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.
October 15, 2009

Water Docket

Environmental Protection Agency

Mailcode: 4101T

1200 Pennsylvania Ave., NW

Washington DC 20460

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

Re: Comments on the EPA’s Proposed Federal Requirements under the Underground Injection 

Control (UIC) Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) wells; Notice of Data 

Availability.

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

API appreciates the opportunity to comment on EPA’s Notice of Data Availability on its proposed rule for 

Carbon Dioxide Geologic Sequestration Wells under the Underground Injection Control Program. API, 

the national trade association of the U.S. oil and natural gas industry, represents nearly 400 companies 

involved in all aspects of the oil and natural gas industry, including exploration and production, refining, 

marketing and transportation, as well as the service companies that support our industry.

As an industry, we have over 35 years of experience safely transporting, producing, and injecting CO2 for 

enhanced oil and gas recovery (EOR). While constantly evolving, the technology, operating experience, 

and regulatory requirements that have been developed for enhanced oil and gas recovery are extensive, 

mature, and provide a sound basis for regulations of GS. In the U.S. alone, the oil and gas industry 

operates over 13,000 CO2 EOR wells, over 3,500 miles of high pressure CO2 pipelines, and has injected 

over 600 million tons of CO2 for EOR alone, all while maintaining an excellent health, environment, and 

safety record. 

Comments on Research, Data Analysis, and Findings

Class VI well construction, operational, and monitoring requirements

EPA has noted in the NODA that the SECARB project “employs, demonstrates, and validates the EPA’s 

proposed Class VI well construction, operational, and monitoring requirements” (NODA, p. 44806). 

However API notes that the well involved in this project is permitted as a Class V well and largely meets 

Class I design standards. API continues to urge EPA to reconsider its proposed well construction and 

operation requirements, which while protective, are more prescriptive than necessary for commercialKyle B. Isakower

Director

Policy Analysis Department

1220 L Street, NW

Washington, DC 20005-4070

USA

Telephone 202-682-8314

Fax 202-682-8296

Email Isakowerk@api.org
scale implementation of CCS and do not reflect industry’s 35-plus years of success in injecting CO2 under 

the Class II UIC program.1 The Class II EOR wells constructed for these CO2 injection projects - and their 

operating practices - have an excellent record of mechanical integrity and of protecting USDWs. Some 

of EPA’s proposed requirements are not only unnecessarily burdensome, but might also interfere with 

operations and could introduce unintended risks. For example, cementing the longstring casing to 

surface is not always possible and prevents the annulus from serving many of the same functions that a 

monitoring well might. The results of the SECARB project do not imply that regulations more similar to 

Class II regulations would not have worked equally well.

Several recent papers demonstrate the effectiveness of the Class II UIC program. The first study by 

Duncan et al. examines the safety risks associated with large scale CO2 sequestration by taking a 

systematic review of all accident and blowout data associated with CO2 pipeline transport and injection 

and concludes that “The CO2-EOR industry has an excellent safety record” and “the rarity of corrosion 

related incidents reflects the industry’s success in implementing anti-corrosion measures.”2 The second 

study by Smyth et al. demonstrates the industry’s protection of the environment. It examines the 

groundwater in the SACROC CO2-EOR field and finds “that no widespread degradation of water quality 

exists inside the SACROC oilfield as a result of CO2-injection.”3 

Monitoring

The development of a monitoring strategy for a given GS project requires the consideration of a variety 

of subsurface factors and location specific concerns. Monitoring techniques used in pilot or 

demonstration projects may not necessarily be appropriate for a particular commercial-scale geologic 

storage project, either because of site specific differences or because the cost of scaling-up these 

techniques could be cost-prohibitive.

The Pump Canyon Project represents just one test of tracers and so its outcome should not be 

generalized beyond its specific circumstances. Use of tracers should be a site specific decision. Of more

concern, the perfluorocarbon (PFT) tracers used in the Escatawpa pilot project are greenhouse gases 

much more potency than CO2. Tracers may be useful for CO2 storage in some circumstances, but 

potential unintended consequences should be considered when deciding whether tracers are 

appropriate, and if so, what kind of tracer is best for the project.

 

1 For a complete discussion of API’s concerns with the proposed well construction and operating requirements, 

please see API’s December 2008 comments on EPA’s Proposed Class VI rules.

2 Duncan, I.J., Nicot, J.P., Choi, J.W.: “Risk assessment for future CO2 Sequestration Projects Based CO2 Enhanced 

Oil Recovery in the U.S.,” presented at the 9th International Conference on Greenhouse Gas Control 

Technologies (GHGT-9), Washington, D.C., November 16-20, 2008. GCCC Digital Publication Series #08-03i

3 Smyth, R.C., Hovorka, S.D., Lu, J., Romanak, K.D., Partin, J.W., Wong, C. and Yang, C.: “Assessing risk to fresh 

water resources from long term CO2 injection – laboratory and field studies,” paper GCCC Digital Publication 

Series #08-03j, presented at the 9th International Conference on Greenhouse Gas Control Technologies 

(GHGT-9), Washington, D.C., November 16-20, 2008. Download from BEG/UT website: 

http://www.beg.utexas.edu/gccc/bookshelf/2008/GHGT9/08-03j-Final.pdf
Soil and air monitoring, used at both the Escatawpa and Aneth Field pilot projects, are unlikely to see a

positive signal and are therefore unnecessary under most foreseeable circumstances. Natural CO2

concentration in soil can have high spatial and temporal variation resulting from complex environmental 

interactions, particularly in wet, warm environments.4 In the air, CO2 has a high detection limit, reducing 

the benefits of using air monitoring. Leakage detection would be particularly difficult in industrial areas 

or near population centers, where CO2 concentration in the air is already high and variable. While

having knowledge of CO2 flux in the soil and air at a given site location may prove useful for site 

characterization, the utility of soil and air monitoring will be highly site specific. The general strategy of 

monitoring programs should be to detect leakage long before it reaches the surface.

Risk to Groundwater from Trace Element Mobilization

API urges EPA not to take the results of the LBNL study out of context. First, the LBNL study goal, as 

stated in Apps et al. is to develop a “comprehensive geochemical model that describes the complete 

chemistry of a range of specified shallow aquifer systems”5; the authors did not, contrary to EPA’s 

assertion, model a “representative groundwater” (NODA p. 44807). Specifically, the groundwater 

samples chosen for the model had to have been tested for at least one of the following to be included in 

the study: As, Ba, Cd, Hg, Pb, Sb, Se, U, or Zn. These analyses are not commonly run in many parts of 

the U.S. or in aquifers known to be free of heavy metal constituents. There are many areas of the U.S. 

where the mobilization of arsenic, lead, and other trace elements is not a concern because the minerals 

in which these elements are typically found are not present. This does not make the LBNL results invalid, 

but it does indicate that the results may not be typical. It is also important to point out that the 

presence of minerals containing these elements would be taken into consideration during the site 

selection process.

Second, heavy metal contamination will require multiple events and therefore the probability of 

occurrence of contamination is the product of the probabilities of each event, which in all likelihood will 

be very small. The events and associated probabilities will include: CO2 movement out of the intended 

storage zone, a migration path to a USDW, passing through or ending up in a unit with minerals that 

contain heavy metal assemblages, non-detection of a large-scale leak, no pH buffering or immobilization

through mineral precipitation or adsorption onto clays/organics. The probability of USDW 

contamination, based on the probabilities of each of these individual events, will be different for every 

site. The risk of trace metal contamination of groundwater will typically be small, knowable, and 

manageable at properly selected and managed geologic storage sites. 

Third, actual field results – as opposed to modeling exercises - have shown the risk of contamination is 

low. For example, at SACROC oilfield in Scurry County, TX, where CO2 has been injected for EOR since 

 

4 Duncker Romanak, K., 1997, Vadose-Zone Geochemistry of Playa Wetlands, High Plains, Texas, The University of 

Texas at Austin, Ph.D. dissertation, 273 p., 49 figs.

