: 0200 Comment ID: 24671 Letter Lines: 1701 to 1717 

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) 

Anadarko Petroleum Corporation (APC) 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 

88
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: 0200 Comment ID: 24672 Letter Lines: 1719 to 1725 

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)(v) 

Anadarko Petroleum Corporation (APC) Comments: (v) Corrosiveness COMPOSITION 

of the carbon dioxide stream and formation fluids; 

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: 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. 

Letter ID: 0200 Comment ID: 24673 Letter Lines: 1727 to 1732 

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)(vi) 

Anadarko Petroleum Corporation (APC) Comments: (vi) Down-hole temperatures AND 

PRESSURES; 

Rationale: Technical clarification 

Individual Response: EPA clarifies that information on down-hole pressures is required at 

§146.86(b)(1)(ii). 

89
Letter ID: 0200 Comment ID: 24674 Letter Lines: 1734 to 1739 

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)(viii) 

Anadarko Petroleum Corporation (APC) Comments: (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." 

Letter ID: 0200 Comment ID: 24675 Letter Lines: 1741 to 1748 

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) 

Anadarko Petroleum Corporation (APC) 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. As described above, EPA 

disagrees that the surface casing requirements in the GS rule preclude injection below deep 

USDWs. EPA also 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. 

Letter ID: 0200 Comment ID: 24676 Letter Lines: 1750 to 1767 

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) 

90
Anadarko Petroleum Corporation (APC) Comments: (3) At least one long string 

casing, using a sufficient number of centralizers TO CREATE A CEMENT BOND 

THROUGH THE INJECTION AND CONFINING ZONE(S), 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. 

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 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: 0200 Comment ID: 24677 Letter Lines: 1769 to 1777 

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

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

Comment: Rule Provision: 146.86(b)(4) 

Anadarko Petroleum Corporation (APC) 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. 

Rationale: Same as above 

Individual Response: EPA disagrees that the requirement 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. 

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: 0200 Comment ID: 24678 Letter Lines: 1779 to 1793 

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)(5) 

Anadarko Petroleum Corporation (APC) 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. 

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 with the suggested edits. 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 

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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. 

EPA also believes that GS is sufficiently different from Class II ER operations to warrant the 

tailored construction requirements for Class VI wells at §146.86. 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 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. Therefore, Class VI GS reservoir pressures will increase during the 

injection phase of the GS project. 

Letter ID: 0200 Comment ID: 24679 Letter Lines: 1795 to 1803 

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)(ii) 

Anadarko Petroleum Corporation (APC) 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 of the CO2 stream. The 

composition of the CO2 stream is more relevant to the design of a tubing and 

packer system. 

Individual Response: As written, the text at §146.86(c)(3)(ii) accounts for all characteristics of 

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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. 

The final GS rule at §146.86(c)(1) also requires that tubing materials used in Class VI wells must 

meet or exceed standards developed by the American Petroleum Institute, ASTM International, 

or comparable standards acceptable to the Director. EPA believes that this requirement invokes 

the expertise of these bodies without the added burden of a certification program. 

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: 0200 Comment ID: 24680 Letter Lines: 1805 to 1813 

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)(iii) - (v) 

Anadarko Petroleum Corporation (APC) 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: 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: 0200 Comment ID: 24681 Letter Lines: 1815 to 1838 

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) 

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Anadarko Petroleum Corporation (APC) 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 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: 

Rationale: In well defined areas, these evaluations are frequently unnecessary. 

The director should have discretion to select the appropriate requirements 

necessary to ensure sufficient baseline data and information are available. 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 disagrees that the requirements for logs, surveys, and tests are 

unnecessary. 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. 

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Letter ID: 0200 Comment ID: 24682 Letter Lines: 1840 to 1847 

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) 

Anadarko Petroleum Corporation (APC) Comments: (i) Resistivity, spontaneous 

potential, and caliper logs before the casing is installed; and 

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. 

Individual Response: As described above, EPA disagrees that the requirements for logs, 

surveys, and tests are excessive or duplicative. All logs, surveys, and tests listed at §146.87(a) 

are necessary to verify information about the injection and confining zones and ensure that the 

well is being drilled and cased as approved, and has mechanical integrity. EPA notes that the 

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

equivalent or better information. 

