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.
Comments of the Carbon Sequestration Council on 

EPA’s NODA for the Geologic Sequestration Rule 

74 Fed. Reg. 44802-13 (August 31, 2009) 

Docket: EPA–HQ–OW–2008–0390 

No. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

1 44803 Availability of this new 

information could change EPA’s approach to the final rulemaking. 

The Carbon Sequestration Council (“the Council”) has reviewData Availability (NODA) and the accompanying data and republic review and comment. We see nothing in the new info

that EPA should depart from the adaptive approach to regulatdiscussed as the basic objective for the geologic sequestration 

2 44805 EPA is providing this [sic] data 

and associated project summaries because the Agency expects that there may be additional studies and data on other GS projects, the use of existing technologies, and GSrelated research that may inform the Agency’s regulatory development process for GS. Such data could contribute to the Agency’s understanding of site characterization, well construction, operation, and monitoring requirements. 

The state of the science for CO2 storage and the over 35 years CO2 injection for enhanced oil and gas recovery are more thasupport EPA proceeding with final rule promulgation.

3 44805 Many commenters suggested 

that supplementary research on GS is necessary prior to rule promulgation and that EPA should wait until the Department of Energy (DOE)-sponsored Phase II and Phase III pilot 

Extensive additional research is proceeding on many differencapture, transportation, and sequestration, and the resulting fi

add to our current understanding of these aspects. However, technical breakthroughs that need to occur before beginning cCO2 storage operations in the United States. Moreover, adhe

approach for regulations will facilitate new information being responsible way. 

Comments of the Carbon Sequestration Council 1 rfvanvoo
Comments of the Carbon Sequestration Council 2 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

projects are complete before finalizing the GS rule. 

4 44805 Comments on the proposal 

encouraged additional research and investigations on areas including (but not limited to): confining zone characterization; modeling; CO2 plume 

movement; geochemistry; impacts of GS on saline formations; leakage from abandoned wells caused by material and cement degradation; potential pathways for contamination of USDWs; leak mitigation and remediation; and criteria for determining that the CO2 plume has stabilized. 

Furthermore, the oil and gas industry has relevant experience over 35 years of injecting CO2 for EOR, over 90 years of natu150 years of oil and gas production. The industry also operat

storage projects in offshore Norway, Algeria, and Canada, anoperations that have proven safe and effective. 

5 44805 EPA’s Office of Research and 

Development is conducting intramural and extramural research activities to develop modeling and monitoring tools for protecting underground sources of drinking water. 

Monitoring and modeling needs will be different for each potsite, and we encourage flexibility in the model requirements. prescriptive in requiring certain models or monitoring techniqsite and the operational experience for each GS project will bMoreover, existing and future work may yield improved and approaches to modeling for particular circumstances. 

6 44805 Analytic and semi-analytic 

models are being developed and evaluated for determining the area of review based on geologic and hydrologic conditions. 

Same comment as in 5 above. 

7 44805 Comprehensive laboratory tests 

are being applied to the 

The proposed EPA regulation was drafted with the recognitioone suite of monitoring tools that is appropriate for all potent
Comments of the Carbon Sequestration Council 3 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

development and field-testing of monitoring strategies that can detect migration of fluids into shallow aquifers and assess potential geochemical impacts. 

sites. A variety of subsurface factors and location specific coconsidered to develop the best monitoring strategy for a given many monitoring tools that could be shown to have some utilfollow that every tool – or any particular tool – should be usegiven geological storage project, especially as scaling-up som

monitoring techniques from pilot to commercial scale would For example, soil and air monitoring are unnecessary under m

circumstances. The general strategy of monitoring programs 

the validity of the site selection and characterization process 

leakage long before it reaches the surface. 

8 44806 This SECARB project employs, 

demonstrates, and validates the EPA’s proposed Class VI well construction, operational, and monitoring requirements. 

No one project “validates” a given monitoring technique in a While the well design used in the SECARB project was suffia rich database of successful well construction is also offered and underground gas storage experience. 1. The model used in the Escatawpa project was accurate in pdistance the plume moved, taking into consideration the smalwith only 3,027 tons of CO2 injected over 30 days. 2. All monitoring activities were concluded in September 200migration was detected or suspected to have occurred. 3. The purpose of the shallow monitoring was to determine if 

into shallow geology, groundwater, or ecosystems either thropathways or up the well bore. 4. Monitoring was performed in the target reservoir with timedown hole geophysical methods and in the near surface with groundwater quality testing. Although the injection well for the Escatawpa project was pethe Mississippi Department of Environmental Quality (MDEQmore stringent Class I hazardous waste injection well (Class I

standards be met. Construction to these Class IH standards w
Comments of the Carbon Sequestration Council 4 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

proposed by the SECARB project team. EPA should not condesign standards are warranted based on this single pilot projdid not even assess the sufficiency of alternative designs. Insadopt less prescriptive standards that are sufficiently protectivindustry’s more than 35 years of success in injecting CO2 und

program. The Class II EOR wells constructed for these projeoperating practices - have an excellent record of mechanical iprotecting USDWs. At this point it cannot be concluded that the project componedesign demonstrate and validate EPA’s well construction, opmonitoring requirements. Since this was a research and develrequirements were more stringent and some may have been lewould be required for a commercial-scale geologic sequestratThe Escatawpa project was essentially an injection test but wfrom the standpoint of outreach and education, permitting prosite characterization. Some of the practices employed at Escatawpa, such as cemencasing to surface, may not be possible in all circumstances. TSECARB project do not imply that less burdensome regulatioworked equally well. See the construction recommendations MSD Recommendation Letters of May 14, 2009 and May 15

9 44806 The Aneth Field project 

confirms the need for a project design with a robust monitoring plan, and tests the importance of monitoring and modeling agreement in GS projects. 

Data collected for monitoring will allow for improvement andexisting model. As the feedback between monitoring and moconfidence, the monitoring plan can be adapted as needed (Se2009). It is important that the regulations allow for refinemenmonitoring plan, should modeling or reservoir performance roperational or monitoring changes are appropriate.

10 44806 In addition, the project 

demonstrates the utility of 

There are many monitoring tools that could be shown to have does not follow that every tool – or any particular tool – shou
Comments of the Carbon Sequestration Council 5 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

various monitoring technologies that may be used by owners and operators of Class VI wells. 

required for every geological sequestration project, especially of these monitoring techniques from pilot to commercial scalprohibitive. For example, soil and air monitoring are unneceforeseeable circumstances. The testing of particular monitorinot show the necessity of these techniques or the inadequacy were not tested. Soil flux monitoring was not valuable to the because background and control point measurements were hidata interpretation was difficult. Tracers also did not appear t

11 44806 The Agency sought comment on 

using unmineable coal seams for GS in the proposed rule. The investigation at Pump Canyon will inform a determination on whether CO2 can be effectively and safely sequestered in coal seams. 

Coal bed injection is promising, but it is at a more experimen

injection into other types of reservoirs. CO2 storage within c

but complicated, due to swelling of the coal as methane is dis

fracturing , and the low permeability of coal matrices. We recommend that coal bed injection wells used for GS be lexperimental wells at this time. See MSD Recommendation Item 1. 

12 44807 LBNL conducted multiple 

model runs to assess a variety of scenarios and aquifer conditions and, as discussed below, found that if injected CO2 comes into contact with shallow USDWs, some trace element concentrations such as arsenic could increase. 

The LBNL study goal, as stated in Apps, et al., 2009, is to de“comprehensive geochemical model that describes the complrange of specified shallow aquifer systems”. In reality, they d“representative groundwater” (NODA p. 44807). See Attach

13 44807 A preliminary assessment of 

CO2-related water quality 

changes, including pH, was conducted by calculating the expected equilibrium concentrations of trace elements as a function of the amount of 

The groundwater samples chosen for the model had to have bleast one of the following to be included in the study: As, BaU, or Zn. These analyses are not commonly run in parts of thknown to be free of heavy metal contamination. There will liof the U.S. where the mobilization of arsenic, lead, and other 

a concern because the minerals that these elements are typicapresent in those formations. This does not necessarily render 
Comments of the Carbon Sequestration Council 6 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

CO2 in a representative potable groundwater. Results of this modeling obtained for typical aquifers under reducing conditions indicate that arsenic could potentially exceed Federal drinking water standards at elevated CO2 concentrations (40 CFR 141.62 (b)(16)). 

invalid, but it does indicate that the results may not be typical representative. 

14 44807 Other trace elements, such as 

barium, cadmium, lead, antimony, and zinc, may also be mobilized in certain circumstances, but the majority of results did not show mobilization at levels exceeding the MCL or AL. (action level) 

The modeling used a number of assumptions in order to test selement mobilization was likely to occur. The results focused given elements would exceed the maximum contaminant levewhether mobilization would realistically occur in various sce

15 44807 While LBNL studies did suggest 

that CO2 interaction could cause significant concentration increases compared to the initial water composition, the MCL for arsenic was exceeded in only a few simulation scenarios, while the lead concentrations remained below the AL under all scenarios. 

To the extent that these studies could be viewed as presenting some comfort might be drawn from such results. We are conwith the absence of realistic scenarios, as noted below. It is mview the studies to date as a preliminary test of the methods aSubsequent testing might provide useful results as realistic scdeveloped and particularly as the methods can be tested with characteristics. The identification of methodologies and poteuseful by itself as a step toward site assessment and the develand management plans. 

16 44807 It is important to emphasize that 

these studies looked at potential consequences of CO2 leakage into the USDW, not the likelihood of such leakage 

The probability of trace element contamination of groundwatmultiplied probabilities of CO2 movement out of the intended finding a migration path to a USDW, passing through or endiminerals that contain heavy metal assemblages, environmentafavorable to dissolution, and an undetected, unremediated lea
Comments of the Carbon Sequestration Council 7 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

occurring. these elements. The probability of USDW contamination, ba

probabilities of each of these individual events, will be differThe risk of trace metal contamination of groundwater will typknowable, and manageable at well selected and managed geo

17 44808 The Agency will use these 

preliminary results and public comments on this research as well as potential site-specific analyses, to refine and inform site characterization, monitoring, and remediation requirements and guidance, if necessary, in the Agency’s final rulemaking. 

In general, reactive transport modeling represents the correct evaluating the possible impacts on USDWs by the leakage of 

underlying CCS reservoir. The LBNL work verifies that TOUtransport modeling technology is suitable for this purpose. Horeported by Zheng et al. are based on hypothetical cases. Theto establish regulations because: (1) these results have not beeanalog scenarios; (2) the recompiled thermodynamic data theverified by experimental data; (3) more realistic conditions an

the migration of a mixture of CO2-saturated reservoir brine, sand/or other gases are not considered; and (4) their model doedynamic effects during the loss of containment for a CCS res

18 44808 The Agency seeks comment on 

this research and any additional studies related to a) mobilization of constituents and b) the likelihood or frequency of such leakage/risks. 

See the following references (full citation in “References” beSmyth, R.C., et al., 2009 Koplos, J., 2007 Duncan, et al., 2009

19 44808 LBNL studied a hypothetical, 

future scenario of GS in a sedimentary basin as an illustrative example to demonstrate the potential for basin-scale hydrologic impacts of CO2 storage (Birkholzer et al., 2008b). 

Modeling Issues: 

• The model assumes lateral homogeneity of all stratigrap• Permeability in the Eau Claire Shale top seal may vary lateral sense at regional scales (Arnold et al., 1996). In the permeability is uniform. • Compressibility values of the Mount Simon are less thaIncreasing compressibility would reduce the predicted pres• It was noted in Juanes, 2006, that in general coarse grid

movement and capillary trapping. The adaptive gridding apIllinois Basin model uses progressively larger grid cells awarea. The largest cells near the edge of the basin are 10 x 1
Comments of the Carbon Sequestration Council 8 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

maximum thickness of any grid block was set to 10 m. The and large size of these cells may introduce significant numethe model results. Conclusions based on the modeled brine basin and far field pressure effects should be considered qugiven the constraints of the model. 

20 44808 [S]imulation runs indicated that 

injection pressures did not exceed fracture pressure or the maximum value used in the model for this basin. However, results also indicated that farfield pressure changes could propagate as far away as 200 km (124 miles) from the core injection area where the geologic sequestration projects are located. 

The far-field pressure changes observed in the model are on t(14-29 psi). These changes are very small, and would not lik

observed if the model had included lateral heterogeneities in porosity and higher compressibility. The predicted pressure p

minor that they could not be accurately distinguished from nopressure data collection. 

21 44808 “[A] pressure increase of 0.5 bar 

existed at an areal extent of nearly 400 km by 400 km (249 miles by 249 miles) after 50 years. These model results indicate that basin-wide pressure influences can be large and may have intersecting pressure perturbations in a multiple-site scenario.” 

Regarding the NODA summary of LBNL studies on “Basin-SImpacts of CO2 Storage”, we feel that a clarification of the re

preliminary simulation and their implications are needed. In noted that, a pressure increase of 0.5 bar might be expected athe regional aquifer (200 km from the core injection area). Tstates that “...basin-wide pressure influences can be large.” bar (~0.5 atm) pressure elevation at the perimeter of the basin Whereas we recognize that pressure perturbations will be signinjection area (especially where pressure fields intersect), a 0pressure at the basin perimeter is not significant in terms of thcontainment. 

22 44808 While simulated changes in 

salinity within the storage formation were relatively small, 

Water displacement up dip was insignificant in this study as w

2008, in which the equivalent of 50 million tons of CO2 was i

50 years, resulting in an average water table rise of only abou
Comments of the Carbon Sequestration Council 9 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

the predicted pressure changes could push saline water upward into overlying aquifers if localized pathways such as conductive faults existed. 

Storage locations with significant faulting would have to be cfor leakage potential. The oil and gas industry has developed and workflows to predict whether a given fault is likely to lea

have been tested on numerous hydrocarbon prospects and grofaults known to seal or leak. 

23 44808 As these large scale simulations 

indicated, limitations on injection volumes related to basin-scale pressure build-up should be considered during CO2 capacity estimation. 

Basin-scale modeling can be informative with respect to issuein the future with multiple injection projects using the same sgiven basin. The work of Birkholzer, Zhou and others (referrherein) is illustrative in this regard in that it utilizes an actual characterized basin framework. In assessing the pressure fielmigration potential developed as part of this work, it has to bhowever, that a spatially concentrated and certainly arbitrary was required to generate the perturbations resulting in the moscenario was designed to create these perturbations and in itsemember of the range of scenarios that might be utilized. Certhad to be made regarding increases in seal permeability to geresults and these assumptions need significant refinement. Aacceptable as a modeling exercise and as a guide to future stupredictable outcome or even a generalized outcome, and in fafor further strategies for pressure monitoring and the improvemodels. Although the authors highlight far-field impacts, it ito consider any basin-scale mandates other than intensive datassessment, including support for improvement in basin-scale that are indicators of large-scale hydrologic impacts. This woan indicator of a research need, given the hypothetical concenlarge storage projects in a limited area, not of the need for devbasin-scale regulations as part of the current Class VI developlatter approach would be counterproductive in that it may negdevelopment of multiple initial projects essential to more defvery safeguards that groundwater protection strategies are deand (2) suppress the realization of more appropriate injection 
Comments of the Carbon Sequestration Council 10 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

period, and placement) that would yield more realistic results selected for the author’s modeling. Support of this position is found in the authors work. They civelocity across the top model boundary, averaged over the mmm/year at 50 years of injection and an average Darcy velociboundaries of about half that value. The authors then go on tmigration distances of saline water associated with these bouconstitute a concern for the groundwater resources in overlyinneighboring basins.” The authors also note that current groun

practices in the northern Illinois Basin are pulling saline watewells, and that “these impacts dwarf the predicted environmethe hypothetical CO2 storage scenario studied...”. New data are being developed as a result of currently funded deployment testing. An example of the impacts of incompletparameters can be seen in the discussion of hydraulic diffusivthe Illinois Basin indicates that the porosity value chosen for relative to higher porosity values obtained from recent drillininjection area, thus recent data would tend to reduce the pressoutside of the injection area. The authors narrate a sensitivity state, would reduce the region from 190 km to only 60 km in also be dependent on lower permeability and greater compresthe higher porosity. Again, initial storage project developmebetter define key parameters. Further, it is also important to recognize that the discussion oassessments for the basin compared to the 50-year, 5,000 Mt model confuses the sequestration resource with basin capacity 

the DOE atlas are resources, not capacity. There is no expectDOE resource assessments would represent actual capacity. statement that these resource estimates are subject to “an imp
Comments of the Carbon Sequestration Council 11 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

the storage capacity is not constrained by pressure buildup anmigration...” is incorrect, and researchers involved with crea

would be unlikely to agree with this assumption. These are nof the work, simply an indication that definitions need to be rterminology needs to become more widespread. The authors basin with multiple storage sites, industrial-scale storage projsupply valuable data “to reliably estimate the expected pressuprojects”. That is certainly where we must go to answer key acknowledging that the state of understanding of modeling basequestration impacts is in its early stages and is premature fotime. 

24 44808 EPA believes that the example 

studied by LBN L illustrates the importance of basin-scale evaluation of reservoir pressures and far-field pressures resulting from CO2 injection. EPA requests comment on this study and welcomes additional studies that provide information on the need for basin-scale evaluations for GS injection. 

The model results are not applicable to Area of Review decissite selection this early in the development of geologic storag

making would allow for adjustments to encompass multi-projsame basin if needed in the future. See MSG Joint Letter datItem 2 on suggested language for managing pressure interferethis recommended provision will help to address and manage interference concerns if and when they occur.) 

25 44808 Schnaar and Digiulio (2009) 

present a research review of over forty GS modeling studies spanning from 1993-2008. The complete modeling review is available in the online public docket at www.regulations.gov. 

The identified “need to couple multiphase flow, reactive tran

geomechanical processes” (NODA p.44808) is an idealized ctrue need. Such a model is certainly possible but will likely bexpensive, and it will still be at the mercy of the quality of thimportant to correctly capture the range of processes and posgiven location than to use a particular software package or tyRobust yet less complex models capturing the most importanchemical processes can accomplish the modeling goals necesThe Schnaar and Digiulio, 2009 literature review on CO2 mo
Comments of the Carbon Sequestration Council 12 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

heavily on finite difference simulation of CO2 storage in salin

on references to analogous modeling of CO2-EOR storage an

storage, and also short on alternative flow modeling theories applied to certain geologic storage applications.

26 44809 The basis of these requirements 

is the principle that placing distance between the injection formation and USDWs decreases risks to USDWs. 

This is too simplistic; distance will undoubtedly help, but disdeserve to be singled out like this. The nature and characterismaterial is paramount and must be considered along with distthe sufficiency of containment at any particular site. 

27 44809 In these deep-well injection 

scenarios, the added depth and distance between the injection zone and overlying formations serve both as a buffer allowing for pressure dissipation and as a zone for monitoring that may detect any excursions (of the injectate) out of the injection zone. 