5 Apps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J., 2009, Identification of thermodynamic controls defining 

the concentrations of hazardous elements in potable ground waters and the potential impact of increasing 

carbon dioxide partial pressure, GHGT-9, Energy Procedia I, 1917-1924. 
1972, Smyth et al., 2009 determined that “*They+ do not see evidence of As or Pb having been mobilized 

from injection zones at SACROC into overlying USDW’s . . .”. 6

The LBNL report’s authors realize the limitations to their models and EPA should also. Despite having 

set up the simulation so that trace element mobilization would likely result, the authors conclude that “. 

. . model uncertainties, kinetic factors, and post-withdrawal water treatment methods all suggest 

diligence rather than alarm.”

7

Basin Scale Impacts of CO2 Injection

EPA states that the LBNL study of Basin-Scale impacts “illustrates the importance of basin-scale 

evaluation of reservoir pressures and far-field pressures resulting from CO2 injection” (NODA, p. 44808). 

API cautions EPA against basing regulations or permit requirements on the outcomes of this due to the 

constraints of the model. Three examples of modeling assumptions/design impacting the results stand 

out. First, the model assumes lateral homogeneity of all stratigraphic units. Permeability in the Eau 

Claire Shale top seal may vary considerably in a lateral sense at regional scales8but in the model, the 

permeability is uniform. Second, the compressibility values of the Mount Simon that were used are less 

than published values. Increasing compressibility would reduce the predicted pressure buildup. Third, it 

was noted in Juanes, 2006, that in general, coarse grids overestimate CO2 movement and capillary 

trapping.9 The adaptive gridding approach used in the Illinois Basin model uses progressively larger grid 

cells away from the injection area. The largest cells near the edge of the basin are 10 x 10 km, and the 

maximum thickness of any grid block was set to 10 m. The high aspect ratio and large size of these cells 

may introduce significant numerical dispersion in the model results. Conclusions based on the modeled 

brine flow out of the basin and far field pressure effects should be considered qualitative at best, and 

are likely conservative given the constraints of the model. 

Nonetheless, contrary to EPA’s interpretation of the results - that “basin-wide pressure influences can 

be large” (NODA, p. 44808)- the modeled brine out-flow and far field pressure effects (an increase of 

0.5 bar) are very small, and would likely have been even lower if the model had included lateral 

heterogeneities in permeability and porosity and used a higher compressibility. The predicted pressure 

perturbations are so minor that they would likely not be accurately distinguished from normal variation

in routine pressure data collection.

 

6 Smyth, R.C., Hovarka, S., Lu, J., Romanak, K., Partin, J., Wong, C., and Yang, C., 2009, Assessing risk to fresh water 

resources form long term CO2 injection – laboratory and field studies, GHGT-9, Energy Procedia I: 1957-1964.

7 Apps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J., 2009, Identification of thermodynamic controls defining 

the concentrations of hazardous elements in potable ground waters and the potential impact of increasing 

carbon dioxide partial pressure, GHGT-9, Energy Procedia I, 1917-1924.

8 Arnold, T., Bahr, J., and Fantucci, R., 1996, Paleohydrogeology of the Upper Mississippi Valley Zinc-Lead District, 

in Sangster, D. F., ed., Carbonate-Hosted Lead-Zinc Deposits, Society of Economic Geologists Special 

Publication Number 4, p. 378-389. 

9 Juanes, R., Spiteri, E.J., Orr, F.M., and Blunt, M.J., 2006, Impact of relative permeability hysteresis on geological 

CO2 storage, Water Resource Research, Vol. 42, No. 12, W12418.
Moreover, basin-wide modeling is not applicable to Area of Review determinations. While basin-scale 

modeling may be informative, responsibility for this undertaking falls outside the scope of individual 

project permitting. Furthermore, adaptive rule-making will allow for adjustments to encompass 

multiple projects in the same basin if and when needed in the future. 

CO2 Modeling

EPA states that “modeling the injection and sequestration of CO2 poses unique challenges” (NODA p. 

44808). This statement exaggerates the challenges and fails to take into account the modeling 

experience of industry. Industry is constantly being faced with new situations that pose “unique 

challenges”. For example, development of the Canadian oil sands presented “unique challenges” such 

as simulating heavy oil thermal recovery operations which require steam injection into shallow 

reservoirs at high temperature, causing thermal alteration of the oil, reactivity of mineral species, and 

over pressurization. These operations are more complicated and more chemically reactive than CO2

storage operations yet industry now does this type of modeling routinely. This shows industry’s ability 

to overcome challenges in order to effectively model highly complex and dynamic subsurface processes.

Additionally, the state of modeling for CO2 storage is more than adequate to proceed with EPA rule 

promulgation. Additional research is always encouraged, but there are no major technical 

breakthroughs in the realm of modeling that need to occur before beginning commercial-scale CO2

storage operations in the United States. Adaptive regulations will facilitate new information being 

implemented in a responsible way.

API does not support EPA’s assertion that there is a “. . . need to couple multiphase flow, reactive 

transport, and geomechanical processes” (NODA p.44808). Such a model is certainly possible but will 

likely be intractable, expensive, and it will still be at the mercy of the quality of the input and the 

fundamental model framework. It is more important to correctly capture the range of processes and 

possible outcomes at a given location than to use a particular software package or type of modeling. 

Robust yet less complex models capturing the most important physical and chemical processes can 

accomplish the modeling goals necessary for safe storage.

Lastly, the Schnaar and Digiulio, 2009 literature review on CO2 modeling, which appears to be the basis 

for EPA’s statements above, focuses heavily on finite difference simulation of CO2 storage in saline 

aquifers.10 It has few references to analogous modeling of CO2-EOR storage and underground gas 

storage. It also lacks discussion of alternative flow modeling theories (e.g. percolation) that could be 

applied to certain geologic storage applications. 

Injection Depth for GS Projects

API is supportive of EPA’s effort to introduce flexibility on the depth of injection relative to the location 

of USDWs by proposing a waiver process. API holds that CO2 can be injected above a USDW while 

 

10 Schnarr, G. and D. Digiulio. 2009. Computational Modeling of theGeologic Sequestration of Carbon Dioxide. 

Vadose Zone Journal, 8(2), 389-403.
protecting the USDW and maintaining access to the USDW for future use. As noted in API’s testimony 

last year, the Salt Creek EOR project in Wyoming, which has a USDW below the injection zone, is an 

excellent example of how industry can operate CO2 injection wells in an EOR context without 

endangering or limiting access to USDWs that are located below the injection zone. Accessing USDWs 

below a storage site, while not trivial, does not present significant technological hurdles. Industry has 

the technology and experience needed to drill through over-pressured gas reservoirs which are 

analogous to GS sites. There are some excellent examples of off-shore technologies for drilling through 

salt formations and shallow gas pockets that involve the same type of pressure issues that would be 

encountered in drilling through a GS site. 

API, while supportive of the concept of a waiver process, has concerns with how the proposed waiver 

process would function. First, the scope and applicability of the proposed waiver process appears very 

limited. EPA's apparent intent is to issue waivers for situations where the injection zone is 1) a saline 

formation overlying a USDW or 2) a depleted oil or gas reservoir overlying a USDW. With respect to the 

former situation, these conditions are relatively uncommon and would not address the problem faced in 

large portions of the western US where USDWs may extend from the surface to very great depths. 

Applicability would also be limited in the latter situation because frequently the water legs of oil and gas 

reservoirs meet the definition of a USDW. In effect then, a waiver may not be sufficient to inject into 

such a depleted oil and gas reservoir without also obtaining an aquifer exemption.

Second, for the waiver system to work effectively, the final decision making authority for a waiver 

should be with the agency holding primacy for the proposed Class VI UIC program. EPA’s current 

proposal would appear to give a Public Water Supply Supervision (PWSS) Program Director veto power 

over a waiver. API believes this is not appropriate because a PWSS Program Director (and the Director’s 

staff) is rarely as knowledgeable regarding underground injection as the UIC Program Director (and the 

Director’s staff). The PWSS director should participate with a commenting role in the waiver process as 

opposed to being the decision making authority.

Third, EPA should integrate the waiver process into the normal permit approval process as much as 

possible. For example, EPA should combine the public hearing for the waiver along with the public 

hearing for the permit, if one is held. 