Letter ID: 0200 Comment ID: 24683 Letter Lines: 1849 to 1860 

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)(ii) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: EPA clarifies at §146.87(a)(2)(ii) that owners or operators must perform a 

cement bond (i.e., cement evaluation) log after the casing is set and cemented. 

Letter ID: 0200 Comment ID: 24684 Letter Lines: 1862 to 1871 

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

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

Comment: Rule Provision: 146.87(a)(3)(i) 

Anadarko Petroleum Corporation (APC) 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 drawn on. 

Individual Response: EPA believes that a minimum suite of logs and tests is necessary at all 

Class VI wells. All logs, surveys, and tests listed at §146.87(a) are necessary to verify 

information about the injection and confining zones and ensure that the well is being drilled and 

cased as approved and has mechanical integrity. 

EPA notes that owners or operators will describe in their permit applications how they will 

construct and test the well, and will also submit site-specific information about the subsurface 

geology. The Director will evaluate the proposed logging activities along with site-specific 

geologic information to identify geologic data of interest. 

EPA adds that, should alternative methods be shown to provide equivalent or better information 

or if site-specific conditions and risk factors dictate that other logs are necessary, the Director has 

the discretion at §146.87(a)(5) to require further logs and tests if necessary and to approve 

alternative methods that provide equivalent or better information. 

Letter ID: 0200 Comment ID: 24685 Letter Lines: 1873 to 1880 

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)(3)(ii) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: EPA clarifies at 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. 

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Letter ID: 0200 Comment ID: 24686 Letter Lines: 1882 to 1894 

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)(4) 

Anadarko Petroleum Corporation (APC) 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 

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

Rationale: Technical and grammatical corrections 

In (iv), "if required by the Director" is unnecessary. 

Individual Response: 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. 

The Agency clarifies that a tracer survey is one of the mechanical integrity tests that 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 at 

§146.87(a)(4) 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.” 

Letter ID: 0200 Comment ID: 24687 Letter Lines: 1896 to 1906 

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(b) 

Anadarko Petroleum Corporation (APC) 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 

such DATA are representative of conditions in the wellbore. 

Rationale: The information required should be sufficient to properly describe 

the injection and confining zones. 

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Individual Response: 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: 0200 Comment ID: 24688 Letter Lines: 1908 to 1916 

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) 

Anadarko Petroleum Corporation (APC) Comments: (c) PRIOR TO INJECTION WELL 

OPERATION, the owner or operator must record 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. 

Individual Response: EPA disagrees that "reservoir pressure" and "static fluid level" 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. 

Letter ID: 0200 Comment ID: 24689 Letter Lines: 1918 to 1933 

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(d) 

Anadarko Petroleum Corporation (APC) 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. 

99
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 (3) are too vague. 

Individual Response: EPA believes that the requirement to provide information on the injection 

and confining zones in §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. 

Letter ID: 0200 Comment ID: 24690 Letter Lines: 1935 to 1953 

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(e) 

Anadarko Petroleum Corporation (APC) Comments: (e) (D) Upon completion 

but Prior to INJECTION WELL operation, the owner or operator must ESTIMATE 

FRACTURE PRESSURES OF THE INJECTION AND CONFINING ZONES AND conduct 

the 

following tests to verify hydrogeologic AND GEOMECHANICAL characteristics of 

the injection zone, E.G., INJECTIVITY TESTS, ESTIMATES BASED ON OPEN-HOLE 

LOGGING TOOLS (E.G. MECHANICAL PROPERTIES LOGS), AND OTHER 

APPROPRIATE METHODS. 

(1) A pump test; or 

(2) Injectivity tests. 

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. 

Individual Response: EPA clarifies that the owner or operator has the option of using the 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. 

EPA disagrees that the wording at §146.87(d) would lead the owner or operator to employ 

100
destructive testing methods for determination of fracture pressure. The wording "determined or 

calculated" allows for calculations to be performed based on non-destructive methods. 

