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.
Docket ID No. EPA-HQ-OW-2008-0390 

The North Dakota Industrial Commission, Oil and Gas Division offers the 

following comments on issues specifically identified by EPA in the preamble on 

which the Agency is seeking comment: 

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.

 The North Dakota Industrial Commission has drafted legislation concerning 

capture and storage of carbon dioxide to be acted upon during the upcoming legislative 

session in January 2009. This legislation was crafted using the IOGCC model. If the 

legislation is enacted, administrative rules will be promulgated. As with most regulatory 

programs, the states are best qualified to take state-specific issues into account and to 

tailor the regulatory needs to fit their unique circumstances. To this end, partial primacy 

for Class VI wells is imperative. 

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. 

 This approach makes the most sense since enhanced recovery operations have 

proven successful at increasing and maximizing oil and gas recovery while successfully 

sequestering carbon dioxide. As long as production of oil and gas is occurring, it would 

be inefficient and confusing to change the rules and processes under which these wells 

are regulated. 

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. 

 If a well has been utilized for injection and is properly constructed under existing 

regulations, it is constructed to prevent the migration of the injectate into a USDW. The 

demonstrated well performance is indicative that well construction is protective of 

USDWs. A review to verify the existing construction as protective is sufficient to 

grandfather the construction as protective as a Class VI injection well. 

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. 

 See 3 above. 
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. 

 This arbitrary exclusion would eliminate a vast number of potential sequestration 

zones. Enhanced recovery operations above the lowermost USDW have been taking 

place for a very long time. Unmineable coals in North Dakota are found in high clay 

content glacial till which, if unfractured, serves as an excellent confining zone. Based 

upon carbon dioxide’s affinity to adhere to coals, it is unwise to arbitrarily eliminate a 

potentially large number of sequestration zones. Exclusion of these zones even in 

areas where other abundant supplies of freshwater are available may severely limit 

sequestration options. These situations are best handled locally where all of the 

pertinent regional geologic factors can be considered. 

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. 

 This arbitrary exclusion would eliminate a vast number of potential sequestration 

zones. Enhanced oil and gas recovery operations above the lowermost USDW have 

been taking place for a very long time. Exclusion of these zones where other abundant 

supplies of freshwater are available may unnecessarily limit sequestration options. 

These situations are best handled locally where all the pertinent regional geologic 

factors can be considered. The buoyancy of carbon dioxide suggests this in an 

unnecessary restriction since it would move injectate away from the USDWs below the 

sequestration zone. 

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. 

 The presence of certain hazardous wastes should not preclude the overall carbon 

dioxide stream from injection into a sequestration zone. The process of removing the 

carbon dioxide and making it suitable for transportation and injection should render it 

relatively pure. The presence of impurities can be dealt with at a specific source and 

the overall waste stream certified for injection. If the well construction and geologic 

setting is suitable to confine the carbon dioxide stream and prevent its migration into a 

USDW, then certain impurities and/or hazardous wastes should be allowed. 

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. 
 Carbon dioxide should not be classified as a hazardous waste. Carbon dioxide is 

not hazardous or toxic under normal conditions. CERCLA liability will not only impact 

owners and operators of carbon dioxide sequestration projects, but also pore space 

owners. Subjecting pore space owners to CERCLA liability and joint and several liability 

under CERCLA will greatly hamper carbon dioxide sequestration projects. EPA should 

take the opportunity in this rulemaking to alleviate any CERCLA liability concerns. 

9. EPA also requests comment on other considerations associated with the 

presence of impurities in the CO2 stream related to CERCLA. EPA Notice 43504. 

 CERCLA should not apply to carbon dioxide sequestration. EPA needs to provide 

assurances to facilitate carbon dioxide sequestration projects. 

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. 

 Redundant confining zones should not be required. If the primary confining zone is 

adequate, by definition it is sufficient. If one sequestration site identifies one confining 

zone and another identifies multiples, it may lead to public confusion and lack of 

confidence in a site that only has one confining zone even though it is just as protective. 

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. 

 There is concern about the lack of information necessary to construct a valid model 

in areas where the sequestration zone has not been extensively studied. This lack of 

information may make modeling difficult or not very useful. Any modeling used should 

be re-examined and recalibrated over time with additional data gathered. Modeling 

should not be solely relied upon where real data offers a different view. Seismic and 

offset well data can help delineate the AOR. 

12 In some cases, owners or operators may choose to use proprietary models 

(i.e., not available for free to the general public). EPA says it is aware that the use 

of proprietary codes may prevent full evaluation of model results (e.g., NRC, 
2007). Several popular codes in the petroleum-reservoir engineering discipline 

are proprietary and owners or operators of particular sites may prefer to use 

these codes as they have previous experience with them, and they have been 

used in peer-reviewed studies to model CO2 sequestration. When using a 

proprietary model, owners or operators should clearly disclose the code 

assumptions, relevant equations, and scientific basis. EPA seeks comment on 

allowing the use of proprietary models for GS sites. EPA Notice 43507. 

 The use of proprietary models is widely used and accepted in oil and gas reservoir 

simulation. These models are a logical fit to simulate carbon dioxide sequestration 

projects. These models are verified using a history-match. The regulatory agency 

responsible for monitoring carbon dioxide sequestration does not need access to the 

code in order to conduct or evaluate a history-match. A regulatory agency could 

conduct reservoir modeling using its own modeling software to compare. Elimination of 

these widely used and understood reservoir models would be unwise. The assumptions 

and equations used in the modeling along with a valid history match will provide the 

regulating authority the ability to assess the model’s accuracy. 

13. EPA seeks comment on the applicability of computational fluid flow models 

for delineating the AoR of GS sites. EPA Notice 43507. 

 The use of computational flow models is appropriate, however; modeling should 

not be the sole criteria to determine the AOR if actual measured data exists. 

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. 

 It is appropriate to reevaluate the AOR on a periodic basis. The conditions and 

frequency under which the AOR is reevaluated should be based upon monitoring. 

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. 

 A phased approach is appropriate. Corrective action for some aspects of the 

project may not be necessary at the outset and a phased approach would allow an 

operator to optimize capital expenditures to make a project more feasible. Wholesale 

corrective action at the outset of a project may ultimately result in corrective action in 

areas unaffected by the project. In addition, the procurement of rigs and other 

equipment and the time necessary to conduct corrective actions in areas that might not 

be affected for a significant period of time could unnecessarily delay a sequestration 

project. 
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. 

 Requiring setting surface casing below the lowermost USDW would preclude 

injection above the lowermost USDW, which as earlier stated, would eliminate a vast 

number of potential sequestration zones. Enhanced recovery operations above the 

lowermost USDW have been taking place for a very long time. Exclusion of these 

zones where other abundant supplies of freshwater are available may unnecessarily 

limit sequestration options. These situations are best handled locally where the regional 

geologic factors can be considered. Setting the surface casing below the lowermost 

USDW may not be technically feasible. Cementing of the long-string casing to surface 

may not be desirable in all situations; an annulus that can be monitored may be 

desirable. The long-string casing should be cemented to at least above the upper 

confining zone. Requiring the packer be set opposite a cemented interval is 

appropriate. 

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. 

 If a well has been utilized for injection and is properly constructed under existing 

regulations, it is constructed to prevent the migration of the injectate into a USDW. The 

demonstrated well performance is indicative that it is protective of USDWs. A review to 

verify the construction is sufficient to grandfather the construction as protective as a 

Class VI injection well. Additional realistic remedial actions short of new construction 

could be required to make the well more protective. 

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. 

 Horizontal wells should be allowed. The drilling of these wells has become 

common in certain basins. Their use would maximize injection while minimizing the 

surface footprint and injection pressure. Well construction requirements should be 

similar to vertical wells i.e., the vertical portion of the well should be cemented to above 

the upper confining zone. 

19. EPA seeks comment regarding requirements for degradation-resistant well 

construction materials, such as acid-resistant cements and corrosion resistant 

casing. EPA Notice 43510. 

 Based upon history in carbon dioxide injection projects, construction requirements 

should be based upon actual needs as identified in these projects and upon actual 

subsurface conditions. Industry experience with carbon dioxide EOR projects supports 

the use of conventional tubing, casing, and cements. These wells have been 

demonstrated to protect USDWs. Corrosion mitigation measures such as lined tubing, 

use of corrosion inhibitors, and proper dehydration of carbon dioxide provide adequate 

protection. 
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. 

 Hydraulic fracturing should be allowed as long as it does not compromise the 

confining zone. Computer modeling to predict the fracture growth can be utilized in 

fracture stimulation design. 

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. 

 This type of information needs to be obtained from industry. Many basins have 

implemented hydraulic fracturing of certain formations for a number of years. These 

situations are best handled locally where the regional geologic factors can be 

considered. 

22. EPA seeks comment on the merits of requiring down-hole shut-off valves in 

GS wells. EPA Notice 43511. 

 Requiring down-hole shut-off valves may be problematic. To protect the entire 

tubing-casing annulus they would need to be installed at or below the injection packer. 

This may make the tool prone to failure. These valves may restrict or preclude the 

running of down hole monitoring or logging tools. Inclusion of a seating nipple directly 

above the injection packer which would allow the installation of a wire line set plug may 

be more appropriate. 

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 into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are available 

may severely limit sequestration options. These situations are best handled locally 

where other regional geologic factors can be considered. Demonstration that the upper 

and lower confining zones are adequate to prevent migration should be sufficient. The 

fact that the carbon dioxide plume is buoyant will protect any deeper USDW. 

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. 
 Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are available 

may severely limit sequestration options. These situations are best handled locally 

where other regional geologic factors can be considered. Demonstration that the upper 

and lower confining zones are adequate to prevent migration should be sufficient. The 

fact that the carbon dioxide plume is buoyant will protect any deeper USDW. 

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. 

 Aquifer exemptions should be allowed pursuant to existing requirements in other 

injection well classes. 

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 not be a minimum injection depth. The determining factor should be 

whether the project will be protective of USDWs. A minimum depth requirement 

suggests a requirement to inject carbon dioxide in a supercritical phase. This is not 

appropriate since there may be projects where injection of carbon dioxide in other 

phases is the most effective option. 

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. 

 Discretion on whether to use a tracer is appropriate. Radioactive tracers have 

been successfully utilized in oil and gas operations. The small amount used should not 

threaten human health or USDWs. However, modeling and monitoring are generally 

more appropriate techniques to track a plume since tracers have a limited radius of 

investigation. 

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. 

 The monitoring of this data is appropriate. Continuous monitoring should be 

clarified as daily for most applications. This could be more stringent or frequent on a 

case-by-case basis. 
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. 

 A five-year frequency to conduct and review internal and external mechanical 

integrity is appropriate. A standard pressure test utilizing a fluid compatible with the 

annular fluid is widely practiced but other methods should be available. More frequent 

testing or review could be required based upon specific factors. 

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. 

 Monitoring of the carbon dioxide plume is appropriate however caution is advised 

with respect to requiring monitoring wells since these may provide a conduit for 

unwanted migration. 4D seismic and predictive models will improve over time due to 

iterative processes. 

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. 

 An initial pressure fall-off test could be required and subsequent tests required at 

the time the AOR is reevaluated. 

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. 

 Tracking the plume and pressure front will allow for verification of the reservoir 

model. Pressure transient testing and seismic techniques may be useful alternatives. 

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 should be determined on a site-specific basis and be based 

upon potential risks posed by the project and the cost versus benefit of monitoring. 

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 postinjection site care and site closure plan. EPA seeks comment on the merits of 

requiring plans for monitoring, AoR, and post-injection site care as part of a 

permit application. EPA Notice 43517. 