Finally, the assertion that “...placing distance between the injection formation and USDWs decreases 

risks to USDWs” (NODA p. 44809) is an overly general statement that should not influence regulation. 

Injection depth requirements would not accomplish the goal of protecting USDWs because the true 

issue is the quality of the sealing formation(s) and the presence or absence of other likely leakage 

pathways. A good quality top seal is demonstrated by permeability, porosity, mineralogy, and other 

physical properties rather than thickness or distance from USDWs.
Other Issues

Need for Additional Research

The Notice of Data Availability (NODA) references new studies that EPA can use to finalize its rulemaking for geologic storage of CO2. However, API sees nothing in the newly available information that 

suggests a need to postpone the development of final rules, as opposed to proceeding with adaptive 

regulations. While there is always room to expand the knowledge base, and research into various 

aspects of CO2 storage should continue, the state of the science is more than adequate to proceed with 

EPA rule promulgation and commercial-scale implementation of geologic storage in the United States. 

The proven success of 30+ years of CO2 enhanced oil recovery, 70+ years of natural gas storage, and 150 

years of oil and gas production, demonstrates the industry knows how to safely and effectively drill 

wells, inject and store fluids, and monitor for containment. 

State Primacy

API contends that states and tribes should play a leading role in managing GS projects going forward. 

Accordingly, states should be permitted to seek primacy for the Class VI program, even in the absence of 

primacy for other well classes (partial primacy). Numerous states have decades of experience in 

regulating CO2 injection through Class II programs, and those states in particular may have much to offer 

in the context of Class VI wells. A critical component of the primacy delegation process is for EPA to 

ensure that States will be adequately funded to deal with the increased workload associated with 

managing the Class VI program. Conversely, some states may not have formations with the necessary 

geologic characteristics to allow GS and so may want to pass on obtaining primacy for this program.

50-year Default Post-Injection Site Care

EPA did not raise the issue of its proposed 50-year default period for post-injection site care in the 

NODA. However, API encourages EPA to reconsider this extreme time frame, as there does not seem to 

be a scientific basis for the selected period of 50 years. Establishing a fixed and unusually long time 

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

considering entry into GS operations. Criteria for determining the period for post-injection site care 

should be performance-based and a function of the site specific characteristics of a project such as 

project size, geologic factors, and relative risk of the project. Clear guidelines also need to be 

established regarding when operators have met the performance standards that determine site closure. 

Specifically, the standard that the project no longer poses an endangerment to USDWs needs to be 

defined using reasonable risk-based criteria. Consideration should also be given as to the mechanism 

for transfer of long-term liability to the appropriate government entity; what entity will be responsible 

for the long-term liability and what type of stewardship is required. Please refer back to API’s 

comments submitted in Dec., 2008 for specific suggested changes on site closure criteria and 

requirements.
Conclusion

API supports the waiver approach for dealing with injection above the lowermost USDW, but is very 

concerned that the current administrative arrangement may limit its value in facilitating GS. API 

remains concerned with EPA’s proposed Class VI well construction, operational, and monitoring 

requirements. We continue to advocate for performance-based standards over prescriptive 

requirements. GS is one of the essential technologies that could help to ensure that we can continue to 

produce the clean energy society demands. If you have questions, please contact Steve Crookshank of 

API’s Policy Analysis at (202) 682-8542 or crookshanks@api.org.

Sincerely,

Kyle Isakower

Director, Policy Analysis
Letter ID: 0350  

Commenter: Kyle Isakower  

Organization: American Petroleum Institute (API)  

Letter ID: 0350 Comment ID: 28037 Letter Lines: 53 to 74  

Comment Code: 2110 2.1.1. SECARB (Escatawpa, MS)  

Comment: Class VI well construction, operational, and monitoring requirements  

EPA has noted in the NODA that the SECARB project "employs, demonstrates, and  

validates the EPA's proposed Class VI well construction, operational, and  

monitoring requirements" (NODA, p. 44806). However API notes that the well  

involved in this project is permitted as a Class V well and largely meets Class  

I design standards. API continues to urge EPA to reconsider its proposed well  

construction and operation requirements, which while protective, are more  

prescriptive than necessary for commercial‐ scale implementation of CCS and do  

not reflect industry's 35‐plus years of success in injecting CO2 under the Class  

II UIC program. [Footnote 1] The Class II EOR wells constructed for these CO2  

injection projects ‐ and their operating practices ‐ have an excellent record of  

mechanical integrity and of protecting USDWs. Some of EPA's proposed  

requirements are not only unnecessarily burdensome, but might also interfere  

with operations and could introduce unintended risks. For example, cementing  

the longstring casing to surface is not always possible and prevents the  

annulus from serving many of the same functions that a monitoring well might.  

The results of the SECARB project do not imply that regulations more similar to  

Class II regulations would not have worked equally well.  

[Footnote 1] For a complete discussion of API's concerns with the proposed well  

construction and operating requirements, please see API's December 2008 comments  

on EPA's Proposed Class VI rules.  

Individual Response: EPA recognizes that the oil and gas industry has experience injecting CO2 and that

many of the wells used for ER may be suitable for GS; however, GS is sufficiently different from Class II

ER operations to warrant the tailored construction requirements for GS wells at §146.86. For example,

the volume of CO2 anticipated to be injected in Class VI wells is significantly greater than for Class II

wells. Reservoir pressure conditions will be different, with Class VI injection operations involving large

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

projects. The Class VI regulations also address the unique physical characteristics of CO2 including its
buoyancy and potential corrosivity. See the response to comments document for the proposed rule for

additional information on EPA’s final approach to construction of GS wells.  

Letter ID: 0350 Comment ID: 28038 Letter Lines: 76 to 100  

Comment Code: 2400 2.4. Other Research Offered by Commenters (seeking comment)  

Comment: Several recent papers demonstrate the effectiveness of the Class II UIC program.  

The first study by Duncan et al. examines the safety risks associated with large  

scale CO2 sequestration by taking a systematic review of all accident and  

blowout data associated with CO2 pipeline transport and injection and concludes  

that "The CO2‐EOR industry has an excellent safety record" and "the rarity of  

corrosion related incidents reflects the industry's success in implementing  

anti‐corrosion measures." [Footnote 2] The second study by Smyth et al.  

demonstrates the industry's protection of the environment. It examines the  

groundwater in the SACROC CO2‐EOR field and finds "that no widespread  

degradation of water quality exists inside the SACROC oilfield as a result of  

CO2‐injection." [Footnote 3]  

[Footnote 2]: Duncan, I.J., Nicot, J.P., Choi, J.W.: "Risk assessment for future  

CO2 Sequestration Projects Based CO2 Enhanced Oil Recovery in the U.S.,"  

presented at the 9th International Conference on Greenhouse Gas Control  

Technologies (GHGT‐9), Washington, D.C., November 16‐20, 2008. GCCC Digital  

Publication Series #08‐03i  

[Footnote 3]: Smyth, R.C., Hovorka, S.D., Lu, J., Romanak, K.D., Partin, J.W.,  

Wong, C. and Yang, C.: "Assessing risk to fresh water resources from long term  

CO2 injection ‐ laboratory and field studies," paper GCCC Digital Publication  

Series #08‐03j, presented at the 9th International Conference on Greenhouse Gas  

Control Technologies (GHGT‐9), Washington, D.C., November 16‐20, 2008. Download  

from BEG/UT website:  

http://www.beg.utexas.edu/gccc/bookshelf/2008/GHGT9/08‐03j‐Final.pdf  

Individual Response: EPA acknowledges the submittal and will continue to review studies related to the

use of CO2 for ER and risk to fresh water resources from CO2 injection. EPA intends to continue to

collect data on GS and to incorporate such data and information as it implements its adaptive approach

to the GS rulemaking to incorporate new research, data, and information about GS. For more

information on the adaptive approach, see the responses to comments on the proposed rule in the

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

demonstrated the effectiveness of many of the technologies that will be employed at GS sites. The GS

rule builds on this expertise with requirements tailored to the unique issues associated with GS through

proper permitting, siting, well construction, operation, monitoring, and closure of GS projects.  