Again, this assertion goes too far. Distance is not the only wa

these objectives and will not make up for otherwise poor site does the lack of depth defeat a good site with sufficient conta

28 44809 Additional distance also allows 

trapping mechanisms, including dissolution of CO2 in native fluids and mineralization, to occur over time – thereby reducing risks that CO2 may 

migrate from the injection zone and endanger USDWs. 

Site selection and characterization must focus on the trapping 

mechanisms themselves without giving undue weigh to distanrole but is not always determinative. 

29 44809 Additionally, the depth and 

distance below the lowermost USDW allow the potential for the presence of additional confining layers (between the 

If demonstrated containment is sufficient to meet the siting re

additional confining layers are unnecessary. 
Comments of the Carbon Sequestration Council 13 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

injection zone and overlying formations/USDWs). 

30 44809 Water availability research in 

the United States indicates that water treatment of higher salinity waters (in excess of the USDW protectiveness threshold of 10,000 ppm TDS) may be more cost effective than the cost of obtaining water rights or surface water elsewhere in the area (Sengebush, 2008). 

There is a growing recognition that CCS may be treated as a 

future long term planning should include provision for CO2 s

water supply. The appropriate authorities will need to work tsuch plans to assure that resources are effectively deployed. Rthis activity falls outside that of individual CCS project devel

31 44809 Furthermore, some specific 

research on CO2 injection for GS into various formations including shallow, volcanic rocks such as flood basalts (McGrail, et al., 2006) and coal seam injection (Dooley, et al., 2006; IPCC, 2005; MIT 2007; White et al., 2005) illustrates the potential for GS in these formations, but only if there is depth requirement flexibility. 

The Council agrees that broad categories of formations shoulexcluded from use solely on the grounds of underlying USDWshould be able to consider all locations and receiving injectiomeet the siting requirements by providing sufficient containmThe proposed exclusion of formations is thus inconsistent witadaptability approach in disallowing for the advancements thresearch and development projects that identify additional suiformations for GS. The Council has joined with other MSD participants to recomin basalts, coal seams, salt caverns and shale formations shouexperimental wells under Class V, recognizing that completinresearch, development and demonstration likely will require iexperimental projects in addition to pilot projects. “Keeping these wells under Class V would allow EPA and thenough experience to develop suitable permitting requiremento tailor those requirements at both the pilot and commercial agencies are ready to regulate such wells under an appropriatRecommendation Letter, May 14, 2009, Item 1. 
Comments of the Carbon Sequestration Council 14 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 32 44809 Certain States have indicated 

that where USDWs are very deep (e.g., 15,000 ft/4,572 meters and deeper) and layered (stratified) these regions would become unavailable for largescale GS projects because injectors would not be able to comply with the current injection depth (and well construction) requirements. These States suggest that GS should be allowed in certain areas if a site-specific demonstration can be made that USDWs will be protected. 

We support the provision to allow CO2 injection into formati

lowermost USDW when adequate containment of injected CO

USDWs can be demonstrated. As noted in our comments of we would prefer to have the necessary criteria for GS project containment demonstration built into the normal permitting prequirements would be routinely applicable whenever a permproposing to inject into a saline formation that is above the loThe permitting process – with the notice, comment, hearing aprovisions we support – would provide adequately for considnecessary technical issues. Nevertheless, we also believe thasite-specific waiver process for geologic storage above the lobe made workable but requires some improvements which arin these Comments. 

33 44809-

10 

Class II and Class III owners and operators of sites where injection is taking place above and between USDWs must identify and demonstrate upper and lower impermeable confining units. These confining units serve as barriers to fluid movement and pressure and must ensure continuous injectate isolation, confinement, and USDW protection. Identification of such units is conducted through analysis of sonic and resistivity logs, drill stem tests, and wire line tests. 

The requirement to demonstrate the suitability of the confininproposed injection zone is reasonable and technically feasiblecharacterization requirements are not significantly different thstorage below the lowermost USDW. As reflected in recommendations presented by the Multi-Stakparticipants in the MSD Recommendation Letters of DecembOctober 9, 2009, which the Council and many of our memberrequirement that GS take place in formations beneath the lowshould not be imposed on GS taking place in oil and gas rese

which are located above the lowermost USDW and have dem

containment capabilities over geologic time and through mangas production operations. 
Comments of the Carbon Sequestration Council 15 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 34 44810 EPA believes that a waiver 

process may respond to the range of comments, both for and against the proposed requirement that Class VI wells inject below the lowermost USDW. 

EPA should integrate the waiver process into the normal permas much as possible, for example, by combining the public hewith the public hearing for the permit, if one is held. Hearingoption, and not an automatic requirement. Hearings should bpotential option but should not be required unless warranted ithe Director. 

35 44810 EPA believes this approach may 

additionally accommodate requests for geographic flexibility while placing such determinations at the State or Regional level. 

These determinations should be at the state or regional level, Regions often will not be in a position to make these determinas a state agency because the EPA regional offices typically hinvolvement in the related areas of program oversight. Wheroffices are making permitting decisions for Class VI wells, thwith the relevant state agencies. 

36 44810 Lastly, the approach is designed 

to acknowledge and accommodate comments and concerns about drinking water resource availability and the potential/known future needs, and to afford such water resources protection. 

EPA should clarify the scope and applicability of the proposeFirst, EPA's intent appears to be to issue waivers only for situsaline reservoir is overlying a USDW. These conditions are uwould not address the problem faced in large portions of the w

USDWs may extend from the surface to very great depths. Tthese regions, the waivers would necessarily have to authorizUSDWs above the lowermost USDW. Second, for the waiveffectively, the final decision making authority for a waiver s

agency holding primacy for the proposed Class VI UIC progr

37 44810 Second, the alternative under 

consideration does not prohibit injection into any specific formation types (e.g., basalts and/or coal seams). It affords all formations equal treatment and allows specific regions of the country the regulatory flexibility to determine if any injection at a particular site and depth is the 

We are supportive of EPA’s effort to introduce flexibility on injection relative to the location of USDWs by proposing a w

stated in our December 24, 2008 Comments, we agree that C

above a USDW while protecting the USDW and maintaining for future use. As noted in our Comments, the Salt Creek EOWyoming, which has a USDW below the injection zone, is an of how industry can operate CO2 injection wells in an EOR c

endangering or limiting access to USDWs that are located bezone. Accessing USDWs below a CCS site, while not trivialsignificant technological hurdles. Industry has the technolog
Comments of the Carbon Sequestration Council 16 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

appropriate approach. It will also help to manage injection in areas where there may be multiple, stratified formations with significant assessed cumulative capacity. 

over-pressured gas reservoirs which are analogous to CCS sitexcellent examples of off-shore technologies for drilling throand shallow gas pockets that involve the same type of pressurbe encountered in drilling through a CCS site. 

38 44810 Third, because the Agency 

believes that it is necessary to address the specific, unique characteristics of Class VI injection (e.g., large injection volumes, viscosity, and buoyancy) and the Agency does not have information or data indicating that Class II operations are entirely analogous to Class VI, large-scale injection, this alternative allows Class VI injection depth considerations to be tailored for GS. 

Within the past year, there have been several papers that have excellent record of producing, transporting, and injecting CO

Duncan et al. (2009) examines the safety risks associated wit

sequestration by taking a systematic review of all accident anassociated with CO2 pipeline transport and injection and find

EOR industry has an excellent safety record” and “the rarity oincidents reflects the industries [sic] success in implementing measures.” The second study by Smyth et al. (2009) demonprotection of the environment. It examines the groundwater iCO2-EOR field and finds “that no widespread degradation of inside the SACROC oilfiled [sic] as a result of CO2-injection

the mechanical integrity of CO2 injection wells is in progress 

completed in time for consideration by EPA. 

39 44810 A number of dominant 

differences between Class II and Class VI operations indicate that these well classes warrant different treatment. EPA received comment during the public comment period supporting the need for such a distinction. These differences include: the risk profiles for these operations; the greater 

The Multi-Stakeholder discussions (MSD) and recommendatparticipants have addressed these issues in a series of recommaccount for the different risk profiles. The December 23, 2008 letter from MSD participants explainreached on the proposed language describing wells in a propoclassification 40 CFR 146.5(b)(4) that would establish a “brigdistinguishing (1) wells that inject CO2 for EOR/EGR and tho

for GS in conjunction with EOR/EGR from (2) wells that inje

where EOR/EGR activities and any hydrocarbon production wThe signatories to the December 23, 2008, letter recommende
Comments of the Carbon Sequestration Council 17 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

total injection volumes (of CO2) for Class VI GS; and, differences in formation pressures (potentially higher for GS), greater opportunities for mobilization of constituents, and injection rates and operating conditions. 

EPA’s intent, that wells used for EOR/EGR should remain in wells used for EOR/EGR with GS – that meet the recommend– should also remain in Class II and be subject to the current Class II. Signatories to that letter also agreed that the wells usgas reservoirs that do not meet the criteria of (b)(4) should be requirements. That letter noted an agreement to define such w“for geologic sequestration in oil and gas formations and wheparagraph (b)(4) are not met.” In a letter dated October 9, 2009, MSD participants agreed thin oil and gas reservoirs that do not meet the criteria of paragrsubject to a set of additional requirements different from thosunder the current Class II provisions to wells that inject CO2 GS, due to the potential change in the risk profile when EOR/cease. This common view is also reflected in the four letters March 17, 2009 from MSD participants. Each of those March to include this approach in its final GS rule. Accordingly, EPrecommended provisions for a new section 146.25 and the resubmitted with respect to Class V GS wells and Class VI GS Recommendation Letters dated December 23, 2008; May 14, 2009. 

40 44810 The alternative EPA is 

considering relies on the principle of site-suitability for GS: injection zones/formations that have suitable upper and lower confining units, appropriate lateral and vertical extent to receive and contain the injected CO2, and an appropriate management scheme to ensure that the water and other 

We support the provision to allow CO2 injection into formatilowermost USDW when adequate containment of injected CO

USDWs can be demonstrated. As noted in our comments of we would prefer to have the necessary criteria for GS project containment demonstration built into the normal permitting prequirements would be routinely applicable whenever a permproposing to inject into a saline formation that is above the loThe permitting process – with the notice, comment, hearing aprovisions we support – would provide adequately for considnecessary technical issues. Nevertheless, we also believe thasite-specific waiver process for geologic storage above the lo
Comments of the Carbon Sequestration Council 18 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

resources contained within the injection zone will not be needed in the future. The management scheme will also ensure that there is a strategy developed to address future needs to access formations below the injection zone. 

be made workable but requires some improvements which arin these Comments. We are concerned in particular that EPA may lack the authorwaiver process as specifically presented in the NODA becausdecisionmaking authority that EPA appears to be proposing flacks a decisionmaking standard that is consistent with the exrequirements of the SDWA and EPA’s UIC regulations; assigPWSS Directors would encroach upon the prerogatives of the UIC primacy program in violation of the UIC regulations; anauthority between UIC Directors and PWSS Directors would inefficient, and potentially disruptive if the Directors disagree 

41 44810 EPA is weighing the fact that 

this alternative would be a divergence from the existing UIC deep-well injection requirements for industrial and hazardous waste injection. It will result in greater injection depth variability throughout the United States and may result in emplacement of fluids by injection in closer proximity to USDWs than would occur under the proposed requirements. Additionally, adoption of this alternative could potentially add a new administrative burden to UIC programs pursuing the waiver approach. 

Divergence from deep well injection requirements for industrwastes is completely justified because GS does not involve wthe same risk profiles. Moreover, this limitation on waste injoriginal part of the UIC program and, as has been noted in coproposal, is not warranted in all instances for waste disposal. 

this one run counter to EPA’s avowed commitments to perfor

adaptable requirements. Instead of identifying and applying tcontainment criteria, EPA would be imposing a requirement thave already shown to be unwarranted in every instance. The burdens to which EPA alludes could be avoided by incorporaconsideration of appropriate requirements for injection above USDW into the normal permitting process rather than in a sepprocess. The burdens also can be minimized by integrating ththese criteria as closely as possible with the GS UIC permittinminimizing the amount of duplicative reviews that are requireby separate agencies at the state and/or EPA regional levels. 

42 44810 The owner or operator would be 

required to demonstrate to 

As stated in the Council’s December 23, we support the use o

these criteria to the extent necessary to protect USDWs. We 
Comments of the Carbon Sequestration Council 19 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

regulatory authorities that such injection can be undertaken and completed in a manner that prevents fluid movement into overlying (and underlying) USDWs, thereby preventing the endangerment of public health from USDW contamination. 

particular reason why these criteria could not be specified and of the regular permit application process when injection is prinjection zone that is overlying a USDW. 

43 44810 This process would be separate 

from aquifer exemptions and has no effect on 40 CFR Parts 144.7 and 146.4. 

In many cases, waivers are likely to require an aquifer exempzone itself. Consequently, it is unclear as to how a waiver prbeneficial to either state agencies or applicants. If states still aquifer exemption; which must be approved by EPA, we belinegate the benefit of a waiver process that does not require EFurther, 40 CFR Part 146.4 does not currently have a criterioexemption on the basis of “use as a storage zone for CO2 geoSince no changes to the aquifer exemption criteria have been that obtaining an exemption for USDWs above the lowermospurpose of geosequestration would be very difficult. In effecrequirement for injection below the lowermost USDW regardnot a waiver process exists. 

44 44811 The waiver application would 

need to demonstrate: 1) Laterally continuous, impermeable confining units above and below the injection zone adequate to prevent fluid movement and pressure buildup; 2) A laterally continuous injection zone/formation with adequate injectability, including sufficient porosity and permeability, and appropriate 

The information identified in item 3 is important for confininnecessary for things that occur solely within an injection zonejoined with other MSD participants in recommending a revisetransmissive faults or fractures that takes into account the pot

the lowermost USDW: The recommendation recognizes that EPA’s proposed rule in require a confining zone(s) that is free of transmissive faults o

proposed §146.81 would define this term as “A fault or fractupermeability and vertical extent to allow fluids to move betwThe MSD letter recommends the following modification to th
Comments of the Carbon Sequestration Council 20 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

soil-rock chemistry (so as to ensure that the injection matrix is not dissolved as a result of injection); 3) An injection zone and confining formations free of transmissive fractures and faults; and, 4) A characterization of regional fracture properties and a demonstration that such fractures will not interfere with injection, serve as conduits, or endanger USDWs. 

§146.81(d) in order to avoid unduly restricting movement thaformations: “Transmissive fault or fracture means a fault or fracture that hpermeability and vertical extent to allow fluids to move beyozone.” MSD Recommendation Letter, May 14, 2009, Item 3. 

45 44811 Due to the potential risk that 

artificial penetrations pose as fluid/injectate conduits, the owner/operator would need to map and identify all artificial penetrations in the AoR that penetrate the injection zone, the 

upper and lower confining zones, and all USDWs in the area. The purpose of this demonstration would be to ensure that public water supplies, private wells, and potential future water resources are identified and the location of artificial penetrations into such formations are known and these artificial penetrations can be 

appropriately plugged during the permitting phase. 

These requirements for the area of review and corrective actiowould apply to all permit applications. It should not be neceswells during the permitting phase, only to demonstrate either constructed and/or plugged so as to prevent fluid movement uUSDWs, or that a plan will be executed to remediate wells thappropriately constructed and/or plugged. See Bachu and Wcharacteristics in pre-existing wells that correspond to higher 
Comments of the Carbon Sequestration Council 21 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 46 44811 The owner or operator would 

need to supplement the emergency and remedial response plan (submitted as part of the waiver application process and as part of the UIC Class VI permit) to ensure protection of USDWs above and below the injection zone. The purpose of this plan would be to explain that the owner or operator has considered regional water resource issues and has explored alternative water supplies or water treatment options to address unanticipated movement of the injectate or formation fluids (e.g., CO2, brine, or other 

fluids) into any overlying or underlying USDWs. 

The requirements described would not be any different from required in this context under the original proposed Class VI the extent that this statement is intended to indicate that multiplans must be prepared and submitted, such a requirement wounwarranted burden on both applicants and permitting agencian approach could lead to having inconsistent plans for GS prEPA should clarify exactly what is to be required and should permit and waiver application can be a single submission to tagency. It is confusing to refer to a need to “supplement” the remedial response plan when it is clear from the context that application for GS injection into a formation above the lowerneed to include these explanations from the outset rather than 

47 44811 The owner/operator would also 

demonstrate sufficient, additional financial responsibility to address any potential contamination of USDWs above or below the injection zone. 

Financial assurance is tied to plans and should not be changed requirement. There is no appropriate additional basis for addcontamination” beyond what would already be required in prmaintaining the appropriate required plans. 

48 44811 Upon compliance with the 

waiver process requirements, the owner/operator would need to submit the information jointly to the UIC Program Director and 

The language in this statement may be creating unnecessary c

intent is to provide for notice to the PWSS Program Director 

comments can be submitted to the UIC Program Director for preparing and approving a permit, that would be acceptable. 

however, suggest that there would be shared decisionmaking 
Comments of the Carbon Sequestration Council 22 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

the PWSS Program Director. Directors, which would be inefficient and could lead to confl

agencies. Moreover, this type of approach would not be legaprovisions of the SDWA and 40 CFR Part 145, which allow sagencies to participate in UIC permitting and to provide how will be divided among the participating state agencies. 40 CFauthority for granting a waiver should rest solely with the staagency. 

49 44811 These Directors would consider 

factors such as: * * * • The potential capacity of the geologic formation to sequester CO2, accounting for the 

availability of alternative injection sites; * * * 

There are many factors that project developers must consider appropriate site for geologic sequestration. A review of the e

process and alternatives is not an appropriate task for Directobe a need to make comparison demonstrations to prove one sanother if the proposed GS site meets all of the permitting req

50 44811 • Planned needs, potential and/or 

future use of USDWs and nonUSDWs in the area; 

Concrete plans for future use of formations can and should be in comments from the PWSS Director for consideration but mwithin the context of the SDWA endangerment standard for p

51 44811 • 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; 

Same comment as 50 above. 

52 44811 • The proposed plan for securing 

alternative resources or treating 

This is a matter to be addressed on a site-specific basis by the 

the emergency response plan. It should not be required in all 
Comments of the Carbon Sequestration Council 23 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

USDW formation waters in the event of contamination related to the Class VI injection activity; and, 

should be a part of the plan only where chosen as an approach owner/operator to meet the regular permit requirement for premaintenance of that plan. 

53 44811 • Any other locally applicable 

considerations. 

Such considerations would be appropriate to the extent relateendangerment standard that is applied by the Director in makdecisions. 

54 44811 The waiver may also be subject 

to local notice and public hearing. Following a public hearing and waiver approval by both Program Directors, the owner/operator may complete and submit the Class VI permit application. 

