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Responses on each topic area are compiled and are also available in the rulemaking docket.October 15, 2009Comments of the Carbon Sequestration Council onEPA’s NODA for the Geologic Sequestration Rule74 Fed. Reg. 44802-13 (August 31, 2009)Docket: EPA–HQ–OW–2008–0390No.PageIssue Topic from EPA’s NODACarbon Sequestration Council Comments144803Availability of this newinformation could change EPA’sapproach to the finalrulemaking.The Carbon Sequestration Council (“the Council”) has reviewed the Notice ofData Availability (NODA) and the accompanying data and results presented forpublic review and comment. We see nothing in the new information that suggeststhat EPA should depart from the adaptive approach to regulation that EPA hasdiscussed as the basic objective for the geologic sequestration (GS) rule.244805EPA is providing this [sic] dataand associated projectsummaries because the Agencyexpects that there may beadditional studies and data onother GS projects, the use ofexisting technologies, and GSrelated research that may informthe Agency’s regulatorydevelopment process for GS.Such data could contribute to theAgency’s understanding of sitecharacterization, wellconstruction, operation, andmonitoring requirements.The state of the science for CO2storage and the over 35 years of experience withCO2injection for enhanced oil and gas recovery are more than adequate tosupport EPA proceeding with final rule promulgation.344805Many commenters suggestedthat supplementary research onGS is necessary prior to rulepromulgation and that EPAshould wait until the Departmentof Energy (DOE)-sponsoredPhase II and Phase III pilotExtensive additional research is proceeding on many different aspects of carboncapture, transportation, and sequestration, and the resultingfindings will certainlyadd to our current understanding of theseaspects. However, there are no majortechnical breakthroughs that need tooccur before beginning commercial-scaleCO2storage operations in the United States. Moreover, adherence to an adaptiveapproach for regulations will facilitatenew information being implemented in aresponsible way.Comments of the Carbon Sequestration Council1rfvanvoorhees@bryancave.comOctober 15, 2009Comments of the Carbon Sequestration Council2rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsprojects are complete beforefinalizing the GS rule.444805Comments on the proposalencouraged additional researchand investigations on areasincluding (but not limited to):confining zone characterization;modeling; CO2plumemovement; geochemistry;impacts of GS on salineformations; leakage fromabandoned wells caused bymaterial and cementdegradation; potential pathwaysfor contamination of USDWs;leak mitigation and remediation;and criteria for determining thatthe CO2plume has stabilized.Furthermore, the oil and gas industry hasrelevant experience to draw on fromover 35 years of injecting CO2for EOR, over 90 years of natural gas storage, and150 years of oil and gas production. Theindustry also operates large-scale CO2storage projects in offshore Norway, Algeria, and Canada, and has other relatedoperations that have proven safe and effective.544805EPA’s Office of Research andDevelopment is conductingintramural and extramuralresearch activities to developmodeling and monitoring toolsfor protecting undergroundsources of drinking water.Monitoring and modeling needs willbe different for each potential CO2storagesite, and we encourage flexibility in the model requirements. EPA should not beprescriptive in requiring certain modelsor monitoring techniques, as each storagesite and the operational experience for each GS project willbe different.Moreover, existing and future workmay yield improved and alternativeapproaches to modeling for particular circumstances.644805Analytic and semi-analyticmodels are being developed andevaluated for determining thearea of review based on geologicand hydrologic conditions.Same comment as in 5 above.744805Comprehensive laboratory testsare being applied to theThe proposed EPA regulation was draftedwith the recognition that there is noone suite of monitoring tools that is appropriate for all potential sequestrationOctober 15, 2009Comments of the Carbon Sequestration Council3rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsdevelopment and field-testing ofmonitoring strategies that candetect migration of fluids intoshallow aquifers and assesspotential geochemical impacts.sites. A variety of subsurface factors and location specific concerns need to beconsidered to develop the best monitoringstrategy for a given project. There aremany monitoring tools that could be shown to have some utility, but it does notfollow that every tool – or any particulartool – should be used or required for anygiven geological storageproject, especially asscaling-up some of thesemonitoring techniques from pilot to commercial scale would be cost-prohibitive.For example, soil and air monitoringare unnecessary under most foreseeablecircumstances. The general strategy ofmonitoring programs should be to confirmthe validity of the site selection and characterization processand to detect anyleakage long before it reaches the surface.844806This SECARB project employs,demonstrates, and validates theEPA’s proposed Class VI wellconstruction, operational, andmonitoring requirements.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-EORand underground gas storage experience.1. The model used in the Escatawpa project was accurate in predicting thedistance the plume moved, taking into consideration the small scale of the project,with only 3,027 tons of CO2injected over 30 days.2. All monitoring activities were concluded in September 2009. No unanticipatedmigration was detected or suspected to have occurred.3. The purpose of the shallow monitoring was to determine if CO2was seepinginto shallow geology, groundwater, or ecosystems either through geologicpathways or up the well bore.4. Monitoring was performed in the target reservoir with time-lapse VSP anddown hole geophysical methods and in the near surface with tracers, soil flux, andgroundwater quality testing.Although the injection well for the Escatawpa project was permitted as Class V,the Mississippi Department of Environmental Quality (MDEQ) required that themore stringent Class I hazardous wasteinjection well (Class IH) constructionstandards be met. Construction to these Class IH standards was not voluntarilyOctober 15, 2009Comments of the Carbon Sequestration Council4rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsproposed by the SECARB project team.EPA should not conclude that thesedesign standards are warranted based on thissingle pilot project experience thatdid not even assess the sufficiency ofalternative designs. Instead, EPA shouldadopt less prescriptive standards that are sufficiently protective based onindustry’s more than 35 yearsof success in injecting CO2under the Class II UICprogram. The Class II EOR wells constructed for these projects - and theiroperating practices - have an excellent record of mechanical integrity and ofprotecting USDWs.At this point it cannot be concluded thatthe project components and constructiondesign demonstrate and validate EPA’s well construction, operational, andmonitoring requirements. Since this was aresearch and development project somerequirements were more stringent and some may have been less stringent thanwould be required for a commercial-scale geologic sequestration project.The Escatawpa project was essentially aninjection test but was very valuablefrom the standpoint of outreach and education, permitting process analysis, andsite characterization.Some of the practices employed at Escatawpa, such as cementing the long stringcasing to surface, may not be possible inall circumstances. The results of theSECARB project do not imply that less burdensome regulations would not haveworked equally well. See the construction recommendations presented in theMSD Recommendation Letters of May 14, 2009 and May 15, 2009.944806The Aneth Field projectconfirms the need for a projectdesign with a robust monitoringplan, and tests the importance ofmonitoring and modelingagreement in GS projects.Data collected for monitoring will allow for improvement and/or refinement of anexisting model. As the feedback between monitoring and modeling increasesconfidence, the monitoring plan can be adapted as needed (See Cooper, C., ed.,2009). It is important thatthe regulations allow for refinements of the originalmonitoring plan, should modeling or reservoir performance results indicateoperational or monitoring changes are appropriate.1044806In addition, the projectdemonstrates the utility ofThere are many monitoring tools that could be shown to have some utility, but itdoes not follow that every tool – or anyparticular tool – should be used orOctober 15, 2009Comments of the Carbon Sequestration Council5rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsvarious monitoring technologiesthat may be used by owners andoperators of Class VI wells.required for every geologicalsequestration project, especially as scaling-up someof these monitoring techniques from pilot to commercial scale would be costprohibitive. For example, soil and air monitoring are unnecessary under mostforeseeable circumstances. The testingof particular monitoring technologies doesnot show the necessity of these techniquesor the inadequacy of alternatives thatwere not tested. Soil flux monitoring was not valuable to the Aneth project teambecause background and control point measurements were highly variable anddata interpretation was difficult. Tracersalso did not appear to be necessary.1144806The Agency sought comment onusing unmineable coal seams forGS in the proposed rule. Theinvestigation at Pump Canyonwill inform a determination onwhether CO2can be effectivelyand safely sequestered in coalseams.Coal bed injection is promising, but it isat a more experimental stage than CO2injection into other types of reservoirs. CO2storage within coaldeposits is viablebut 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 Vexperimental wells at this time.See MSD Recommendation Letter May 14, 2009,Item 1.1244807LBNL conducted multiplemodel runs to assess a variety ofscenarios and aquifer conditionsand, as discussed below, foundthat if injected CO2comes intocontact with shallow USDWs,some trace elementconcentrations such as arseniccould increase.The LBNL study goal, as stated in Apps, et al., 2009, is to develop a“comprehensive geochemical model that describes the complete chemistry of arange of specified shallow aquifer systems”. In reality, they did not model a“representative groundwater” (NODA p. 44807). See Attachment A.1344807A preliminary assessment ofCO2-related water qualitychanges, including pH, wasconducted by calculating theexpected equilibriumconcentrations of trace elementsas a function of the amount ofThe groundwater samples chosen for the model had to have been tested for atleast one of the following to be includedin the study: As, Ba, Cd, Hg, Pb, Sb, Se,U, or Zn. These analyses are not commonlyrun in parts of the U.S. or in aquifersknown to be free of heavy metal contamination. There will likely be many areasof the U.S. where the mobilization of arsenic, lead, and other trace elements is nota concern because the minerals that these elements are typically found in are notpresent in those formations. This doesnot necessarily render the LBNL resultsOctober 15, 2009Comments of the Carbon Sequestration Council6rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council CommentsCO2in a representative potablegroundwater. Results of thismodeling obtained for typicalaquifers under reducingconditions indicate that arseniccould potentially exceed Federaldrinking water standards atelevated CO2concentrations (40CFR 141.62 (b)(16)).invalid, but it does indicate that the results may not be typical and thus notrepresentative.1444807Other trace elements, such asbarium, cadmium, lead,antimony, and zinc, may also bemobilized in certaincircumstances, but the majorityof results did not showmobilization at levels exceedingthe MCL or AL. (action level)The modeling used a number of assumptionsin order to test scenarios where traceelement mobilization was likely to occur.The results focused on whether or notgiven elements would exceed the maximum contaminant levels (MCLs), notwhether mobilization would realistically occur invarious scenarios.1544807While LBNL studies did suggestthat CO2interaction could causesignificant concentrationincreases compared to the initialwater composition, the MCL forarsenic was exceeded in only afew simulation scenarios, whilethe lead concentrations remainedbelow the AL under allscenarios.To the extent that these studies could beviewed as presenting extreme scenarios,some comfort might be drawn from suchresults. We are concerned, however,with the absence of realistic scenarios, asnoted below. It ismore appropriate toview the studies to date as a preliminary test of the methods and models.Subsequent testing might provide usefulresults as realistic scenarios aredeveloped and particularly as the methodscan be tested with actual project sitecharacteristics. The identification ofmethodologies and potential approaches isuseful by itself as a step toward siteassessment and the development of operationand management plans.1644807It is important to emphasize thatthese studies looked at potentialconsequences of CO2leakageinto the USDW, not thelikelihood of such leakageThe probability of trace element contamination of groundwater requires themultiplied probabilities of CO2movement out of theintended storage zone,finding a migration path to a USDW, passing through or ending up in a unit withminerals that contain heavy metal assemblages, environmental conditionsfavorable to dissolution, and an undetected, unremediated leak that mobilizesOctober 15, 2009Comments of the Carbon Sequestration Council7rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsoccurring.these