Letter ID: 0350 Comment ID: 28039 Letter Lines: 102 to 116  

Comment Code: 2130 2.1.3. SWP (Pump Canyon, NM)  

Comment: Monitoring  

The development of a monitoring strategy for a given GS project requires the  

consideration of a variety of subsurface factors and location specific concerns.  

Monitoring techniques used in pilot or demonstration projects may not  

necessarily be appropriate for a particular commercial‐scale geologic storage  

project, either because of site specific differences or because the cost of  

scaling‐up these techniques could be cost‐prohibitive.  

The Pump Canyon Project represents just one test of tracers and so its outcome  

should not be generalized beyond its specific circumstances. Use of tracers  

should be a site specific decision. Of more concern, the perfluorocarbon (PFT)  

tracers used in the Escatawpa pilot project are greenhouse gases much more  

potency than CO2. Tracers may be useful for CO2 storage in some circumstances,  

but potential unintended consequences should be considered when deciding whether  

tracers are appropriate, and if so, what kind of tracer is best for the project.  

Individual Response: EPA acknowledges that the pilot sites studied involved extensive monitoring that

may not necessarily be appropriate for all GS sites. However, a robust monitoring program is critical to

ensuring protection of USDWs at GS projects from endangerment, and EPA clarifies that the use of any

monitoring technique in the pilot projects does not amount to an endorsement by EPA or an intent by

EPA to require that particular method. By testing multiple technologies, the pilot sites provide valuable

data that demonstrate whether or not these technologies are viable and informed the final GS rule

about the appropriate use of monitoring technologies.

EPA acknowledges that the appropriate monitoring methods and technologies will be determined on a

site‐specific basis. Data from the projects presented supports the need for a site‐specific monitoring

plan that will allow use of a range of monitoring technologies suitable for each unique GS site.

EPA recognizes that certain monitoring technologies, such as tracers are subject to variability and may

not be appropriate or necessary in all settings. The GS rule at §146.90 gives the Director discretion to

determine what methods are appropriate. All monitoring must be performed according to the Director‐
approved testing and monitoring plan. See the response to comments document for the proposed rule

for additional information on EPA’s final approach to monitoring at GS sites.

EPA acknowledges comments regarding the costs associated with monitoring. The Agency believes the

requirements for comprehensive monitoring are necessary to protect USDWs. A discussion of the costs

attributed to monitoring technologies (used during injection and the post‐injection site care timeframes)

is available in the Technology and Cost Document for the GS rule, which is in the federal docket for this

rulemaking.  

Letter ID: 0350 Comment ID: 28040 Letter Lines: 118 to 134  

Comment Code: 2110 2.1.1. SECARB (Escatawpa, MS)  

Comment Code: 2120 2.1.2. SWP (Aneth Field, UT)  

Comment: Soil and air monitoring, used at both the Escatawpa and Aneth Field pilot  

projects, are unlikely to see a positive signal and are therefore unnecessary  

under most foreseeable circumstances. Natural CO2 concentration in soil can  

have high spatial and temporal variation resulting from complex environmental  

interactions, particularly in wet, warm environments.[Footnote 4] In the air,  

CO2 has a high detection limit, reducing the benefits of using air monitoring.  

Leakage detection would be particularly difficult in industrial areas or near  

population centers, where CO2 concentration in the air is already high and  

variable. While having knowledge of CO2 flux in the soil and air at a given  

site location may prove useful for site characterization, the utility of soil  

and air monitoring will be highly site specific. The general strategy of  

monitoring programs should be to detect leakage long before it reaches the  

surface.  

[Footnote 4]: Duncker Romanak, K., 1997, Vadose‐Zone Geochemistry of Playa  

Wetlands, High Plains, Texas, The University of Texas at Austin, Ph.D.  

dissertation, 273 p., 49 figs.  

Individual Response: EPA acknowledges that the pilot sites studied involved extensive monitoring that

may not necessarily be appropriate for all GS sites. However, EPA believes that a robust monitoring

program is critical to ensuring protection of USDWs at GS projects from endangerment, but clarifies that

the use of any monitoring technique in the pilot projects does not amount to an endorsement by EPA or

an intent by EPA to require that particular method. By testing multiple technologies, the pilot sites

provide valuable data that demonstrate whether or not these technologies are viable and informed the

final GS rule about the appropriate use of monitoring technologies.
EPA acknowledges that the appropriate monitoring methods and technologies will be determined on a

site‐specific basis. Data from the projects presented supports the need for a site‐specific monitoring

plan that will allow use of a range of monitoring technologies suitable for each unique GS site.

EPA recognizes that certain monitoring technologies, particularly surface air and soil gas monitoring are

subject to variability and may not be appropriate or necessary in all settings. The GS rule at 146.90 gives

the Director discretion to determine what methods are appropriate. All monitoring must be performed

according to the Director‐approved testing and monitoring plan. See the response to comments

document for the proposed rule for additional information on EPA’s final approach to monitoring at GS

sites.  

Letter ID: 0350 Comment ID: 28041 Letter Lines: 137 to 193  

Comment Code: 2210 2.2.1. Groundwater Quality and Mobilization of Trace Elements (seeking

comment)  

Comment: API urges EPA not to take the results of the LBNL study out of context. First,  

the LBNL study goal, as stated in Apps et al. is to develop a "comprehensive  

geochemical model that describes the complete chemistry of a range of specified  

shallow aquifer systems" [Footnote 5]; the authors did not, contrary to EPA's  

assertion, model a "representative groundwater" (NODA p. 44807). Specifically,  

the groundwater samples chosen for the model had to have been tested for at  

least one of the following to be included in the study: As, Ba, Cd, Hg, Pb, Sb,  

Se, U, or Zn. These analyses are not commonly run in many parts of the U.S. or  

in aquifers known to be free of heavy metal constituents. There are many areas  

of the U.S. where the mobilization of arsenic, lead, and other trace elements is  

not a concern because the minerals in which these elements are typically found  

are not present. This does not make the LBNL results invalid, but it does  

indicate that the results may not be typical. It is also important to point out  

that the presence of minerals containing these elements would be taken into  

consideration during the site selection process.  

[Footnote 5] Apps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J.,  

2009, Identification of thermodynamic controls defining the concentrations of  

hazardous elements in potable ground waters and the potential impact of  

increasing carbon dioxide partial pressure, GHGT‐9, Energy Procedia I,  

1917‐1924.  

Second, heavy metal contamination will require multiple events and therefore the  

probability of occurrence of contamination is the product of the probabilities  
of each event, which in all likelihood will be very small. The events and  

associated probabilities will include: CO2 movement out of the intended storage  

zone, a migration path to a USDW, passing through or ending up in a unit with  

minerals that contain heavy metal assemblages, non‐detection of a large‐scale  

leak, no pH buffering or immobilization through mineral precipitation or  

adsorption onto clays/organics. The probability of USDW contamination, based on  

the probabilities of each of these individual events, will be different for  

every site. The risk of trace metal contamination of groundwater will typically  

be small, knowable, and manageable at properly selected and managed geologic  

storage sites.  

Third, actual field results ‐ as opposed to modeling exercises ‐ have shown the  

risk of contamination is low. For example, at SACROC oilfield in Scurry County,  

TX, where CO2 has been injected for EOR since 1972, Smyth et al., 2009  

determined that "[They] do not see evidence of As or Pb having been mobilized  

from injection zones at SACROC into overlying USDW's . . .". [Footnote 6]  

[Footnote 6]: Smyth, R.C., Hovarka, S., Lu, J., Romanak, K., Partin, J., Wong,  

C., and Yang, C., 2009, Assessing risk to fresh water resources form long term  

CO2 injection ‐ laboratory and field studies, GHGT‐9, Energy Procedia I:  

1957‐1964.  

The LBNL report's authors realize the limitations to their models and EPA should  

also. Despite having set up the simulation so that trace element mobilization  

would likely result, the authors conclude that ". . . model uncertainties,  

kinetic factors, and post‐withdrawal water treatment methods all suggest  

diligence rather than alarm." [Footnote 7]  

[Footnote 7]: Apps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J.,  

2009, Identification of thermodynamic controls defining the concentrations of  

hazardous elements in potable ground waters and the potential impact of  

increasing carbon dioxide partial pressure, GHGT‐9, Energy Procedia I,  

1917‐1924.  