The authority for granting a waiver should rest solely with thagency. It would, however, seem appropriate to provide a spthe PWSS Director with opportunity to comment. 

55 44811 The owner/operator may be 

required to comply with additional requirements that apply as a result of receipt of the waiver, designed to ensure the protection of USDWs both above and below the injection zone. 

Appropriate permit conditions may be included as necessary 

protection of USDWs both above and below the injection zonrequirements of the proposed rule, additional requirements unwaiver should be appropriate and site specific. For example, 

tracking may not be possible in some instances but other monmay provide sufficient protection of USDWs. 

56 44811 Due to the range of concerns and 

comments related to the injection depth requirements and the nature of the suggested waiver approval procedure, EPA believes that adoption of any such injection depth waiver process, as previously described, should be at the discretion of the 

There should not be a requirement for states to make special a

conduct a waiver program; the use of formations above the loshould be available where permit requirements can be met. Sthe ability to impose more stringent requirements if they choo
Comments of the Carbon Sequestration Council 24 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

UIC Program Director. 

57 44811 Some stakeholders are 

concerned about the risks associated with the use of formations other than deep saline and depleted reservoirs (e.g., coal seams, basalts, etc.). EPA is seeking comment on whether the waiver process should apply to formations other than these. 

The Council has joined with other MSD participants to make recommendations regarding these types of formations: “We agree that EPA has ample basis for adopting rules to reghydrocarbon reservoirs and in deep saline formations under th

types of geologic formations, there is a widespread technical 

assess and manage risks, what data is needed to characterize sites, how to conduct injection operations, how to model the b

the reservoir, and how to monitor project performance. “There is less technical support on the ability to conduct GS iseams, salt caverns, and shales. As compared with deep salinhydrocarbon reservoirs, the trapping/containment mechanism

operational engineering involved in basalts, coal seams, salt cmay be significantly different and using identical regulatory lbe appropriate. In fact, it is not known at this time whether Gin some cases) can be done at commercial scale in each of theformations – GS efforts in these formations are still in the expWells in basalts, coal seams, salt caverns and shale formationas experimental wells under Class V, recognizing that compleresearch, development and demonstration likely will require iexperimental projects in addition to pilot projects. “Keeping these wells under Class V would allow EPA and thenough experience to develop suitable permitting requiremento tailor those requirements at both the pilot and commercial agencies are ready to regulate such wells under an appropriat“To implement this approach, sections 144.6(f), 144.80(f), 14definition of sequestration in 146.81 should be revised. The pprovision that the construction, operation or maintenance of aClass V GS well is prohibited should be retained, but only wi
Comments of the Carbon Sequestration Council 25 rfvanvooNo. Page Issue Topic from EPA’s NODA Carbon Sequestration Council Comments 

that this prohibition is not intended to limit the size or scale oGS operation.” MSD Recommendation Letter May 14, 2009

58 44811-

44812 

Additionally, the Agency is interested in: 1) Information on specific areas of the United States where injection depth and USDW depth are of concern (including formation depth, location, and assessed capacity; demonstrated confinement and GS suitability; and, formation salinity/TDS) as determined by well-log analyses, cross sections, and formation fluid analyses; 2) Data, information, and evidence from owners and operators constructing and operating injection wells through existing CO2 plumes to access resources 

(e.g., water, hydrocarbon, etc.) below the injection zone and whether or not such operations are safe and do not endanger USDWs; and, 3) Strategies that States, Tribes, and regions are considering to manage competing GS and resource issues. 

As noted in our Comments, the Salt Creek EOR project in WUSDW below the injection zone, is an excellent example of hoperate CO2 injection wells in an EOR context without endanaccess to USDWs that are located below the injection zone. Abelow a CCS site, while not trivial, does not present significahurdles. Industry has the technology to drill through over-prereservoirs which are analogous to CCS sites. There are some of off-shore technologies for drilling through salt formations pockets that involve the same type of pressure issues that wouin drilling through a CCS site. 
References 

Apps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J., 2009, Identification of thermodynamic controls defconcentrations of hazardous elements in potable ground waters and the potential impact of increasing carbon dioGHGT-9, Energy Procedia I, 1917-1924. Arnold, T., Bahr, J., and Fantucci, R., 1996, Paleohydrogeology of the Upper Mississippi Valley Zinc-Lead DistrF., ed., Carbonate-Hosted Lead-Zinc Deposits, Society of Economic Geologists Special Publication Number 4, pBachu, S. and Watson T., Factors Affecting or Indicating Potential Wellbore Leakage, IEA GHG 3rd Wellbore InMeeting, Santa Fe, 2007. Chadwick, A., Arts, R., Bernstone, C., May, F., Thibeau, S., and Zweigel, P., 2008, Best Practice for the Storage Aquifers - Observations and Guidelines from the SACS and CO2STORE projects: Nottingham, UK, British Geo267pp. (British Geological Survey Occasional Publication, 14). Cooper, C., ed., 2009, A Technical Basis for Carbon Dioxide Storage: New York, Chris Fowler International, C86p. Duncan, I., Nicot, J. P., and Choi, J., 2009, Risk assessment for future CO2 sequestration projects based on CO2 ein the U.S., GHGT-9, Energy Procedia I, 2037-2042 – presented at the 9th International Conference on GreenhouTechnologies (GHGT-9), Washington, D.C., November 16-20, 2008. GCCC Digital Publication Series #08-03i. Duncker Romanak, K., 1997, Vadose-Zone Geochemistry of Playa Wetlands, High Plains, Texas, The University Ph.D. dissertation, 273 p., 49 figs. Holloway, S., ed., 2003: Saline Aquifer CO2 Storage project (SACS) - Best Practice Manual. - IEA Greenhouse G

Programme, Report PH4/21, 53pp. Juanes, R., Spiteri, E.J., Orr, F.M., and Blunt, M.J., 2006, Impact of relative permeability hysteresis on geologica

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

Comments of the Carbon Sequestration Council 26 rfvanvoo
Comments of the Carbon Sequestration Council 27 rfvanvooKoplos, J., 2007, A Review of Injection Well Mechanical Integrity Testing Data and Implications for GeosequesWellbore Integrity Network Meeting, Santa Fe, 2007. Smyth, R.C., Hovarka, S., Lu, J., Romanak, K., Partin, J., Wong, C., and Yang, C., 2009, Assessing risk to fresh long term CO2 injection – laboratory and field studies, GHGT-9, Energy Procedia I: 1957-1964 – paper GCCC D

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

November 16-20, 2008. Download from BEG/UT website: http://www.beg.utexas.edu/gccc/bookshelf/2008/GHG

U.S. DOE, 2009, Best Practices for: Monitoring, Verification, and Acounting of CO2 Stored in Deep Geologic F

Fossil Energy, National Energy Technology Laboratory. http://www.netl.doe.gov/technologies/carbon_seq/refshelf/MVA_Document.pdf. 
Attachment A October 15, 2009 

Detailed Comments of the Carbon Sequestration Council 

regarding: 

Birkholzer, J., J. Apps, L. Zheng, Y. Zhang, T. Xu, and C.-F. Tsang, 2008. Research 

Project on CO2 Geological Storage and Groundwater Resources: Water Quality Effects 

Caused by CO2 Intrusion into Shallow Groundwater, Technical Report 2008, Earth 

Sciences Division, Lawrence Berkeley National Laboratory. 

Observations 

Stated project goal: 

o Develop a general understanding of the potential vulnerability of United States 

potable groundwater resources in the event of CO2 leakage into potable aquifers. 

Major tasks: 

o Developed comprehensive geochemical model representing what are presented as 

“typical” conditions in many freshwater aquifers 

o Conduct systematic reactive transport study to quantify effects of CO2 intrusion 

into shallow groundwater aquifers 

Subtasks: 

o Identify mineral hosts controlling solubility 

 Data from ore and coal mineralogy 

o Conduct thermodynamic analysis of water samples 

 Data from USGS NWIS database 

o Improve thermodynamic data where necessary 

Comments: 

o Overall comments: 

o The modeling effort is screening level and contains many uncertainties. 

o The conclusion that As may exceed the maximum contaminant level 

(MCL) is limited to a few modeling scenarios that are localized and shortterm effects. 

o Conclusions could be viewed as issues that might warrant further 

investigation through field-scale experimentation, but cannot reasonably 

be viewed as evidence of eminent risk posed by CO2 geologic 

sequestration. 

Carbon Sequestration Council 1 rfvanvoorhees@bryancave.com 
Attachment A October 15, 2009 

o Project Goal: 

o The goal of the study was to evaluate the effects that CO2 migration into 

drinking water aquifers might have with respect to mobilizing trace 

elements and exceeding drinking water standards. The authors were very 

clear that the study was conducted as a screening level assessment. The 

scope of this particular study was exceptionally broad, which required 

broad assumptions to be made. Conclusions from the study should be 

viewed as theoretical geochemical reactions that might warrant further 

investigation under circumstances where site characteristics and 

operational experience indicate a significant potential for leakage, rather 

than evidence that eminent risks are posed by CO2 geologic sequestration. 

No model created by the authors can be viewed as reflecting an actual 

aquifer composition; therefore no conclusion can be implied to represent 

an actual risk. 

o Geochemical Model Development: 

o The authors created “typical” aquifer conditions by combining 

assumptions related to major mineralogy, trace element mineralogy and 

groundwater analyses into a theoretical aquifer condition. Any conclusion 

derived from the study is fictive. Some aquifers may not contain natural 

arsenic at concentrations posing any significant risk for future 

mobilization. 

o Reactive transport and sensitivity analysis: 

o Results showed that, while Pb and As were modeled to be mobilized by 

geochemical reactions resulting from CO2 intrusion, Pb concentrations did 

not exceed the MCL. As concentrations exceeded the MCL in only a few 

simulation cases. 

o Sensitivity analyses of the Coastal Plain aquifer example showed that 

there are many cases where As does not exceed the MCL when CO2 is 

introduced to the system. These cases include: 

 When initially adsorbed arsenic is assumed negligible, eliminating 

an initial pulse of arsenic that is desorbed from the aquifer matrix: 

• In the study, the occurrence of a MCL exceedance for As is 

suggested when adsorption is neglected, but no modeling 

evidence is presented to verify the suggestion. Therefore, 

the suggestion is unsubstantiated. 

 When adsorption surface site densities are low, creating less 

adsorption sites for initially adsorbed arsenic: 

• The primary adsorbing surface in the model is illite, a clay 

mineral. Surface site densities for illite may be lower than 

assumed in the base case, creating less opportunity for local 

and short-term mobilization of As above the MCL. This is 

acknowledged by the authors. 

Carbon Sequestration Council 2 rfvanvoorhees@bryancave.com 
Attachment A October 15, 2009 

Carbon Sequestration Council 3 rfvanvoorhees@bryancave.com 

• In the base case, illite comprises 2.85% of the rock 

composition by weight. Evidence from deep coastal plain 

sandstones suggests that illite may comprise only 1% of the 

rock composition by weight. This lower percentage would 

effectively reduce the potential for initial arsenic 

mobilization, but would ensure potential for long-term 

adsorption of arsenic and limiting arsenic aqueous 

concentrations below the MCL. 

 When the arsenopyrite solubility product is reduced: 

• The authors illustrated that minor reductions in the 

solubility of arsenopyrite can result in substantially lower 

aqueous As concentrations during reactive transport 

analysis. No MCL exceedances occurred with a reduced 

solubility product. 

o Initially elevated partial pressures of CO2(g) may result in As 

concentrations exceeding the MCL prior to additional CO2(g) migration 

into the aquifer. This case must be considered as a strong possibility. 

o Mineral hosts controlling trace element solubility: 

o The model assumes that trace element mineral hosts in typical aquifers are 

the same as those found in coal and ore materials. A lack of additional 

information has resulted in the construction of a purely fictive scenario, 

which is the case in many screening level modeling efforts. This is 

recognized by the authors as a limitation. Although the authors make a 

sound attempt at the project scope with available data, it is not at all clear 

that there is enough information available to make the entire modeling 

effort worthwhile. 

o Thermodynamic analysis of water samples: 

o Assessing the saturation state and solubility of various mineral phases 

relies heavily upon accurate reconstruction of initial in situ pH and 

carbonate species distribution, specifically pCO2(g). The authors point out 

numerous complications with pH and initial pCO2(g) reconstruction - a 

common problem with deep and shallow aquifer characterization. It is 

critically important to understand that modeling simulation results should 

be viewed as relative changes to an assumed initial condition. The 

uncertainty of an initial condition is multiplied when that assumed 

condition is perturbed. Any projected exact result, such as the occurrence 

of a particular As concentration (0.01 mg/L), should be viewed with 

appropriate caution. 

o Improvement of thermodynamic data: 

o Improvement of thermodynamic data based on the NWIS database is a 

questionable approach, given the complications arising from inconsistent 

sampling and analysis methods that the authors point out. 
Letter ID: 0382  

Commenter: Robert Voorhees  

Organization: Carbon Sequestration Council  

Letter ID: 0382 Comment ID: 27952 Letter Lines: 26 to 41  

Comment Code: 1000 1. General Comments on the Notice of Data Availability  

Comment: Comment No.1  

Page 44803  

Issue Topic from EPA's NODA  

Availability of this new information could change EPA's approach to the final  

rulemaking.  

Carbon Sequestration Council Comments  

The Carbon Sequestration Council ("the Council") has reviewed the Notice of Data  

Availability (NODA) and the accompanying data and results presented for public  

review and comment. We see nothing in the new information that suggests that  

EPA should depart from the adaptive approach to regulation that EPA has  

discussed as the basic objective for the geologic sequestration (GS) rule.  

Individual Response: EPA clarifies that it is following an 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.  

Letter ID: 0382 Comment ID: 27953 Letter Lines: 43 to 60  

Comment Code: 2000 2. Comments on Research, Data Analysis, and Findings presented in the NODA

(seeking comment)  

Comment: Comment No. 2  

Page 44805  
Issue Topic from EPA's NODA  

EPA is providing this [sic] data and associated project summaries because the  

Agency expects that there may be additional studies and data on other GS  

projects, the use of existing technologies, and GS‐ related research that may  

inform the Agency's regulatory development process for GS. Such data could  

contribute to the Agency's understanding of site characterization, well  

construction, operation, and monitoring requirements.  

Carbon Sequestration Council Comments  

The state of the science for CO2 storage and the over 35 years of experience  

with CO2 injection for enhanced oil and gas recovery are more than adequate to  

support EPA proceeding with final rule promulgation.  

Individual Response: EPA acknowledges the comment and agrees that sufficient data exist on which to

base final requirements for GS at this time.  

Letter ID: 0382 Comment ID: 27954 Letter Lines: 62 to 81  

Comment Code: 2000 2. Comments on Research, Data Analysis, and Findings presented in the NODA

(seeking comment)  

Comment: Comment No. 3  

Page 44805  

Issue Topic from EPA's NODA  

Many commenters suggested that supplementary research on GS is necessary prior  

to rule promulgation and that EPA should wait until the Department of Energy  

(DOE)‐sponsored Phase II and Phase III pilot projects are complete before  

finalizing the GS rule.  

Carbon Sequestration Council Comments  

Extensive additional research is proceeding on many different aspects of carbon  

capture, transportation, and sequestration, and the resulting findings will  

certainly add to our current understanding of these aspects. However, there are  

no major technical breakthroughs that need to occur before beginning commercial‐  
scale CO2 storage operations in the United States. Moreover, adherence to an  

adaptive approach for regulations will facilitate new information being  

implemented in a responsible way.  

Individual Response: EPA acknowledges the comment and agrees that sufficient data exist on which to

base final requirements for GS at this time. EPA plans to continue to monitor ongoing research on GS,

however and intends to use an adaptive approach to the GS regulation. EPA plans, every six years, to

collect and review data on GS projects to determine whether the appropriate amount and types of

information and appropriate documentation are being collected, and to determine if modifications to

the requirements are appropriate or necessary.  

Letter ID: 0382 Comment ID: 27955 Letter Lines: 83 to 102  

Comment Code: 2000 2. Comments on Research, Data Analysis, and Findings presented in the NODA

(seeking comment)  

Comment: Comment No. 4  

Page 44805  

Issue Topic from EPA's NODA  

Comments on the proposal encouraged additional research and investigations on  

areas including (but not limited to): confining zone characterization; modeling;  

CO2 plume movement; geochemistry; impacts of GS on saline formations; leakage  

from abandoned wells caused by material and cement degradation; potential  

pathways for contamination of USDWs; leak mitigation and remediation; and  

criteria for determining that the CO2 plume has stabilized.  

Carbon Sequestration Council Comments  

Furthermore, the oil and gas industry has relevant experience to draw on from  

over 35 years of injecting CO2 for EOR, over 90 years of natural gas storage,  

and 150 years of oil and gas production. The industry also operates large‐scale  

CO2 storage projects in offshore Norway, Algeria, and Canada, and has other  

related operations that have proven safe and effective.  

Individual Response: EPA recognizes that industry has decades of experience with injection well

construction and operation. EPA believes that this experience has led to the development of well

materials and construction and operating procedures that are applicable to GS wells.  
Letter ID: 0382 Comment ID: 27956 Letter Lines: 104 to 134  

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

Comment: Comment No. 5  

Page 44805  

Issue Topic from EPA's NODA  

EPA's Office of Research and Development is conducting intramural and extramural  

research activities to develop modeling and monitoring tools for protecting  

underground sources of drinking water.  

Carbon Sequestration Council Comments  

Monitoring and modeling needs will be different for each potential CO2 storage  

site, and we encourage flexibility in the model requirements. EPA should not be  

prescriptive in requiring certain models or monitoring techniques, as each  

storage site and the operational experience for each GS project will be  

different. Moreover, existing and future work may yield improved and alternative  

approaches to modeling for particular circumstances.  

Comment No. 6  

Page 44805  

Issue Topic from EPA's NODA  

Analytic and semi‐analytic models are being developed and evaluated for  

determining the area of review based on geologic and hydrologic conditions.  

Carbon Sequestration Council Comments  

Same comment as in 5 above.  

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: 0382 Comment ID: 27957 Letter Lines: 138 to 160  

Comment Code: 5450 5.9. Comments on the Proposed Monitoring Requirements (146.90)  

Comment: Page 44805  

Issue Topic from EPA's NODA  

Comprehensive laboratory tests are being applied to the development and field‐  

testing of monitoring strategies that can detect migration of fluids into  

shallow aquifers and assess potential geochemical impacts.  