 Allowing for different plans would be much more effective than prescriptive 

regulations; however, a plan modification should not be considered a major permit 
modification. Caution needs to be taken when monitoring the injection formation due to 

the artificial penetration of the confining zone to gain data. The number of monitoring 

wells should be decided on a case-by case basis. It is unclear how monitoring wells will 

be regulated since they are not injection wells. The timing of plan submittal should be 

linked to the activity being addressed. Site closure plans, post-closure plans, well 

plugging plans, etc., should not be required many years in advance since conditions, 

understanding of the sequestration zones, and technology change over time. 

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

requirements. EPA Notice 43517. 

 Reporting frequency should coincide with requirements for existing UIC injection 

well classes unless there is a need for more frequent reporting. 

36. EPA seeks comment on the requirement for electronic reporting in its 

proposed rule. EPA Notice 43518. 

 Electronic reporting should not be required. State systems may already be in 

place to collect data but may not be compatible with sending or receiving systems. 

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. 

 During the active injection phase of a project, reports and frequencies similar to 

those which exist in other UIC classes should be sufficient. Once active injection 

ceases, an annual report may be appropriate. 

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. 

 A performance-based time period is appropriate rather than a fixed timeframe. 

39. EPA is requesting comments on the proposed requirements for well 

plugging, post-injection site care, and site closure, including the proposed 

requirements for the post-injection time period. EPA Notice 43520. 

 A performance-based time period is appropriate rather than a fixed timeframe. 

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. 
 A performance-based time period is appropriate rather than a fixed timeframe. 

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. 

 The pay-in period should coincide with the estimated risk. 

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. 

 Financial assurance should be left to state lawmakers and the regulating agency 

and should not be a prescribed mechanism. 

43. EPA is assessing whether a financial ratings threshold for all companies 

using a self-guarantee, similar to those used by other Federal agencies, is 

appropriate. The Agency also is considering what constitutes an appropriate 

financial rating threshold, and whether a financial rating greater than BBB or Baa 

(i.e., the current rating threshold established under the UIC regulations) is 

appropriate for GS wells. EPA Notice 43522. 

 Financial assurance should be left to state lawmakers and the regulating agency 

and should not be a prescribed mechanism. 

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. 

 Financial assurance should be left to state lawmakers and the regulating agency 

and should not be a prescribed mechanism. 

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. 

 This seems a sensible approach however; financial assurance should be left to the 

regulating agency and not prescribed. 
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. 

 Public participation requirements should be left to the regulating agency and not 

prescribed. Requirements could mirror the agency’s existing public notice and 

participation requirements. 

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. 

 Public participation requirements should be left to the regulating agency and not 

prescribed. The applicant should be allowed to do some site characterization to assess 

site suitability and project feasibility before the public is engaged. Requirements could 

mirror the agency’s existing public notice and participation requirements. 

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. 

 Partial primacy should be granted for Class VI wells independently of other well 

classes and through a process similar to granting primacy under existing UIC classes, 

allowing the states to determine the appropriate regulating agency. 

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. 

 Partial primacy should be granted for Class VI wells independently of other well 

classes allowing the states to determine the appropriate regulating agency. This will 

encourage states to apply for primacy. 

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. 

 This will reduce administrative burdens that would yield little or no environmental 

benefit. 
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. 

 The number of monitoring wells required will be very site specific. 

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. 

 There are no known unique characteristics of carbon dioxide injection or its 

potential impacts on USDWs that have not been addressed within existing UIC rules or 

found in current carbon dioxide injection projects. 
The North Dakota Industrial Commission, Oil and Gas Division offers the 

following comments on the proposed regulations for the underground injection of 

carbon dioxide for geologic sequestration: 

144.6 Class VI wells are to be limited to injection beneath the lowermost formation 

containing a USDW. This arbitrary exclusion would eliminate a vast number of potential 

sequestration zones. Enhanced oil and gas recovery operations above the lowermost 

USDW have been taking place for a very long time. Exclusion of these zones where 

other abundant supplies of freshwater are available may unnecessarily limit 

sequestration options. These situations are best handled locally where all the pertinent 

regional geologic factors can be considered. The buoyancy of carbon dioxide suggests 

this in an unnecessary restriction since it would move injectate away from the USDWs 

below the sequestration zone. 

144.36 Permits for Class VI wells should be effective indefinitely, until the well is 

plugged. 

146.81(d) Geologic sequestration project should be redefined as follows: Geologic 

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

stream into an injection zone for geologic sequestration. Geologic sequestration 

projects should not be limited to beneath the lowermost formation containing a USDW. 

146.82(a) Overlying formations needs to be defined. Geologic information should be 

limited to the injection and confining zones. 

 Capillary pressure is difficult to measure outside a lab and would not be 

available if no wells have been drilled in a project. Do not see necessity for this 

information. 

146.82(g) Baseline geochemical data on subsurface formations is too broad. Should 

be limited to the injection zone, confining zones, and possibly the next porous and 

permeable zone above the upper confining zone. 

146.82(u) Site closure plans, post-closure plans, well plugging plans, etc., should not 

be required many years in advance since conditions, understanding of the sequestration 

zones, and technology change over time. 

146.83(a)1 An injection zone capable of receiving the total anticipated volume of 

carbon dioxide should not be an absolute requirement. The volume to be injected may 

be difficult to ascertain since the life of a power plant or other source may change with 

advances in technology or under certain economic conditions. A candidate injection 

zone should not be excluded if it can only serve as a sequestration zone for a portion of 

a project. 
146.83(b) Delete reference to identification of additional confining zones. This 

implies this will be required. Redundant confining zones are not required in other UIC 

well classes. 

146.85(b) The frequency specified for written updates of adjustments to cost 

estimates should coincide with the AOR reevaluation. 

146.86(b)1(v) How is corrosiveness measured? 

146.86(b)2 Requiring setting surface casing below the lowermost USDW would 

preclude injection above the lowermost USDW, which as earlier stated, would eliminate 

a vast number of potential sequestration zones. Enhanced recovery operations above 

the lowermost USDW have been taking place for a very long time. Exclusion of these 

zones where other abundant supplies of freshwater are available may unnecessarily 

limit sequestration options. These situations are best handled locally where the regional 

geologic factors can be considered. Setting the surface casing below the lowermost 

USDW may not be technically feasible. 

146.86(b)3 Cementing of the long-string casing to surface may not be desirable in all 

situations; an annulus that can be monitored may be desirable. The long-string casing 

should be cemented to at least above the upper confining zone. 

146.86(b)5 Request clarification whether a CBL with VDL image is sufficient. 

146.86(c)2(ii) How is corrosiveness measured? 

146.87(a) Relevant geologic formations is too broad. This information should only 

be required for the injection and confining zones and possibly the next porous and 

permeable zone above the upper confining zone. 

146.87(a)2 Open hole logs in the surface hole are unusual and not necessary. If 

required, certainly not in every well in a project. 

146.87(a)3 Should specify basic logging requirement not specific logs. 

146.87(b) Coring should not be required if an adequate core and report exists for a 

nearby well. Coring should only be required of the injection and confining zones and 

possibly the next porous and permeable zone above the upper confining zone. 

146.87(d)2 Vague and ambiguous. 

146.87(f) Unrealistic time frame. Tie initial reporting to spud date and 48 hour 

notification thereafter. 
146.88(c) Pressure on the annulus is not necessary in all situations. Maintaining 

pressure above the injection pressure will subject the long-string casing to unnecessary 

stress and is not commensurate with the risk associated with carbon dioxide injection. 

146.88(e) Is continuous recording of annular fluid volume possible or practical? 

 Requiring down-hole shut-off valves may be problematic. To protect the 

entire tubing-casing annulus they would need to be installed at or below the injection 

packer. This may make the tool prone to failure. These valves may restrict or preclude 

the running of down hole monitoring or logging tools. Inclusion of a seating nipple 

directly above the injection packer which would allow the installation of a wire line set 

plug may be more appropriate. 

146.89(c) Annual tracer surveys, temperature or noise logs, or casing inspection 

logs is too burdensome. This frequency should coincide with AOR reevaluation. 

146.90(b) Is continuous recording of annular fluid volume possible or practical? 

146.90(c) Quarterly is too onerous. Director should have discretion to require less 

frequently based upon performance. 

146.91(a) Injection volumes and pressures should be reported monthly. 

146.91(c) Electronic reporting should not be required. State systems may already 

be in place to collect data but may not be compatible with sending or receiving systems. 

146.92(d) Simplify. Plugging reports should be required within a consistent time 

frame. 

146.93(b) A performance-based time period is appropriate rather than a fixed 

timeframe. Establishing an arbitrary and long time frame will inhibit operators from 

entering into this activity. 

Respectfully submitted, 

Mark Bohrer 

Petroleum Engineer/UIC Manager 

North Dakota Industrial Commission 

Oil and Gas Division 

600 E Blvd-Dept 405 

Bismarck ND 58505-0405 

mbohrer@nd.gov 

(701) 328-8020 
Letter ID: 0241 

Commenter: Mark Bohrer 

Organization: North Dakota Industrial Commission 

Letter ID: 0241 Comment ID: 23223 Letter Lines: 22 to 33 

Comment Code: 1530 1.2.3.1 State regulatory efforts on GS (seeking comment) 

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

Comment: 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. 

The North Dakota Industrial Commission has drafted legislation concerning 

capture and storage of carbon dioxide to be acted upon during the upcoming 

legislative session in January 2009. This legislation was crafted using the 

IOGCC model. If the legislation is enacted, administrative rules will be 

promulgated. As with most regulatory programs, the states are best qualified to 

take state-specific issues into account and to tailor the regulatory needs to 

fit their unique circumstances. To this end, partial primacy for Class VI wells 

is imperative. 

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

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

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

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

primacy for Class I wells, the State would also need to accept responsibility for Class III, IV, and 

V wells. This policy 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. 

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 

1
from endangerment through the UIC regulatory framework. EPA believes that, due to the 

importance of implementing an effective, comprehensive, and seamless CCS program, States 

should be provided the flexibility to obtain primacy for Class VI only. 

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

primacy approval process for states. EPA's willingness to accept independent primacy 

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

"partial primacy." It is very important to note that this shift in policy allowing for Class VI 

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

discourage applications for partial primacy for all other well types under Section 1422. 

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

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

Federal requirements (e.g., permitting, inspection, operation, monitoring, and recordkeeping 

requirements) provided in the final GS rule. EPA believes that existing programs can adapt their 

expertise to the new requirements for Class VI wells and will be able to develop a primacy 

application for Class VI wells under section 1422 of SDWA and ensure that their GS programs 

integrate into national climate change priorities and protect USDWs from endangerment. 

EPA recognizes that some states have already begun legislative efforts that are wider in scope 

than the Federal GS rule and believes that allowing Class VI primacy (independent of other well 

classes) may encourage states to take responsibility for implementation of a more comprehensive 

approach to managing CCS projects (e.g., capture, transportation, and geologic sequestration). 

Letter ID: 0241 Comment ID: 23224 Letter Lines: 35 to 46 

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: 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. 

This approach makes the most sense since enhanced recovery operations have 

proven successful at increasing and maximizing oil and gas recovery while 

successfully sequestering carbon dioxide. As long as production of oil and gas 

is occurring, it would be inefficient and confusing to change the rules and 

processes under which these wells are regulated. 

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. The Agency believes that the 

nature and risks of CO2 injection for the primary purpose of long term storage poses different 

2
risks than injection for the primary purpose of EOR, and therefore has developed new Class VI 

regulations to address these unique risks. For example, the volume of CO2 anticipated to be 

injected for long term storage is significantly greater than for EOR operations. Reservoir 

pressure conditions will also be different, with Class VI injection operations involving large 

volumes of CO2 and likely having higher pressures within their storage formations than Class II 

EOR projects. 