Individual Response: EPA clarifies that in Apps et al. (2009), referenced in the LBNL study, one typical

ground water composition and aquifer mineralogy scenario was modeled in order to determine the

thermodynamic response of increasing CO2 partial pressures on the concentrations in groundwater of

the nine cited elements: As, Ba, Cd, Hg, Pb, Sb, Se, U, or Zn. The purpose of the analysis was to establish

the potential equilibrium concentrations of the cited elements in equilibrium with specified CO2 partial

pressures. A range of specified shallow aquifer systems, all of which are representative of aquifers

utilized for potable water, was then evaluated in the reactive transport simulations conducted in Section

4 of Birkholzer et al. (2008).  
EPA notes that all of the cited elements are generally present in natural ground waters regardless of

location, albeit typically at trace concentrations. However, it is true that analyses for many potentially

hazardous trace elements are not made routinely, and further, the analytical methods used have often

been insufficiently sensitive to quantify the concentrations present. Birkholzer et al. (2008) evaluated

concentrations in soils and sediments from the National Geochemistry Database (NGS) maintained by

the USGS and also looked at evidence from crustal abundances and abundances in domestic coals. They

concluded that many trace elements occur ubiquitously in soils, sediments, and aquifer rocks

throughout the world.

EPA understands (and mentioned in the NODA) that the risk of CO2 leaking from deep storage is low for

properly managed GS projects, but the leakage probability is not necessarily zero (i.e., pre‐injection site

characterization may fail to detect leakage pathways, or monitoring during and after injection may miss

small‐scale signals of local leaks). Therefore, the consequences of unlikely leakage events need to be

understood and predictive capabilities need to be developed as a basis for risk and vulnerability

assessment. EPA agrees that risk assessment studies, as well as additional geochemical investigations on

ground water vulnerability, should be site specific.

EPA notes the cited paper by Smyth et al. (2009) suggests that no contamination of an overlying aquifer

has occurred at the SACROC oil field. However, the paper does not establish (1) if this is because no CO2

leakage occurred, (2) if leakage occurred but the leaking CO2 has not yet reached the aquifer, or (3) if

CO2 has migrated into the aquifer but has not caused noticeable geochemical response. The latter is

unlikely, as other studies have clearly suggested mobilization of metals in response to increased CO2

levels in the water. For example, the same cited paper by Smyth et al. (2009) reports on laboratory

experiments with exposure of diverse aquifer rocks to CO2, showing geochemical response within hours

to days after introduction of CO2. A recent paper by Kharaka et al. (2009) reports on a field experiment

with injection of CO2 into shallow groundwater, also showing a rapid and systematic geochemical

response in the aquifer, with concentration increases observed for several trace metals. These studies

support the LBNL findings suggesting that CO2 intrusion into USDW, however unlikely, can lead to

mobilization of trace elements.  

EPA clarifies that all GS project owner or operators must submit detailed, site‐specific information about

a proposed GS site, including information on the porosity, permeability, mineralogy, and geochemistry

of the targeted injection and confining zones as well as all USDWs within the Area of Review. Operators

must also present information on the compatibility of the CO2 stream with fluids in the injection zone

and minerals in the injection and confining zones (§146.82(c)(3)). For additional information on EPA’s

approach to site characterization for GS wells, see the responses to comments on the proposed rule in

the rulemaking docket.  
Letter ID: 0350 Comment ID: 28042 Letter Lines: 195 to 239  

Comment Code: 2220 2.2.2. Basin‐Scale Hydrologic Impacts of CO2 Storage (seeking comment)  

Comment: Basin Scale Impacts of CO2 Injection  

EPA states that the LBNL study of Basin‐ Scale impacts "illustrates the  

importance of basin‐scale evaluation of reservoir pressures and far‐field  

pressures resulting from CO2 injection" (NODA, p. 44808). API cautions EPA  

against basing regulations or permit requirements on the outcomes of this due to  

the constraints of the model. Three examples of modeling assumptions/design  

impacting the results stand out. First, the model assumes lateral homogeneity  

of all stratigraphic units. Permeability in the Eau Claire Shale top seal may  

vary considerably in a lateral sense at regional scales but in the model, the  

permeability is uniform. Second, the compressibility values of the Mount Simon  

that were used are less than published values. Increasing compressibility would  

reduce the predicted pressure buildup. Third, it was noted in Juanes, 2006, that  

in general, coarse grids overestimate CO2 movement and capillary  

trapping.[Footnote 9] The adaptive gridding approach used in the Illinois Basin  

model uses progressively larger grid cells away from the injection area. The  

largest cells near the edge of the basin are 10 x 10 km, and the maximum  

thickness of any grid block was set to 10 m. The high aspect ratio and large  

size of these cells may introduce significant numerical dispersion in the model  

results. Conclusions based on the modeled brine flow out of the basin and far  

field pressure effects should be considered qualitative at best, and are likely  

conservative given the constraints of the model.  

[Footnote 8]: Arnold, T., Bahr, J., and Fantucci, R., 1996, Paleohydrogeology of  

the Upper Mississippi Valley Zinc‐Lead District, in Sangster, D. F., ed.,  

Carbonate‐Hosted Lead‐Zinc Deposits, Society of Economic Geologists Special  

Publication Number 4, p. 378‐389.  

[Footnote 9]: Juanes, R., Spiteri, E.J., Orr, F.M., and Blunt, M.J., 2006,  

Impact of relative permeability hysteresis on geological CO2 storage, Water  

Resource Research, Vol. 42, No. 12, W12418.  

Nonetheless, contrary to EPA's interpretation of the results ‐ that "basin‐wide  

pressure influences can be large" (NODA, p. 44808)‐ the modeled brine out‐flow  

and far field pressure effects (an increase of 0.5 bar) are very small, and  

would likely have been even lower if the model had included lateral  

heterogeneities in permeability and porosity and used a higher compressibility.  

The predicted pressure perturbations are so minor that they would likely not be  

accurately distinguished from normal variation in routine pressure data  
collection.  

Moreover, basin‐wide modeling is not applicable to Area of Review  

determinations. While basin‐scale modeling may be informative, responsibility  

for this undertaking falls outside the scope of individual project permitting.  

Furthermore, adaptive rule‐making will allow for adjustments to encompass  

multiple projects in the same basin if and when needed in the future.  

Individual Response: EPA acknowledges that basin‐scale predictions are uncertain due to the limited

information generally available for large subsurface volumes. While the example modeling study cited in

the NODA is based on the best information available, significant prediction uncertainty remains and

results should be viewed as illustrative, as acknowledged in Birkholzer and Zhou (2009). While generic

studies such as this one provide value and demonstrate that the necessary modeling technology is

available to support for such evaluations, EPA recognizes that each GS site is unique, and for this reason,

the GS rule requires a detailed site‐specific evaluation of local geologic conditions (§146.82) and

modeling to delineate the AoR (§146.84).

Regarding the comment that basin‐wide modeling is not applicable to AoR determinations, EPA clarifies

that the purpose of this study was not to model an actual reservoir; rather it was to provide a better

understanding of the potential impact of industrial‐scale CO2 injection on regional ground water

systems for a wide range of geological conditions. EPA will look at basin‐scale impacts as part of its

adaptive rulemaking approach.  

Regarding the comment on “lateral homogeneity” in the Eau Claire Shale top seal, EPA clarifies that the

seal data were too sparse to reliably estimate lateral heterogeneity. The impact of seal permeability was

evaluated in sensitivity cases assuming two different (homogeneous) seal permeability values

(Birkholzer and Zhou, 2009). The general outcome of the simulation study (i.e., size of the pressure‐

affected region) was not strongly influenced by the parameter choice.

The model choice for pore compressibility is discussed in detail in Zhou et al. (2009), and is believed to

be well constrained. The pore compressibility used in the model was obtained through a pumping test in

central Illinois, at a depth of 2000 m just north of the assumed injection area. Additional pumping tests

available in shallower parts of the storage reservoir corroborate the chosen value. These values used in

the model are within the range of pore compressibility reported for well‐consolidated sandstones at in

situ effective stresses representative of Mt. Simon.  