elements. The probability of USDW contamination, based on theprobabilities 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 selectedand managed geologic storage sites.1744808The Agency will use thesepreliminary results and publiccomments on this research aswell as potential site-specificanalyses, to refine and informsite characterization, monitoring,and remediation requirementsand guidance, if necessary, inthe Agency’s final rulemaking.In general, reactive transport modeling represents the correct method ofevaluating the possible impacts on USDWs by the leakage of CO2from anunderlying CCS reservoir. The LBNL workverifies that TOUGHREACT reactivetransport modeling technology is suitablefor this purpose. However, the resultsreported by Zheng et al. arebased on hypothetical cases. They should not be usedto establish regulations because: (1) these results have not been validated foranalog scenarios; (2) the recompiled thermodynamic data they used have not beenverified by experimental data; (3) more realistic conditions andprocesses such asthe migration of a mixture of CO2-saturated reservoir brine, supercritical CO2,and/or other gases are not considered; and (4) their model does not integratedynamic effects during the loss of containment for a CCS reservoir.1844808The Agency seeks comment onthis research and any additionalstudies related to a) mobilizationof constituents and b) thelikelihood or frequency of suchleakage/risks.See the following references (fullcitation in “References” below):Smyth, R.C., et al., 2009Koplos, J., 2007Duncan, et al., 20091944808LBNL studied a hypothetical,future scenario of GS in asedimentary basin as anillustrative example todemonstrate the potential forbasin-scale hydrologic impactsof CO2storage (Birkholzer et al.,2008b).Modeling Issues:•The model assumes lateral homogeneity of all stratigraphic units.•Permeability in the Eau Claire Shale top seal may vary considerably in alateral sense at regional scales (Arnold et al., 1996). In the model, thepermeability 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 ingeneral coarse grids overestimate CO2movement and capillary trapping. The adaptive gridding approach used in theIllinois Basin model uses progressively larger grid cells away from the injectionarea. The largest cells near the edgeof the basin are 10 x 10 km, and theOctober 15, 2009Comments of the Carbon Sequestration Council8rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsmaximum thickness of any grid block wasset to 10 m. The high aspect ratioand large size of these cells may introduce significant numerical dispersion inthe model results. Conclusions basedon the modeled brine flow out of thebasin and far field pressure effects should be considered qualitative at best,given the constraints of the model.2044808[S]imulation runs indicated thatinjection pressures did notexceed fracture pressure or themaximum value used in themodel for this basin. However,results also indicated that farfield pressure changes couldpropagate as far away as 200 km(124 miles) from the coreinjection area where thegeologic sequestration projectsare located.The far-field pressure changes observed inthe model are on the order of 1-2 bars(14-29 psi). These changes are very small, and would not likely have beenobserved if the model had included lateral heterogeneities in permeability andporosity and higher compressibility. The predicted pressure perturbations are sominor that they could not be accurately distinguished from noise in routinepressure data collection.2144808“[A] pressure increase of 0.5 barexisted at an areal extent ofnearly 400 km by 400 km (249miles by 249 miles) after 50years. These model resultsindicate that basin-wide pressureinfluences can be large and mayhave intersecting pressureperturbations in a multiple-sitescenario.”Regarding the NODA summary of LBNLstudies on “Basin-Scale HydrologicImpacts of CO2Storage”, we feel that a clarification of the results of thispreliminary simulation and their implications are needed. Inparticular, it wasnoted that, a pressure increase of 0.5 bar mightbe expected at the distal extent ofthe regional aquifer (200 km from the core injection area). The next sentencestates that “...basin-wide pressure influences can be large.” This implies that 0.5bar (~0.5 atm) pressure elevation at the perimeter of the basin is “large”.Whereas we recognize that pressure perturbations will be significant in the coreinjection area (especially where pressure fields intersect), a 0.5 bar increase inpressure at the basin perimeter is notsignificant in terms of threateningcontainment.2244808While simulated changes insalinity within the storageformation were relatively small,Water displacement up dip was insignificant in this study as well as in Nicot,2008, in which the equivalent of 50 million tons of CO2was injected annually for50 years, resulting in an average water table rise of only about 1 meter.October 15, 2009Comments of the Carbon Sequestration Council9rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsthe predicted pressure changescould push saline water upwardinto overlying aquifers iflocalized pathways such asconductive faults existed.Storage locations with significant faulting would have tobe carefully evaluatedfor leakage potential. The oil and gas industry has developed a variety of toolsand workflows to predict whether a given fault is likely to leak. These processeshave been tested on numerous hydrocarbon prospects and ground-truthed onfaults known to seal or leak.2344808As these large scale simulationsindicated, limitations oninjection volumes related tobasin-scale pressure build-upshould be considered duringCO2capacity estimation.Basin-scale modeling can be informative withrespect to issues that may be facedin the future with multiple injection projects using the same storage reservoir in agiven basin. The work of Birkholzer, Zhouand others (referred to as the authorsherein) is illustrative in this regard in that it utilizes an actual but not yet fullycharacterized basin framework. In assessing the pressure field and brinemigration potential developed as part ofthis work, it has to be clearly noted,however, that a spatially concentrated and certainly arbitrary injection scenariowas required to generate the perturbationsresulting in the model outcomes. Thescenario was designed to create these perturbations and in itself is a far-endmember of the range of scenarios that might be utilized. Certain assumptions alsohad to be made regarding increases in seal permeability to generate the modelresults and these assumptions need significant refinement. As such, this isacceptable as a modeling exercise and as aguide to future studies but not as apredictable outcome or evena generalized outcome, and in fact the authors callfor further strategies for pressure monitoring and the improvement of predictivemodels. Although the authors highlight far-field impacts, it is premature for EPAto consider any basin-scale mandates other than intensive data collection