Letter ID: 0200 Comment ID: 24691 Letter Lines: 1955 to 1966 

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(f) 

Anadarko Petroleum Corporation (APC) 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 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 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: 0200 Comment ID: 24692 Letter Lines: 1968 to 1988 

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) 

Anadarko Petroleum Corporation (APC) 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 

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MAXIMUM 

INJECTION PRESSURE LIMIT, THE DIRECTOR SHALL CONSIDER THE RESULTS OF 

WELL TESTS. 

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: Maintaining the integrity of the confining zone is the critical 

parameter. 

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

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, 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 operator102
submitted 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: 0200 Comment ID: 24693 Letter Lines: 1990 to 1998 

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) 

Anadarko Petroleum Corporation (APC) Comments: (b) Injection OF THE CO2 STREAM 

between the outermost casing protecting USDWs 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. 

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: 0200 Comment ID: 24694 Letter Lines: 2000 to 2014 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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. 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 

103
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: 0200 Comment ID: 24695 Letter Lines: 2016 to 2046 

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) 

Anadarko Petroleum Corporation (APC) 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 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 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, 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 

104
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: 0200 Comment ID: 24696 Letter Lines: 2048 to 2058 

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) 

Anadarko Petroleum Corporation (APC) 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: 0200 Comment ID: 24697 Letter Lines: 2060 to 2065 

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) 

Anadarko Petroleum Corporation (APC) Comments: (3) Notify the Director within 24 

hours OF DISCOVERY; 

No rationale provided 

105
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 

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: 0200 Comment ID: 24698 Letter Lines: 2067 to 2077 

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) 

Anadarko Petroleum Corporation (APC) 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 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. 

40 CFR §146.91(a)(2) requires that monthly averages of the continuous annulus monitoring be 

reported on a semiannual basis. EPA agrees with the commenter that recording annulus fluid 

volume may not be appropriate. EPA believes that 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 implements the suggested change from “long-stem” to 

“long-string” casing. 

106
Letter ID: 0200 Comment ID: 24699 Letter Lines: 2079 to 2097 

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) 

Anadarko Petroleum Corporation (APC) 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 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. 

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. 

Number 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 (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 

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 for determining the presence or absence of 

corrosion of the long-string casing, and is required if the Director determines that it is necessary 

based on site-specific information. EPA has revised the final GS rule to require that the 

frequency of the casing inspection log must be specified in the approved testing and monitoring 

plan. See §146.89(d). 

Letter ID: 0200 Comment ID: 24700 Letter Lines: 2099 to 2118 

107
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 

Anadarko Petroleum Corporation (APC) Comments: 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: 

(A) BASED ON A SITE-SPECIFIC ASSESSMENT OF THE POTENTIAL FOR FLUID 

MOVEMENT FROM 

THE INJECTION WELL OR INJECTION ZONE, AND ON THE POTENTIAL VALUE OF 

MONITORING 

WELLS TO DETECT SUCH MOVEMENT, 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 INCLUDE A DESCRIPTION 

OF HOW THE 

OWNER OR OPERATOR WILL MEET THE REQUIREMENTS OF THIS SECTION; 

No rationale provided 

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 risk-assessment. 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: 0200 Comment ID: 24701 Letter Lines: 2120 to 2154 

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) 

108
Comment: Rule Provision: 146.90(b) 

Anadarko Petroleum Corporation (APC) Comments: (b) The testing and monitoring 

plan must, at a minimum, include: 

(a1) Analysis of the carbon dioxide stream with sufficient frequency to 

yield data representative of its chemical and physical characteristics; 

(b2) Installation and use, except during well workovers as defined in § 

146.86(d), of continuous recording MONITORING DEVICES (INCLUDING DIGITAL 

DEVICES CAPTURING PERIODIC DATA) to monitor injection pressure, rate and volume; 

AND TO RECORD AT LEAST DAILY the pressure on the annulus between the tubing and 

the long string casing; and the annulus fluid volume; 

(3) A DEMONSTRATION OF EXTERNAL MECHANICAL INTEGRITY PURSUANT TO 

§146.89(C) 

UNTIL THE WELL IS PLUGGED; 

(4) MONITORING OF THE PRESSURE BUILDUP IN THE INJECTION ZONE 

ANNUALLY, INCLUDING 

AT A MINIMUM, A SHUTDOWN OF THE WELL FOR A TIME SUFFICIENT TO 

CONDUCT A VALID 

OBSERVATION OF THE PRESSURE FALLOFF CURVE AT LEAST ONCE EVERY FIVE 

YEARS; AND 

(5) A QUALITY ASSURANCE PLAN FOR ALL TESTING AND MONITORING 

REQUIREMENTS. 