Regarding “gridding and numerical dispersion,” numerical dispersion is a concern for solute transport

with sharp interfaces (advection‐dispersion equation) and/or for multi‐phase transport. For single phase

flow, such as ground water flow and pressure perturbation, there is no numerical dispersion, only the

possibility of small approximation errors. Thus, there may be some gridding effect and numerical

dispersion when simulating CO2 movement and capillary trapping, but this effect is small because the

discretization is refined in the vicinity of each CO2 plume. As to the far‐field pressure response,
numerical dispersion is not an issue.  

Regarding the comment on “far‐field pressure effects,” the 0.5‐bar pressure threshold was used as an

example illustrating the enormous size of the region affected by some pressure perturbation; it was not

meant to imply that a 0.5‐bar pressure increase is a significant threat. However, even a more significant

5‐bar threshold would still result in a large pressure‐affected region. It is pointed out in Birkholzer and

Zhou (2009) that the modeled brine migration within the reservoir and into/through the seals would not

constitute a concern for ground water resources. Pressure perturbation, however, could become a

concern if deep saline water was pushed upward into overlying fresh water aquifers via potentially

existing localized pathways, which were not included in the model.  

Letter ID: 0350 Comment ID: 28043 Letter Lines: 241 to 280  

Comment Code: 2310 2.3.1. Review of Modeling Studies (seeking comment)  

Comment: CO2 Modeling  

EPA states that "modeling the injection and sequestration of CO2 poses unique  

challenges" (NODA p. 44808). This statement exaggerates the challenges and  

fails to take into account the modeling experience of industry. Industry is  

constantly being faced with new situations that pose "unique challenges". For  

example, development of the Canadian oil sands presented "unique challenges"  

such as simulating heavy oil thermal recovery operations which require steam  

injection into shallow reservoirs at high temperature, causing thermal  

alteration of the oil, reactivity of mineral species, and over pressurization.  

These operations are more complicated and more chemically reactive than CO2  

storage operations yet industry now does this type of modeling routinely. This  

shows industry's ability to overcome challenges in order to effectively model  

highly complex and dynamic subsurface processes.  

Additionally, the state of modeling for CO2 storage is more than adequate to  

proceed with EPA rule promulgation. Additional research is always encouraged,  

but there are no major technical breakthroughs in the realm of modeling that  

need to occur before beginning commercial‐scale CO2 storage operations in the  

United States. Adaptive regulations will facilitate new information being  

implemented in a responsible way.  

API does not support EPA's assertion that there is a ". . . need to couple  

multiphase flow, reactive transport, and geomechanical processes" (NODA  

p.44808). Such a model is certainly possible but will likely be intractable,  

expensive, and it will still be at the mercy of the quality of the input and the  
fundamental model framework. It is more important to correctly capture the  

range of processes and possible outcomes at a given location than to use a  

particular software package or type of modeling. Robust yet less complex models  

capturing the most important physical and chemical processes can accomplish the  

modeling goals necessary for safe storage.  

Lastly, the Schnaar and Digiulio, 2009 literature review on CO2 modeling, which  

appears to be the basis for EPA's statements above, focuses heavily on finite  

difference simulation of CO2 storage in saline aquifers.[Footnote 10] It has few  

references to analogous modeling of CO2‐EOR storage and underground gas storage.  

It also lacks discussion of alternative flow modeling theories (e.g.  

percolation) that could be applied to certain geologic storage applications.  

[Footnote 10] Schnarr, G. and D. Digiulio. 2009. Computational Modeling of  

the Geologic Sequestration of Carbon Dioxide. Vadose Zone Journal, 8(2), 389‐403.  

Individual Response: EPA believes that modeling of CO2 injection for GS does pose several unique

challenges, based on review of relevant technical literature, and participation in several technical

symposia and workshops related to computational modeling in this area. While this type of multiphase,

non‐isothermal, multi‐component computational modeling may be familiar in certain advanced

industries, it is certainly novel to the UIC community, and is more sophisticated than modeling typically

required in U.S. EPA regulations. However, EPA agrees with the commenter that advanced

computational modeling of GS sites is feasible, and trusts that experts in industry will meet the

challenges posed by GS modeling. For this reason, EPA has required computational modeling for

delineation of the AoR in a Class VI permit application.  

EPA also agrees with the commenter that coupling of multiphase flow, reactive transport, and

geomechanical processes may not be necessary in all cases for modeling to delineate the AoR in a Class

VI permit application. EPA clarifies that today’s federal regulation requires that models used for AoR

delineation be able to account for multiphase flow and the buoyancy of CO2. However, the Director has

the discretion to require more advanced models be used for AoR delineation, including additional

coupling of reactive transport and geomechanical processes. EPA agrees with the commenter that these

types of fully coupled models are possible, and believes that in certain cases they will be necessary for

accurate delineation of the AoR. For many projects, however, simpler models, as advocated by the

commenter, may be suitable for AoR delineation. EPA believes that the Director of individual projects is

in the best position to determine the specific technical requirements of the model(s) used.  

EPA does not agree with the commenter regarding comments on the modeling research review paper

cited in the NODA (Schnaar and Digiulio, 2009). This paper provides a comprehensive review of peer‐

reviewed modeling studies of GS available in the technical literature, including studies of GS in oil and

gas reservoirs, and studies using modeling codes common in petroleum engineering (e.g., ECLIPSE).
Furthermore, the review paper provides a discussion and review of a range of simulators used to model

GS, including simpler analytic and semi‐analytic approaches cited by the commenter.  

Letter ID: 0350 Comment ID: 28044 Letter Lines: 283 to 296  

Comment Code: 3210 3.2.1. Comments Generally in Support of the Approach  

Comment: API is supportive of EPA's effort to introduce flexibility on the depth of  

injection relative to the location of USDWs by proposing a waiver process. API  

holds that CO2 can be injected above a USDW while protecting the USDW and  

maintaining access to the USDW for future use. As noted in API's testimony last  

year, the Salt Creek EOR project in Wyoming, which has a USDW below the  

injection zone, is an excellent example of how industry can operate CO2  

injection wells in an EOR context without endangering or limiting access to  

USDWs that are located below the injection zone. Accessing USDWs below a  

storage site, while not trivial, does not present significant technological  

hurdles. Industry has the technology and experience needed to drill through  

over‐pressured gas reservoirs which are analogous to GS sites. There are some  

excellent examples of off‐shore technologies for drilling through salt  

formations and shallow gas pockets that involve the same type of pressure issues  

that would be encountered in drilling through a GS site.  

Individual Response: EPA acknowledges the commenter's support of the waiver approach and site‐

specific flexibility in regulatory development and permitting as described in the NODA and Request for

Comment. The Agency acknowledges that there are some situations where injection into non‐USDW

formations above the lowermost USDW can be performed in a manner that protects USDWs. The final

GS rule at §146.95 establishes a process by which owners and operators can seek a waiver of the Class

VI injection depth requirements. The Agency believes the waiver 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.  

EPA agrees with the commenter that technologies exist to address the challenges associated with GS

and injection that will be conducted under the waiver approach, e.g., to inject through over‐pressurized

reservoirs. However, EPA also believes that additional considerations are necessary when permitting
such wells to ensure protection of all USDWs and that the additional requirements that apply to owners

or operators of Class VI wells granted a waiver of the injection depth requirements at §146.95 will

provide this protection.  

Letter ID: 0350 Comment ID: 28045 Letter Lines: 298 to 309  

Comment Code: 3410 3.4.1. Applicability of Waiver Process to Deep Saline and Other Types of

Formations (seeking comment)  

Comment: API, while supportive of the concept of a waiver process, has concerns with how  

the proposed waiver process would function. First, the scope and applicability  

of the proposed waiver process appears very limited. EPA's apparent intent is  

to issue waivers for situations where the injection zone is 1) a saline  

formation overlying a USDW or 2) a depleted oil or gas reservoir overlying a  

USDW. With respect to the former situation, these conditions are relatively  

uncommon and would not address the problem faced in large portions of the  

western US where USDWs may extend from the surface to very great depths.  