andassessment, including support for improvement in basin-scale simulation modelsthat are indicators of large-scale hydrologicimpacts. This work must be taken asan indicator of a research need, giventhe hypothetical concentration of twentylarge storage projects in a limited area, notof the need for developing any specificbasin-scale regulations as part of the current Class VI development process. Thelatter approach would be counterproductive in that it may negate: (1) thedevelopment of multiple initial projects essential to more definitively define thevery safeguards that groundwater protection strategies are designed to achieve,and (2) suppress the realization of more appropriate injection scenarios (rate,October 15, 2009Comments of the Carbon Sequestration Council10rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsperiod, and placement) that would yield more realistic results than the inputsselected for the author’s modeling.Support of this position is found in theauthors work. They cite a Darcy flowvelocity across the top model boundary,averaged over the model domain, of 0.47mm/year at 50 years of injection and anaverage Darcy velocity across the lateralboundaries of about half that value. Theauthors then go on to state: “The lateralmigration distances of saline water associated with these boundary flows do notconstitute a concern for the groundwaterresources in overlying aquifers orneighboring basins.” The authors also note that current groundwater withdrawalpractices in the northern Illinois Basin are pulling saline water toward some waterwells, and that “these impacts dwarf thepredicted environmental consequences ofthe hypothetical CO2 storage scenario studied...”.New data are being developed as a result of currently funded sequestrationdeployment testing. An example of the impacts of incompletely known chosenparameters can be seen in the discussionof hydraulic diffusivity. Recent work inthe Illinois Basin indicates that the porosity value chosen for the modeling is lowrelative to higher porosity values obtained from recent drilling in the modelinjection area, thus recent data would tend to reduce the pressure-affected regionoutside of the injection area.The authors narrate a sensitivity case that, theystate, would reduce the region from 190 kmto only 60 km in radius, but wouldalso be dependent on lower permeability and greater compressibility, as well asthe higher porosity. Again, initial storage project development must occur tobetter define key parameters.Further, it is also important to recognize that the discussion of the capacityassessments for the basin compared tothe 50-year, 5,000 Mt perturbation in themodel confuses the sequestration resource with basin capacity and the numbers inthe DOE atlas are resources, not capacity.There is no expectation that the earlyDOE resource assessments would represent actual capacity. The authorsstatement that these resource estimates aresubject to “an implicit assumption thatOctober 15, 2009Comments of the Carbon Sequestration Council11rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsthe storage capacity is not constrained by pressure buildup and brinemigration...” is incorrect,and researchers involved with creating these estimateswould be unlikely to agreewith this assumption. These are not undue criticismsof the work, simply an indication that definitions need to be refined and commonterminology needs to become more widespread. The authors conclude that in abasin with multiple storage sites, industrial-scale storage projects are needed tosupply valuable data “to reliably estimatethe expected pressure impacts of laterprojects”. That is certainly where we must go to answer key questions whileacknowledging that the state of understanding of modeling basin-scalesequestration impacts is in its early stagesand is premature for rule making at thistime.2444808EPA believes that the examplestudied by LBN L illustrates theimportance of basin-scaleevaluation of reservoir pressuresand far-field pressures resultingfrom CO2injection. EPArequests comment on this studyand welcomes additional studiesthat provide information on theneed for basin-scale evaluationsfor GS injection.The model results are not applicable toArea of Review decisions for individualsite selection this early in the development of geologic storage. Adaptive rulemaking would allow for adjustments to encompass multi-project scenarios in thesame basin if needed in the future. See MSG Joint Letter dated May 14, 2009,Item 2 on suggested language for managing pressure interference. (Adoption ofthis recommended provision will help to address and manage multi-projectinterference concerns ifand when they occur.)2544808Schnaar and Digiulio (2009)present a research review of overforty GS modeling studiesspanning from 1993-2008. Thecomplete modeling review isavailable in the online publicdocket atwww.regulations.gov.The identified “need to couple multiphase flow, reactive transport, andgeomechanical processes” (NODA p.44808) is an idealized concept rather than atrue need. Such a model is certainly possible but will likely be intractable,expensive, and it will still be at the mercyof the quality of the input. It is moreimportant to correctly capture the range of processesand possible outcomes at agiven location than to use a particularsoftware package or type of modeling.Robust yet less complex models capturing the most important physical andchemical processes can accomplish the modeling goals necessary for safe storage.The Schnaar and Digiulio,2009 literature review on CO2modeling focusesOctober 15, 2009Comments of the Carbon Sequestration Council12rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsheavily on finite difference simulation of CO2storage in saline aquifers. It is shorton references to analogous modeling of CO2-EOR storage and underground gasstorage, and also short onalternative flow modelingtheories which could beapplied to certain geologic storage applications.2644809The basis of these requirementsis the principle that placingdistance between the injectionformation and USDWsdecreases risks to USDWs.This is too simplistic; distance will undoubtedly help, but distance does notdeserve to be singled out like this. The nature and characteristics of the confiningmaterial is paramount and must be considered along with distance in determiningthe sufficiency of containment at any particular site.2744809In these deep-well injectionscenarios, the added depth anddistance between the injectionzone and overlying formationsserve both as a buffer allowingfor pressure dissipation and as azone for monitoring that maydetect any excursions (of theinjectate) out of the injectionzone.Again, this assertion goes too far. Distance is not the only way to accomplishthese objectives and will notmake up for otherwise poorsite characteristics. Nordoes the lack of depth defeat a goodsite with sufficient containment.2844809Additional distance also allowstrapping mechanisms, includingdissolution of CO2in nativefluids and