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

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

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

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

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

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

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

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

while allowing for site-specific flexibility. 

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: 0241 Comment ID: 23225 Letter Lines: 48 to 65 

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

Comment: 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. 

If a well has been utilized for injection and is properly constructed under 

existing regulations, it is constructed to prevent the migration of the 

injectate into a USDW. The demonstrated well performance is indicative that 

well construction is protective of USDWs. A review to verify the existing 

construction as protective is sufficient to grandfather the construction as 

protective as a Class VI injection well. 

4. Additionally, EPA seeks comment on how the grandfathering approach for 

existing wells may affect compliance with the other requirements in its 

3
proposal. EPA Notice 43502. 

See 3 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). 

Following re-permitting of the well as Class VI, 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: 0241 Comment ID: 23226 Letter Lines: 67 to 80 

Comment Code: 2163 1.6.3.1 Comments in favor of injection into unmineable coal seams 

Comment Code: 4430 2.4.4.3.3 Injection into coal seams above USDWs (seeking comment) 

Comment: 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. 

This arbitrary exclusion would eliminate a vast number of potential 

sequestration zones. Enhanced recovery operations above the lowermost USDW have 

been taking place for a very long time. Unmineable coals in North Dakota are 

found in high clay content glacial till which, if unfractured, serves as an 

excellent confining zone. Based upon carbon dioxide’s affinity to adhere to 

coals, it is unwise to arbitrarily eliminate a potentially large number of 

sequestration zones. Exclusion of these zones even in areas where other 

abundant supplies of freshwater are available may severely limit sequestration 

options. These situations are best handled locally where all of the pertinent 

regional geologic factors can be considered. 

Individual Response: EPA acknowledges that site-suitability for GS is dependent on a number 

of factors and that many formation types may be suitable for GS. The final GS rule does not 

preclude injection into unmineable coal seams (or any formation type) provided owners or 

operators can demonstrate that GS can be performed in a manner that protects USDWs from 

endangerment based on requirements under today’s rulemaking. The Agency anticipates that in 

the near-term, most GS in unmineable coal seams will continue to be experimental. Such projects 

may be permitted as Class V experimental technology wells if they are of an experimental nature 

(i.e., to test GS technologies and collect data). EPA will continue to review data on early GS 

projects, including those in unmineable coal seams, to determine whether the appropriate amount 

and types of information and documentation are required and being collected. EPA plans, every 

4
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. 

EPA recognizes that GS in unmineable coal seams has been the subject of less research than 

saline formations or depleted oil and gas reservoirs. However, EPA has examined select field 

projects involving injection into unmineable coal seams, including the Pump Canyon Site, near 

Archuleta, New Mexico. In the Notice of Data Availability and Request for Comment, EPA 

described research at the Pump Canyon site where the Southwest Partnership is studying CO2 

injection into deep, unmineable coal seams and performing a "seal analysis" of the ability of the 

Kirtland Formation to act as a barrier to the movement of CO2 or other reservoir fluids. EPA 

continues to follow this project, recently completed projects, and ongoing GS projects injecting 

into unmineable coal seams. Other coal seam injection projects are underway through the RCSPs 

in the Illinois Basin, Black Warrior Basin, and Central Appalachian Basin. 

EPA clarifies that the final rule requires that injection for GS be into non-USDWs below the 

lowermost USDW; however, owners or operators may apply for a waiver from this requirement, 

as described in §146.95. For more information, see the discussion of waivers in the preamble to 

the final rule. 

Letter ID: 0241 Comment ID: 23227 Letter Lines: 82 to 93 

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

USDW 

Comment: 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. 

This arbitrary exclusion would eliminate a vast number of potential 

sequestration zones. Enhanced oil and gas recovery operations above the 

lowermost USDW have been taking place for a very long time. Exclusion of these 

zones where other abundant supplies of freshwater are available may 

unnecessarily limit sequestration options. These situations are best handled 

locally where all the pertinent regional geologic factors can be considered. 

The buoyancy of carbon dioxide suggests this in an unnecessary restriction since 

it would move injectate away from the USDWs below the sequestration zone. 

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. 

5
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: 0241 Comment ID: 23228 Letter Lines: 95 to 110 

Comment Code: 1614 1.3.1.2 Impurities in captured CO2; purity standards for CO2 

Comment Code: 1630 1.3.3 RCRA/hazardous waste issues (seeking comment) 

Comment: 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. 

The presence of certain hazardous wastes should not preclude the overall carbon 

dioxide stream from injection into a sequestration zone. The process of 

removing the carbon dioxide and making it suitable for transportation and 

injection should render it relatively pure. The presence of impurities can be 

dealt with at a specific source and the overall waste stream certified for 

injection. If the well construction and geologic setting is suitable to confine 

the carbon dioxide stream and prevent its migration into a USDW, then certain 

impurities and/or hazardous wastes should be allowed. 

Individual Response: EPA recognizes 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. For this reason, 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 

6
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. 

EPA received many comments regarding the applicability of the RCRA regulations and statute to 

CO2 streams that are geologically sequestered under the final Class VI UIC well requirements. 

As a result, 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: 0241 Comment ID: 23229 Letter Lines: 112 to 130 

Comment Code: 1640 1.3.4 CERCLA issues (seeking comment) 

Comment: 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. 

Carbon dioxide should not be classified as a hazardous waste. Carbon dioxide is 

not hazardous or toxic under normal conditions. CERCLA liability will not only 

impact owners and operators of carbon dioxide sequestration projects, but also 

pore space owners. Subjecting pore space owners to CERCLA liability and joint 

and several liability under CERCLA will greatly hamper carbon dioxide 

sequestration projects. EPA should take the opportunity in this rulemaking to 

alleviate any CERCLA liability concerns. 

9. EPA also requests comment on other considerations associated with the 

presence of impurities in the CO2 stream related to CERCLA. EPA Notice 43504. 

CERCLA should not apply to carbon dioxide sequestration. EPA needs to provide 

assurances to facilitate carbon dioxide sequestration projects. 

Individual Response: EPA notes that the GS rule is not promulgated under the RCRA or 

CERCLA statutes, and further, the applicability of those statutes will not be determined under 

the SDWA or the terms of the GS rule, but rather according to those statutes themselves and any 

implementing regulations that may apply. To the extent the commenter is seeking interpretations 

7
of CERCLA or RCRA and its related provisions, such interpretations are beyond the scope of 

this rulemaking. 

EPA received many comments regarding the applicability of the RCRA regulations and statute to 

CO2 streams that are geologically sequestered under the final Class VI UIC well requirements. 

As a result, 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. 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. 

Letter ID: 0241 Comment ID: 23230 Letter Lines: 132 to 150 

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

(seeking comment) 

Comment: 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. 

Redundant confining zones should not be required. If the primary confining zone 

is adequate, by definition it is sufficient. If one sequestration site 

identifies one confining zone and another identifies multiples, it may lead to 

public confusion and lack of confidence in a site that only has one confining 

8
zone even though it is just as protective. 

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 

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: 0241 Comment ID: 23231 Letter Lines: 152 to 165 

Comment Code: 3320 2.2.1.2 Comments opposed to requiring computational models to 

delineate the AoR 

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

comment) 

Comment: 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. 

There is concern about the lack of information necessary to construct a valid 

model in areas where the sequestration zone has not been extensively studied. 

This lack of information may make modeling difficult or not very useful. Any 

modeling used should be re-examined and recalibrated over time with additional 

data gathered. Modeling should not be solely relied upon where real data offers 

a different view. Seismic and offset well data can help delineate the AOR. 

Individual Response: The Agency believes that AoR delineation using computational modeling 

that accounts for the multiphase flow of CO2 and native fluids (i.e., naturally occurring salty 

water), including density-driven flow (i.e., buoyancy), is necessary to ensure protection of 

USDWs from endangerment. The computational models used for this purpose are required to 

predict the fate of injected CO2 and changes in formation pressure. EPA believes that the 

requirements at 146.84(c)(1) to delineate the AoR using computational modeling are appropriate 

and encompass the significant processes that could affect the location of the CO2 plume and 

associated pressure front and has retained this in the final rule. 

9
EPA agrees that the modeling should be re-examined and recalibrated over time. The GS 

regulation at 146.84(e) also requires owners or operators to periodically reevaluate the AoR to 

incorporate monitoring and operational data. This process provides additional opportunities to 

verify that the models have accurately predicted movement of the CO2 plume and to make any 

needed adjustments to corrective action or monitoring at the site. 

Letter ID: 0241 Comment ID: 23232 Letter Lines: 167 to 187 

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

Comment: 12 In some cases, owners or operators may choose to use proprietary models 

(i.e., not available for free to the general public). EPA says it is aware that 

the use of proprietary codes may prevent full evaluation of model results (e.g., 

NRC, 2007). Several popular codes in the petroleum-reservoir engineering 

discipline are proprietary and owners or operators of particular sites may 

prefer to use these codes as they have previous experience with them, and they 

have been used in peer-reviewed studies to model CO2 sequestration. When using 

a proprietary model, owners or operators should clearly disclose the code 

assumptions, relevant equations, and scientific basis. EPA seeks comment on 

allowing the use of proprietary models for GS sites. EPA Notice 43507. 

The use of proprietary models is widely used and accepted in oil and gas 

reservoir simulation. These models are a logical fit to simulate carbon dioxide 

sequestration projects. These models are verified using a history-match. The 

regulatory agency responsible for monitoring carbon dioxide sequestration does 

not need access to the code in order to conduct or evaluate a history-match. A 

regulatory agency could conduct reservoir modeling using its own modeling 

software to compare. Elimination of these widely used and understood reservoir 

models would be unwise. The assumptions and equations used in the modeling 

along with a valid history match will provide the regulating authority the 

ability to assess the model’s accuracy. 

Individual Response: EPA agrees with commenters that available proprietary models may meet 

the complex needs for calculating the AoRs of GS sites, and shares their concern about the need 

to evaluate the inputs and assumptions used. EPA will allow the use of proprietary models in 

meeting the requirements for the GS regulation, as long as GS well operators using a proprietary 

model clearly disclose, to the Director's satisfaction, the code assumptions, relevant equations, 

and scientific basis. EPA adds that its Confidential Business Information requirements at 40 CFR 

144.5 will apply to the use of proprietary models. 

EPA acknowledges that several proprietary models are currently, successfully used by 

petroleum-reservoir engineering professionals as well as in peer-reviewed studies to model CO2 

sequestration. 

10
Letter ID: 0241 Comment ID: 23233 Letter Lines: 189 to 193 

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

comment) 

Comment: 13. EPA seeks comment on the applicability of computational fluid flow models 

for delineating the AoR of GS sites. EPA Notice 43507. 

The use of computational flow models is appropriate, however; modeling should 

not be the sole criteria to determine the AOR if actual measured data exists. 

Individual Response: EPA agrees that a detailed geologic assessment is essential to evaluating 

the presence and adequacy of a proposed site to receive and confine the CO2. The AoR and 

corrective action plan required at §146.84(b) must describe the site characterization data on 

which the model will be based. The Director has discretion to require the use of existing data if it 

is not initially included. 

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). 

The Agency believes that predicting the complex multiphase buoyant flow of the CO2, coinjectates, and compounds that may be mobilized due to injection requires the sophistication of 

computational models. Models can predict CO2 fate and transport, as well as changes in 

formation pressure, in three dimensions, as a function of time in order to delineate the subsurface 

storage site and the AoR. Models can account for site-specific and predicted operating conditions 

as well as geologic heterogeneities and potential migration through faults, fractures, and artificial 

penetrations. 

Letter ID: 0241 Comment ID: 23234 Letter Lines: 195 to 201 

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

Comment: 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. 