Applicability would also be limited in the latter situation because frequently  

the water legs of oil and gas reservoirs meet the definition of a USDW. In  

effect then, a waiver may not be sufficient to inject into such a depleted oil  

and gas reservoir without also obtaining an aquifer exemption.  

Individual Response: EPA clarifies that injection depth waivers are required in all situations where CO2

injection for GS would be above the lowermost USDW. EPA believes the requirements at §146.95 are

necessary to ensure USDW protection above and below the injection zone and offer additional flexibility

and capacity beyond what was contained in the proposed GS rule. EPA recognizes that there may still be

regions where GS would be prohibited but clarifies that USDW protection is the primary purpose of the

GS rule.

EPA acknowledges that there are limited circumstances where aquifer exemptions for GS may be

warranted. The final rule allows for the expansion of the areal extent of existing aquifer exemptions for

Class II EOR/EGR wells transitioning to Class VI injection for GS pursuant to requirements at §§146.4 and

144.7(d). Class VI owners or operators granted expansions of existing Class II EOR/EGR aquifer

exemptions for GS projects must meet all of the tailored requirements for GS wells in the final GS rule.

However, the final rule precludes the issuance of new aquifer exemptions for Class VI GS wells; that is,

aquifer exemptions will only be granted for projects that are transitioning from Class II EOR/EGR wells to

Class VI.  

The Agency clarifies that the aquifer exemption requirements and the injection depth waiver

requirements serve different purposes. Class VI owners or operators granted expansions of existing
Class II EOR/EGR aquifer exemptions for GS projects must meet all of the tailored requirements for GS

wells in the final GS rule, including the site criteria at §146.83. EPA believes that, in most cases, the

injection depth waiver is a more appropriate option than aquifer exemptions for Class VI injection, and

believes that aquifer exemption expansions for GS should be granted in limited circumstances.  

Letter ID: 0350 Comment ID: 28046 Letter Lines: 311 to 319  

Comment Code: 3350 3.3.5. Requirement to Submit Waiver Application to UIC and PWSS Program

Directors  

Comment: Second, for the waiver system to work effectively, the final decision making  

authority for a waiver should be with the agency holding primacy for the  

proposed Class VI UIC program. EPA's current proposal would appear to give a  

Public Water Supply Supervision (PWSS) Program Director veto power over a  

waiver. API believes this is not appropriate because a PWSS Program Director  

(and the Director's staff) is rarely as knowledgeable regarding underground  

injection as the UIC Program Director (and the Director's staff). The PWSS  

director should participate with a commenting role in the waiver process as  

opposed to being the decision making authority.  

Individual Response: The final GS rule includes a requirement that the UIC Program Director consult

with the PWSS Directors of all States, Territories, and Tribes having jurisdiction within the AoR of a well

for which a waiver is sought as specified in §146.95(b)(2). EPA believes this process is necessary and

appropriate to ensure that water system concerns are considered when evaluating a waiver application.

EPA requires that this consultation be documented to ensure transparent public disclosure of all

information evaluated by the Directors and their respective recommendations. EPA clarifies that the

PWSS director does not have "veto power" over a UIC permitting decision; instead, the role of the PWSS

Director is to ensure consideration of water system and water resource issues where injection into non‐

USDW formations above the lowermost USDW is being considered. Due to the unique nature of the

injection depth waiver process and in an effort to ensure national consistency and application of the

requirements, the requirement at §146.95(d) indicates that the Regional Administrator makes the final

determination regarding waiver issuance following an evaluation of all site‐specific information, public

notice, and recommendations from the UIC Director. EPA believes that UIC Program staff is in the

appropriate position to evaluate the technical details of the waiver application, in concert with the UIC

permit application, to inform the Regional Administrator’s decision. EPA adds that adoption of the

waiver process will remain at the discretion of individual UIC programs.  

Letter ID: 0350 Comment ID: 28047 Letter Lines: 321 to 323  
Comment Code: 3360 3.3.6. Requirement to Apply for Waiver Separately from UIC Permit Application

(seeking comment)  

Comment: Third, EPA should integrate the waiver process into the normal permit approval  

process as much as possible. For example, EPA should combine the public hearing  

for the waiver along with the public hearing for the permit, if one is held.  

Individual Response: EPA agrees that it is appropriate to consider and evaluate the waiver application in

concert with the UIC permit application, and not under a separate process. For this reason, the final

requirements at §146.95 create an application and review process for GS injection depth waivers that is

integrated with the UIC permit application process while ensuring that the proposed project is

considered in the context of the presence of USDWs above and below the injection zone and potential

impacts on water systems.

For example, rather than submit a separate waiver application, owners or operators seeking waivers

must provide a supplemental report (the GS Class VI injection depth waiver application report)

referenced at §146.82(d) and outlined at §146.95(a) with additional, site‐specific information relevant to

operation under an injection depth waiver. This report, suggested by commenters, is designed to ensure

that all waiver information is discrete (from the permit application) and can be made available to the

Director, PWSS Directors, and the public when the waiver is publicly noticed. The UIC permit application

and waiver application would be reviewed together. If the permitting authority receives comments on

the injection depth waiver during the public comment period for both the waiver and the permit

application, the Director in consultation with the Regional Administrator, must evaluate comments prior

to providing a recommendation to the Regional Administrator regarding a waiver and issuing the Class

VI permit.

In addition, the public notification process for the waiver must occur concurrently with the UIC permit

notification to ensure that all necessary information is disclosed to the public for notice and comment

and that the public understands that the site, if permitted, would be operating under a waiver from the

injection depth requirements as specified in §146.95(c). EPA believes these requirements balance USDW

protection and disclosure of PWSS information with the GS permit application process requirements.  

Letter ID: 0350 Comment ID: 28048 Letter Lines: 325 to 332  

Comment Code: 3100 3.1. Comments on Concerns About Injection Depth for Class VI Wells  

Comment: Finally, the assertion that "...placing distance between the injection formation  

and USDWs decreases risks to USDWs" (NODA p. 44809) is an overly general  

statement that should not influence regulation. Injection depth requirements  

would not accomplish the goal of protecting USDWs because the true issue is the  
quality of the sealing formation(s) and the presence or absence of other likely  

leakage pathways. A good quality top seal is demonstrated by permeability,  

porosity, mineralogy, and other physical properties rather than thickness or  

distance from USDWs.  

Individual Response: EPA agrees that suitable confining layers (e.g., low‐permeability, low‐porosity

formations identified through proper site characterization process) along with proper well construction,

operation, monitoring, and post‐injection site care are key to protecting USDWs from endangerment.  

Additionally, the Agency believes that distance between the injection zone and USDWs can impede

vertical fluid movement, allow for pressure dissipation, and provide additional sites for monitoring,

mitigation, and remediation if conditions warrant.  

Owners and operators seeking waivers must provide a supplemental report (the GS Class VI injection

depth waiver application report) referenced at §146.82(d) and outlined at §146.95(a) with additional,

site‐specific information including: additional information about the injection zone; identification of

confining units above and below the injection zone; tailored AoR modeling above and below the

injection zone; a demonstration that well design is appropriate and protective of USDWs, in lieu of

specific requirements at §146.86; a description of how monitoring will be tailored for injection

above/between USDWs; and information about public water supplies in the AoR.  

Letter ID: 0350 Comment ID: 28049 Letter Lines: 336 to 348  

Comment Code: 5700 5.14. Comments on Other Aspects of the Proposed Rule  

Comment: Need for Additional Research  

The Notice of Data Availability (NODA) references new studies that EPA can use  

to finalize its rule‐ making for geologic storage of CO2. However, API sees  

nothing in the newly available information that suggests a need to postpone the  

development of final rules, as opposed to proceeding with adaptive regulations.  

While there is always room to expand the knowledge base, and research into  

various aspects of CO2 storage should continue, the state of the science is more  

than adequate to proceed with EPA rule promulgation and commercial‐scale  

implementation of geologic storage in the United States. The proven success of  

30+ years of CO2 enhanced oil recovery, 70+ years of natural gas storage, and  

150 years of oil and gas production, demonstrates the industry knows how to  

safely and effectively drill wells, inject and store fluids, and monitor for  

containment.  