mineralization, tooccur over time – therebyreducing risks that CO2maymigrate from the injection zoneand endanger USDWs.Site selection and characterization mustfocus on the trapping and containmentmechanisms themselves without giving undue weigh to distance, which plays arole but is not always determinative.2944809Additionally, the depth anddistance below the lowermostUSDW allow the potential forthe presence of additionalconfining layers (between theIf demonstrated containment is sufficient to meet the siting requirements, thenadditional confining layers are unnecessary.October 15, 2009Comments of the Carbon Sequestration Council13rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsinjection zone and overlyingformations/USDWs).3044809Water availability research inthe United States indicates thatwater treatment of highersalinity waters (in excess of theUSDW protectiveness thresholdof 10,000 ppm TDS) may bemore cost effective than the costof obtaining water rights orsurface water elsewhere in thearea (Sengebush, 2008).There is a growing recognition that CCS may be treated as a public necessity, andfuture long term planning should include provision for CO2storage as well aswater supply. The appropriate authorities will need to work together to reconcilesuch plans to assure that resources are effectively deployed. Responsibility forthis activity falls outside that ofindividual CCS project developers.3144809Furthermore, some specificresearch on CO2injection for GSinto various formationsincluding shallow, volcanicrocks such as flood basalts(McGrail, et al., 2006) and coalseam injection (Dooley, et al.,2006; IPCC, 2005; MIT 2007;White et al., 2005) illustrates thepotential for GS in theseformations, but only if there isdepth requirement flexibility.The Council agrees that broad categoriesof formations should not be arbitrarilyexcluded from use solely on the groundsof underlying USDWs. Site selectionshould be able to consider all locationsand receiving injection zones that canmeet the siting requirements by providing sufficient containment of CO2streams.The proposed exclusion of formations isthus inconsistent with EPA’s basicadaptability approach in disallowing forthe advancements that may result fromresearch and development projects thatidentify additional suitable types offormations for GS.The Council has joined withother MSD participants torecommend that “[w]ellsin basalts, coal seams, salt caverns andshale formations should be treated asexperimental wells under Class V, recognizing that completing the process ofresearch, development and demonstration likely will require initial full scaleexperimental projects in addition to pilot projects.“Keeping these wells under Class V would allow EPA and the states to gainenough experience to develop suitable permitting requirements for such wells andto tailor those requirementsat both the pilot and commercial scales until theagencies are ready to regulate such wells under an appropriate class.” MSDRecommendation Letter, May 14, 2009, Item 1.October 15, 2009Comments of the Carbon Sequestration Council14rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Comments3244809Certain States have indicatedthat where USDWs are verydeep (e.g., 15,000 ft/4,572meters and deeper) and layered(stratified) these regions wouldbecome unavailable for largescale GS projects becauseinjectors would not be able tocomply with the currentinjection depth (and wellconstruction) requirements.These States suggest that GSshould be allowed in certainareas if a site-specificdemonstration can be made thatUSDWs will be protected.We support the provision to allow CO2injection into formations above thelowermost USDW when adequatecontainment of injected CO2and protection ofUSDWs can be demonstrated. As noted in our comments of December 24, 2008,we would prefer to have the necessarycriteria for GSproject siting andcontainment demonstration built into the normal permitting process, where theserequirements would be routinely applicable whenever a permit applicant isproposing to inject into a saline formation that is above the lowermost USDW.The permitting process – with the notice, comment, hearing and permittingprovisions we support – would provide adequately for consideration of thenecessary technical issues. Nevertheless,we also believe that the concept of asite-specific waiver process for geologicstorage above the lowermost USDW canbe made workable but requires some improvements which are specifically notedin these Comments.3344809-10Class II and Class III ownersand operators of sites whereinjection is taking place aboveand between USDWs mustidentify and demonstrate upperand lower impermeableconfining units.These confiningunits serve as barriers to fluidmovement and pressure andmust ensure continuous injectateisolation, confinement, andUSDW protection. Identificationof such units is conductedthrough analysis of sonic andresistivity logs, drill stem tests,and wire line tests.The requirement to demonstrate the suitability of the confining unit below theproposed injection zone is reasonable and technically feasible. Other sitecharacterization requirements are not significantly different than for geologicstorage below the lowermost USDW.As reflected in recommendations presented by the Multi-Stakeholder Discussionparticipants in the MSD Recommendation Letters of December 23, 2008 andOctober 9, 2009, which the Council and many of our members signed, therequirement that GS take place in formations beneath the lowermost USDWshould not be imposed on GS taking placein oil and gas reservoirs, many ofwhich are located above the lowermost USDW and have demonstratedcontainment capabilities over geologictime and through many years of oil andgas production operations.October 15, 2009Comments of the Carbon Sequestration Council15rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Comments3444810EPA believes that a waiverprocess may respond to therange of comments, both for andagainst the proposedrequirement that Class VI wellsinject below the lowermostUSDW.EPA should integrate the waiver processinto the normal permit approval processas much as possible, for example, by combining the public hearing for the waiverwith the public hearing forthe permit, if one is held. Hearings should be anoption, and not an automatic requirement.Hearings should be offered as apotential option but shouldnot be required unless warranted in the judgment ofthe Director.3544810EPA believes this approach mayadditionally accommodaterequests for geographicflexibility while placing suchdeterminations at the State orRegional level.These determinations should be at the state or regional level, although EPARegions often will not be in a position to make these determinations as effectivelyas a state agency because the EPA regional offices typically have limitedinvolvement in the related areas ofprogram oversight. Where EPA regionaloffices are making permitting decisions forClass VI wells, they should coordinatewith the relevant state agencies.3644810Lastly, the approach is designedto acknowledge andaccommodate comments andconcerns about drinking waterresource availability and thepotential/known future needs,and to afford such waterresources protection.