(b) Installation and use, except during well workovers as defined in §146.88(d), 

of continuous 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; 

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. 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 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. Class VI injection wells must be equipped with dedicated 

computer-based continuous pressure monitoring devices (in concert with the Director-approved 

109
shut-off systems required for GS wells), which typically take readings several times per second 

and record them electronically in a computer system.. 

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 site-specific 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, at least every five years. EPA disagrees that the rule should provide specifics of 

the testing at the degree suggested, however. 

EPA clarifies that periodic MITs are not be required following plugging of the well. 

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: 0200 Comment ID: 24702 Letter Lines: 2156 to 2204 

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

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: Rule Provision: 146.86(c) 

Anadarko Petroleum Corporation (APC) Comments: (C) WHERE APPROPRIATE, THE 

TESTING AND MONITORING PLAN SHALL ALSO INCLUDE: 

(1) CONTINUOUS MONITORING FOR PRESSURE CHANGES IN AN APPROPRIATELY 

POROUS AND 

PERMEABLE FORMATION OVERLYING THE CONFINING ZONE. WHEN A WELL IS 

INSTALLED TO 

ENABLE SUCH MONITORING, THE OWNER OR OPERATOR SHALL, ON A SPECIFIED 

FREQUENCY OR 

AT SPECIFIED TIMES, SAMPLE THE FORMATION AND ANALYZE FOR 

CONSTITUENTS SPECIFIED 

IN THE PLAN; 

(2) THE USE OF INDIRECT, GEOPHYSICAL TECHNIQUES TO DETERMINE THE 

POSITION OF THE 

CO2 STREAM FRONT, THE WATER QUALITY IN A DESIGNATED FORMATION, OR 

TO PROVIDE 

OTHER SITE SPECIFIC DATA; 

(3) PERIODIC MONITORING OF WATER QUALITY IN AN APPROPRIATELY POROUS 

110
AND 

PERMEABLE FORMATION OVERLYING THE INJECTION ZONE; 

(4) PERIODIC MONITORING OF WATER QUALITY IN ONE OR MORE USDWS; 

(5) CORROSION MONITORING OF THE WELL MATERIALS FOR LOSS OF MASS, 

THICKNESS, 

CRACKING, PITTING AND OTHER SIGNS OF CORROSION PERFORMED AND 

RECORDED AT LEAST 

QUARTERLY 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: 

(I) ANALYZING COUPONS OF THE WELL CONSTRUCTION MATERIALS PLACED IN 

CONTACT WITH 

THE CARBON DIOXIDE STREAM; OR 

(II) ROUTING THE CARBON DIOXIDE STREAM THROUGH A LOOP CONSTRUCTED 

WITH THE 

MATERIAL USED IN THE WELL AND INSPECTING THE MATERIALS IN THE LOOP; 

OR 

(III) USING AN ALTERNATIVE METHOD, MATERIALS, OR TIME PERIOD APPROVED 

BY THE 

DIRECTOR; 

(6) ANY ADDITIONAL TESTING AND MONITORING APPROPRIATE TO SUPPORT 

MODELING THE 

EXTENT OF THE CARBON DIOXIDE PLUME AND THE POSITION OF THE PRESSURE 

FRONT; AND 

(7) ANY ADDITIONAL TESTING AND MONITORING NECESSARY TO DETERMINE 

WHETHER FLUID 

MOVEMENT IS OCCURRING INTO OR BETWEEN USDWS THAT WOULD ENDANGER 

A USDW. 

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. 

APC 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 

111
stream. 

Individual Response: EPA believes that quarterly corrosion monitoring of GS wells is 

necessary. 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, 

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). 