Carbon Sequestration Council Comments  

The proposed EPA regulation was drafted with the recognition that there is no  

one suite of monitoring tools that is appropriate for all potential  

sequestration sites. A variety of subsurface factors and location specific  

concerns need to be considered to develop the best monitoring strategy for a  

given project. There are many monitoring tools that could be shown to have some  

utility, but it does not follow that every tool ‐ or any particular tool ‐  

should be used or required for any given geological storage project, especially  

as scaling‐up some of these monitoring techniques from pilot to commercial scale  

would be cost‐prohibitive. For example, soil and air monitoring are unnecessary  

under most foreseeable circumstances. The general strategy of monitoring  

programs should be to confirm the validity of the site selection and  

characterization process and to detect any leakage long before it reaches the  

surface.  

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: 0382 Comment ID: 27958 Letter Lines: 162 to 218  

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

Comment: Comment No. 8  

Page 44806  
Issue Topic from EPA's NODA  

This SECARB project employs, demonstrates, and validates the EPA's proposed  

Class VI well construction, operational, and monitoring requirements.  

Carbon Sequestration Council Comments  

No one project "validates" a given monitoring technique in a general sense.  

While the well design used in the SECARB project was sufficient for the project,  

a rich database of successful well construction is also offered by the CO2‐EOR  

and underground gas storage experience.  

1. The model used in the Escatawpa project was accurate in predicting the  

distance the plume moved, taking into consideration the small scale of the  

project, with only 3,027 tons of CO2 injected over 30 days. 2. All monitoring  

activities were concluded in September 2009. No unanticipated migration was  

detected or suspected to have occurred. 3. The purpose of the shallow monitoring  

was to determine if CO2was seeping into shallow geology, groundwater, or  

ecosystems either through geologic pathways or up the well bore. 4. Monitoring  

was performed in the target reservoir with time‐lapse VSP and down hole  

geophysical methods and in the near surface with tracers, soil flux, and  

groundwater quality testing.  

Although the injection well for the Escatawpa project was permitted as Class V,  

the Mississippi Department of Environmental Quality (MDEQ) required that the  

more stringent Class I hazardous waste injection well (Class IH) construction  

standards be met. Construction to these Class IH standards was not voluntarily  

proposed by the SECARB project team. EPA should not conclude that these design  

standards are warranted based on this single pilot project experience that did  

not even assess the sufficiency of alternative designs. Instead, EPA should  

adopt less prescriptive standards that are sufficiently protective based on  

industry's more than 35 years of success in injecting CO2 under the Class II UIC  

program. The Class II EOR wells constructed for these projects ‐ and their  

operating practices ‐ have an excellent record of mechanical integrity and of  

protecting USDWs.  

At this point it cannot be concluded that the project components and  

construction design demonstrate and validate EPA's well construction,  

operational, and monitoring requirements. Since this was a research and  

development project some requirements were more stringent and some may have been  
less stringent than would be required for a commercial‐scale geologic  

sequestration project.  

The Escatawpa project was essentially an injection test but was very valuable  

from the standpoint of outreach and education, permitting process analysis, and  

site characterization.  

Some of the practices employed at Escatawpa, such as cementing the long string  

casing to surface, may not be possible in all circumstances. The results of the  

SECARB project do not imply that less burdensome regulations would not have  

worked equally well. See the construction recommendations presented in the MSD  

Recommendation Letters of May 14, 2009 and May 15, 2009.  

Individual Response: EPA acknowledges that a single project does not prove that a given design is

effective in all cases or is the only design that would be effective, and disagrees that the proposed rule

requirements are more prescriptive than necessary. The results of the SECARB project, however, do

show that the proposed requirements are effective in the studied case and can provide for safe injection

of carbon dioxide that protects USDWs from endangerment.  

EPA believes that 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.

For more information on the construction requirements for GS wells, see the responses to comments on

the proposed rule in the rulemaking docket.  

Letter ID: 0382 Comment ID: 27959 Letter Lines: 220 to 263  

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

Comment: Comment No.9  

Page 44806  

Issue Topic from EPA's NODA  
The Aneth Field project confirms the need for a project design with a robust  

monitoring plan, and tests the importance of monitoring and modeling agreement  

in GS projects.  

Carbon Sequestration Council Comments  

Data collected for monitoring will allow for improvement and/or refinement of an  

existing model. As the feedback between monitoring and modeling increases  

confidence, the monitoring plan can be adapted as needed (See Cooper, C., ed.,  

2009). It is important that the regulations allow for refinements of the  

original monitoring plan, should modeling or reservoir performance results  

indicate operational or monitoring changes are appropriate.  

[Reference]: Cooper, C., ed., 2009, A Technical Basis for Carbon Dioxide Storage:  

New York, Chris Fowler International, CO2 Capture Project, 86p.  

Comment No. 10  

Page 44806  

Issue Topic from EPA's NODA  

In addition, the project demonstrates the utility of various monitoring  

technologies that may be used by owners and operators of Class VI wells.  

Carbon Sequestration Council Comments  

There are many monitoring tools that could be shown to have some utility, but it  

does not follow that every tool ‐ or any particular tool ‐ should be used or  

required for every geological sequestration project, especially as scaling‐up  

some of these monitoring techniques from pilot to commercial scale would be  

cost‐ prohibitive. For example, soil and air monitoring are unnecessary under  

most foreseeable circumstances. The testing of particular monitoring  

technologies does not show the necessity of these techniques or the inadequacy  

of alternatives that were not tested. Soil flux monitoring was not valuable to  

the Aneth project team because background and control point measurements were  

highly variable and data interpretation was difficult. Tracers also did not  

appear to be necessary.  

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 and

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.  

Letter ID: 0382 Comment ID: 27960 Letter Lines: 265 to 284  

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

Comment: Comment No. 11  

Page 44806  

Issue Topic from EPA's NODA  

The Agency sought comment on using unmineable coal seams for GS in the proposed  

rule. The investigation at Pump Canyon will inform a determination on whether  

CO2 can be effectively and safely sequestered in coal seams.  

Carbon Sequestration Council Comments  

Coal bed injection is promising, but it is at a more experimental stage than CO2  

injection into other types of reservoirs. CO2 storage within coal deposits is  

viable but complicated, due to swelling of the coal as methane is displaced by  

CO2, fracturing , and the low permeability of coal matrices.  

We recommend that coal bed injection wells used for GS be left as Class V  

experimental wells at this time. See MSD Recommendation Letter May 14, 2009,  
Item 1.  

Individual Response: EPA acknowledges concerns with ECBM and basalt projects but believes that it

may be possible to safely utilize these types of formations for GS. The RCSP projects have contributed to

the state of knowledge about injection into coal seams and basalts for GS, e.g., to determine under what

conditions such projects can be achieved safely. While the Archuleta project is a small volume, other

projects will use larger volumes if this project succeeds.  

EPA does not intend to ban ECBM projects. In the final GS rule, GS into unmineable coal seams will be

allowed, provided the owner or operator can demonstrate that GS at the site can be performed without

endangering USDWs. Owners or operators of unmineable coal seam projects will be subject to the same

site characterization requirements (at §146.82) as those required of other projects.

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).  

Letter ID: 0382 Comment ID: 27961 Letter Lines: 286 to 308  

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

comment)  

Comment: Comment No. 12  

Page 44807  

Issue Topic from EPA's NODA  

LBNL conducted multiple model runs to assess a variety of scenarios and aquifer  

conditions and, as discussed below, found that if injected CO2 comes into  

contact with shallow USDWs, some trace element concentrations such as arsenic  

could increase.  

Carbon Sequestration Council Comments  

The LBNL study goal, as stated in Apps, et al., 2009, is to develop a  

"comprehensive geochemical model that describes the complete chemistry of a  

range of specified shallow aquifer systems". In reality, they did not model a  

"representative groundwater" (NODA p. 44807). See Attachment A.  
[Reference]: 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

(average) ground water composition and aquifer mineralogy was modeled in order to determine the

thermodynamic response of increasing CO2 partial pres¬sures on the concen¬trations in groundwater of

As, Ba, Cd, Hg, Pb, Sb, Se, U, or Zn. The purpose of the analysis was to establish the potential equilibrium

concentrations of these elements in equilibrium with specified CO2 partial pressures. A range of

specified shallow aquifer systems, all of which are representative aquifers utilized for potable water,

was then evaluated in the reactive transport simulations conducted in Section 4 of Birkholzer et al.

(2008).  

Letter ID: 0382 Comment ID: 27962 Letter Lines: 310 to 350  

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

comment)  

Comment: Comment No. 13  

Page 44807  

Issue Topic from EPA's NODA  

A preliminary assessment of CO2 ‐related water quality changes, including pH,  

was conducted by calculating the expected equilibrium concentrations of trace  

elements as a function of the amount of CO2 in a representative potable  

groundwater. Results of this modeling obtained for typical aquifers under  

reducing conditions indicate that arsenic could potentially exceed Federal  

drinking water standards at elevated CO2 concentrations (40 CFR 141.62 (b)(16)).  

Carbon Sequestration Council Comments  

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 parts of the U.S. or in  

aquifers known to be free of heavy metal contamination. There will likely be  

many areas of the U.S. where the mobilization of arsenic, lead, and other trace  
elements is not a concern because the minerals that these elements are typically  

found in are not present in those formations. This does not necessarily render  

the LBNL results invalid, but it does indicate that the results may not be  

typical and thus not representative.  

Comment No. 14  

Page 44807  

Issue Topic from EPA's NODA  

Other trace elements, such as barium, cadmium, lead, antimony, and zinc, may  

also be mobilized in certain circumstances, but the majority of results did not  

show mobilization at levels exceeding the MCL or AL. (action level)  

Carbon Sequestration Council Comments  

The modeling used a number of assumptions in order to test scenarios where trace  

element mobilization was likely to occur. The results focused on whether or not  

given elements would exceed the maximum contaminant levels (MCLs), not whether  

mobilization would realistically occur in various scenarios.  

Individual Response: EPA notes that all of the cited elements included in LBNL’s study (and others not

cited here) are generally present in natural ground waters regardless of location, albeit typically at very

small (i.e., trace) concentrations. However, it is true that analyses for many potentially hazardous trace

elements are not made routinely, and further, that the analytical methods used have often been

insufficiently sensitive to quantify the concentrations actually present. Regarding the presence or

absence of minerals hosting the potentially hazardous trace elements, very few studies have been

conducted on the mineralogy of potable water aquifer host rocks in which the modes of occurrence of

trace elements have been characterized. 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.

The objective of LBNL’s study was to better understand, in a global sense, the vulnerability of

representative and relevant aquifer types in the case of CO2 intrusion. It was therefore assumed that

CO2 leakage into a USDW would occur through a local pathway and the evolution of USDW water

quality was predicted for a leakage period of 100 years. The risk of CO2 leaking from deep storage is low

for properly managed GS projects; thus this assumption is testing the unlikely scenario that CO2 leaks.

All other assumptions made in the study (e.g., regarding aquifer geochemistry and mineralogy) are

considered realistic, although not specific to any particular site.  
EPA agrees that the results of the LBNL study or the presence of the metals cited may not be typical of

all GS sites, and believes that site‐specific data are necessary to understand the potential geochemical

reactions at a GS site. For this reason, 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)). The

data can help the Director determine the potential for geochemical reactions between the injectate

(CO2) and the host geologic formations. 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: 0382 Comment ID: 27963 Letter Lines: 352 to 373  

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

comment)  

Comment: Comment No. 15  

Page 44807  

Issue Topic from EPA's NODA  

While LBNL studies did suggest that CO2 interaction could cause significant  

concentration increases compared to the initial water composition, the MCL for  

arsenic was exceeded in only a few simulation scenarios, while the lead  

concentrations remained below the AL under all scenarios.  

Carbon Sequestration Council Comments  

To the extent that these studies could be viewed as presenting extreme  

scenarios, some comfort might be drawn from such results. We are concerned,  

however, with the absence of realistic scenarios, as noted below. It is more  

appropriate to view the studies to date as a preliminary test of the methods and  

models. Subsequent testing might provide useful results as realistic scenarios  

are developed and particularly as the methods can be tested with actual project  

site characteristics. The identification of methodologies and potential  

approaches is useful by itself as a step toward site assessment and the  

development of operation and management plans.  
Individual Response: EPA notes the generic simulation conditions and site characteristics were generally

realistic given the current state of knowledge. LBNL did not address the question of the likelihood of

leakage. This topic is a subject for risk analysis, and is distinct from the development of realistic

geochemical models. EPA acknowledges the commenter’s point that further site‐specific studies are

recommended including laboratory experiments and field experiments, as well as evaluation of natural

analogs. As part of its adaptive approach to the GS regulation, EPA plans, every six years, to collect and

review data on GS projects to determine whether the appropriate amount and types of information and

appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

EPA clarifies that site‐specific data are necessary to understand the potential geochemical reactions at a

GS site. For this reason, 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)). The data can help the

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

geologic formations. 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: 0382 Comment ID: 27964 Letter Lines: 375 to 421  

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

comment)  

Comment: Comment No. 16  

Page 44807  

Issue Topic from EPA's NODA  

It is important to emphasize that these studies looked at potential consequences  

of CO2 leakage into the USDW, not the likelihood of such leakage occurring.  

Carbon Sequestration Council Comments  

The probability of trace element contamination of groundwater requires the  

multiplied probabilities of CO2 movement out of the intended storage zone,  

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

minerals that contain heavy metal assemblages, environmental conditions  
favorable to dissolution, and an undetected, unremediated leak that mobilizes  

these elements. 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 well selected and managed geologic storage  

sites.  

Comment No. 17  

Page 44808  

Issue Topic from EPA's NODA  

The Agency will use these preliminary results and public comments on this  

research as well as potential site‐specific analyses, to refine and inform site  

characterization, monitoring, and remediation requirements and guidance, if  

necessary, in the Agency's final rulemaking.  

Carbon Sequestration Council Comments  

In general, reactive transport modeling represents the correct method of  

evaluating the possible impacts on USDWs by the leakage of CO2 from an  

underlying CCS reservoir. The LBNL work verifies that TOUGHREACT reactive  

transport modeling technology is suitable for this purpose. However, the results  

reported by Zheng et al. are based on hypothetical cases. They should not be  

used to establish regulations because: (1) these results have not been validated  

for analog scenarios; (2) the recompiled thermodynamic data they used have not  

been verified by experimental data; (3) more realistic conditions and processes  

such as the migration of a mixture of CO2 ‐saturated reservoir brine,  

supercritical CO2, and/or other gases are not considered; and (4) their model  

does not integrate dynamic effects during the loss of containment for a CCS  

reservoir.  

Individual Response: EPA agrees (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 potential 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 clarifies that CO2 is not likely to reach a shallow potable water aquifer in a supercritical state and
believes that the assumed leakage scenario is reasonable. EPA agrees with the commenter that further

studies would be beneficial, including validation of the predictive models using laboratory experiments

and field experiments as well as evaluation of natural analogs. EPA also acknowledges that even a

comprehensive sensitivity study cannot encompass all possible scenarios, conditions and processes, and

agrees that additional investigations could be conducted (e.g., regarding the co‐migration of CO2‐brine

mixtures, as well as dynamic effects related to loss of containment). It should be noted that most of the

thermodynamic data and some of the kinetic data are based on experimental studies reported in the

literature. As part of its adaptive rulemaking approach, EPA plans, every six years, to collect and review

data on GS projects to determine whether the appropriate amount and types of information and

appropriate documentation are being collected, and to determine if modifications to the requirements

are appropriate or necessary.

EPA adds that it is not the intent to use the study to specify which models are to be used in AoR

delineations, and also clarifies that the GS regulation does not specifically require reactive transport

modeling for AoR delineation. EPA believes that flexibility in selecting models is appropriate. For

additional information on EPA’s approach to AoR delineation for GS wells, see the responses to

comments on the proposed rule in the rulemaking docket.  

Letter ID: 0382 Comment ID: 27965 Letter Lines: 423 to 455  

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

comment)  

Comment: Comment No. 18  

Page 44808  

Issue Topic from EPA's NODA  

The Agency seeks comment on this research and any additional studies related to  

a) mobilization of constituents and b) the likelihood or frequency of such  

leakage/risks.  

Carbon Sequestration Council Comments  

See the following references (full citation in "References" below): Smyth, R.C.,  

et al., 2009 Koplos, J., 2007 Duncan, et al., 2009  

[References]:  

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 ‐ 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.  

Koplos, J., 2007, A Review of Injection Well Mechanical Integrity Testing Data  

and Implications for Geosequestration, IEA GHG 3rd Wellbore Integrity Network  

Meeting, Santa Fe, 2007.  

Duncan, I., Nicot, J. P., and Choi, J., 2009, Risk assessment for future CO2  

sequestration projects based on CO2 enhanced oil recovery in the U.S., GHGT‐9,  

Energy Procedia I, 2037‐2042 ‐ 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.  

Individual Response: EPA acknowledges the studies cited and believes they are a valuable contribution

to knowledge in the area of risk assessment of GS wells and has reviewed them in the course of the

rulemaking process. EPA adds that the reference by Koplos is a presentation based on an EPA‐funded

study that informed the final MIT requirements for GS wells. They are in the final rulemaking docket.

EPA clarifies that site‐specific data are necessary to understand the potential geochemical reactions at a

GS site. For this reason, 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)). The data can help the

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

geologic formations. 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: 0382 Comment ID: 27966 Letter Lines: 457 to 492  

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

Comment: Comment No. 19  

Page 44808  
Issue Topic from EPA's NODA  

LBNL studied a hypothetical, future scenario of GS in a sedimentary basin as an  

illustrative example to demonstrate the potential for basin‐scale hydrologic  

impacts of CO2 storage (Birkholzer et al., 2008b).  

Carbon Sequestration Council Comments  

Modeling Issues: ‐ 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 (Arnold et al., 1996). In the model, the  

permeability is uniform. ‐ Compressibility values of the Mount Simon are less  

than published values. Increasing compressibility would reduce the predicted  

pressure buildup. ‐ It was noted in Juanes, 2006, that in general coarse grids  

overestimate CO2 movement and capillary trapping. 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, given the constraints of the model.  

[Reference]:  

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.  

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.  

Individual Response: 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.

EPA also clarifies that 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.  

Letter ID: 0382 Comment ID: 27968 Letter Lines: 645 to 665  

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

Comment: Comment No. 24  

Page 44808  

Issue Topic from EPA's NODA  

EPA believes that the example studied by LBN L illustrates the importance of  

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

from CO2 injection. EPA requests comment on this study and welcomes additional  

studies that provide information on the need for basin‐scale evaluations for GS  

injection.  

Carbon Sequestration Council Comments  

The model results are not applicable to Area of Review decisions for individual  

site selection this early in the development of geologic storage. Adaptive  

rule‐ making would allow for adjustments to encompass multi‐project scenarios in  

the same basin if needed in the future. See MSG Joint Letter dated May 14,  

2009, Item 2 on suggested language for managing pressure interference.  

(Adoption of this recommended provision will help to address and manage multi‐  

project interference concerns if and when they occur.)  