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 moresaline reservoir is overlying a USDW. These conditions are uncommon andwould not address the problem faced inlarge portions of the western US whereUSDWs may extend from the surface to very great depths. To allow CCS inthese regions, the waivers would necessarily have to authorize injection intoUSDWs above the lowermost USDW. Second, for the waiver system to workeffectively, the final decision making authority for a waiver should be with theagency holding primacy for the proposed Class VI UIC program.3744810Second, the alternative underconsideration does not prohibitinjection into any specificformation types (e.g., basaltsand/or coal seams). It affords allformations equal treatment andallows specific regions of thecountry the regulatory flexibilityto determine if any injection at aparticular site and depth is theWe are supportive of EPA’s effort to introduce flexibility on the depth ofinjection relative to the location of USDWs by proposing a waiver process. Asstated in our December 24, 2008 Comments, we agree that CO2can be injectedabove a USDW while protecting the USDWand maintaining access to the USDWfor future use. As noted in our Comments, the Salt Creek EOR project inWyoming, which has a USDW below the injection zone, is an excellent exampleof how industry can operate CO2injection wells in an EOR context withoutendangering or limiting access to USDWs that are located below the injectionzone. Accessing USDWs below a CCS site, while not trivial, does not presentsignificant technological hurdles. Industry has the technology to drill throughOctober 15, 2009Comments of the Carbon Sequestration Council16rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsappropriate approach. It will alsohelp to manage injection in areaswhere there may be multiple,stratified formations withsignificant assessed cumulativecapacity.over-pressured gas reservoirs which are analogous to CCS sites. There are someexcellent examples of off-shore technologies for drilling through salt formationsand shallow gas pockets that involve the same type of pressure issues that wouldbe encountered in drilling through a CCS site.3844810Third, because the Agencybelieves that it is necessary toaddress the specific, uniquecharacteristics of Class VIinjection (e.g., large injectionvolumes, viscosity, andbuoyancy) and the Agency doesnot have information or dataindicating that Class IIoperations are entirely analogousto Class VI, large-scaleinjection, this alternative allowsClass VI injection depthconsiderations to be tailored forGS.Within the past year, there have been several papers that have demonstrated thisexcellent record of producing,transporting, and injecting CO2. The first study byDuncan et al. (2009) examines the safety risks associated with large scale CO2sequestration by taking a systematic review of all accident and blowout dataassociated with CO2pipeline transport and injection and finds that “The CO2-EOR industry has an excellent safety record” and “the rarity of corrosion relatedincidents reflects the industries[sic]success in implementing anti-corrosionmeasures.” The second study by Smyth etal. (2009) demonstrates the industry’sprotection of the environment. It examines the groundwater in the SACROCCO2-EOR field and finds “that no widespreaddegradation of water quality existsinside the SACROC oilfiled[sic]as a result of CO2-injection.” A third study onthe mechanical integrity of CO2injection wells is in progress and should becompleted in time for consideration by EPA.3944810A number of dominantdifferences between Class II andClass VI operations indicate thatthese well classes warrantdifferent treatment. EPAreceived comment during thepublic comment periodsupporting the need for such adistinction. These differencesinclude: the risk profiles forthese operations; the greaterThe Multi-Stakeholder discussions (MSD) and recommendations from MSDparticipants have addressed these issuesin a series of recommendations thataccount for the differentrisk profiles.The December 23, 2008 letter from MSD participants explained the agreementreached on the proposed language describing wells in a proposed newclassification 40 CFR 146.5(b)(4) that would establish a “bright line” definitiondistinguishing (1) wells that inject CO2for EOR/EGR and those that inject CO2for GS in conjunction with EOR/EGR from (2) wells that inject CO2for GSwhere EOR/EGR activities and any hydrocarbon production would be minimal..The signatories to the December 23, 2008, letter recommended, consistent withOctober 15, 2009Comments of the Carbon Sequestration Council17rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentstotal injection volumes (of CO2)for Class VI GS; and,differences in formationpressures (potentially higher forGS), greater opportunities formobilization of constituents, andinjection rates and operatingconditions.EPA’s intent, that wells used for EOR/EGR should remain in Class II and thatwells used for EOR/EGR with GS – thatmeet the recommended (b)(4) definition– should also remain in Class II and besubject to the current requirements forClass II. Signatories to that letter also agreed that the wells used for GS in oil andgas reservoirs that do not meet the criteria of (b)(4) should be subject to additionalrequirements. That letter noted an agreement to define such wells as wells used“for geologic sequestration inoil and gas formations and where the criteria ofparagraph (b)(4) are not met.”In a letter dated October 9, 2009, MSD participants agreed that wells used for GSin oil and gas reservoirs that do not meetthe criteria of paragraph (b)(4) should besubject to a set of additional requirements different from those that would applyunder the current Class II provisions to wells that inject CO2for EOR/EGR andGS, due to the potential change in the risk profile when EOR/EGR activitiescease. This common view is also reflected in the four letters EPA received onMarch 17, 2009 from MSD participants. Eachof those March 17 letters asks EPAto include this approach in its final GSrule. Accordingly, EPA should adopt therecommended provisions for a new section 146.25 and the recommendationssubmitted with respect to Class V GS wells and Class VI GS wells. See MSDRecommendation Letters dated December 23, 2008; May 14, 2009 and May 15,2009.4044810The alternative EPA isconsidering relies on theprinciple of site-suitability forGS: injection zones/formationsthat have suitable upper andlower confining units,appropriate lateral and verticalextent to receive and contain theinjected CO2, and an appropriatemanagement scheme to ensurethat the water and otherWe support the provision to allow CO2injection into formations above thelowermost USDW when adequatecontainment of injected CO2and protection ofUSDWs can be demonstrated. As noted in our