It is appropriate to reevaluate the AOR on a periodic basis. The conditions and 

frequency under which the AOR is reevaluated should be based upon monitoring. 

Individual Response: EPA agrees that site-specific factors, including monitoring data, should 

11
be considered in the reevaluation schedule, and notes that the AoR and corrective action plan 

must specify the site-specific monitoring and operational conditions that warrant reevaluation, as 

specified in §146.84(b)(2)(ii). In addition, the Director has discretion to require more frequent 

AoR reevaluation if he or she has reason to believe, based on site-specific information, that a 

five-year reevaluation schedule is not sufficiently protective of USDWs. However, EPA believes 

that setting a minimum reevaluation frequency is appropriate. In the final rule, the Agency 

changed the minimum frequency for the AoR reevaluation at §146.84(e) from 10 years to 5 years 

in the final GS rule. EPA believes that this revised frequency addresses commenters' concerns 

about the inherent uncertainties in modeling CO2 movement, the emerging nature of GS 

technology, risk-based targeting of monitoring activities, and the unique nature of CO2 GS. 

Letter ID: 0241 Comment ID: 23235 Letter Lines: 203 to 217 

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

Comment: 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. 

A phased approach is appropriate. Corrective action for some aspects of the 

project may not be necessary at the outset and a phased approach would allow an 

operator to optimize capital expenditures to make a project more feasible. 

Wholesale corrective action at the outset of a project may ultimately result in 

corrective action in areas unaffected by the project. In addition, the 

procurement of rigs and other equipment and the time necessary to conduct 

corrective actions in areas that might not be affected for a significant period 

of time could unnecessarily delay a sequestration project. 

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. EPA clarifies that all wells in the AoR of a GS project that need corrective action 

must receive it at some point. 

Regarding the comment that some wells identified in the original AoR ultimately may not be 

affected by the storage project, EPA clarifies that, if monitoring or modeling data indicate a 

change in the AoR, the owner or operator would need to review and amend the AoR and 

corrective action plan and follow the amended plan. 

12
Letter ID: 0241 Comment ID: 23236 Letter Lines: 219 to 230 

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

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

USDW 

Comment: 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. 

Requiring setting surface casing below the lowermost USDW would preclude 

injection above the lowermost USDW, which as earlier stated, would eliminate a 

vast number of potential sequestration zones. Enhanced recovery operations 

above the lowermost USDW have been taking place for a very long time. Exclusion 

of these zones where other abundant supplies of freshwater are available may 

unnecessarily limit sequestration options. These situations are best handled 

locally where the regional geologic factors can be considered. Setting the 

surface casing below the lowermost USDW may not be technically feasible. 

Individual Response: EPA disagrees that the surface casing requirements in the GS rule 

preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface 

casing extend through the base of the lowermost USDW and be cemented to the surface through 

the use of a single string or multiple strings of casing and cement. It does not, however, specify 

how cementing must be accomplished, and it allows the owner or operator to propose alternate 

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

protected from endangerment. EPA notes that there are many potential ways to meet the 

requirement, such as the use of staged cementing. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

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

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

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

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

USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS 

rule for additional information. 

EPA stresses that protection of USDWs from endangerment, regardless of their depth or the 

number of USDWs in an area, 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, 

the activity will not be allowed under UIC requirements or the SDWA. 

Letter ID: 0241 Comment ID: 23237 Letter Lines: 231 to 233 

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

13
Comment: Cementing of the long-string casing to surface may not be desirable in all 

situations; an annulus that can be monitored may be desirable. The long-string 

casing should be cemented to at least above the upper confining zone. Requiring 

Individual Response: EPA does not believe that the cementing requirements at §146.86 would 

prevent monitoring, operation and remediation of Class VI wells. Cementing of deep wells has 

been performed successfully in the past by owners or operators of Class I hazardous and Class I 

municipal waste disposal wells. Some of these wells, which must meet the same cementing and 

casing requirements as Class VI wells, are up to 12,000 feet deep and have been successfully 

cemented in a manner that maintains integrity and allows for all required well testing, operation, 

and remediation (EPA, 2001). See the discussion of Class VI well construction requirements in 

the preamble to the final GS rule for additional information. Additionally, EPA is developing 

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

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

Letter ID: 0241 Comment ID: 23238 Letter Lines: 233 to 234 

Comment Code: 3826 2.3.1.3 Packer requirements (seeking comment) 

Comment: casing should be cemented to at least above the upper confining zone. Requiring 

the packer be set opposite a cemented interval is appropriate. 

Individual Response: EPA agrees that the use of tubing and packer in accordance with 

§146.86(c) will offer the best multiple-barrier protection of USDWs from endangerment. This 

requirement is retained in the final 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: 0241 Comment ID: 23239 Letter Lines: 236 to 246 

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

Comment: 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. 

If a well has been utilized for injection and is properly constructed under 

existing regulations, it is constructed to prevent the migration of the 

injectate into a USDW. The demonstrated well performance is indicative that it 

is protective of USDWs. A review to verify the construction is sufficient to 

grandfather the construction as protective as a Class VI injection well. 

Additional realistic remedial actions short of new construction could be 

required to make the well more protective. 

14
Individual Response: As described above, EPA agrees that many Class I, Class II, and Class V 

experimental technology wells are designed and constructed to withstand exposure to CO2. The 

final GS rule provides for the construction of these wells to be grandfathered per §146.81(c), 

provided the owner or operator can demonstrate to the Director that the wells were engineered 

and constructed to meet the requirements at §146.86(a) and ensure protection of USDWs, in lieu 

of requirements at §146.86(b) and §146.87(a). EPA clarifies that only the construction 

requirements are grandfathered and that all other Class VI requirements (reporting, monitoring, 

mechnical integrity testing, etc.) must be met following a determination under §146.81(c). 

Letter ID: 0241 Comment ID: 23240 Letter Lines: 248 to 256 

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

Comment: 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. 

Horizontal wells should be allowed. The drilling of these wells has become 

common in certain basins. Their use would maximize injection while minimizing 

the surface footprint and injection pressure. Well construction requirements 

should be similar to vertical wells i.e., the vertical portion of the well 

should be cemented to above the upper confining zone. 

Individual Response: In this 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: 0241 Comment ID: 23241 Letter Lines: 258 to 268 

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: 19. EPA seeks comment regarding requirements for degradation-resistant well 

construction materials, such as acid-resistant cements and corrosion resistant 

casing. EPA Notice 43510. 

Based upon history in carbon dioxide injection projects, construction 

requirements should be based upon actual needs as identified in these projects 

15
and upon actual subsurface conditions. Industry experience with carbon dioxide 

EOR projects supports the use of conventional tubing, casing, and cements. 

These wells have been demonstrated to protect USDWs. Corrosion mitigation 

measures such as lined tubing, use of corrosion inhibitors, and proper 

dehydration of carbon dioxide provide adequate protection. 

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. The rule 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). 

EPA believes, however, that casings and cement and other materials used must have sufficient 

strength and be designed for the life of the sequestration project. That is, corrosion mitigation 

measures, as suggested by the commenter, alone are not sufficient to protect USDWs. For this 

reason, the rule requires that materials meet standards established in the rule and be compatible 

with fluids with which the materials may be expected to come into contact. 

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: 0241 Comment ID: 23242 Letter Lines: 270 to 277 

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

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

comment) 

Comment: 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. 

Hydraulic fracturing should be allowed as long as it does not compromise the 

confining zone. Computer modeling to predict the fracture growth can be 

utilized in fracture stimulation design. 

Individual Response: EPA agrees that stimulation, such as hydraulic fracturing should be 

permitted in some situations, and the final rule allows the use of hydraulic fracturing at GS sites, 

where approved by the Director. Hydraulic fracturing is one of several stimulation technologies 

available to improve wellbore and formation injectivity. EPA clarifies that fracturing is permitted 

during stimulation, but not during injection. During injection, the injection pressure must not 

16
exceed 90 percent of the fracture pressure, as specified in §146.88(a). 

All stimulation, including hydraulic fracturing, must be approved by the Director. Owners or 

operators must submit a proposed stimulation program as part of the permit application under 

§146.82(a)(9); the plan must demonstrate that any stimulation activities will not compromise the 

integrity of the confining zone. The Director will evaluate the owner or operator's proposed 

stimulation plan in the context of all information about the site, and the owner or operator must 

perform stimulation only as approved. It is possible that computer simulations may support this 

determination to the Director's satisfaction. EPA clarifies that all data submitted with the permit 

application, including modeling of the AoR, will inform the Director's decision on whether 

hydraulic fracturing is acceptable at a GS site. 

Letter ID: 0241 Comment ID: 23243 Letter Lines: 279 to 286 

Comment Code: 4140 2.4.1.4 Use of fracturing for GS in specific geologic settings (seeking 

comment) 

Comment: 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. 

This type of information needs to be obtained from industry. Many basins have 

implemented hydraulic fracturing of certain formations for a number of years. 

These situations are best handled locally where the regional geologic factors 

can be considered. 

Individual Response: EPA clarifies that all stimulation, including hydraulic fracturing, must be 

approved by the Director based on site-specific information. 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. 

The final rule at §146.91(d)(2) also requires that the owner or operator notify the Director 30 

days before performing stimulation during the operational phase of a GS project; this will 

provide an additional opportunity for the Director to review the owner or operator's plans for 

stimulation and add other requirements as needed. EPA clarifies that UIC regulations prohibit 

fracturing of the confining zone at any time during injection or stimulation. 

Letter ID: 0241 Comment ID: 23244 Letter Lines: 288 to 296 

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

Comment: 22. EPA seeks comment on the merits of requiring down-hole shut-off valves in GS 

17
wells. EPA Notice 43511. 

Requiring down-hole shut-off valves may be problematic. To protect the entire 

tubing-casing annulus they would need to be installed at or below the injection 

packer. This may make the tool prone to failure. These valves may restrict or 

preclude the running of down hole monitoring or logging tools. Inclusion of a 

seating nipple directly above the injection packer which would allow the 

installation of a wire line set plug may be more appropriate. 

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

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

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

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

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

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

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

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

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

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

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

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

subsurface fluid movement and ensure protection of USDWs. 

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. 

Letter ID: 0241 Comment ID: 23245 Letter Lines: 298 to 315 

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

USDW 

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

USDWs in certain circumstances 

Comment: 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. 

18
Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may severely limit sequestration options. These situations are best 

handled locally where other regional geologic factors can be considered. 

Demonstration that the upper and lower confining zones are adequate to prevent 

migration should be sufficient. The fact that the carbon dioxide plume is 

buoyant will protect any deeper USDW. 

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. The 

final rule also establishes limited circumstances under which expansions of the areal extent of 

aquifer exemptions may be granted for owners or operators of Class II EOR/EGR wells 

transitioning to Class VI injection for GS. 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 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., 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: 0241 Comment ID: 23246 Letter Lines: 317 to 332 

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

USDW 

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

USDWs in certain circumstances 

19
Comment: 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. 

Injection into a formation above the lowermost USDW should be allowed. As 

commented earlier, if injection above the lowermost USDW is not allowed it would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may severely limit sequestration options. These situations are best 

handled locally where other regional geologic factors can be considered. 

Demonstration that the upper and lower confining zones are adequate to prevent 

migration should be sufficient. The fact that the carbon dioxide plume is 

buoyant will protect any deeper USDW. 

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: 0241 Comment ID: 23247 Letter Lines: 334 to 339 

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

circumstances 

Comment: 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. 

Aquifer exemptions should be allowed pursuant to existing requirements in other 

injection well classes. 

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. 