Individual Response: The results of the modeling study did not cause EPA to change any aspects of the

site characterization or AoR delineation requirements for GS projects. The final GS rule focuses on
permitting of individual GS wells and therefore does not include requirements for basin‐scale

evaluations. However, EPA agrees that proactive management of basin scale concerns to maintain

pressures within acceptable ranges is important, and encourages owners or operators and permitting

authorities to communicate planned GS activities to maximize coordination and minimize pressure

interference. If a permit applicant (or the permitting authority) is aware of pending GS projects near a

proposed well, the AoR delineation performed pursuant to §146.84 should account for the impacts of

multiple owners and operators injecting within a single basin. EPA anticipates that, where multiple

operators are involved, the Director would not approve modeling that does not account for changes that

may result from all injection operations. The proximity of injection sites to each other and the relative

timing of each injection operation might indicate a possible increase in risk for the containment of the

total CO2 and/or the effects of hydraulic perturbations and brine displacement. For additional

information regarding EPA’s requirements for AoR delineation for GS projects, see the responses to

comments on the proposed rule in the rulemaking docket.  

Letter ID: 0382 Comment ID: 27969 Letter Lines: 699 to 709  

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

Comment: Issue Topic from EPA's NODA  

The basis of these requirements is the principle that placing distance between  

the injection formation and USDWs decreases risks to USDWs.  

Carbon Sequestration Council Comments  

This is too simplistic; distance will undoubtedly help, but distance does not  

deserve to be singled out like this. The nature and characteristics of the  

confining material is paramount and must be considered along with distance in  

determining the sufficiency of containment at any particular site.  

Individual Response: EPA believes 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.  

However, EPA acknowledges that there are situations where injection into non‐USDW formations 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 and

operators can seek a waiver of the Class VI injection depth requirements.  

Letter ID: 0382 Comment ID: 27970 Letter Lines: 711 to 726  

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

Comment: Comment No. 27  

Page 44809  

Issue Topic from EPA's NODA  

In these deep‐well injection scenarios, the added depth and distance between the  

injection zone and overlying formations serve both as a buffer allowing for  

pressure dissipation and as a zone for monitoring that may detect any excursions  

(of the injectate) out of the injection zone.  

Carbon Sequestration Council Comments  

Again, this assertion goes too far. Distance is not the only way to accomplish  

these objectives and will not make up for otherwise poor site characteristics.  

Nor does the lack of depth defeat a good site with sufficient containment.  

Individual Response: EPA believes 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.  

However, EPA acknowledges that there are situations where injection into non‐USDW formations 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 and

operators can seek a waiver of the Class VI injection depth requirements. For additional information on

site selection for GS projects, see the preamble to the final rule and the responses to comments on the

proposed GS rule.  
Letter ID: 0382 Comment ID: 27971 Letter Lines: 728 to 742  

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

Comment: Comment No. 28  

Page 44809  

Issue Topic from EPA's NODA  

Additional distance also allows trapping mechanisms, including dissolution of  

CO2 in native fluids and mineralization, to occur over time ‐ thereby reducing  

risks that CO2 may migrate from the injection zone and endanger USDWs.  

Carbon Sequestration Council Comments  

Site selection and characterization must focus on the trapping and containment  

mechanisms themselves without giving undue weigh to distance, which plays a role  

but is not always determinative.  

Individual Response: EPA believes 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.  

However, EPA acknowledges that there are situations where injection into non‐USDW formations 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 and

operators can seek a waiver of the Class VI injection depth requirements.  

For additional information on site selection for GS projects, see the preamble to the final rule and the

responses to comments on the proposed GS rule.  

Letter ID: 0382 Comment ID: 27972 Letter Lines: 744 to 755  

Comment Code: 3100 3.1. Comments on Concerns About Injection Depth for Class VI Wells  
Comment: Comment No. 29  

Page 44809  

Issue Topic from EPA's NODA  

Additionally, the depth and distance below the lowermost USDW allow the  

potential for the presence of additional confining layers (between the injection  

zone and overlying formations/USDWs).  

If demonstrated containment is sufficient to meet the siting requirements, then  

additional confining layers are unnecessary.  

Individual Response: EPA believes 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.  

However, EPA acknowledges that there are situations where injection into non‐USDW formations 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 and

operators can seek a waiver of the Class VI injection depth requirements. For additional information on

confining zones for GS projects, see the preamble to the final rule and the responses to comments on

the proposed GS rule.  

Letter ID: 0382 Comment ID: 27973 Letter Lines: 757 to 775  

Comment Code: 3000 3. Injection Depth for GS Projects  

Comment: Comment No. 30  

Page 44809  

Issue Topic from EPA's NODA  

Water availability research in the United States indicates that water treatment  

of higher salinity waters (in excess of the USDW protectiveness threshold of  

10,000 ppm TDS) may be more cost effective than the cost of obtaining water  

rights or surface water elsewhere in the area (Sengebush, 2008).  

Carbon Sequestration Council Comments  
There is a growing recognition that CCS may be treated as a public necessity,  

and future long term planning should include provision for CO2 storage as well  

as water supply. The appropriate authorities will need to work together to  

reconcile such plans to assure that resources are effectively deployed.  

Responsibility for this activity falls outside that of individual CCS project  

developers.  

Individual Response: EPA agrees that CCS is an important climate change mitigation tool; however the

primary goal of the GS rule is the protection of USDWs. EPA believes that the waiver process at §146.95

provides flexibility to address storage capacity concerns while assuring that appropriate requirements

are in place to protect USDWs from endangerment.  

Letter ID: 0382 Comment ID: 27974 Letter Lines: 777 to 810  

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

Formations (seeking comment)  

Comment: Comment No. 31  

Page 44809  

Issue Topic from EPA's NODA  

Furthermore, some specific research on CO2 injection for GS into various  

formations including shallow, volcanic rocks such as flood basalts (McGrail, et  

al., 2006) and coal seam injection (Dooley, et al., 2006; IPCC, 2005; MIT 2007;  

White et al., 2005) illustrates the potential for GS in these formations, but  

only if there is depth requirement flexibility.  

Carbon Sequestration Council Comments  

The Council agrees that broad categories of formations should not be arbitrarily  

excluded from use solely on the grounds of underlying USDWs. Site selection  

should be able to consider all locations and receiving injection zones that can  

meet the siting requirements by providing sufficient containment of CO2streams.  

The proposed exclusion of formations is thus inconsistent with EPA's basic  

adaptability approach in disallowing for the advancements that may result from  

research and development projects that identify additional suitable types of  

formations for GS.  
The Council has joined with other MSD participants to recommend that[w]ells in  

basalts, coal seams, salt caverns and shale formations should be treated as  

experimental wells under Class V, recognizing that completing the process of  

research, development and demonstration likely will require initial full scale  

experimental projects in addition to pilot projects.  

"Keeping these wells under Class V would allow EPA and the states to gain enough  

experience to develop suitable permitting requirements for such wells and to  

tailor those requirements at both the pilot and commercial scales until the  

agencies are ready to regulate such wells under an appropriate class." MSD  

Recommendation Letter, May 14, 2009, Item 1.  

Individual Response: EPA agrees and clarifies that the GS rule does not categorically preclude or

prohibit injection into any type of formation. EPA believes that the requirements that allow owners or

operators to seek waivers from the injection depth requirements at §146.95, along with proper siting,

well construction, operation, monitoring, and post‐injection site care pursuant to the GS rule

requirements will ensure USDW protection.

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow and

above the lowermost USDW. The Agency expects that injection for GS into these shallow formations can

be issued waivers and permitted as Class VI wells, provided their owners or operators can meet all of the

requirements at §146.95 and demonstrate that such injection can be performed in a manner that

protects USDWs.  

EPA adds that wells used to inject into these formations types or other formation types (e.g., salt domes

and shales) for experimental purposes would be permitted as Class V experimental technology wells. To

facilitate experimental injection for GS and to increase global understanding of injection into basalts,

shales, and other formation types, the Agency is preparing an addendum to the Class V experimental

technology guidance on wells that meet the criteria. The decision about whether a well should be

permitted as a Class V experimental technology well or a Class VI well will be site‐specific and depend on

the nature of the project.  

Letter ID: 0382 Comment ID: 27975 Letter Lines: 812 to 838  

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

Comment: Comment No. 32  

Page 44809  
Issue Topic from EPA's NODA  

Certain States have indicated that where USDWs are very deep (e.g., 15,000  

ft/4,572 meters and deeper) and layered (stratified) these regions would become  

unavailable for large‐ scale GS projects because injectors would not be able to  

comply with the current injection depth (and well construction) requirements.  

These States suggest that GS should be allowed in certain areas if a site‐  

specific demonstration can be made that USDWs will be protected.  

Carbon Sequestration Council Comments  

We support the provision to allow CO2 injection into formations above the  

lowermost USDW when adequate containment of injected CO2 and protection of USDWs  

can be demonstrated. As noted in our comments of December 24, 2008, we would  

prefer to have the necessary criteria for GS project siting and containment  

demonstration built into the normal permitting process, where these requirements  

would be routinely applicable whenever a permit applicant is proposing to inject  

into a saline formation that is above the lowermost USDW. The permitting process  

‐ with the notice, comment, hearing and permitting provisions we support ‐ would  

provide adequately for consideration of the necessary technical issues.  

Nevertheless, we also believe that the concept of a site‐specific waiver process  

for geologic storage above the lowermost USDW can be made workable but requires  

some improvements which are specifically noted in these Comments.  

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.  
Letter ID: 0382 Comment ID: 27976 Letter Lines: 840 to 867  

Comment Code: 3310 3.3.1. Site Characterization  

Comment: Comment No. 33  

Page 44809‐10  

Issue Topic from EPA's NODA  

Class II and Class III owners and operators of sites where injection is taking  

place above and between USDWs must identify and demonstrate upper and lower  

impermeable confining units. These confining units serve as barriers to fluid  

movement and pressure and must ensure continuous injectate isolation,  

confinement, and USDW protection. Identification of such units is conducted  

through analysis of sonic and resistivity logs, drill stem tests, and wire line  

tests.  

Carbon Sequestration Council Comments  

The requirement to demonstrate the suitability of the confining unit below the  

proposed injection zone is reasonable and technically feasible. Other site  

characterization requirements are not significantly different than for geologic  

storage below the lowermost USDW.  

As reflected in recommendations presented by the Multi‐Stakeholder Discussion  

participants in the MSD Recommendation Letters of December 23, 2008 and October  

9, 2009, which the Council and many of our members signed, the requirement that  

GS take place in formations beneath the lowermost USDW should not be imposed on  

GS taking place in oil and gas reservoirs, many of which are located above the  

lowermost USDW and have demonstrated containment capabilities over geologic time  

and through many years of oil and gas production operations.  

Individual Response: EPA acknowledges the comment. For additional information on characterization of

GS sites, see the preamble to the final rule and the responses to comments on the proposed GS rule.  

Letter ID: 0382 Comment ID: 27977 Letter Lines: 869 to 886  

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

(seeking comment)  
Comment: Comment No. 34  

Page 44810  

Issue Topic from EPA's NODA  

EPA believes that a waiver process may respond to the range of comments, both  

for and against the proposed requirement that Class VI wells inject below the  

lowermost USDW.  

Carbon Sequestration Council Comments  

EPA should integrate the waiver process into the normal permit approval process  

as much as possible, for example, by combining the public hearing for the waiver  

with the public hearing for the permit, if one is held. Hearings should be an  

option, and not an automatic requirement. Hearings should be offered as a  

potential option but should not be required unless warranted in the judgment of  

the Director.  

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: 0382 Comment ID: 27978 Letter Lines: 888 to 904  

Comment Code: 3390 3.3.9. Comments Regarding State Discretion to Adopt the Waiver Approach  

Comment: Comment No. 35  

Page 44810  

Issue Topic from EPA's NODA  

EPA believes this approach may additionally accommodate requests for geographic  

flexibility while placing such determinations at the State or Regional level.  

Carbon Sequestration Council Comments  

These determinations should be at the state or regional level, although EPA  

Regions often will not be in a position to make these determinations as  

effectively as a state agency because the EPA regional offices typically have  

limited involvement in the related areas of program oversight. Where EPA  

regional offices are making permitting decisions for Class VI wells, they should  

coordinate with the relevant state agencies.  

Individual Response: EPA clarifies that adoption of the waiver process remains at the discretion of

individual UIC programs. Therefore, States, Territories, and Tribes seeking primacy for Class VI wells are

not required to provide for injection depth waivers in their UIC regulations and may choose not to make

this process available to Class VI wells under their jurisdiction. Although some commenters asked EPA to

require that waivers be applied nationally, the Agency believes that the decision about whether a waiver

program is appropriate in a specific State, Tribe, or Territory should be made by each program. This

approach allows flexibility for individual program Directors to determine the appropriateness of allowing

for waivers based on regional or state‐specific conditions, such as the predominant geologic settings

anticipated to be used for GS or other land uses in the state while ensuring maximum protection of

USDWs. The final approach for injection depth waivers represents minimum Federal requirements. UIC

program Directors may adopt GS requirements that do not allow injection above or between USDWs if

they determine this to be appropriate (for conditions in their State, Territory, Tribe, or Region) and

protective.

EPA clarifies that, pursuant to §146.95(d), the Regional Administrator will make the final determination
whether to issue an injection depth waiver. However, prior to a final decision, the Director must provide

the Regional Administrator with the information collected during the waiver application and the public

notice processes. Based on this information and pursuant to requirements at §146.95(d), the Regional

Administrator will provide written concurrence or non‐concurrence regarding waiver issuance. The

Agency clarifies that these requirements are within the authority of the Safe Drinking Water Act.  

Letter ID: 0382 Comment ID: 27979 Letter Lines: 906 to 926  

Comment Code: 3200 3.2. Comments on Alternative Injection Depth Waiver Approach  

Comment: Comment No. 36  

Page 44810  

Issue Topic from EPA's NODA  

Lastly, the approach is designed to acknowledge and accommodate comments and  

concerns about drinking water resource availability and the potential/known  

future needs, and to afford such water resources protection.  

Carbon Sequestration Council Comments  

EPA should clarify the scope and applicability of the proposed waiver process.  

First, EPA's intent appears to be to issue waivers only for situations where a  

more saline reservoir is overlying a USDW. These conditions are 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. To allow CCS in these  

regions, the waivers would necessarily have to authorize injection into USDWs  

above the lowermost USDW. 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.  

Individual Response: EPA clarifies that injection depth waivers are necessary whenever owners or

operators seek to inject CO2 for GS into non‐USDWs that are above the lowermost formation containing

a USDW or in between formations containing USDWs. Commenters on the proposed GS rule indicated

that there are many circumstances, particularly in the western U.S., where there are deep USDWs and

that the proposed injection depth requirements could preclude GS in certain regions of the country.

These commenters also indicated that injection depth flexibility for GS is important to ensure that no

parts of the country are excluded from GS activities and that CCS deployment is not restricted. The

waiver process will allow injection into formations above the lowermost USDW if it can be
demonstrated that the site is equally as protective of USDWs as injecting beneath the lowermost USDW.  

Regarding decisions on granting of injection depth waivers, EPA clarifies that the final determination

regarding waiver issuance will be made by the Director, following evaluation of all site‐specific

information, public notice, and receipt of written concurrence or non‐concurrence from the Regional

Administrator. However, prior to a final decision, the Director must provide the Regional Administrator

with the information collected during the waiver application and the public notice processes. Based on

this information and pursuant to requirements at §146.95(d), the Regional Administrator will provide

written concurrence or non‐concurrence regarding waiver issuance. EPA believes Agency input is

necessary in making injection depth waiver decisions and agrees with commenters who expressed

interest in ensuring that multi‐state boundary and water resource issues are addressed. The Agency also

believes that Agency involvement in the waiver decision process will contribute to national consistency

in waiver issuance.  

Letter ID: 0382 Comment ID: 27980 Letter Lines: 928 to 957  

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

Formations (seeking comment)  

Comment: Comment No. 37  

Page 44810  

Issue Topic from EPA's NODA  

Second, the alternative under consideration does not prohibit injection into any  

specific formation types (e.g., basalts and/or coal seams). It affords all  

formations equal treatment and allows specific regions of the country the  

regulatory flexibility to determine if any injection at a particular site and  

depth is the appropriate approach. It will also help to manage injection in  

areas where there may be multiple, stratified formations with significant  

assessed cumulative capacity.  

Carbon Sequestration Council Comments  

We are supportive of EPA's effort to introduce flexibility on the depth of  

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

stated in our December 24, 2008 Comments, we agree that CO2 can be injected  

above a USDW while protecting the USDW and maintaining access to the USDW for  

future use. As noted in our Comments, 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 CCS site, while not trivial, does not present  

significant technological hurdles. Industry has the technology to drill through  

over‐pressured gas reservoirs which are analogous to CCS 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 CCS site.  

Individual Response: EPA agrees that the GS rule should be flexible and not categorically preclude or

prohibit injection into any type of formation. EPA believes that the requirements that allow owners or

operators to seek waivers from the injection depth requirements at §146.95, along with proper siting,

well construction, operation, monitoring, and post‐injection site care pursuant to the GS rule

requirements will ensure USDW protection.

EPA recognizes that some types of formations, such as coal seams and basalts, are typically shallow and

above the lowermost USDW. The Agency expects that injection for GS into these shallow formations can

be issued waivers and permitted as Class VI wells, provided their owners or operators can meet all of the

requirements at §146.95 and demonstrate that such injection can be performed in a manner that

protects USDWs.  

Letter ID: 0382 Comment ID: 27981 Letter Lines: 959 to 1002  

Comment Code: 2320 2.3.2. Recent Publications on Risk and Risk Management  

Comment Code: 3130 3.1.3. Addressing the Differences Between Class II and Class VI Wells  

Comment: Comment No. 38  

Page 44810  

Issue Topic from EPA's NODA  

Third, because the Agency believes that it is necessary to address the specific,  

unique characteristics of Class VI injection (e.g., large injection volumes,  

viscosity, and buoyancy) and the Agency does not have information or data  

indicating that Class II operations are entirely analogous to Class VI, large‐  

scale injection, this alternative allows Class VI injection depth considerations  

to be tailored for GS.  
Carbon Sequestration Council Comments  

Within the past year, there have been several papers that have demonstrated this  

excellent record of producing, transporting, and injecting CO2. The first study  

by Duncan et al. (2009) 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 finds that "The CO2‐EOR  

industry has an excellent safety record" and "the rarity of corrosion related  

incidents reflects the industries [sic] success in implementing anti‐corrosion  

measures." The second study by Smyth et al. (2009) 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 oilfiled [sic] as a result of CO2‐injection." A third study  

on the mechanical integrity of CO2 injection wells is in progress and should be  

completed in time for consideration by EPA.  