comments of December 24, 2008,we would prefer to have the necessarycriteria for GSproject siting andcontainment demonstration built into the normal permitting process, where theserequirements would be routinely applicable whenever a permit applicant isproposing to inject into a saline formation that is above the lowermost USDW.The permitting process – with the notice, comment, hearing and permittingprovisions we support – would provide adequately for consideration of thenecessary technical issues. Nevertheless,we also believe that the concept of asite-specific waiver process for geologicstorage above the lowermost USDW canOctober 15, 2009Comments of the Carbon Sequestration Council18rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsresources contained within theinjection zone will not be neededin the future. The managementscheme will also ensure thatthere is a strategy developed toaddress future needs to accessformations below the injectionzone.be made workable but requires some improvements which are specifically notedin these Comments.We are concerned in particular that EPA may lack the authority to require awaiver process as specificallypresented in the NODA because thedecisionmaking authority that EPA appears to be proposing for PWSS Directorslacks a decisionmaking standard that isconsistent with the existing statutoryrequirements of the SDWA and EPA’s UICregulations; assigning such a role toPWSS Directors would encroach upon theprerogatives of the states under theUIC primacy program in violation ofthe UIC regulations; and division ofauthority between UIC Directors andPWSS Directors would be burdensome,inefficient, and potentially disruptiveif the Directors disagree on approvals.4144810EPA is weighing the fact thatthis alternative would be adivergence from the existingUIC deep-well injectionrequirements for industrial andhazardous waste injection. It willresult in greater injection depthvariability throughout the UnitedStates and may result inemplacement of fluids byinjection in closer proximity toUSDWs than would occur underthe proposed requirements.Additionally, adoption of thisalternative couldpotentially adda new administrative burden toUIC programs pursuing thewaiver approach.Divergence from deep well injection requirements for industrial and hazardouswastes is completely justified because GS does not involve waste disposal or posethe same risk profiles. Moreover, this limitation on waste injection was anoriginal part of the UIC program and, ashas been noted in comments on the GSproposal, is not warranted inall instances for waste disposal. Restrictions such asthis one run counter to EPA’s avowedcommitments to performance based andadaptable requirements. Instead of identifying and applying the proper siting andcontainment criteria, EPA would be imposing a requirement that commentershave already shown to be unwarrantedin every instance. The administrativeburdens to which EPA alludes could be avoided by incorporating theconsideration of appropriate requirements for injection above the lowermostUSDW into the normal permitting process rather than in a separate waiverprocess. The burdens also can be minimized by integrating the consideration ofthese criteria as closely as possiblewith the GS UIC permitting process andminimizing the amount of duplicative reviews that are requiredto be conductedby separate agencies at the state and/or EPA regional levels.4244810The owner or operator would berequired to demonstrate toAs stated in the Council’s December 23, wesupport the use of this approach andthese criteria to the extent necessaryto protect USDWs. We see, however, noOctober 15, 2009Comments of the Carbon Sequestration Council19rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsregulatory authorities that suchinjection can be undertaken andcompleted in a manner thatprevents fluid movement intooverlying (and underlying)USDWs, thereby preventing theendangerment of public healthfrom USDW contamination.particular reason why these criteria could not be specified and considered as partof the regular permit application processwhen injection is proposed for a salineinjection zone thatis overlying a USDW.4344810This process would be separatefrom aquifer exemptions and hasno effect on 40 CFR Parts 144.7and 146.4.In many cases, waivers are likely to requirean aquifer exemption for the injectionzone itself. Consequently, it is unclear as to how a waiver process would bebeneficial to either state agencies or applicants. If states still need to obtain anaquifer exemption; which must be approved by EPA, we believe this wouldnegate the benefit of a waiver processthat does not require EPA approval.Further, 40 CFR Part 146.4 does not currently have a criterion for aquiferexemption on the basis of “use as a storage zone for CO2geosequestration”.Since no changes to the aquifer exemptioncriteria have beenproposed, it appearsthat obtaining an exemption for USDWs above the lowermost USDW for thepurpose of geosequestration would be very difficult. In effect, this would create arequirement for injection below the lowermost USDW regardless of whether ornot a waiver process exists.4444811The waiver application wouldneed to demonstrate: 1)Laterally continuous,impermeable confining unitsabove and below the injectionzone adequate to prevent fluidmovement and pressure buildup;2) A laterally continuousinjection zone/formation withadequate injectability, includingsufficient porosity andpermeability, and appropriateThe information identified in item 3 isimportant for confining zones, but notnecessary for things that occur solely within an injection zone. The Council hasjoined with other MSD participants inrecommending a revised definition fortransmissive faults or fractures that takes into account the potential for GS abovethe lowermost USDW:The recommendation recognizes that EPA’s proposed rule in §146.83(a)(2) wouldrequire a confining zone(s) thatis free of transmissivefaults or fractures, whileproposed §146.81 would define this term as “Afault or fracture that has sufficientpermeability and vertical extent to allowfluids to move between formations”.The MSD letter recommends the following modification to the definition inOctober 15, 2009Comments of the Carbon Sequestration Council20rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentssoil-rock chemistry (so as toensure that the injection matrixis not dissolved as a result ofinjection); 3) An injection zoneand confining formations free oftransmissive fractures and faults;and, 4) A characterization ofregional fracture properties anda demonstration that suchfractures will not interfere withinjection, serve as conduits, orendanger USDWs.