20
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: 0241 Comment ID: 23248 Letter Lines: 341 to 349 

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

Comment: 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 not be a minimum injection depth. The determining factor should be 

whether the project will be protective of USDWs. A minimum depth requirement 

suggests a requirement to inject carbon dioxide in a supercritical phase. This 

is not appropriate since there may be projects where injection of carbon dioxide 

in other phases is the most effective option. 

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. 

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: 0241 Comment ID: 23249 Letter Lines: 351 to 360 

Comment Code: 4490 2.4.5 Use of tracers and potential impact on human health or ecosystems 

21
(seeking comment) 

Comment: 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. 

Discretion on whether to use a tracer is appropriate. Radioactive tracers have 

been successfully utilized in oil and gas operations. The small amount used 

should not threaten human health or USDWs. However, modeling and monitoring are 

generally more appropriate techniques to track a plume since tracers have a 

limited radius of investigation. 

Individual Response: EPA believes that, in some circumstances, tracers can be an important 

component of a multifaceted approach to monitoring GS projects. However, the Agency 

recognizes that tracers may not be appropriate in all GS projects. For this reason, EPA does not 

require the use of tracers at all GS sites; however, the Director has discretion to require their use 

if he/she determines that the use of tracers could improve monitoring of the site and enhance 

USDW protection from endangerment. 

While the intent of the GS regulations is to prevent leaks of CO2 to USDWs, EPA clarifies that 

all of the protective components of the regulation, including a comprehensive monitoring 

program per §146.90 (which includes testing of the well, ground water quality monitoring, and 

tracking of the CO2 plume and pressure front) support a multi-barrier approach to protecting 

USDWs. Additionally, some studies (e.g., Phelps and Cole, 2008; Hovorka et al., 2004; 

McCallum et al., 2005) found that tracers can provide useful CO2 monitoring information at 

injection wells both at depth and at near-surface locations. At Frio, tracers enabled quantification 

of CO2 plume behavior and provided a technique for model validity testing (McCallum et al., 

2005). EPA will continue to track research related to tracer use. 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: 0241 Comment ID: 23250 Letter Lines: 362 to 371 

Comment Code: 4543 2.5.2.1 MIT procedures and methods for GS (seeking comment) 

Comment: 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. 

The monitoring of this data is appropriate. Continuous monitoring should be 

clarified as daily for most applications. This could be more stringent or 

22
frequent on a case-by-case basis. 

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

demonstrating internal mechanical integrity (MI), and that continuous pressure monitoring of 

Class VI wells is appropriate. EPA disagrees with the suggested changes, however. 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 (e.g., more frequently than daily) and record them 

electronically in a computer system. 

Continuous monitoring was found to be very important in an EPA study of UIC Class I internal 

MIT failure rates and causes (USEPA 1993). The study reviewed MIT results over a 5 year 

period and found 135 MIT failures in 428 wells (a single well can have more than one MIT 

failure). In all cases, the MIT failures were found through continuous annulus monitoring which 

served the important role of an early warning to prevent any well failure. 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 and record them electronically in a computer system. §146.91(a)(2) requires 

that monthly averages of the continuous annulus monitoring be reported on a semiannual basis. 

Letter ID: 0241 Comment ID: 23251 Letter Lines: 373 to 381 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: 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. 

A five-year frequency to conduct and review internal and external mechanical 

integrity is appropriate. A standard pressure test utilizing a fluid compatible 

with the annular fluid is widely practiced but other methods should be 

available. More frequent testing or review could be required based upon 

specific factors. 

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. 

23
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 clarifies that internal MI must be demonstrated through continuous pressure monitoring 

under §146.89(b); EPA believes this is superior to an annual annulus pressure MIT, given the 

unique properties of CO2 injection 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: 0241 Comment ID: 23252 Letter Lines: 383 to 390 

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

Comment: 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. 

Monitoring of the carbon dioxide plume is appropriate however caution is advised 

with respect to requiring monitoring wells since these may provide a conduit for 

unwanted migration. 4D seismic and predictive models will improve over time due 

to iterative processes. 

Individual Response: To mitigate the risk of fluid movement, EPA requires owners and 

operators to submit a testing and monitoring plan that describes how the owner or operator plans 

to site and construct monitoring wells. 

EPA believes, however, that monitoring using wells in the injection zone, e.g., for pressure 

monitoring as required at §146.90(g)(1), can be safely performed if the wells are constructed to 

prevent flow between the injection zone and USDWs or other layers above the confining zone. 

Such construction technologies exist and have been used in the oil and gas industry for years. 

EPA believes that properly constructed monitoring wells will be a safe way to obtain the data 

that is essential to ensure that the injected CO2 remains confined in the injection zone and that 

pressure changes are not causing movement of formation or other fluids. EPA is developing 

guidance on well construction that will include recommendations for monitoring well 

construction. The guidance will be available on EPA’s website at 

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

EPA is developing guidance on testing and monitoring to assist owners or operators and 

24
Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

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

Letter ID: 0241 Comment ID: 23253 Letter Lines: 392 to 397 

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

Comment: 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. 

An initial pressure fall-off test could be required and subsequent tests 

required at the time the AOR is reevaluated. 

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 adds that this frequency is 

the same as that required for AoR reevaluations. 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. 

Letter ID: 0241 Comment ID: 23254 Letter Lines: 399 to 407 

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

Comment: 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. 

Tracking the plume and pressure front will allow for verification of the 

reservoir model. Pressure transient testing and seismic techniques may be 

useful alternatives. 

Individual Response: 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 

25
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 is affording Director's discretion regarding the use of 

geophysical techniques at some sites because the Agency recognizes that geophysical methods 

are not appropriate in all geologic settings. EPA clarifies that this determination will be made by 

the Director based on the site-specific geologic information submitted by the owner or operator 

with their permit application. 

EPA believes that this approach provides flexibility to develop a site-specific monitoring plan, 

ensures that direct monitoring is available to track the movement of the CO2 and validate 

models, and recognizes that indirect techniques are not appropriate in all situations. The owner or 

operator's approved testing and monitoring plan will include the site-specific details, 

technologies, testing and monitoring frequencies, and other pertinent information. 

Letter ID: 0241 Comment ID: 23255 Letter Lines: 409 to 417 

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

comment) 

Comment: 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 should be determined on a site-specific basis and be based 

upon potential risks posed by the project and the cost versus benefit of 

monitoring. 

Individual Response: EPA agrees that monitoring plans and methods need to be site-specific 

and believes that the monitoring requirements for GS sites at §146.90 provide an appropriate 

level of flexibility in structuring a testing and monitoring plan that protects USDWs from 

endangerment. 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 sitespecific information such as the calculated AoR, injection rate and volume, site geology, baseline 

data, and the presence of artificial penetrations within the AoR. EPA believes that this is the best 

approach for addressing potential risks at GS sites. 

EPA recognizes that installation of monitoring wells entails additional resources. However, the 

Agency believes that such monitoring is necessary to ensure that GS projects are appropriately 

operated and monitored and to protect USDWs from endangerment. 

Although a significant cost in absolute terms, monitoring costs are expected to be a small 

fraction of site operating costs, according to EPA's cost analysis for the GS rulemaking (which is 

26
available in the docket). While the rule requirements will necessitate additional costs, the 

requirements are guided by the necessity to address the unique challenges posed by CO2 

injection (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) as they protect USDWs from endangerment. 

The UIC requirements are designed to ensure that where GS is employed, it is done in a manner 

that protects USDWs from endangerment, consistent with the UIC Program's authority under 

SDWA. 

EPA is developing guidance on testing and monitoring to assist owners or operators and 

Directors in evaluating requirements under §146.90, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

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

Letter ID: 0241 Comment ID: 23256 Letter Lines: 419 to 432 

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: 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 postinjection site care and site closure plan. EPA seeks comment on the merits of 

requiring plans for monitoring, AoR, and post-injection site care as part of a 

permit application. EPA Notice 43517. 

Allowing for different plans would be much more effective than prescriptive 

regulations; however, a plan modification should not be considered a major 

permit modification. Caution needs to be taken when monitoring the injection 

formation due to the artificial penetration of the confining zone to gain data. 

The number of monitoring wells should be decided on a case-by case basis. It is 

unclear how monitoring wells will be regulated since they are not injection 

wells. The timing of plan submittal should be linked to the activity being 

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 site27
specific information as the testing and monitoring plan is developed. 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 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 5 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 

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, 

including: alterations or additions to the facility; availability of additional information; new 

regulations; and compliance schedule modifications. 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). These include correction of typographical 

errors; more frequent monitoring or reporting; changes in an interim compliance date; changes in 

ownership or control of a facility; changes in the quantities or types of fluids injected which are 

within the capacity of the facility; changes in construction requirements; or amendments to a 

plugging and abandonment plan. In the final rule, EPA added a subparagraph (h) to §144.41 that 

would include minor amendments (e.g., to clarify, correct, or update) 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, including proposed monitoring plans. The 

guidance describes available technologies and recommended approaches for implementing a 

testing and monitoring plan, including pre-operational geophysical logging and testing of 

injection wells, MITs, injection well testing during operation, groundwater quality monitoring, 

tracking the CO2 plume and pressure front, and soil gas and surface air monitoring which may 

be required by the UIC Director for specific GS projects. The guidance can be found on EPA’s 

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

28
Letter ID: 0241 Comment ID: 23257 Letter Lines: 432 to 435 

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: wells. The timing of plan submittal should be linked to the activity being 

addressed. Site closure plans, post-closure plans, well plugging plans, etc., 

should not be required many years in advance since conditions, understanding of 

the sequestration zones, and technology change over time. 

Individual Response: EPA disagrees with the commenter's assertion that that the timing of plan 

submittals should be linked to the specific activity being addressed, and believes that submittal 

and review of each of the owner or operator's plans required at §146.82 at the time of the permit 

application is necessary for the Director to make a permit approval determination. While 

injection well plugging, post-injection site care and site closure will likely not occur for years 

after injection commences, the Director needs to have assurance that the owner or operator has 

planned for these events. 

Letter ID: 0241 Comment ID: 23258 Letter Lines: 437 to 441 

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

Comment: 35. EPA seeks comment on the frequency of all proposed reporting requirements. 

EPA Notice 43517. 

Reporting frequency should coincide with requirements for existing UIC injection 

well classes unless there is a need for more frequent reporting. 

Individual Response: EPA clarifies that reporting requirements for existing injection wells vary 

by well class. The Agency believes semi-annual reporting is appropriate for Class VI GS wells 

during the operational phase of the project. EPA believes that the potentially large injection 

volumes and injection pressures associated with GS warrant more frequent reporting than for 

other well classes. See the final rule and preamble for further discussion on EPA's final approach 

to reporting and recordkeeping. 

EPA is using an adaptive approach to regulating GS. 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: 0241 Comment ID: 23259 Letter Lines: 443 to 448 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

29
Comment: 36. EPA seeks comment on the requirement for electronic reporting in its 

proposed rule. EPA Notice 43518. 

Electronic reporting should not be required. State systems may already be in 

place to collect data but may not be compatible with sending or receiving 

systems. 

Individual Response: EPA believes that electronic formatting is the most appropriate format for 

submitting Class VI project information to the Director, and based on comments received on the 

proposed rule, the majority of Class VI well owners or operators will have the capability to 

report electronically, and requires this at §146.91(e). 

Acknowledging that some States may have to develop electronic data systems to receive 

electronic information from the owner or operator, and that many States which already have 

electronic data systems will have to make changes to accommodate a new class of UIC well 

(Class VI), EPA believes that it is prudent to provide assistance by developing a central 

framework for the electronic system that will be used by States to gather and track owner or 

operator data. This will enable owners or operators to submit data without having to wait for a 

State to develop a system. It will also provide for standardized submissions across the country 

and enable States to focus State resources on reviewing and approving permit applications rather 

than building or upgrading separate, independent databases for GS information. 