EPA maintains that plume tracking and pressure monitoring are key components of monitoring 

at GS sites. A rigorous plume tracking and pressure monitoring scheme, such as one that meets 

the requirements at §146.90(g), is imperative for ensuring that the CO2 plume is contained 

within the injection zone. Pressure monitoring in the injection zone is necessary to track the 

development and movement of the pressure front and CO2 plume. When combined with 

information on temperature, pressure data provide an indication of the phase (e.g., gas, 

112
supercritical) and distribution of the injected CO2. 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. 

EPA also believes that the ground water geochemical monitoring outlined in §146.90(d) will 

maximize protection of USDWs from endangerment at GS sites. Direct geochemical sampling is 

an important part of a monitoring program. See the final rule and preamble for further discussion 

on EPA's final approach. 

Letter ID: 0200 Comment ID: 24703 Letter Lines: 2206 to 2220 

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) 

Anadarko Petroleum Corporation (APC) Comments: (c) Corrosion monitoring of the 

well materials for loss of mass, thickness, cracking, pitting and other signs of 

corrosion must be performed on a quarterly basis to ensure that the well 

components meet the minimum standards for material strength and performance set 

forth in § 146.86(b) by: 

(1) Placing coupons of the well construction materials in contact with the 

carbon dioxide stream; or 

(2) Routing the carbon dioxide stream through a loop constructed with the 

material used in the well; or 

(3) Using an alternative method approved by the Director; 

Rationale: See 146.90(5)(i-iii) 

Individual Response: EPA believes that corrosion monitoring is necessary for all Class VI wells 

to prevent endangerment of 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. 

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: 0200 Comment ID: 24704 Letter Lines: 2222 to 2238 

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

Comment Code: 4660 2.6.6 Geochemical monitoring 

113
Comment: Rule Provision: 146.90(d) 

Anadarko Petroleum Corporation (APC) Comments: (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); 

Rationale: See 146.90(c)(1 thru 4 and 7) 

Individual Response: EPA did not make the suggested changes, but agrees that monitoring 

plans and methods need to be site-specific and based on baseline data and data collected 

throughout operations. EPA 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. 

The final regulation provides for flexibility in: 1) methodologies used to collect these data, 2) the 

spatial resolution at which the data should be collected, and 3) how often the data should be 

collected. The number and placement of monitoring wells will be based on site-specific 

information such as the calculated AoR, injection rate and volume, site geology, baseline data, 

and the presence of artificial penetrations within the AoR. In some instances, there may be a 

limited number of options for complying with EPA's minimum requirements. For example, 

monitoring for geochemical changes will require use of monitoring wells and collection of 

groundwater samples for chemical analysis. Many options currently exist for complying with 

other requirements, such as tracking the position of the plume and pressure front within the 

injection zone. 

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 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 

114
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: 0200 Comment ID: 24705 Letter Lines: 2240 to 2246 

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(e) 

Anadarko Petroleum Corporation (APC) Comments: (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; 

Rationale: See 146.90(b)(3) 

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 

purpose of including all testing and monitoring requirements in §146.90 is to clarify and to 

specify the content of the required testing and monitoring plan. 

Letter ID: 0200 Comment ID: 24706 Letter Lines: 2248 to 2254 

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(f) 

Anadarko Petroleum Corporation (APC) Comments: (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; 

Rationale: See 146.90(b)(4) 

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 

purpose of including all testing and monitoring requirements in §146.90 is to clarify and to 

specify the content of the required testing and monitoring plan. 

115
Letter ID: 0200 Comment ID: 24707 Letter Lines: 2256 to 2270 

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: 146.90(g) 

Anadarko Petroleum Corporation (APC) Comments: (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); 

Rationale: See 146.90(c)(1 thru 4 and 7) 

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 believes that direct pressure measurements are appropriate and 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 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. Sitespecific testing and monitoring plans should 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 

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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 

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 

CO2 Stored in Deep Geologic Formations" (DOE/NETL-311/081508); this manual is included in 

the docket for the final GS rule. 

Letter ID: 0200 Comment ID: 24708 Letter Lines: 2272 to 2288 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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. 