Individual Response: EPA recognizes that the oil and gas industry has decades of experience injecting
CO2 for the purpose of EOR. The GS rulemaking builds upon existing experience and knowledge about

safe injection practices in EOR and other injection industries, with tailored requirements that address

the unique nature of CO2 injection for GS.  

The remainder of this comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0350 Comment ID: 28050 Letter Lines: 351 to 361  

Comment Code: 5700 5.14. Comments on Other Aspects of the Proposed Rule  

Comment: API contends that states and tribes should play a leading role in managing GS  

projects going forward. Accordingly, states should be permitted to seek primacy  

for the Class VI program, even in the absence of primacy for other well classes  

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

injection through Class II programs, and those states in particular may have  

much to offer in the context of Class VI wells. A critical component of the  

primacy delegation process is for EPA to ensure that States will be adequately  

funded to deal with the increased workload associated with managing the Class VI  

program. Conversely, some states may not have formations with the necessary  

geologic characteristics to allow GS and so may want to pass on obtaining  

primacy for this program.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0350 Comment ID: 28051 Letter Lines: 364 to 381  

Comment Code: 5600 5.12. Comments on the Proposed Post‐Injection Site Care Requirements (146.93)  

Comment: EPA did not raise the issue of its proposed 50‐year default period for post‐  

injection site care in the NODA. However, API encourages EPA to reconsider this  

extreme time frame, as there does not seem to be a scientific basis for the  

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

period, even with the Director discretion provided, may create a significant  

barrier for operators considering entry into GS operations. Criteria for  

determining the period for post‐ injection site care should be performance‐based  
and a function of the site specific characteristics of a project such as project  

size, geologic factors, and relative risk of the project. Clear guidelines also  

need to be established regarding when operators have met the performance  

standards that determine site closure. Specifically, the standard that the  

project no longer poses an endangerment to USDWs needs to be defined using  

reasonable risk‐based criteria. Consideration should also be given as to the  

mechanism for transfer of long‐term liability to the appropriate government  

entity; what entity will be responsible for the long‐term liability and what  

type of stewardship is required. Please refer back to API's comments submitted  

in Dec., 2008 for specific suggested changes on site closure criteria and  

requirements.  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0350 Comment ID: 28052 Letter Lines: 384 to 386  

Comment Code: 3360 3.3.6. Requirement to Apply for Waiver Separately from UIC Permit Application

(seeking comment)  

Comment: API supports the waiver approach for dealing with injection above the lowermost  

USDW, but is very concerned that the current administrative arrangement may  

limit its value in facilitating GS. API remains concerned with EPA's proposed  

Individual Response: EPA believes that it is appropriate to consider and evaluate the waiver application

in concert with the UIC permit application, and not under a separate process. For this reason, the final

requirements at §146.95 create an application and review process for GS injection depth waivers that is

integrated with the UIC permit application process while ensuring that the proposed project is

considered in the context of the presence of USDWs above and below the injection zone and potential

impacts on water systems.

For example, rather than submit a separate waiver application, owners or operators seeking waivers

must provide a supplemental report (the GS Class VI injection depth waiver application report)

referenced at §146.82(d) and outlined at §146.95(a) with additional, site‐specific information relevant to

operation under an injection depth waiver. This report, suggested by commenters, is designed to ensure

that all waiver information is discrete (from the permit application) and can be made available to the

Director, PWSS Directors, and the public when the waiver is publicly noticed. The UIC permit application

and waiver application would be reviewed together. If the permitting authority receives comments on

the injection depth waiver during the public comment period for both the waiver and the permit
application, the Director in consultation with the Regional Administrator, must evaluate comments prior

to providing a recommendation to the Regional Administrator regarding a waiver and issuing the Class

VI permit.

In addition, the public notification process for the waiver must occur concurrently with the UIC permit

notification to ensure that all necessary information is disclosed to the public for notice and comment

and that the public understands that the site, if permitted, would be operating under a waiver from the

injection depth requirements as specified in §146.95(c). EPA believes these requirements balance USDW

protection and disclosure of PWSS information with the GS permit application process requirements.  

Letter ID: 0350 Comment ID: 28397 Letter Lines: 387 to 390  

Comment Code: 5000 5. Comments on the Proposed Rule (out of NODA Scope)  

Comment: Class VI well construction, operational, and monitoring requirements. We  

continue to advocate for performance‐based standards over prescriptive  

requirements. GS is one of the essential technologies that could help to ensure  

that we can continue to produce the clean energy society demands. If you have  

Individual Response: This comment pertains to EPA’s proposed GS rule (73 FR 43492) and is outside the

scope of the Notice of Data Availability. Please see responses to comments on the proposed rule for

EPA’s response to similar comments.  

Letter ID: 0350 Comment ID: 28567 Letter Lines: 290 to 296  

Comment Code: 3420 3.4.2. Request for Information on Areas Where Injection Depth and USDWs Are a

Concern (seeking comment)  

Comment: USDWs that are located below the injection zone. Accessing USDWs below a  

storage site, while not trivial, does not present significant technological  

hurdles. Industry has the technology and experience needed to drill through  

over‐pressured gas reservoirs which are analogous to GS sites. There are some  

excellent examples of off‐shore technologies for drilling through salt  

formations and shallow gas pockets that involve the same type of pressure issues  

that would be encountered in drilling through a GS site.  

Individual Response: EPA acknowledges that technologies and past experience exist to inject through

over‐pressured formations while maintaining zonal isolation (e.g., oil and gas industry experience in

drilling through shallow pockets of gas or other zones that have higher pressures). EPA has reviewed
information on these types of projects and has determined that, if properly constructed, wells can be

drilled through pressurized zones without causing fluid movement. However, to provide additional

USDW protection and ensure that any planned drilling is conducted appropriately, the final GS rule

requires the Director to consider planned or permitted water, hydrocarbon, or mineral resource

exploitation potential of the proposed injection formation and other formations both above and below

the injection zone to determine if there are any plans to drill through the formation to access resources

in or beneath the proposed injection zone/formation as specified in §146.95(b)(1)(vii).  

Letter ID: 0350 Comment ID: 28657 Letter Lines: 172 to 193  

Comment Code: 2400 2.4. Other Research Offered by Commenters (seeking comment)  

Comment: Third, actual field results ‐ as opposed to modeling exercises ‐ have shown the  

risk of contamination is low. For example, at SACROC oilfield in Scurry County,  

TX, where CO2 has been injected for EOR since 1972, Smyth et al., 2009  

determined that "[They] do not see evidence of As or Pb having been mobilized  

from injection zones at SACROC into overlying USDW's . . .". [Footnote 6]  

[Footnote 6]: Smyth, R.C., Hovarka, S., Lu, J., Romanak, K., Partin, J., Wong,  

C., and Yang, C., 2009, Assessing risk to fresh water resources form long term  

CO2 injection ‐ laboratory and field studies, GHGT‐9, Energy Procedia I:  

1957‐1964.  

The LBNL report's authors realize the limitations to their models and EPA should  

also. Despite having set up the simulation so that trace element mobilization  

would likely result, the authors conclude that ". . . model uncertainties,  

kinetic factors, and post‐withdrawal water treatment methods all suggest  

diligence rather than alarm." [Footnote 7]  

[Footnote 7]: Apps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J.,  

2009, Identification of thermodynamic controls defining the concentrations of  

hazardous elements in potable ground waters and the potential impact of  

increasing carbon dioxide partial pressure, GHGT‐9, Energy Procedia I,  

1917‐1924.  

Individual Response: EPA has reviewed the papers and acknowledges the submittal. EPA will continue

to review studies related to the evaluation of actual field results and the limitations of sampling and

analysis, as well as the limitations of modeling. EPA intends to continue to collect data on GS and to

incorporate such data and information as it implements its adaptive approach to the GS rulemaking to
incorporate new research, data, and information about GS. For more information on the adaptive

approach, see the responses to comments on the proposed rule in the rulemaking docket.