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional 

data management needs associated with GS activities and provides recommended guidelines on 

the types of data to be collected for tracking GS projects, reporting to EPA for compliance 

tracking, and transfer of data to EPA's GS data system. The recordkeeping and reporting 

guidance will be available on EPA's web site, at 

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

Letter ID: 0241 Comment ID: 23260 Letter Lines: 450 to 459 

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

Comment: 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. 

During the active injection phase of a project, reports and frequencies similar 

to those which exist in other UIC classes should be sufficient. Once active 

injection ceases, an annual report may be appropriate. 

Individual Response: EPA clarifies that reporting requirements for existing injection wells vary 

by well class. The Agency believes semi-annual reporting is appropriate for Class VI GS wells 

30
during the operational phase of the project. EPA believes that the potentially large injection 

volumes and injection pressures associated with GS warrant more frequent reporting than for 

other well classes. EPA adds, at §146.93(a)(2)(iv), that reporting during the post-injection site 

care timeframe would be at the frequency described in the approved post-injection site care and 

site closure plan. For additional information, please see the final rule and the preamble for a 

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

Letter ID: 0241 Comment ID: 23261 Letter Lines: 461 to 469 

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: 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. 

A performance-based time period is appropriate rather than a fixed timeframe. 

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 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 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. 

31
Letter ID: 0241 Comment ID: 23262 Letter Lines: 471 to 475 

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: 39. EPA is requesting comments on the proposed requirements for well plugging, 

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

for the post-injection time period. EPA Notice 43520. 

A performance-based time period is appropriate rather than a fixed timeframe. 

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 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 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: 0241 Comment ID: 23263 Letter Lines: 477 to 482 

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

Comment: 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. 

32
A performance-based time period is appropriate rather than a fixed timeframe. 

Individual Response: The PISC requirements in the final GS rule, as specified in §146.93(b), 

incorporate a combination of a fixed timeframe and a performance standard approach. EPA 

believes that a default PISC timeframe of 50 years, with Director's discretion to shorten or 

lengthen this timeframe, combined with a site-specific Director’s discretion to create an 

alternative PISC time frame, ensures that USDWs are protected. 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 PISC period based on sitespecific data, pursuant to requirements at §146.93(b); or (2) affording the Director discretion to 

allow a Class VI well owner or operator to demonstrate, based on substantial data during the 

permitting process, that an alternative PISC timeframe may be appropriate if it ensures nonendangerment 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: 0241 Comment ID: 23264 Letter Lines: 484 to 494 

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

CFR 146.85) 

Comment: 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. 

The pay-in period should coincide with the estimated risk. 

33
Individual Response: EPA acknowledges that there may be several possible approaches to 

setting pay-in periods for trust funds. The final rule requires that the Director approve the use 

and length of pay-in periods. EPA is developing guidance (available on EPA's website at 

http://water.epa.gov/type/groundwater/uic/wells_sequestration.cfm) that describes the types of 

financial instruments that owners or operators can use to meet financial responsibility 

requirements for GS wells. Specifically, the guidance will discuss pay-in periods and provide 

guidance for Directors to use in determining an appropriate pay-in period. EPA adds that owners 

or operators may choose from a variety of financial instruments to meet their financial 

responsibility obligations. See the final rule and preamble for further discussion of EPA's final 

approach to financial responsibility. 

Letter ID: 0241 Comment ID: 23265 Letter Lines: 496 to 506 

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

CFR 146.85) 

Comment: 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. 

Financial assurance should be left to state lawmakers and the regulating agency 

and should not be a prescribed mechanism. 

Individual Response: Regarding the suggestion that financial assurance requirements be left to 

the states, EPA notes that it is providing consistency nationwide by requiring that any state that 

wishes to assume primacy for Class VI wells would need to demonstrate that its financial 

responsibility requirements are at least as stringent as the minimum federal requirements at 

§146.85. EPA does not believe that the final rule is prescriptive; rather it is flexible in order to 

tailor the regulations to the unique characteristics of long term storage of CO2. 

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 obligations, provided the Director determines that the owner or 

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. See the final rule and preamble for 

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

34
Letter ID: 0241 Comment ID: 23266 Letter Lines: 508 to 516 

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

comment) 

Comment: 43. EPA is assessing whether a financial ratings threshold for all companies 

using a self-guarantee, similar to those used by other Federal agencies, is 

appropriate. The Agency also is considering what constitutes an appropriate 

financial rating threshold, and whether a financial rating greater than BBB or 

Baa (i.e., the current rating threshold established under the UIC regulations) 

is appropriate for GS wells. EPA Notice 43522. 

Financial assurance should be left to state lawmakers and the regulating agency 

and should not be a prescribed mechanism. 

Individual Response: EPA disagrees that the GS rule is overly prescriptive; rather it offers an 

adaptive and flexible approach that will be best for purposes of addressing the variety of sitespecific circumstances to be encountered in GS projects. Furthermore, EPA notes that it is 

providing consistency nationwide by requiring that any state that wishes to assume primacy for 

Class VI wells demonstrate that its financial responsibility requirements are at least as stringent 

as the minimum federal requirements at §146.85. 

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

Additionally, 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: 0241 Comment ID: 23267 Letter Lines: 518 to 525 

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

comment) 

Comment: 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 

35
to the financial responsibility mechanisms should be considered, all subject to 

EPA’s authority under the SDWA. EPA Notice 43522. 

Financial assurance should be left to state lawmakers and the regulating agency 

and should not be a prescribed mechanism. 

Individual Response: EPA agrees that it is appropriate to allow a flexible approach for financial 

responsibility; however, EPA believes that a minimum framework for financial responsibility is 

necessary. Under the final GS rule 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)). 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)). 

EPA is developing guidance (available on EPA's website at 

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

Letter ID: 0241 Comment ID: 23268 Letter Lines: 527 to 532 

Comment Code: 5436 2.9.1.3 Allowing separate financial demonstrations for plugging and 

abandonment and post-injection site care (seeking comment) 

Comment: 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. 

This seems a sensible approach however; financial assurance should be left to 

the regulating agency and not prescribed. 

Individual Response: EPA will allow owners or operators to use separate financial 

responsibility instruments for well plugging and site closure. However, owners or operators must 

demonstrate adequate financial responsibility for all required activities with their permit 

applications, per §146.82(a)(14), and financial responsibility will need to be reevaluated prior to 

well plugging or site closure, or at any other time deemed appropriate by the Director. EPA 

believes this is necessary to ensure that resources are available to prevent the endangerment of 

USDWs in the event that the owner or operator experiences financial difficulties at any time 

during the life of the GS project. 

Regarding the suggestion that financial assurance requirements be left to the states, EPA notes 

that it is providing consistency nationwide by requiring that any state that wishes to assume 

primacy for Class VI wells would need to demonstrate that its financial responsibility 

requirements are at least as stringent as the minimum federal requirements at §146.85. EPA does 

not believe that the final rule is prescriptive; rather it is flexible in order to tailor the regulations 

to the unique characteristics of long term storage of CO2. 

36
Letter ID: 0241 Comment ID: 23269 Letter Lines: 534 to 542 

Comment Code: 5520 2.10.1 Appropriateness of existing public participation requirements 

(Part 25 and Part 124) for GS (seeking comment) 

Comment: 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. 

Public participation requirements should be left to the regulating agency and 

not prescribed. Requirements could mirror the agency’s existing public notice 

and participation requirements. 

Individual Response: EPA agrees that the existing UIC public participation requirements as 

specified in 40 CFR 25 and 40 CFR 124 are appropriate for GS projects. In addition, because of 

the unique nature of GS projects, and the anticipated level of public interest in GS projects, EPA 

encourages (but does not require) 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 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: 0241 Comment ID: 23270 Letter Lines: 544 to 552 

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

Comment: 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. 

Public participation requirements should be left to the regulating agency and 

not prescribed. The applicant should be allowed to do some site 

characterization to assess site suitability and project feasibility before the 

public is engaged. Requirements could mirror the agency’s existing public 

notice and participation requirements. 

Individual Response: EPA believes that the existing UIC public participation requirements as 

37
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 

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

Letter ID: 0241 Comment ID: 23271 Letter Lines: 554 to 563 

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

Comment: 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. 

Partial primacy should be granted for Class VI wells independently of other well 

classes and through a process similar to granting primacy under existing UIC 

classes, allowing the states to determine the appropriate regulating agency. 

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. 

Letter ID: 0241 Comment ID: 23272 Letter Lines: 565 to 576 

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

Comment: 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. 

38
Partial primacy should be granted for Class VI wells independently of other well 

classes allowing the states to determine the appropriate regulating agency. 

This will encourage states to apply for 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. 

Letter ID: 0241 Comment ID: 23273 Letter Lines: 578 to 583 

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

comment) 

Comment: 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. 

This will reduce administrative burdens that would yield little or no 

environmental benefit. 

Individual Response: 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 once every 5 years to 

determine whether it should be modified, revoked and reissued, terminated or a minor 

modification made as provided in §§144.39, 144.40, or 144.41. The Director’s review will be 

informed by the owners’ or operators’ iterative reevaluation of the project. Specifically, the final 

rule includes a requirement that the AoR be reevaluated at least every five years, and also 

requires owners or operators to review and update the AoR and corrective action plan, the testing 

and monitoring plan, and the emergency and remedial response plan throughout the life of the 

project (146.84(e), 146.90(j), and 146.94(d)). Owners or operators must review each plan and 

identify necessary amendments or demonstrate to the Director that no amendment is needed. In 

no case can reviews occur less often than once every five years. The iterative process and 

subsequent plan reevaluations ensure that time and resources are committed to the most critical 

aspects of the permit in preventing endangerment to USDWs. 

Letter ID: 0241 Comment ID: 23274 Letter Lines: 585 to 594 

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

comment) 

Comment: 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 

39
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. 

The number of monitoring wells required will be very site specific. 

Individual Response: EPA agrees 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. 

EPA is developing guidance on monitoring and testing to assist owners or operators and 

Directors in evaluating requirements under §146.90, including developing determining the 

appropriate number of monitoring wells for a GS site. This guidance will be available on EPA’s 

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

Letter ID: 0241 Comment ID: 23275 Letter Lines: 596 to 603 

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

Comment: 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. 

40
There are no known unique characteristics of carbon dioxide injection or its 

potential impacts on USDWs that have not been addressed within existing UIC 

rules or found in current carbon dioxide injection projects. 

Individual Response: EPA is funding research related to the potential for USDW contamination 

associated with GS projects. In addition, the Agency is tracking external research that focuses on 

potential exceedances of drinking water standards, which were developed by EPA and take into 

account impacts on children's health. 

In the August 31, 2009, Notice of Data Availability (NODA) and Request for Comment (74 FR 

44802), EPA published the results of a study in which Lawrence Berkeley National Laboratory 

(LBNL) evaluated the potential for GS to cause changes in ground water quality as a result of 

CO2 leakage and subsequent mobilization of trace elements such as arsenic, barium, cadmium, 

mercury, lead, antimony, selenium, zinc, and uranium (Birkholzer et al., 2008a). LBNL 

estimated the amount of trace elements from native mineral species that could potentially be 

mobilized by the intrusion of CO2 and the potential ground water concentrations that could result 

to determine the potential for drinking water standards to be exceeded. EPA has also examined 

potential methods for conducting treatment of water affected by a CO2 leak; this study is 

presented in the final rulemaking docket. 