(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; 

Rationale: In most situations soil and air monitoring does not provide an 

effective method of protecting USDWs. 

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. 

In the final rule, at §146.90(h), the decision to require such monitoring as an additional measure 

to ensure USDW protection rests with the Director as a means of identifying leaks that may pose 

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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 Agency agrees with the commenter that, if air and soil gas monitoring is performed, baseline 

soil CO2 levels need to be determined before monitoring. This would be considered and 

described in the site-specific testing and monitoring plan. 

Letter ID: 0200 Comment ID: 24709 Letter Lines: 2290 to 2297 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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 

Rationale: See 146.90(c)(6) 

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: 0200 Comment ID: 24710 Letter Lines: 2299 to 2304 

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(j) 

Anadarko Petroleum Corporation (APC) Comments: (j) A quality assurance and 

surveillance plan for all testing and monitoring requirements. 

Rationale: See 146.90(b)(5) 

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: 0200 Comment ID: 24711 Letter Lines: 2306 to 2319 

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

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Comment Code: 4720 2.7.2 Operational recordkeeping and reporting 

Comment: Rule Provision: 146.91(a) 

Anadarko Petroleum Corporation (APC) 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. 

Individual Response: EPA retained this provision 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, and that information will aid in his/her 

determination of whether these indicate problems at the site, and what is the appropriate course 

of action (e.g., a well workover, modification of operating parameters, or imposition of a 

penalty) to remediate such problem(s). 

Letter ID: 0200 Comment ID: 24712 Letter Lines: 2321 to 2332 

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(3) & (4) 

Anadarko Petroleum Corporation (APC) 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. 

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Individual Response: EPA retained this provision 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, and that information will aid in his/her 

determination of whether these indicate problems at the site, and what is the appropriate course 

of action (e.g., a well workover, modification of operating parameters, or imposition of a 

penalty) to remediate such problem(s). 

Letter ID: 0200 Comment ID: 24713 Letter Lines: 2334 to 2342 

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(a) 

Anadarko Petroleum Corporation (APC) 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: 0200 Comment ID: 24714 Letter Lines: 2344 to 2353 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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 

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Rationale: Many of the components that would be tested by an internal MIT are 

removed or tested during the plugging process. 

Individual Response: Regarding the suggested edit at 146.92(b)(2), 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. 

Regarding the edit at 146.92(b)(5), 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: 0200 Comment ID: 24715 Letter Lines: 2355 to 2366 

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) 

Anadarko Petroleum Corporation (APC) 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 APC 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: 0200 Comment ID: 24716 Letter Lines: 2368 to 2377 

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) 

Anadarko Petroleum Corporation (APC) Comments: (1) The owner or operator must 

submit the postinjection site care and site closure plan as a part of the permit 

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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(3). 

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. 

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 however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in most cases. The default 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. 

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. 

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: 0200 Comment ID: 24717 Letter Lines: 2379 to 2397 

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) 

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Anadarko Petroleum Corporation (APC) 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 

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: 0200 Comment ID: 24718 Letter Lines: 2399 to 2406 

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) 

Anadarko Petroleum Corporation (APC) Comments: (4) AT ANY TIME DURING THE POSTINJECTION 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 postinjection 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 

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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 is issuing 

guidance with recommended approaches for 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. 

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." 

Letter ID: 0200 Comment ID: 24719 Letter Lines: 2408 to 2425 

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 Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: Rule Provision: 146.93(b)(1) 

Anadarko Petroleum Corporation (APC) Comments: (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 no longer poses an 

endangerment to USDWs. PURSUANT TO THE PERFORMANCE BASED CRITERIA 

DESCRIBED IN 

§146.93(B)(3). 

Rationale: 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 may 

create a significant barrier for operators considering entry into CCS 

operations. Criteria for determining the period for postinjection 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. APC offers such criteria in our edits to §146.93(b)(3). 

Individual Response: EPA disagrees that a post-injection site care timeframe of 50 years is 

excessive in most cases or 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, titled "Computational Modeling of Underground Injection of Carbon 

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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 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. 

EPA believes however, that to ensure USDW protection from endangerment, a default timeframe 

for post-injection site care will be necessary in all but a limited number of cases. This default 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. 