[References]:  

Duncan, I., Nicot, J. P., and Choi, J., 2009, Risk assessment for future CO2  

sequestration projects based on CO2 enhanced oil recovery in the U.S., GHGT‐9,  

Energy Procedia I, 2037‐2042 ‐ 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.  

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 ‐ 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 that several recent and ongoing studies are examining the risks

associated with CCS, including those studies cited by the commenter, which focus on drawing an

analogy between ongoing ER projects and CCS. As part of its commitment to an adaptive rulemaking

approach for wells, EPA is tracking the results of GS‐related research and data collected from early GS

projects.  

EPA agrees with the commenter that industry experience injecting CO2 for the purpose of ER must be

leveraged in implementation of GS. However, operation of GS sites, while similar to ER in some respects,

will exhibit the fundamentally different objective of maximizing CO2 injection and sequestration. ER

projects are operated to minimize CO2 use and maximize oil or gas production. Therefore, EPA
anticipates that the risk posed by GS projects to USDWs will be greater than currently operated ER

projects and has designed the Class VI GS requirements accordingly. EPA adds that it has been

monitoring progress at the SACROC site.

As part of its commitment to an adaptive rulemaking approach for wells, EPA will continue to review GS‐

related research such as the forthcoming MIT report and data collected from early GS projects such as

SACROC. The Agency will evaluate the information and determine whether modifications to the

requirements are necessary to protect USDWs from endangerment.

EPA has reviewed the cited studies as part of the final rulemaking. EPA notes that although Duncan et al.

noted that "[t]he CO2‐EOR industry has an excellent safety record," their paper is based on case studies

and does not provide failure rates, so the safety of the industry as a whole cannot be quantified. EPA

also notes that Smyth et al. indicate that the methods used to detect leaks of CO2 from ER were not

adequate to determine if leaks had occurred.  

Letter ID: 0382 Comment ID: 27982 Letter Lines: 1004 to 1051  

Comment Code: 3130 3.1.3. Addressing the Differences Between Class II and Class VI Wells  

Comment: Comment No. 39  

Page 44810  

Issue Topic from EPA's NODA  

A number of dominant differences between Class II and Class VI operations  

indicate that these well classes warrant different treatment. EPA received  

comment during the public comment period supporting the need for such a  

distinction. These differences include: the risk profiles for these operations;  

the greater total injection volumes (of CO2) for Class VI GS; and, differences  

in formation pressures (potentially higher for GS), greater opportunities for  

mobilization of constituents, and injection rates and operating conditions.  

Carbon Sequestration Council Comments  

The Multi‐Stakeholder discussions (MSD) and recommendations from MSD  

participants have addressed these issues in a series of recommendations that  

account for the different risk profiles.  

The December 23, 2008 letter from MSD participants explained the agreement  
reached on the proposed language describing wells in a proposed new  

classification 40 CFR 146.5(b)(4) that would establish a "bright line"  

definition distinguishing (1) wells that inject CO2 for EOR/EGR and those that  

inject CO2 for GS in conjunction with EOR/EGR from (2) wells that inject CO2 for  

GS where EOR/EGR activities and any hydrocarbon production would be minimal..  

The signatories to the December 23, 2008, letter recommended, consistent with  

EPA's intent, that wells used for EOR/EGR should remain in Class II and that  

wells used for EOR/EGR with GS ‐ that meet the recommended (b)(4) definition ‐  

should also remain in Class II and be subject to the current requirements for  

Class II. Signatories to that letter also agreed that the wells used for GS in  

oil and gas reservoirs that do not meet the criteria of (b)(4) should be subject  

to additional requirements. That letter noted an agreement to define such wells  

as wells used "for geologic sequestration in oil and gas formations and where  

the criteria of paragraph (b)(4) are not met."  

In a letter dated October 9, 2009, MSD participants agreed that wells used for  

GS in oil and gas reservoirs that do not meet the criteria of paragraph (b)(4)  

should be subject to a set of additional requirements different from those that  

would apply under the current Class II provisions to wells that inject CO2for  

EOR/EGR and GS, due to the potential change in the risk profile when EOR/EGR  

activities cease. This common view is also reflected in the four letters EPA  

received on March 17, 2009 from MSD participants. Each of those March 17 letters  

asks EPA to include this approach in its final GS rule. Accordingly, EPA should  

adopt the recommended provisions for a new section 146.25 and the  

recommendations submitted with respect to Class V GS wells and Class VI GS  

wells. See MSD Recommendation Letters dated December 23, 2008; May 14, 2009 and  

May 15, 2009.  

Individual Response: EPA acknowledges that Class II well operators have decades of experience

injecting CO2. However, EPA believes that significant operational differences between Class II wells and

Class VI wells to warrant tailored requirements for GS.  

EPA clarifies that the final GS rule contains risk based criteria at §144.19 to inform a Director’s

determination to apply Class VI requirements to wells transitioning from an ER project to a project for

which the primary purpose is long‐term storage of CO2. For additional information on transitioning of

Class II wells for GS, see the preamble to the final rule and the responses to comments on the proposed

GS rule.  

Letter ID: 0382 Comment ID: 27983 Letter Lines: 1053 to 1090  
Comment Code: 3350 3.3.5. Requirement to Submit Waiver Application to UIC and PWSS Program

Directors  

Comment: Comment No. 40  

Page 44810  

Issue Topic from EPA's NODA  

The alternative EPA is considering relies on the principle of site‐suitability  

for GS: injection zones/formations that have suitable upper and lower confining  

units, appropriate lateral and vertical extent to receive and contain the  

injected CO2, and an appropriate management scheme to ensure that the water and  

other resources contained within the injection zone will not be needed in the  

future. The management scheme will also ensure that there is a strategy  

developed to address future needs to access formations below the injection zone.  

Carbon Sequestration Council Comments  

We support the provision to allow CO2 injection into formations above the  

lowermost USDW when adequate containment of injected CO2 and protection of USDWs  

can be demonstrated. As noted in our comments of December 24, 2008, we would  

prefer to have the necessary criteria for GS project siting and containment  

demonstration built into the normal permitting process, where these requirements  

would be routinely applicable whenever a permit applicant is proposing to inject  

into a saline formation that is above the lowermost USDW. The permitting process  

‐ with the notice, comment, hearing and permitting provisions we support ‐ would  

provide adequately for consideration of the necessary technical issues.  

Nevertheless, we also believe that the concept of a site‐specific waiver process  

for geologic storage above the lowermost USDW can be made workable but requires  

some improvements which are specifically noted in these Comments.  

We are concerned in particular that EPA may lack the authority to require a  

waiver process as specifically presented in the NODA because the decisionmaking  

authority that EPA appears to be proposing for PWSS Directors lacks a  

decisionmaking standard that is consistent with the existing statutory  

requirements of the SDWA and EPA's UIC regulations; assigning such a role to  

PWSS Directors would encroach upon the prerogatives of the states under the UIC  

primacy program in violation of the UIC regulations; and division of authority  

between UIC Directors and PWSS Directors would be burdensome, inefficient, and  

potentially disruptive if the Directors disagree on approvals.  
Individual Response: EPA clarifies that, pursuant to §146.95(d), the Regional Administrator will make

the final determination whether to issue an injection depth waiver. However, prior to a final decision,

the Director must provide the Regional Administrator with the information collected during the waiver

application and the public notice processes. Based on this information and pursuant to requirements at

§146.95(d), the Regional Administrator will provide written concurrence or non‐concurrence regarding

waiver issuance. The Agency clarifies that these requirements are within the authority of the Safe

Drinking Water Act.  

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.  

EPA disagrees that consultation with the PWSS Director would be "burdensome," "inefficient," or

"duplicative," and believes that the consultative communication between the UIC Director and PWSS

Directors will enable a comprehensive evaluation of resource concerns and increase USDW protection.

EPA adds that it does not anticipate that the PWSS director would perform the same level of review as

the UIC Director and anticipates states would determine the level of PWSS review.  

Letter ID: 0382 Comment ID: 27984 Letter Lines: 1092 to 1123  

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

(seeking comment)  

Comment: Comment No. 41  

Page 44810  
Issue Topic from EPA's NODA  

EPA is weighing the fact that this alternative would be a divergence from the  

existing UIC deep‐well injection requirements for industrial and hazardous waste  

injection. It will result in greater injection depth variability throughout the  

United States and may result in emplacement of fluids by injection in closer  

proximity to USDWs than would occur under the proposed requirements.  

Additionally, adoption of this alternative could potentially add a new  

administrative burden to UIC programs pursuing the waiver approach.  

Carbon Sequestration Council Comments  

Divergence from deep well injection requirements for industrial and hazardous  

wastes is completely justified because GS does not involve waste disposal or  

pose the same risk profiles. Moreover, this limitation on waste injection was  

an original part of the UIC program and, as has been noted in comments on the GS  

proposal, is not warranted in all instances for waste disposal. Restrictions  

such as this one run counter to EPA's avowed commitments to performance based  

and adaptable requirements. Instead of identifying and applying the proper  

siting and containment criteria, EPA would be imposing a requirement that  

commenters have already shown to be unwarranted in every instance. The  

administrative burdens to which EPA alludes could be avoided by incorporating  

the consideration of appropriate requirements for injection above the lowermost  

USDW into the normal permitting process rather than in a separate waiver  

process. The burdens also can be minimized by integrating the consideration of  

these criteria as closely as possible with the GS UIC permitting process and  

minimizing the amount of duplicative reviews that are required to be conducted  

by separate agencies at the state and/or EPA regional levels.  

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. The Agency believes that this report and

requirements at §146.95 are complementary and not redundant of the Class VI permit application

requirements. Furthermore, to eliminate concerns about duplication or redundancy, the requirements

at §146.82(d) clarify that the supplemental report is not part of the permit application.

Furthermore, EPA believes that the requirements at §146.95 address potential risks associated with

injection into non‐USDW formations above the lowermost USDW. These may include the risk of

downward migration of fluids if there is no lower confining layer or inadequate confinement. In

addition, there is the potential that wells will be drilled through the injection zone in the future to reach

the USDW. EPA believes 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 additional

considerations for owners or operators and Directors when permitting such wells to ensure protection

of all USDWs.

For additional information on EPA's flexible regulatory approach, see the preamble to the final rule and

the responses to comments on the proposed GS rule.  

Letter ID: 0382 Comment ID: 27985 Letter Lines: 1125 to 1142  

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

(seeking comment)  

Comment: Comment No. 42  

Page 44810  

Issue Topic from EPA's NODA  

The owner or operator would be required to demonstrate to regulatory authorities  

that such injection can be undertaken and completed in a manner that prevents  

fluid movement into overlying (and underlying) USDWs, thereby preventing the  

endangerment of public health from USDW contamination.  

Carbon Sequestration Council Comments  

As stated in the Council's December 23, we support the use of this approach and  

these criteria to the extent necessary to protect USDWs. We see, however, no  

particular reason why these criteria could not be specified and considered as  

part of the regular permit application process when injection is proposed for a  

saline injection zone that is overlying a USDW.  
Individual Response: As described above, 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.  

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. 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.  

Letter ID: 0382 Comment ID: 27986 Letter Lines: 1144 to 1166  

Comment Code: 3400 3.4 Additional Information Regarding the Waiver Approach  

Comment: Comment No. 43  

Page 44810  

Issue Topic from EPA's NODA  

This process would be separate from aquifer exemptions and has no effect on 40  

CFR Parts 144.7 and 146.4.  

Carbon Sequestration Council Comments  

In many cases, waivers are likely to require an aquifer exemption for the  

injection zone itself. Consequently, it is unclear as to how a waiver process  

would be beneficial to either state agencies or applicants. If states still  

need to obtain an aquifer exemption; which must be approved by EPA, we believe  

this would negate the benefit of a waiver process that does not require EPA  

approval. Further, 40 CFR Part 146.4 does not currently have a criterion for  

aquifer exemption on the basis of "use as a storage zone for CO2  
geosequestration". Since no changes to the aquifer exemption criteria have been  

proposed, it appears that obtaining an exemption for USDWs above the lowermost  

USDW for the purpose of geosequestration would be very difficult. In effect,  

this would create a requirement for injection below the lowermost USDW  

regardless of whether or not a waiver process exists.  

Individual Response: EPA acknowledges that there are limited circumstances where aquifer exemptions

for GS may be warranted or needed. 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.

EPA clarifies that all decisions regarding whether expansion of existing aquifer exemptions will be at the

Director's discretion and based on site‐specific information. If an owner or operator applies for a Class VI

permit to inject CO2 into a previously exempted aquifer (non‐USDW) that is located above and/or

between USDWs, the permit applicant must also apply for a waiver of the injection depth requirements

pursuant to §146.95 to ensure that if a waiver is granted, USDWs above and below the injection zone

are protected from endangerment. The Agency clarifies that it is anticipated that both of these tools will

be used in limited circumstances.  

Letter ID: 0382 Comment ID: 27987 Letter Lines: 1168 to 1207  

Comment Code: 3310 3.3.1. Site Characterization  

Comment: Comment No. 44  

Page 44811  

Issue Topic from EPA's NODA  
The waiver application would need to demonstrate: 1) Laterally continuous,  

impermeable confining units above and below the injection zone adequate to  

prevent fluid movement and pressure buildup; 2) A laterally continuous injection  

zone/formation with adequate injectability, including sufficient porosity and  

permeability, and appropriate soil‐rock chemistry (so as to ensure that the  

injection matrix is not dissolved as a result of injection); 3) An injection  

zone and confining formations free of transmissive fractures and faults; and, 4)  

A characterization of regional fracture properties and a demonstration that such  

fractures will not interfere with injection, serve as conduits, or endanger  

USDWs.  

Carbon Sequestration Council Comments  

The information identified in item 3 is important for confining zones, but not  

necessary for things that occur solely within an injection zone. The Council  

has joined with other MSD participants in recommending a revised definition for  

transmissive faults or fractures that takes into account the potential for GS  

above the lowermost USDW:  

The recommendation recognizes that EPA's proposed rule in §146.83(a)(2) would  

require a confining zone(s) that is free of transmissive faults or fractures,  

while proposed §146.81 would define this term as "A fault or fracture that has  

sufficient permeability and vertical extent to allow fluids to move between  

formations".  

The MSD letter recommends the following modification to the definition in  

§146.81(d) in order to avoid unduly restricting movement that is merely between  

formations:  

"Transmissive fault or fracture means a fault or fracture that has sufficient  

permeability and vertical extent to allow fluids to move beyond a confining  

zone."  

MSD Recommendation Letter, May 14, 2009, Item 3.  

Individual Response: The final GS rule requires owners and operators seeking injection depth waivers to

demonstrate that the confining units are free of transmissive faults and fractures and that such fractures

will not interfere with injection, serve as conduits, or endanger USDWs as specified in §146.95(a)(2). For

additional information on site characterization for GS projects, see the preamble to the final rule and

the responses to comments on the proposed GS rule.

EPA clarifies that the requirements at §146.95 for owners and operators seeking injection depth waivers
are intended to add to and modify the requirements that all GS well owners or operators must meet,

including those for site‐specific geologic characterization and consideration of the presence of faults and

fractures, to ensure that the proposed site is evaluated in the context of the presence of USDWs above

and below the injection zone. EPA anticipates that issuance of waivers will be limited to circumstances

where there are deep USDWs and/or where the lack of a waiver of injection depth requirements would

result in impractical or technically infeasible well construction, and where USDW protection is

demonstrated and maintained through the life of the GS project.  

Letter ID: 0382 Comment ID: 27988 Letter Lines: 1209 to 1237  

Comment Code: 3320 3.3.2. AoR and Corrective Action  

Comment: Comment No. 45  

Page 44811  

Issue Topic from EPA's NODA  

Due to the potential risk that artificial penetrations pose as fluid/injectate  

conduits, the owner/operator would need to map and identify all artificial  

penetrations in the AoR that penetrate the injection zone, the upper and lower  

confining zones, and all USDWs in the area. The purpose of this demonstration  

would be to ensure that public water supplies, private wells, and potential  

future water resources are identified and the location of artificial  

penetrations into such formations are known and these artificial penetrations  

can be appropriately plugged during the permitting phase.  

Carbon Sequestration Council Comments  

These requirements for the area of review and corrective action are the same as  

would apply to all permit applications. It should not be necessary to plug all  

wells during the permitting phase, only to demonstrate either that wells were  

constructed and/or plugged so as to prevent fluid movement up or down into  

USDWs, or that a plan will be executed to remediate wells that were not  

appropriately constructed and/or plugged. See Bachu and Watson, 2007 for  

characteristics in pre‐existing wells that correspond to higher risks for  

leakage.  

[Reference]: Bachu, S. and Watson T., Factors Affecting or Indicating Potential  

Wellbore Leakage, IEA GHG 3rd Wellbore Integrity Network Meeting, Santa Fe,  
2007.  

Individual Response: EPA clarifies that the final GS rule allows phased corrective action as specified in

an approved AoR and corrective action plan per §146.84. For additional information on corrective action

for GS projects, see the preamble to the final rule and the responses to comments on the proposed GS

rule. EPA adds that the requirements at §146.95 for owners and operators seeking injection depth

waivers are intended to add to and modify the requirements that all GS well owners or operators must

meet, including those for corrective action, to ensure that the proposed site is evaluated in the context

of the presence of USDWs above and below the injection zone.  

Letter ID: 0382 Comment ID: 27989 Letter Lines: 1239 to 1267  

Comment Code: 3330 3.3.3. Emergency and Remedial Response  

Comment: Comment No. 46  

Page 44811  

Issue Topic from EPA's NODA  

The owner or operator would need to supplement the emergency and remedial  

response plan (submitted as part of the waiver application process and as part  

of the UIC Class VI permit) to ensure protection of USDWs above and below the  

injection zone. The purpose of this plan would be to explain that the owner or  

operator has considered regional water resource issues and has explored  

alternative water supplies or water treatment options to address unanticipated  

movement of the injectate or formation fluids (e.g., CO2, brine, or other  

fluids) into any overlying or underlying USDWs.  

Carbon Sequestration Council Comments  

The requirements described would not be any different from what would be  

required in this context under the original proposed Class VI requirements. To  

the extent that this statement is intended to indicate that multiple or  

duplicate plans must be prepared and submitted, such a requirement would be an  

unwarranted burden on both applicants and permitting agencies. Moreover, such  

an approach could lead to having inconsistent plans for GS projects and wells.  

EPA should clarify exactly what is to be required and should provide that the  

permit and waiver application can be a single submission to the permitting  

agency. It is confusing to refer to a need to "supplement" the emergency and  
remedial response plan when it is clear from the context that any permit  

application for GS injection into a formation above the lowermost USDW will need  

to include these explanations from the outset rather than as a "supplement."  