EPA continues to fund research in this area. In December 2009, EPA's Office of Research and 

Development (ORD) awarded a Science to Achieve Results (STAR) grant to Clemson University 

to investigate the potential for GS to affect USDWs. This research will involve laboratory 

experiments and modeling simulations to investigate the fate of dissolved CO2 in underground 

geologic formations and to determine possible risks associated with the dissolution of CO2 in 

underground aquifers. This STAR Grant is among six such grants awarded to major universities 

and institutions focusing on: "Integrated Design, Modeling and Monitoring of Geologic 

Sequestration of Anthropogenic Carbon Dioxide to Safeguard Sources of Drinking Water." 

EPA clarifies that the purpose of the GS rule is to protect USDWs from endangerment through 

permitting, siting, construction, operation, injection, and post-injection site care and site closure 

requirements that are tailored to address the unique nature of GS. The Class VI requirements, 

therefore, minimize health risks to all populations, including children. The "Risk and Occurrence 

Document for the Geologic Sequestration Rulemaking," available in the rulemaking docket, 

presents a broad discussion of risks to human health and the environment associated with GS, 

including those addressed under SDWA authority and those environmental and human health 

impacts that are beyond the scope of the SDWA. 

As part of its adaptive rulemaking approach, EPA plans to collect and review available 

information such as the research described above and data every six years on early GS projects, 

including impacts to USDWs and drinking water quality that may affect the health of children, to 

determine whether the appropriate amount and types of information and documentation are being 

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

41
Letter ID: 0241 Comment ID: 23276 Letter Lines: 610 to 619 

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

USDW 

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

USDWs in certain circumstances 

Comment: 144.6 Class VI wells are to be limited to injection beneath the lowermost 

formation containing a USDW. This arbitrary exclusion would eliminate a vast 

number of potential sequestration zones. Enhanced oil and gas recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may unnecessarily limit sequestration options. These situations are 

best handled locally where all the pertinent regional geologic factors can be 

considered. The buoyancy of carbon dioxide suggests this in an unnecessary 

restriction since it would move injectate away from the USDWs below the 

sequestration zone. 

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: 0241 Comment ID: 23277 Letter Lines: 621 to 622 

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

comment) 

Comment: 144.36 Permits for Class VI wells should be effective indefinitely, until the 

well is plugged. 

Individual Response: The final rule maintains the lifetime permit provision and clarifies that the 

permit extends through the post-injection site care period (144.36(a)). 

Letter ID: 0241 Comment ID: 23278 Letter Lines: 624 to 628 

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: 146.81(d) Geologic sequestration project should be redefined as follows: 

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

a carbon dioxide stream into an injection zone for geologic sequestration. 

42
Geologic sequestration projects should not be limited to beneath the lowermost 

formation containing a USDW. 

Individual Response: EPA has not revised the definition of a geologic sequestration project for 

the final rule. However, 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: 0241 Comment ID: 23279 Letter Lines: 630 to 631 

Comment Code: 1220 1.1.1.1 Terminology and definitions 

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

trapping mechanism) 

Comment: 146.82(a) Overlying formations needs to be defined. Geologic information should 

be limited to the injection and confining zones. 

Individual Response: EPA believes that a detailed geological site characterization (required 

under §146.82) is essential to evaluating the presence and adequacy of the various geologic 

features necessary to receive and confine injected CO2 for GS. The requirements for geologic 

site characterization are based on a long standing UIC regulatory framework developed to 

address specific risks to USDWs posed by injection. The Class VI GS requirements are tailored 

so that they are appropriate for the unique nature of injecting large volumes of CO2 into a variety 

of geological formations for long-term storage. 

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. 

Letter ID: 0241 Comment ID: 23280 Letter Lines: 633 to 635 

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

geologic data than proposed 

Comment: Capillary pressure is difficult to measure outside a lab and would not be 

available if no wells have been drilled in a project. Do not see necessity for 

this information. 

43
Individual Response: 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 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). 

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). 

Letter ID: 0241 Comment ID: 23281 Letter Lines: 637 to 639 

Comment Code: 3140 2.1.4 Comments that the proposed geologic data requirements are too 

stringent 

Comment: 146.82(g) Baseline geochemical data on subsurface formations is too broad. 

Should be limited to the injection zone, confining zones, and possibly the next 

porous and permeable zone above the upper confining zone. 

Individual Response: The Agency believes that the requirement at §146.82(a)(6) to submit 

baseline geochemical data on subsurface geologic formations, including all USDWs in the AoR 

is appropriate and protective of USDWs. EPA believes that this data will support monitoring 

plan development, inform injectate fate and transport model development (e.g., by providing 

appropriate input parameters), and provide information needed to respond to any unexpected and 

unpermitted leaks outside of the injection zone. The baseline geochemical information will allow 

the owner or operator and permitting authority to evaluate monitoring data and identify any 

changes in subsurface geochemistry that may indicate fluid movement. 

The rule requires geochemical analysis of, at a minimum, the injection zone, confining zone, and 

all USDWs (§146.82(a)(6)). These geochemical tests are necessary to ensure the adequacy of the 

confining system and to serve as a baseline for future monitoring. The Director has the discretion 

to require geochemical analysis of additional subsurface zones if in the Director's opinion they 

are necessary for the protection of USDWs from endangerment. 

EPA agrees that site characterization should be site-specific, particularly in light of the variety of 

geologic settings in which GS may be employed. EPA believes that, while there is a large 

amount of required information, the owner or operator is given flexibility in determining what 

methods are used to demonstrate the suitability of a potential site. EPA envisions an ongoing 

44
dialogue between the Director and the owner or operator during the permitting process (as well 

as throughout the operation of the site). 

Letter ID: 0241 Comment ID: 23282 Letter Lines: 641 to 643 

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

Comment: 146.82(u) Site closure plans, post-closure plans, well plugging plans, etc., 

should not be required many years in advance since conditions, understanding of 

the sequestration zones, and technology change over time. 

Individual Response: EPA disagrees with the commenter's assertion that that the timing of plan 

submittals should be linked to the specific activity being addressed, and believes that submittal 

and review of each of the owner or operator's plans required at §146.82 at the time of the permit 

application is necessary. While injection well plugging, post-injection site care and site closure 

will likely not occur for years after injection commences, the Director needs to have assurance 

that the owner or operator has planned for these events. 

Letter ID: 0241 Comment ID: 23283 Letter Lines: 645 to 650 

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

trapping mechanism) 

Comment: 146.83(a)1 An injection zone capable of receiving the total anticipated volume 

of carbon dioxide should not be an absolute requirement. The volume to be 

injected may be difficult to ascertain since the life of a power plant or other 

source may change with advances in technology or under certain economic 

conditions. A candidate injection zone should not be excluded if it can only 

serve as a sequestration zone for a portion of a project. 

Individual Response: The Agency disagrees with the commenter for asserting that there should 

not be an absolute requirement that the injection zone be capable of receiving the total 

anticipated volume of CO2. The GS rule is designed to ensure that the total volume of CO2 

anticipated to be injected can be safely stored within the target injection zone. This evaluation is 

based on site-specific characteristics including the local geology (e.g., data on formation 

thickness, porosity, and permeability and the presence of confining zones). The GS injection 

requirements, under SDWA authority, ensure protection of USDWs from endangerment through 

assessment of the suitability of an injection zone (§146.83), appropriate site characterization 

(§146.82), and area of review evaluation (§146.84) among other requirements. 

The Agency believes that this comment may be based on an assumption that Class VI injection 

wells will be co-located with CO2 producing facilities. While this may, in some cases, be an 

accurate assumption, the specifications, design, and purpose of the CO2 source/facility are not 

addressed by the Class VI GS requirements. 

45
The productivity of the CO2 source (e.g., power plant, industrial facility, etc.) is not the driver of 

site suitability. Rather, the acceptability of a candidate site is determined, in part, by the amount 

of CO2 it can receive without allowing pressures in the injection formation to build up to levels 

that may fracture the confining zone or cause unacceptable fluid movement. If a CO2 source 

produces more than a formation can hold, then once the capacity of the receiving formation is 

reached, any additional CO2 produced would have to be injected elsewhere. 

Letter ID: 0241 Comment ID: 23284 Letter Lines: 652 to 654 

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

(seeking comment) 

Comment: 146.83(b) Delete reference to identification of additional confining zones. 

This implies this will be required. Redundant confining zones are not required 

in other UIC well classes. 

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

sites. Rather, secondary confining zones are required when the Director determines that these 

zones are needed to maximize the protection of USDWs from endangerment. EPA retains the 

requirement to identify additional containment/confining zones, if required by the Director, as 

proposed (e.g., §146.83(b)). EPA believes that, in some situations, the presence of additional 

confining and containment zones above the primary (i.e., lowermost) confining zone can 

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

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

remediation. 

Letter ID: 0241 Comment ID: 23285 Letter Lines: 656 to 657 

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

CFR 146.85) 

Comment: 146.85(b) The frequency specified for written updates of adjustments to cost 

estimates should coincide with the AOR reevaluation. 

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(c) 

requires the owner or operator to provide annual updates to the cost estimate to account for any 

amendments to the AoR and corrective action plan, the injection well plugging plan, and the 

PISC and site closure plan. EPA adds that the Director can also require the owner or operator to 

provide an adjustment of the cost estimate if the Director determines that the original 

demonstration is no longer adequate, as specified at §146.85(e). See the final rule and preamble 

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

46
Letter ID: 0241 Comment ID: 23286 Letter Lines: 659 to 659 

Comment Code: 3860 2.3.3 Well component degradation 

Comment: 146.86(b)1(v) How is corrosiveness measured? 

Individual Response: EPA clarifies that, although corrosiveness does not have a unit of 

measure, corrosiveness can be technically measured and described. Procedures that can identify 

corrosion (or the absence of corrosion) in a Class VI well provide valuable operational 

information that the Director needs to determine appropriate standards for the tubing and packer. 

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: 0241 Comment ID: 23287 Letter Lines: 660 to 669 

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

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

USDW 

Comment: 

146.86(b)2 Requiring setting surface casing below the lowermost USDW would 

preclude injection above the lowermost USDW, which as earlier stated, would 

eliminate a vast number of potential sequestration zones. Enhanced recovery 

operations above the lowermost USDW have been taking place for a very long time. 

Exclusion of these zones where other abundant supplies of freshwater are 

available may unnecessarily limit sequestration options. These situations are 

best handled locally where the regional geologic factors can be considered. 

Setting the surface casing below the lowermost USDW may not be technically 

feasible. 

Individual Response: EPA disagrees that the surface casing requirements in the GS rule 

preclude injection below deep USDWs. The final GS rule at §146.86(b)(2) requires that surface 

casing extend through the base of the lowermost USDW and be cemented to the surface through 

the use of a single or multiple strings of casing and cement. It does not, however, specify how 

cementing must 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 

47
are protected from endangerment. EPA notes that there are many potential ways to meet the 

requirement, such as the use of staged cementing. 

EPA adds 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 a demonstration 

cannot be made, then the activity will not be allowed under UIC requirements or the SDWA. 

EPA recognizes concerns regarding construction of Class VI wells where the lowermost USDW 

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

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

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

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

USDWs are protective. See the discussion of the waiver approach in the preamble to the final GS 

rule for additional information. 

Letter ID: 0241 Comment ID: 23288 Letter Lines: 671 to 673 

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

Comment: 146.86(b)3 Cementing of the long-string casing to surface may not be desirable 

in all situations; an annulus that can be monitored may be desirable. The longstring casing should be cemented to at least above the upper confining zone. 

Individual Response: The final GS rule at §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 adds that, under §146.86(b)(4), 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 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: 0241 Comment ID: 23289 Letter Lines: 675 to 675 

Comment Code: 3820 2.3.1 Well construction procedures 

Comment: 146.86(b)5 Request clarification whether a CBL with VDL image is sufficient. 