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. 

Letter ID: 0200 Comment ID: 24720 Letter Lines: 2427 to 2437 

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 Code: 5240 2.8.2.2 Post injection timeframe (seeking comment) 

Comment: Rule Provision: 146.93(b)(2) 

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Anadarko Petroleum Corporation (APC) Comments: (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: (See above) 

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

timeframe of 50 years is excessive in most cases or arbitrary, and retains the default 50-year 

post-injection site care timeframe in the final rule. 

Letter ID: 0200 Comment ID: 24721 Letter Lines: 2439 to 2467 

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) 

Anadarko Petroleum Corporation (APC) 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 pose an endangerment to USDWs. 

THE OWNER OR OPERATOR MUST DEMONSTRATE, 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 

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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: APC 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. 

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 

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. 

127
Letter ID: 0200 Comment ID: 24722 Letter Lines: 2469 to 2476 

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) 

Anadarko Petroleum Corporation (APC) 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 post-injection site care. 

Rationale: No longer necessary given changes above. 

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

timeframe of 50 years is excessive in most cases or arbitrary, and retains the default 50-year 

post-injection site care timeframe in the final rule. . 

Letter ID: 0200 Comment ID: 24723 Letter Lines: 2478 to 2496 

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) 

Anadarko Petroleum Corporation (APC) Comments: (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. 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 

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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: 0200 Comment ID: 24724 Letter Lines: 2498 to 2517 

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) 

Anadarko Petroleum Corporation (APC) 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. 

EPA clarifies that the Agency expects that owners or operators should take care not to damage 

the well when ceasing injection under §146.94(b)(1). At §146.94(b)(2), EPA is maintaining the 

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requirement to “characterize the release.” 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. 

In response to commenters’ suggestions regarding §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: 0200 Comment ID: 24725 Letter Lines: 2519 to 2526 

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(d) 

Anadarko Petroleum Corporation (APC) 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, as 

required under the SDWA. 

Letter ID: 0200 Comment ID: 24967 Letter Lines: 625 to 634 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

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Comment: Rule Provisions: 146.89(c), 146.90(e) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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, 

APC recommends 5-year frequency in this case as well. The MIT should test 

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 in that: 1) the purpose 

of CO2 injection for GS is permanent storage, whereas for ER operations injected CO2 is often 

recovered (pumped from the sub-surface) relatively soon after injection, 2) typically there is 

minimal formation pressure build-up during ER operations because withdrawals from oil 

recovery wells reduce reservoir pressure, which is not the case in GS reservoirs, and 3) the 

volumes of CO2 anticipated for injection for GS are significantly larger than the volumes of CO2 

injected for ER operations. These conditions illustrate that frequent internal MITs for Class VI 

wells are critically important in ensuring that USDWs are protected. EPA believes that 

continuous pressure monitoring to demonstrate internal mechanical integrity of GS wells, instead 

of periodic testing, which is required for most other types of deep injection wells, is important. 

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. 

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. 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: 0200 Comment ID: 24968 Letter Lines: 634 to 640 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

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Comment: APC 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 methods for detecting mechanical 

failures, managing those risks, and conducting MITs. 

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). EPA 

believes this is 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 also 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 provides 

the Director discretion 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. 

Letter ID: 0200 Comment ID: 29318 Letter Lines: 408 to 427 

Comment Code: 3822 2.3.1.1 Depth of surface casing (seeking comment) 

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

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Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: Rule Provisions: 146.86(b) 

EPA Rule Issue: 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. 

Anadarko Petroleum Corporation (APC) 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 for other methods of 

protecting USDWs 

APC opposes the requirement for cementing the long string casing back to 

surface. Cementing requirements should focus on ensuring competent isolation and 

seal across the 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. 

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 

the standard that USDWs are protected from endangerment, subject to the approval of the 

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

monitoring, operation, and remediation of GS wells. 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) and have been successfully cemented in a 

manner that maintains integrity and allows for all required well testing, operation, and 

remediation. 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. 

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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. 

EPA clarifies that the rule allows discretion in some areas when UIC Directors evaluate and 

approve 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.