Individual Response: The requirements at §146.95 for owners and operators seeking injection depth

waivers are intended to add to and modify the requirements that all GS well owners or operators must

meet, including those for emergency and remedial response, to ensure that the proposed site is

evaluated in the context of the presence of USDWs above and below the injection zone. EPA anticipates

that issuance of waivers will be limited to circumstances where there are deep USDWs and/or where the

lack of a waiver of injection depth requirements would result in impractical or technically infeasible well

construction, and where USDW protection is demonstrated and maintained through the life of the GS

project.  

In the final GS rule, for GS projects where injection depth waivers are sought, the Director must also

consider the proposed emergency and remedial response plan in making a determination whether to

grant a waiver as specified in §146.95(b)(1)(iv).  

EPA is developing guidance on the injection depth waiver process. The guidance describes the

recommended approach an owner or operator may follow when submitting a waiver application,

processing waiver applications by the UIC and PWSS Program Directors, and additional processes that

may apply to projects that have been issued waivers. This guidance will be available on EPA’s website at

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

Letter ID: 0382 Comment ID: 27990 Letter Lines: 1269 to 1284  

Comment Code: 3340 3.3.4. Financial Responsibility  

Comment: Comment No. 47  

Page 44811  

Issue Topic from EPA's NODA  

The owner/operator would also demonstrate sufficient, additional financial  

responsibility to address any potential contamination of USDWs above or below  

the injection zone.  

Carbon Sequestration Council Comments  

Financial assurance is tied to plans and should not be changed for this waiver  
requirement.There is no appropriate additional basis for addressing "potential  

contamination" beyond what would already be required in preparing and  

maintaining the appropriate required plans.  

Individual Response: The requirements at §146.95 for owners and operators seeking injection depth

waivers are intended to add to and modify the requirements that all GS well owners or operators must

meet, including those for financial responsibility, to ensure that the proposed site is evaluated in the

context of the presence of USDWs above and below the injection zone.  

EPA is developing guidance on financial responsibility to assist owners or operators in evaluating the

requirements of §146.85 and to assist Directors in evaluating financial responsibility demonstrations.

EPA is also developing guidance on the injection depth waiver process. The guidance describes the

recommended approach an owner or operator may follow when submitting a waiver application,

processing waiver applications by the UIC and PWSS Program Directors. These guidances will be

available on EPA’s website at water.epa.gov/type/groundwater/uic/wells_sequestration.cfm.  

Letter ID: 0382 Comment ID: 27991 Letter Lines: 1286 to 1309  

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

Directors  

Comment: Comment No. 48  

Page 44811  

Issue Topic from EPA's NODA  

Upon compliance with the waiver process requirements, the owner/operator would  

need to submit the information jointly to the UIC Program Director and the PWSS  

Program Director.  

Carbon Sequestration Council Comments  

The language in this statement may be creating unnecessary confusion. If the  

intent is to provide for notice to the PWSS Program Director so that appropriate  

comments can be submitted to the UIC Program Director for consideration in  

preparing and approving a permit, that would be acceptable. The statements  

here, however, suggest that there would be shared decisionmaking between the two  

Directors, which would be inefficient and could lead to conflicts among the  

agencies. Moreover, this type of approach would not be legal under the  
provisions of the SDWA and 40 CFR Part 145, which allow states to identify the  

agencies to participate in UIC permitting and to provide how the  

responsibilities will be divided among the participating state agencies. 40 CFR  

145.23(b). The authority for granting a waiver should rest solely with the  

state UIC primacy agency.  

Individual Response: EPA clarifies that decision making regarding injection depth waivers will not be

shared and disagrees that consultation with the PWSS Director is duplicative. The communication with

the PWSS Director is consultative and does not constitute a final decision making. 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 clarifies that 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.  

Letter ID: 0382 Comment ID: 27992 Letter Lines: 1311 to 1329  

Comment Code: 3300 3.3. Comments on Specific Elements of the Waiver Approach  

Comment: Comment No. 49  

Page 44811  

Issue Topic from EPA's NODA  

These Directors would consider factors such as:  

* * *  

‐The potential capacity of the geologic formation to sequester CO2, accounting  

for the availability of alternative injection sites;  

* * *  
Carbon Sequestration Council Comments  

There are many factors that project developers must consider in selecting an  

appropriate site for geologic sequestration. A review of the entire selection  

process and alternatives is not an appropriate task for Directors; there should  

not be a need to make comparison demonstrations to prove one site better than  

another if the proposed GS site meets all of the permitting requirements.  

Individual Response: EPA clarifies that the intent of the requirement to consider alternatives ensures

the waiver approach is applied only when needed. EPA anticipates that issuance of waivers will be

limited to circumstances where there are deep USDWs and/or where the lack of a waiver of injection

depth requirements would result in impractical or technically infeasible well construction, and where

USDW protection is demonstrated and maintained through the life of the GS project. EPA clarifies that

the responsibility for making a demonstration that no suitable alternative injection sites exist is the

responsibility of the owner or operator, not the Director.  

Letter ID: 0382 Comment ID: 27993 Letter Lines: 1331 to 1360  

Comment Code: 3300 3.3. Comments on Specific Elements of the Waiver Approach  

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

Directors  

Comment: Comment No. 50  

Page 44811  

Issue Topic from EPA's NODA  

‐ Planned needs, potential and/or future use of USDWs and non‐ USDWs in the  

area;  

Carbon Sequestration Council Comments  

Concrete plans for future use of formations can and should be submitted to EPA  

in comments from the PWSS Director for consideration but must be considered  

within the context of the SDWA endangerment standard for protecting USDWs.  

Comment No. 51  

Page 44811  
Issue Topic from EPA's NODA  

‐ 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;  

Carbon Sequestration Council Comments  

Same comment as 50 above.  

Individual Response: EPA agrees that information on planned and future uses of USDWs and water and

mineral resources near an injection zone should be considered by the UIC and PWSS program staff in the

context of USDW protection, and believes that the final GS rule requirements for consultation allow

consideration from both perspectives.  

EPA believes that the requirements at §146.95 for owners and operators seeking injection depth waivers

are intended to add to and modify the requirements that all GS well owners or operators must meet to

ensure that the proposed site is evaluated in the context of the presence of USDWs above and below

the injection zone.  

EPA clarifies that, pursuant to §146.95(d), the Regional Administrator will make the final determination

whether to issue an injection depth waiver. However, prior to a final decision, the Director must provide

the Regional Administrator with the information collected during the waiver application and the public

notice processes. Based on this information and pursuant to requirements at §146.95(d), the Regional

Administrator will provide written concurrence or non‐concurrence regarding waiver issuance. The

Agency clarifies that these requirements are within the authority of the Safe Drinking Water Act.  

Letter ID: 0382 Comment ID: 27994 Letter Lines: 1362 to 1378  

Comment Code: 3300 3.3. Comments on Specific Elements of the Waiver Approach  

Comment Code: 3340 3.3.4. Financial Responsibility  

Comment: Comment No. 52  

Page 44811  

Issue Topic from EPA's NODA  
‐ The proposed plan for securing alternative resources or treating USDW  

formation waters in the event of contamination related to the Class VI injection  

activity; and,  

Carbon Sequestration Council Comments  

This is a matter to be addressed on a site‐specific basis by the operator as  

part of the emergency response plan. It should not be required in all instances  

and should be a part of the plan only where chosen as an approach by the  

owner/operator to meet the regular permit requirement for preparation and  

maintenance of that plan.  

Individual Response: As described above, the requirements at §146.95 for owners and operators

seeking injection depth waivers are intended to add to and modify the requirements that all GS well

owners or operators must meet, including those for financial responsibility and emergency and remedial

response, to ensure that the proposed site is evaluated in the context of the presence of USDWs above

and below the injection zone.  

EPA clarifies that, for GS projects where injection depth waivers are sought, the Director must also

consider the proposed emergency and remedial response plan in making a determination whether to

grant a waiver per §146.95(b)(1)(iv). EPA believes that additional consideration of the emergency and

remedial response plan, which is required of all owners or operators per §146.94, in the context of

USDWs above and below the injection zone is appropriate where injection depth waivers are being

considered.  

Letter ID: 0382 Comment ID: 27995 Letter Lines: 1380 to 1392  

Comment Code: 3300 3.3. Comments on Specific Elements of the Waiver Approach  

Comment: Comment No. 53  

Page 44811  

Issue Topic from EPA's NODA  

‐ Any other locally applicable considerations.  

Carbon Sequestration Council Comments  
Such considerations would be appropriate to the extent related to the  

endangerment standard that is applied by the Director in making permitting  

decisions.  

Individual Response: EPA agrees that any additional information requested should be limited to that

which supports decisions regarding waivers, based on the potential for USDW endangerment. The final

GS rule, at §146.95(B)(1)(ix), stipulates that the Director consider "any other applicable considerations

or information requested by the Director." EPA believes this requirement provides the Director with

appropriate authority to consider all site‐specific information and promotes the flexibility sought by

commenters.  

Letter ID: 0382 Comment ID: 27996 Letter Lines: 1394 to 1408  

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

Directors  

Comment Code: 3370 3.3.7. Notice and Hearing  

Comment: Comment No. 54  

Page 44811  

Issue Topic from EPA's NODA  

The waiver may also be subject to local notice and public hearing. Following a  

public hearing and waiver approval by both Program Directors, the owner/operator  

may complete and submit the Class VI permit application.  

Carbon Sequestration Council Comments  

The authority for granting a waiver should rest solely with the state UIC  

primacy agency. It would, however, seem appropriate to provide a special  

notification to the PWSS Director with opportunity to comment.  

Individual Response: EPA believes that informing and consulting 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) 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 final determination regarding waiver issuance will be made by the Director,

following evaluation of all site‐specific information, public notice, and receipt of written concurrence or

non‐concurrence from the Regional Administrator. EPA believes Agency input is necessary in making

injection depth waiver decisions and agrees with commenters who expressed interest in ensuring that

multi‐state boundary and water resource issues are addressed. The Agency also believes that Agency

involvement in the waiver decision process will contribute to national consistency in waiver issuance.  

Letter ID: 0382 Comment ID: 27997 Letter Lines: 1410 to 1427  

Comment Code: 3380 3.3.8. Additional Requirements Established by the UIC Director  

Comment: Comment No. 55  

Page 44811  

Issue Topic from EPA's NODA  

The owner/operator may be required to comply with additional requirements that  

apply as a result of receipt of the waiver, designed to ensure the protection of  

USDWs both above and below the injection zone.  

Carbon Sequestration Council Comments  

Appropriate permit conditions may be included as necessary to ensure the  

protection of USDWs both above and below the injection zone. As with other  

requirements of the proposed rule, additional requirements under the proposed  

waiver should be appropriate and site specific. For example, seismic plume  

tracking may not be possible in some instances but other monitoring methods may  

provide sufficient protection of USDWs.  

Individual Response: EPA agrees that all requirements for GS projects, including those operating under

injection depth waivers, must be based on site‐specific conditions. The requirements at §146.95 that

allow owners or operators to seek a waiver from the injection depth requirements for GS wells are

designed to ensure that the owner or operator submit and the Director consider, on a site‐specific basis,

the implications, benefits, and challenges associated with GS and ensuring water availability and USDW

protection. EPA believes 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 additional

considerations for the owner or operator and Director when permitting such wells to ensure protection

of all USDWs.  
Letter ID: 0382 Comment ID: 27998 Letter Lines: 1429 to 1445  

Comment Code: 3390 3.3.9. Comments Regarding State Discretion to Adopt the Waiver Approach  

Comment: Comment No. 56  

Page 44811  

Issue Topic from EPA's NODA  

Due to the range of concerns and comments related to the injection depth  

requirements and the nature of the suggested waiver approval procedure, EPA  

believes that adoption of any such injection depth waiver process, as previously  

described, should be at the discretion of the UIC Program Director.  

Carbon Sequestration Council Comments  

There should not be a requirement for states to make special application to  

conduct a waiver program; the use of formations above the lowermost USDW should  

be available where permit requirements can be met. States already have the  

ability to impose more stringent requirements if they choose to do that.  

Individual Response: As described above, adoption of the waiver process will remain at the discretion of

individual UIC programs. Therefore, States, Territories, and Tribes seeking primacy for Class VI wells are

not required to provide for injection depth waivers in their UIC regulations and may choose not to make

this process available to Class VI wells under their jurisdiction.  

Letter ID: 0382 Comment ID: 27999 Letter Lines: 1447 to 1494  

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

Formations (seeking comment)  

Comment: Comment No. 57  

Page 44811  

Issue Topic from EPA's NODA  

Some stakeholders are concerned about the risks associated with the use of  
formations other than deep saline and depleted reservoirs (e.g., coal seams,  

basalts, etc.). EPA is seeking comment on whether the waiver process should  

apply to formations other than these.  

Carbon Sequestration Council Comments  

The Council has joined with other MSD participants to make specific  

recommendations regarding these types of formations:  

"We agree that EPA has ample basis for adopting rules to regulate GS in  

hydrocarbon reservoirs and in deep saline formations under the SDWA. For these  

types of geologic formations, there is a widespread technical consensus on how  

to assess and manage risks, what data is needed to characterize sites, how to  

select sites, how to conduct injection operations, how to model the behavior of  

CO2 in the reservoir, and how to monitor project performance.  

"There is less technical support on the ability to conduct GS in basalts, coal  

seams, salt caverns, and shales. As compared with deep saline formations and  

hydrocarbon reservoirs, the trapping/containment mechanisms of CO2 and/or  

operational engineering involved in basalts, coal seams, salt caverns and shales  

may be significantly different and using identical regulatory language might not  

be appropriate. In fact, it is not known at this time whether GS (or even  

injection in some cases) can be done at commercial scale in each of these types  

of formations ‐ GS efforts in these formations are still in the experimental  

stage. Wells in basalts, coal seams, salt caverns and shale formations should be  

treated as experimental wells under Class V, recognizing that completing the  

process of research, development and demonstration likely will require initial  

full scale experimental projects in addition to pilot projects.  

"Keeping these wells under Class V would allow EPA and the states to gain enough  

experience to develop suitable permitting requirements for such wells and to  

tailor those requirements at both the pilot and commercial scales until the  

agencies are ready to regulate such wells under an appropriate class.  

"To implement this approach, sections 144.6(f), 144.80(f), 146.5(f) and the  

definition of sequestration in 146.81 should be revised. The proposed 144.15  

provision that the construction, operation or maintenance of any non‐  

experimental Class V GS well is prohibited should be retained, but only with the  

understanding that this prohibition is not intended to limit the size or scale  

of any experimental GS operation." MSD Recommendation Letter May 14, 2009, Item  

1.  
Individual Response: EPA agrees that it may be appropriate to conduct injection into certain formation

types (e.g., in basalts and coal seams) on a small scale as experimental projects; such wells would be

permitted as Class V experimental technology wells. To facilitate experimental injection for GS and to

increase global understanding of injection into these formation types, the Agency is preparing an

addendum to the Class V experimental technology guidance on wells that meet the criteria. The decision

about whether a well should be permitted as a Class V experimental technology well or a Class VI well

will be site‐specific and depend on the nature of the project.  

Letter ID: 0382 Comment ID: 28000 Letter Lines: 1496 to 1524  

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

Concern (seeking comment)  

Comment: Comment No. 58  

Page 44811‐44812  

Issue Topic from EPA's NODA  

Additionally, the Agency is interested in: 1) Information on specific areas of  

the United States where injection depth and USDW depth are of concern (including  

formation depth, location, and assessed capacity; demonstrated confinement and  

GS suitability; and, formation salinity/TDS) as determined by well‐log analyses,  

cross sections, and formation fluid analyses; 2) Data, information, and evidence  

from owners and operators constructing and operating injection wells through  

existing CO2 plumes to access resources (e.g., water, hydrocarbon, etc.) below  

the injection zone and whether or not such operations are safe and do not  

endanger USDWs; and, 3) Strategies that States, Tribes, and regions are  

considering to manage competing GS and resource issues.  

Carbon Sequestration Council Comments  

As noted in our Comments, 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 CCS site, while not trivial, does not present significant technological  

hurdles. Industry has the technology to drill through over‐pressured gas  

reservoirs which are analogous to CCS 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 CCS 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: 0382 Comment ID: 28001 Letter Lines: 1527 to 1690  

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

comment)  

Comment: Attachment A  

October 15, 2009  

Detailed Comments of the Carbon Sequestration Council  

regarding:  

Birkholzer, J., J. Apps, L. Zheng, Y. Zhang, T. Xu, and C.‐F. Tsang, 2008.  

Research Project on CO2 Geological Storage and Groundwater Resources: Water  

Quality Effects Caused by CO2 Intrusion into Shallow Groundwater, Technical  

Report 2008, Earth Sciences Division, Lawrence Berkeley National Laboratory.  

Observations  

Stated project goal:  

o Develop a general understanding of the potential vulnerability of United  

States potable groundwater resources in the event of CO2 leakage into potable  

aquifers.  

Major tasks:  
o Developed comprehensive geochemical model representing what are presented as  

"typical" conditions in many freshwater aquifers  

o Conduct systematic reactive transport study to quantify effects of CO2  

intrusion into shallow groundwater aquifers  

Subtasks:  

o Identify mineral hosts controlling solubility  

‐Data from ore and coal mineralogy  

o Conduct thermodynamic analysis of water samples  

‐Data from USGS NWIS database  

o Improve thermodynamic data where necessary  

Comments:  

o Overall comments:  

o The modeling effort is screening level and contains many  

uncertainties.  

o The conclusion that As may exceed the maximum contaminant level (MCL)  

is limited to a few modeling scenarios that are localized and short‐  

term effects.  

o Conclusions could be viewed as issues that might warrant further  

investigation through field‐scale experimentation, but cannot  

reasonably be viewed as evidence of eminent risk posed by CO2 geologic  

sequestration.  

o Project Goal:  

o The goal of the study was to evaluate the effects that CO2 migration  

into drinking water aquifers might have with respect to mobilizing  

trace elements and exceeding drinking water standards. The authors  

were very clear that the study was conducted as a screening level  

assessment. The scope of this particular study was exceptionally  
broad, which required broad assumptions to be made. Conclusions from  

the study should be viewed as theoretical geochemical reactions that  

might warrant further investigation under circumstances where site  

characteristics and operational experience indicate a significant  

potential for leakage, rather than evidence that eminent risks are  

posed by CO2 geologic sequestration. No model created by the authors  

can be viewed as reflecting an actual aquifer composition; therefore  

no conclusion can be implied to represent an actual risk.  

o Geochemical Model Development:  

o The authors created "typical" aquifer conditions by combining  

assumptions related to major mineralogy, trace element mineralogy and  

groundwater analyses into a theoretical aquifer condition. Any  

conclusion derived from the study is fictive. Some aquifers may not  

contain natural arsenic at concentrations posing any significant risk  

for future mobilization.  

o Reactive transport and sensitivity analysis:  

o Results showed that, while Pb and As were modeled to be mobilized by  

geochemical reactions resulting from CO2 intrusion, Pb concentrations  

did not exceed the MCL. As concentrations exceeded the MCL in only a  

few simulation cases.  

o Sensitivity analyses of the Coastal Plain aquifer example showed that  

there are many cases where As does not exceed the MCL when CO2 is  

introduced to the system. These cases include:  

‐ When initially adsorbed arsenic is assumed negligible,  

eliminating an initial pulse of arsenic that is desorbed from  

the aquifer matrix:  

‐ In the study, the occurrence of a MCL exceedance for  

As is suggested when adsorption is neglected, but no  

modeling evidence is presented to verify the  

suggestion. Therefore, the suggestion is  

unsubstantiated.  