48
Individual Response: A cement bond log with a variable density log image is one of the 

methods that could be used to evaluate cement quality radially. Radial evaluation of cement is 

generally done using acoustic instruments which emit signals through a transmitter and then 

receive the response in receivers. The speed at which the wave returns and the amount of 

attenuation provide information about the material through which the waves travel. The logging 

and testing requirements at §146.87(a) describe the complete suite of tests to be used before and 

upon installation of the surface casing and long-string casing. 

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: 0241 Comment ID: 23290 Letter Lines: 677 to 677 

Comment Code: 3860 2.3.3 Well component degradation 

Comment: 146.86(c)2(ii) How is corrosiveness measured? 

Individual Response: EPA clarifies that, although corrosiveness does not have a unit of 

measure, corrosiveness can be technically measured and described. Procedures that can identify 

corrosion (or the absence of corrosion) in a Class VI well provide valuable operational 

information that the Director needs to determine appropriate standards for the tubing and packer. 

Letter ID: 0241 Comment ID: 23291 Letter Lines: 679 to 681 

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

Comment: 146.87(a) Relevant geologic formations is too broad. This information should 

only be required for the injection and confining zones and possibly the next 

porous and permeable zone above the upper confining zone. 

Individual Response: Regarding clarification of the term "relevant geologic formations," EPA 

expects that during the permit application process, the owner or operator and the permitting 

authority will work together to determine which formations should be studied, based on the sitespecific circumstances. 

EPA is developing guidance on monitoring and testing that will describe recommended tests and 

procedures to assist owners/operators and Directors in evaluating the requirements for preoperational logging and testing under §146.87. This guidance will be available on EPA’s website 

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

Letter ID: 0241 Comment ID: 23292 Letter Lines: 683 to 684 

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

Comment: 146.87(a)2 Open hole logs in the surface hole are unusual and not necessary. If 

required, certainly not in every well in a project. 

Individual Response: Many types of logs (e.g., potential logs) cannot be run in a cased hole. 

Because the borehole for the surface casing runs through the lowermost USDW, it is imperative 

that the geology, lithology, and geochemistry of subsurface formations be defined. EPA adds that 

this type of testing has been successfully performed on Class I hazardous wells. EPA 

acknowledges that, while use of these logs may be unusual in oil and gas fields with a lot of data, 

it would be essential to identify these shallow USDWs or other zones in areas where Class VI 

wells could be drilled. Running caliper logs in surface holes also established a benchmark for 

determining adequate cement to be placed in the well. 

Letter ID: 0241 Comment ID: 23293 Letter Lines: 686 to 686 

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

Comment: 146.87(a)3 Should specify basic logging requirement not specific logs. 

Individual Response: EPA has conducted extensive research and has found that the tests and 

logs specified at §146.87(a) have been proven in industry practice and research to identify 

cementing flaws. EPA adds that these tests 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 demonstrates that the well can be operated and tested 

in a manner that will meet the requirements for Class VI wells. Should alternative methods be 

shown to provide equivalent or better information, the Director may allow such alternatives 

under §146.87(a)(5). 

Letter ID: 0241 Comment ID: 23294 Letter Lines: 688 to 691 

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

Comment: 146.87(b) Coring should not be required if an adequate core and report exists 

for a nearby well. Coring should only be required of the injection and 

confining zones and possibly the next porous and permeable zone above the upper 

confining zone. 

Individual Response: EPA clarifies that §146.87(b) allows information on cores from nearby 

wells to be submitted if the owner or operator can demonstrate that core retrieval is not possible 

and that cores from nearby wells are representative of conditions at the Class VI well. 

Letter ID: 0241 Comment ID: 23295 Letter Lines: 693 to 693 

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

Comment: 146.87(d)2 Vague and ambiguous. 

Individual Response: EPA believes that flexibility on this requirement is warranted to account 

for the variety of geologic conditions that may be encountered at GS sites. The owner or operator 

must describe in the permit application, pursuant to §146.82(a)(8) the proposed formation testing 

program, including how he or she would meet the requirements of §146.87(d). The Director will 

evaluate the proposed formation testing plan, along with site-specific geologic and geochemical 

information. EPA is developing guidance on monitoring and testing that will describe 

recommended tests and procedures to assist owners/operators and Directors in evaluating the 

requirements for pre-operational logging and testing under §146.87. This guidance will be 

available on EPA’s website at 

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

Letter ID: 0241 Comment ID: 23296 Letter Lines: 695 to 696 

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

Comment: 146.87(f) Unrealistic time frame. Tie initial reporting to spud date and 48 

hour notification thereafter. 

Individual Response: EPA disagrees that the 30-day notification requirement is unreasonable. 

The 30-day notification mirrors the current requirement for logging and testing of new Class I 

wells, as described in §146.66. Acknowledging the developing nature of CO2 GS, EPA believes 

that involvement by the permitting authority in each project will provide much needed field data 

for assurance of USDW 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: 0241 Comment ID: 23297 Letter Lines: 698 to 701 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: 146.88(c) Pressure on the annulus is not necessary in all situations. 

Maintaining pressure above the injection pressure will subject the long-string 

casing to unnecessary stress and is not commensurate with the risk associated 

with carbon dioxide injection. 

Individual Response: EPA believes that maintaining an annulus pressure that is higher than the 

injection pressure, as required at §146.88(c), will ensure that if there are leaks in the tubing, the 

annulus fluid will move into the tubing, rather than the injectate moving out of the tubing and 

potentially along the outside of the well. EPA believes this requirement is appropriate for Class 

VI wells given the potential high volumes and supercritical nature of the CO2 injectate, potential 

geomechanical stresses in the wellbore, and the potential for movement of the CO2 in the event 

51
of a mechanical integrity loss. 

EPA does not believe that maintaining annulus pressures that exceed the injection pressure 

would cause unacceptable stress on the casing. A properly designed well that takes into account 

the geologic and geomechanical properties of the site based on information collected under 

§146.82 and meets the construction requirements at §146.86 would be able to maintain integrity 

if the annulus pressure were reasonably higher than injection pressure. 

Letter ID: 0241 Comment ID: 23298 Letter Lines: 703 to 703 

Comment Code: 4100 2.4.1 Injection parameters 

Comment: 146.88(e) Is continuous recording of annular fluid volume possible or practical? 

Individual Response: EPA believes that knowing annulus fluid volume, as required at 

§146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that 

monitoring the annulus fluid volume added is sufficient to meet the intent of continuous 

monitoring of the pressure on the annulus. The final GS rule at §146.90 (b)) requires that owners 

or operators use 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 added. 

Letter ID: 0241 Comment ID: 23299 

Comment: Individual Response: 

Letter ID: 0241 Comment ID: 23300 Letter Lines: 712 to 713 

Comment Code: 4546 2.5.2.2 MIT frequency (seeking comment) 

Comment: 146.89(c) Annual tracer surveys, temperature or noise logs, or casing inspection 

logs is too burdensome. This frequency should coincide with AOR reevaluation. 

Individual Response: The final GS regulation retains the requirement that owners or operators 

of Class VI wells demonstrate injection well external mechanical integrity at least once annually 

at §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. 

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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 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). 

EPA adds that it is using an adaptive approach to regulating GS. The Agency will, every six 

years, collect and review data 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: 0241 Comment ID: 23301 Letter Lines: 715 to 715 

Comment Code: 4620 2.6.2 Injectate monitoring 

Comment: 146.90(b) Is continuous recording of annular fluid volume possible or practical? 

Individual Response: EPA believes that knowing annulus fluid volume, as required at 

§146.88(e), is a necessary component of monitoring well mechanical integrity, but believes that 

monitoring the annulus fluid volume added is sufficient to meet the intent of continuous 

monitoring of the pressure on the annulus. The final GS rule at §146.90 (b)) requires that owners 

or operators use 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 added. 

Letter ID: 0241 Comment ID: 23302 Letter Lines: 717 to 718 

Comment Code: 4630 2.6.3 Corrosion monitoring 

Comment: 146.90(c) Quarterly is too onerous. Director should have discretion to require 

less frequently based upon performance. 

Individual Response: EPA believes that quarterly corrosion monitoring is appropriate given the 

potentially corrosive nature of the CO2 stream. CO2 in the presence of water becomes acidic, 

potentially accelerating corrosion of well materials. The CO2 stream for a GS project may also 

53
contain small volumes of impurities that could contribute to corrosion. For these reasons, the 

final rule requires quarterly corrosion monitoring, at §146.90(c). 

Letter ID: 0241 Comment ID: 23303 Letter Lines: 720 to 720 

Comment Code: 4700 2.7 Proposed Recordkeeping and Reporting Requirements (40 CFR 

146.91) 

Comment: 146.91(a) Injection volumes and pressures should be reported monthly. 

Individual Response: The final rule remains unchanged from the proposal and requires semiannual reporting of monthly average, maximum and minimum values for injection pressure, flow 

rate and volume, annular pressure, and monthly annulus fluid volume added at §146.91(a). EPA 

believes that monthly reporting of routine operational data and monitoring results would provide 

no additional protection of USDWs from endangerment. EPA adds, at §146.91(c), that it has 

included in the final rule a requirement that operators must report within 24 hours of any event 

that may endanger USDWs; noncompliance with a permit condition or malfunction of injection 

system which triggers fluid movement; any triggering of a shut-off system; any failure to 

maintain mechanical integrity; or if anything is detected through surface/air monitoring, if its 

required. EPA notes that states seeking primacy for Class VI wells are free to require more 

frequent reporting. 

Please see the final rule and the discussion of testing and monitoring in the preamble for 

additional information. 

Letter ID: 0241 Comment ID: 23304 Letter Lines: 722 to 724 

Comment Code: 4740 2.7.4 Electronic reporting (seeking comment) 

Comment: 146.91(c) Electronic reporting should not be required. State systems may 

already be in place to collect data but may not be compatible with sending or 

receiving systems. 

Individual Response: EPA believes that electronic formatting is the most appropriate format for 

submitting Class VI project information to the Director, and based on comments received on the 

proposed rule, the majority of Class VI well owners or operators will have the capability to 

report electronically, and requires this at §146.91(e). 

Acknowledging that some States may have to develop electronic data systems to receive 

electronic information from the owner or operator, and that many States which already have 

electronic data systems will have to make changes to accommodate a new class of UIC well 

(Class VI), EPA believes that it is prudent to provide assistance by developing a central 

framework for the electronic system that will be used by States to gather and track owner or 

operator data. This will enable owners or operators to submit data without having to wait for a 

State to develop a system. It will also provide for standardized submissions across the country 

54
and enable States to focus State resources on reviewing and approving permit applications rather 

than building or upgrading separate, independent databases for GS information. 

EPA is developing guidance for states that describes the recordkeeping, reporting, and additional 

data management needs associated with GS activities and provides recommended guidelines on 

the types of data to be collected for tracking GS projects, reporting to EPA for compliance 

tracking, and transfer of data to EPA's GS data system. The recordkeeping and reporting 

guidance will be available on EPA's web site, at 

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

Letter ID: 0241 Comment ID: 23305 Letter Lines: 726 to 727 

Comment Code: 5100 2.8.1 Injection well plugging activities (seeking comment) (40 CFR 

146.92) 

Comment: 146.92(d) Simplify. Plugging reports should be required within a consistent 

time frame. 

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: 0241 Comment ID: 23306 Letter Lines: 729 to 731 

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

Comment: 146.93(b) A performance-based time period is appropriate rather than a fixed 

timeframe. Establishing an arbitrary and long time frame will inhibit operators 

from entering into this activity. 

Individual Response: EPA acknowledges that there will be circumstances where it can be 

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

endangerment to USDWs. For this reason, the 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 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. 

55
56

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.