‐ When adsorption surface site densities are low, creating less  

adsorption sites for initially adsorbed arsenic:  
‐ The primary adsorbing surface in the model is illite,  

a clay mineral. Surface site densities for illite may  

be lower than assumed in the base case, creating less  

opportunity for local and short‐term mobilization of  

As above the MCL. This is acknowledged by the  

authors.  

‐ In the base case, illite comprises 2.85% of the rock  

composition by weight. Evidence from deep coastal plain  

sandstones suggests that illite may comprise only 1% of  

the rock composition by weight. This lower percentage  

would effectively reduce the potential for initial  

arsenic mobilization, but would ensure potential for  

long‐term adsorption of arsenic and limiting arsenic  

aqueous concentrations below the MCL.  

‐ When the arsenopyrite solubility product is reduced:  

‐ The authors illustrated that minor reductions in the  

solubility of arsenopyrite can result in substantially  

lower aqueous As concentrations during reactive  

transport analysis. No MCL exceedances occurred with a  

reduced solubility product.  

o Initially elevated partial pressures of CO2(g) may result in As  

concentrations exceeding the MCL prior to additional CO2(g) migration  

into the aquifer. This case must be considered as a strong  

possibility.  

o Mineral hosts controlling trace element solubility:  

o The model assumes that trace element mineral hosts in typical aquifers are the  

same as those found in coal and ore materials. A lack of additional  

information has resulted in the construction of a purely fictive scenario,  

which is the case in many screening level modeling efforts. This is  

recognized by the authors as a limitation. Although the authors make a sound  

attempt at the project scope with available data, it is not at all clear that  

there is enough information available to make the entire modeling effort  

worthwhile.  

o Thermodynamic analysis of water samples:  
o Assessing the saturation state and solubility of various mineral  

phases relies heavily upon accurate reconstruction of initial in situ  

pH and carbonate species distribution, specifically pCO2(g). The  

authors point out numerous complications with pH and initial pCO2(g)  

reconstruction ‐ a common problem with deep and shallow aquifer  

characterization. It is critically important to understand that  

modeling simulation results should be viewed as relative changes to an  

assumed initial condition. The uncertainty of an initial condition is  

multiplied when that assumed condition is perturbed. Any projected  

exact result, such as the occurrence of a particular As concentration  

(0.01 mg/L), should be viewed with appropriate caution.  

o Improvement of thermodynamic data:  

o Improvement of thermodynamic data based on the NWIS database is a  

questionable approach, given the complications arising from  

inconsistent sampling and analysis methods that the authors point out.  

Individual Response: In general, EPA agrees with the commenter’s observations of Birkholzer et al.

(2008), in particular with respect to model uncertainties and the need for further (site‐specific) studies

including laboratory and field experiments, with associated modeling. EPA also agrees that the study’s

conclusion cannot be viewed as evidence of imminent risk posed by CO2 geologic sequestration. EPA

understands (and mentions in the NODA and request for comment) that the risk of CO2 leaking from

deep storage is low for properly managed GS projects. However, because the leakage probability is not

necessarily zero, the potential consequences of unlikely leakage events need to be understood and

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

Regarding “Geochemical model development”, EPA clarifies that the LBNL study by design was

conducted to study the potential vulnerability of a wide range of typical and relevant aquifer types in

the case of CO2 intrusion, in order to provide a foundation for further studies on groundwater quality

concerns. While the overall results encompass a wide range of possible site specific conditions, the study

was not meant to be site specific; rather the authors suggest the work should be followed by site‐

specific investigations, such as in situ experiments with associated modeling.  

Regarding “Mineral hosts controlling trace element solubility,” the authors of the LBNL study did not

only assume that the trace element mineral hosts in potable water aquifers were the same as those

found in coal and ore materials; they actually tested the hypothesis that they might be the same and

present through comparison between the measured ion activity product and the calculated solubility

product, i.e., by calculating the saturation index (SI) using chemical analyses of potable ground waters in

the National Water Information System (NWIS) database. Modal values consistent with SI ≈ 0 suggested

their presence in many, but not all cases. This provides strong circumstantial evidence that the

postulated mineral hosts are most likely present in the aquifer host rocks. In other cases, results,
particularly with respect to Cd and Hg, were ambiguous, but even then, the number of alternative

choices was significantly narrowed. The study therefore forms a sound basis for further independent

investigations needed to verify the asserted hypothesis.

Regarding “Improvement of thermodynamic data,” it was not the intent, nor did the authors of the LBNL

study state that they were attempting to “improve” the thermo¬dynamic data based on the findings

from analyses of the ground waters from the NWIS database. However, for modeling purposes, LBNL did

calibrate observed mineral solubilities to predict the impact of solubility perturbations due to changes in

CO2 partial pressure, and subsequent modeling of arsenic and lead mobilization and transport, this

being done, as noted, to ensure that the “...results should be viewed as relative changes to an assumed

initial condition.” This calibration process, while common in hydrology, has proved to be controversial,

and in a subsequent paper (Apps et al., 2009), the results have been presented both in calibrated form,

and as a comparison between modeled predictions and field observations. Both sets are consistent

within the uncertainties of the model, and the uncertainties and natural variability of field data from the

NWIS database.  

Letter ID: 0382 Comment ID: 28565 Letter Lines: 945 to 957  

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

Concern (seeking comment)  

Comment: injection relative to the location of USDWs by proposing a waiver process. As  

stated in our December 24, 2008 Comments, we agree that CO2 can be injected  

above a USDW while protecting the USDW and maintaining access to the USDW for  

future use. As noted in our Comments, 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 CCS site, while not trivial, does not present  

significant technological hurdles. Industry has the technology to drill through  

over‐pressured gas reservoirs which are analogous to CCS 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 CCS 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: 0382 Comment ID: 28656 Letter Lines: 667 to 693  

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

Comment: Comment No. 25  

Page 44808  

Issue Topic from EPA's NODA  

Schnaar and Digiulio (2009) present a research review of over forty GS modeling  

studies spanning from 1993‐2008. The complete modeling review is available in  

the online public docket at www.regulations.gov.  

Carbon Sequestration Council Comments  

The identified "need to couple multiphase flow, reactive transport, and  

geomechanical processes" (NODA p.44808) is an idealized concept rather than a  

true need. 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. 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.  

The Schnaar and Digiulio, 2009 literature review on CO2 modeling focuses heavily  

on finite difference simulation of CO2 storage in saline aquifers. It is short  

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

storage, and also short on alternative flow modeling theories which could be  

applied to certain geologic storage applications.  

Individual Response: EPA 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: 0382 Comment ID: 29160 Letter Lines: 494 to 513  

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

Comment: Comment No. 20  

Page 44808  

Issue Topic from EPA's NODA  

[S]imulation runs indicated that injection pressures did not exceed fracture  

pressure or the maximum value used in the model for this basin. However, results  

also indicated that far‐ field pressure changes could propagate as far away as  

200 km (124 miles) from the core injection area where the geologic sequestration  

projects are located.  

Carbon Sequestration Council Comments  

The far‐field pressure changes observed in the model are on the order of 1‐2  

bars (14‐29 psi). These changes are very small, and would not likely have been  

observed if the model had included lateral heterogeneities in permeability and  

porosity and higher compressibility. The predicted pressure perturbations are  

so minor that they could not be accurately distinguished from noise in routine  
pressure data collection.  

Individual Response: Regarding noise in pressure measurements, pressure changes of 1‐2 bar should be

easily distinguishable from noise in routine pressure data.

Regarding lateral variability, the model assumption made about lateral homogeneity in permeability and

porosity is important for determining brine flow and far‐field pressure, but it is not clear without better

knowledge about lateral variability whether inclusion of heterogeneity would increase or decrease far‐

field effects.

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.  

Letter ID: 0382 Comment ID: 29161 Letter Lines: 515 to 538  

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

Comment: Comment No. 21  

Page 44808  

Issue Topic from EPA's NODA  

"[A] pressure increase of 0.5 bar existed at an areal extent of nearly 400 km by  

400 km (249 miles by 249 miles) after 50 years. These model results indicate  

that basin‐wide pressure influences can be large and may have intersecting  

pressure perturbations in a multiple‐site scenario."  

Carbon Sequestration Council Comments  

Regarding the NODA summary of LBNL studies on "Basin‐Scale Hydrologic Impacts of  

CO2Storage", we feel that a clarification of the results of this preliminary  

simulation and their implications are needed. In particular, it was noted that,  

a pressure increase of 0.5 bar might be expected at the distal extent of the  

regional aquifer (200 km from the core injection area). The next sentence  

states that "...basin‐wide pressure influences can be large." This implies that  
0.5 bar (~0.5 atm) pressure elevation at the perimeter of the basin is "large".  

Whereas we recognize that pressure perturbations will be significant in the core  

injection area (especially where pressure fields intersect), a 0.5 bar increase  

in pressure at the basin perimeter is not significant in terms of threatening  

containment.  

Individual Response: EPA clarifies that 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. The concern about pressure perturbation

is that deep saline water could be pushed upward into overlying freshwater aquifers via potentially

existing localized pathways. More research is needed to define at which point such pressure‐induced

localized flow might become a concern for USDW.  

Letter ID: 0382 Comment ID: 29162 Letter Lines: 540 to 560  

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

Comment: Comment No. 22  

Page 44808  

Issue Topic from EPA's NODA  

While simulated changes in salinity within the storage formation were relatively  

small, the predicted pressure changes could push saline water upward into  

overlying aquifers if localized pathways such as conductive faults existed.  

Carbon Sequestration Council Comments  

Water displacement up dip was insignificant in this study as well as in Nicot,  

2008, in which the equivalent of 50 million tons of CO2 was injected annually  

for 50 years, resulting in an average water table rise of only about 1 meter.  

Storage locations with significant faulting would have to be carefully evaluated  

for leakage potential. The oil and gas industry has developed a variety of  

tools and workflows to predict whether a given fault is likely to leak. These  

processes have been tested on numerous hydrocarbon prospects and ground‐truthed  

on faults known to seal or leak.  
Individual Response: EPA recognizes that water displacement updip (within the storage reservoir) is

shown to be insignificant in LBNL's study as well as in Nicot et al. (2008). However, the concern about

pressure perturbation is that deep saline water could be displaced upward into overlying USDWs via

existing localized pathways, such as undetected faults. EPA also agrees that storage locations with

significant faulting or with the potential for improperly sealed wells would have to be carefully

evaluated for leakage potential.

It is for these reasons that the final GS rule requires extensive evaluation of the site, including AoR

modeling that predicts the lateral and vertical migration of the CO2 plume and formation fluids

(§146.84(c)(1)) and an evaluation of known or suspected faults and fractures in the AoR (§146.82(a)(3))

and all artificial penetrations in the AoR (§146.84(c)(2)). The final rule also requires corrective action to

be performed on all wells to prevent the fluid movement into or between USDWs at §146.84(d). For

additional information regarding EPA's requirements for AoR delineation for GS projects, see the

responses to comments on the proposed rule in the rulemaking docket.

EPA also recognizes that the oil and gas industry has developed a variety of tools to predict whether a

given fault is likely to leak. However, it should be noted that site characterization for faulting and

abandoned wells will have to be done on a large scale, i.e., the size of the pressure‐affected areas.  

Letter ID: 0382 Comment ID: 29163 Letter Lines: 562 to 643  

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

Comment: Comment No. 23  

Page 44808  

Issue Topic from EPA's NODA  

As these large scale simulations indicated, limitations on injection volumes  

related to basin‐scale pressure build‐up should be considered during CO2  

capacity estimation.  

Carbon Sequestration Council Comments  

Basin‐scale modeling can be informative with respect to issues that may be faced  

in the future with multiple injection projects using the same storage reservoir  

in a given basin. The work of Birkholzer, Zhou and others (referred to as the  

authors herein) is illustrative in this regard in that it utilizes an actual but  

not yet fully characterized basin framework. In assessing the pressure field  
and brine migration potential developed as part of this work, it has to be  

clearly noted, however, that a spatially concentrated and certainly arbitrary  

injection scenario was required to generate the perturbations resulting in the  

model outcomes. The scenario was designed to create these perturbations and in  

itself is a far‐end member of the range of scenarios that might be utilized.  

Certain assumptions also had to be made regarding increases in seal permeability  

to generate the model results and these assumptions need significant refinement.  

As such, this is acceptable as a modeling exercise and as a guide to future  

studies but not as a predictable outcome or even a generalized outcome, and in  

fact the authors call for further strategies for pressure monitoring and the  

improvement of predictive models. Although the authors highlight far‐field  

impacts, it is premature for EPA to consider any basin‐scale mandates other than  

intensive data collection and assessment, including support for improvement in  

basin‐scale simulation models that are indicators of large‐scale hydrologic  

impacts. This work must be taken as an indicator of a research need, given the  

hypothetical concentration of twenty large storage projects in a limited area,  

not of the need for developing any specific basin‐scale regulations as part of  

the current Class VI development process. The latter approach would be  

counterproductive in that it may negate: (1) the development of multiple initial  

projects essential to more definitively define the very safeguards that  

groundwater protection strategies are designed to achieve, and (2) suppress the  

realization of more appropriate injection scenarios (rate, period, and  

placement) that would yield more realistic results than the inputs selected for  

the author's modeling.  

Support of this position is found in the authors work. They cite a Darcy flow  

velocity across the top model boundary, averaged over the model domain, of 0.47  

mm/year at 50 years of injection and an average Darcy velocity across the  

lateral boundaries of about half that value. The authors then go on to state:  

"The lateral migration distances of saline water associated with these boundary  

flows do not constitute a concern for the groundwater resources in overlying  

aquifers or neighboring basins." The authors also note that current groundwater  

withdrawal practices in the northern Illinois Basin are pulling saline water  

toward some water wells, and that "these impacts dwarf the predicted  

environmental consequences of the hypothetical CO2 storage scenario studied...".  

New data are being developed as a result of currently funded sequestration  

deployment testing. An example of the impacts of incompletely known chosen  

parameters can be seen in the discussion of hydraulic diffusivity. Recent work  

in the Illinois Basin indicates that the porosity value chosen for the modeling  

is low relative to higher porosity values obtained from recent drilling in the  

model injection area, thus recent data would tend to reduce the pressure‐  
affected region outside of the injection area. The authors narrate a  

sensitivity case that, they state, would reduce the region from 190 km to only  

60 km in radius, but would also be dependent on lower permeability and greater  

compressibility, as well as the higher porosity. Again, initial storage project  

development must occur to better define key parameters.  

Further, it is also important to recognize that the discussion of the capacity  

assessments for the basin compared to the 50‐year, 5,000 Mt perturbation in the  

model confuses the sequestration resource with basin capacity and the numbers in  

the DOE atlas are resources, not capacity. There is no expectation that the  

early DOE resource assessments would represent actual capacity. The authors  

statement that these resource estimates are subject to "an implicit assumption  

that the storage capacity is not constrained by pressure buildup and brine  

migration..." is incorrect, and researchers involved with creating these  

estimates would be unlikely to agree with this assumption. These are not undue  

criticisms of the work, simply an indication that definitions need to be refined  

and common terminology needs to become more widespread. The authors conclude  

that in a basin with multiple storage sites, industrial‐scale storage projects  

are needed to supply valuable data "to reliably estimate the expected pressure  

impacts of later projects". That is certainly where we must go to answer key  

questions while acknowledging that the state of understanding of modeling basin‐  

scale sequestration impacts is in its early stages and is premature for rule  

making at this time.  

Individual Response: EPA agrees with the commenter regarding the need for comprehensive site

characterization and data review of large‐scale saline formations. The final GS rule requires owners or

operators of GS wells to delineate the AoR for GS sites using computational fluid flow models designed

for the specific site conditions and injection regime (e.g., current injection activities). Periodic revisions

and recalibrations of the models must be conducted as described in the approved AoR and corrective

action plan required at 146.84. The final rule also requires monitoring of the plume and the pressure

front throughout the injection phase (146.90). For additional information regarding EPA’s requirements

for AoR delineation for GS projects, see the responses to comments on the proposed rule in the

rulemaking docket.

EPA acknowledges the need for improvement/validation of predictive models before considering basin‐

scale mandates, and will continue to collect and review data on early GS projects as part of its adaptive

rulemaking approach. EPA recognizes that inter‐state and even international cooperation may be

necessary where multiple injection operations may interact, but has no plans or authority to develop a

basin‐wide regulatory process. The final GS rule focuses on permitting of individual GS wells and

therefore does not include requirements for basin‐scale evaluations. EPA notes, however that the GS

rule, at §146.82(b), requires that the Director notify representatives of all states, tribes, and territories

in the AoR to inform them of the permit application and offer them an opportunity to be involved in any
relevant activities, such as development of the required project‐specific plans.

Regarding the comment that the paper presents a spatially concentrated and arbitrary injection

scenario, EPA notes that, considering the large volumes that need to be sequestered to make a

contribution to climate change mitigation and the volumes that are produced from large stationary

sources, it may be unrealistic to assume that storage sites can be placed so far from each other that

their pressure envelopes would never overlap. The spatial pattern of GS projects used in LBNL’s work

was developed by placing the 20 storage sites into the center area of the example basin where the

geological conditions were most favorable for CO2 storage.

Regarding the assumption about seal permeability, the base simulation case in the basin‐scale model

used vertical permeability of seal of 1.0 × 10‐18 m2. A sensitivity case was studied in Birkholzer et al.

(2009) assuming a seal permeability of 1.0 × 10‐20 m2. A higher seal permeability allows for pressure

attenuation in the storage formation caused by slow diffuse brine migration into the seals. The two

simulation cases reflect the range of seal properties available for the example basin, from core scale

measurements and regional scale estimates (Zhou et al., 2009).

Regarding capacity, while EPA acknowledges differences in terminology (e.g., the resource estimates

provided in USDOE (2008) correspond to effective capacities in the definition given in CSLF (2008) and

the USDOE capacity estimates correspond to the CSLF practical capacities) the point Birkholzer and Zhou

(2009) are trying to make is that the practice of estimating resource (or effective capacity) via efficiency

factors does not include pressure and brine migration constraints.