§146.81(d) in order to avoid unduly restricting movement that is merely betweenformations:“Transmissive fault or fracture means afault or fracture that has sufficientpermeability and vertical extent to allow fluids to move beyond a confiningzone.”MSD Recommendation Letter, May 14, 2009, Item 3.4544811Due to the potential risk thatartificial penetrations pose asfluid/injectate conduits, theowner/operator would need tomap and identify all artificialpenetrations in the AoR thatpenetrate the injection zone, theupper and lower confiningzones, and all USDWs in thearea. The purpose of thisdemonstration would be toensure that public watersupplies, private wells, andpotential future water resourcesare identified and the location ofartificial penetrations into suchformations are known and theseartificial penetrations can beappropriately plugged during thepermitting phase.These requirements for the area of review and corrective action are the same aswould apply to all permit applications.It should not be necessary to plug allwells during the permitting phase, only to demonstrate either that wells wereconstructed and/or plugged so as toprevent fluid movement up or down intoUSDWs, or that a plan will be executed to remediate wells that were notappropriately constructed and/or plugged. See Bachu and Watson, 2007 forcharacteristics in pre-existing wells thatcorrespond to higher risks for leakage.October 15, 2009Comments of the Carbon Sequestration Council21rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Comments4644811The owner or operator wouldneed to supplement theemergency and remedialresponse plan (submitted as partof the waiver application processandas part of the UIC Class VIpermit) to ensure protection ofUSDWs above and below theinjection zone. The purpose ofthis plan would be to explainthat the owner or operator hasconsidered regional waterresource issues and has exploredalternative water supplies orwater treatment options toaddress unanticipated movementof the injectate or formationfluids (e.g., CO2, brine, or otherfluids) into any overlying orunderlying USDWs.The requirements described would not beany different from what would berequired in this context under the original proposed Class VI requirements. Tothe extent that this statement is intended to indicate that multiple or duplicateplans must be prepared and submitted, such a requirement would be anunwarranted burden on both applicants and permitting agencies. Moreover, suchan approach could lead to having inconsistent plans for GS projects and wells.EPA should clarify exactly what is tobe required and should provide that thepermit and waiver application can be a single submission to the permittingagency. It is confusing to refer toa need to “supplement” the emergency andremedial response plan when it is clear from the context that any permitapplication for GS injection into a formation above the lowermost USDW willneed to include these explanations from the outset rather than as a “supplement.”4744811The owner/operator would alsodemonstrate sufficient,additional financialresponsibility to address anypotential contamination ofUSDWs above or below theinjection zone.Financial assurance is tiedto plans and should not be changed for this waiverrequirement. There is no appropriate additional basis for addressing “potentialcontamination” beyond what would already be required in preparing andmaintaining the appropriate required plans.4844811Upon compliance with thewaiver process requirements, theowner/operator would need tosubmit the information jointly tothe UIC Program Director andThe language in this statement may becreating unnecessary confusion. If theintent is to provide for notice to the PWSS Program Director so that appropriatecomments can be submitted to the UIC Program Director for consideration inpreparing and approving a permit, that would be acceptable. The statements here,however, suggest that there would beshared decisionmaking between the twoOctober 15, 2009Comments of the Carbon Sequestration Council22rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsthe PWSS Program Director.Directors,which would be inefficient andcould lead to conflicts among theagencies. Moreover, this type ofapproach would not be legal under theprovisions of the SDWA and 40 CFR Part145, which allow states to identify theagencies to participate in UIC permitting and to provide howthe responsibilitieswill be divided among the participating state agencies. 40 CFR 145.23(b). Theauthority for granting a waiver should rest solely with the state UIC primacyagency.4944811These Directors would considerfactors such as:* * *•The potential capacity of thegeologic formation to sequesterCO2, accounting for theavailability of alternativeinjection sites;* * *There are many factors that project developers must considerin selecting anappropriate site for geologic sequestration. A reviewof the entire selectionprocess and alternatives is not an appropriate task for Directors; there should notbe a need to make comparison demonstrations to prove onesite better thananother if the proposed GS site meets all of the permitting requirements.5044811•Planned needs, potential and/orfuture use of USDWs and nonUSDWs in the area;Concrete plans for future use of formations can and should be submitted to EPAin comments from the PWSS Director forconsideration but must be consideredwithin the context of the SDWA endangerment standard for protecting USDWs.5144811•Planned (or permitted) water,hydrocarbon, or mineralresource exploitation potential ofthe proposed injection formationand other formations both aboveand below the injection zone –to determine if there are anyplans to drill through theformation to access resources inor beneath the proposedinjection zone/formation;Same comment as 50 above.5244811•The proposed plan for securingalternative resources or treatingThis is a matter to be addressed on a site-specific basis by theoperator as part ofthe emergency response plan. It shouldnot be required inall instances andOctober 15, 2009Comments of the Carbon Sequestration Council23rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council CommentsUSDW formation waters in theevent of contamination related tothe Class VI injection activity;and,should be a part of the plan only where chosen as an approach by theowner/operator to meet the regular permit requirement for preparation andmaintenance of that plan.5344811•Any other locally applicableconsiderations.Such considerations would be appropriate to the extent related to theendangerment standard that is applied by the Director in making permittingdecisions.5444811The waiver may also be subjectto local notice and publichearing. Following a publichearing and waiver approval byboth Program Directors, theowner/operator may completeand submit the Class VI permitapplication.The authority for granting a waiver shouldrest solely with the state UIC primacyagency. It would, however, seem appropriate to provide a special notification tothe PWSS Director withopportunity to comment.5544811The owner/operator may berequired to comply withadditional requirements thatapply as a result of receipt of thewaiver, designed to ensure theprotection of USDWs bothabove and below the injectionzone.Appropriate permit conditions may be included as necessaryto ensure theprotection of USDWs both above and below the injection zone. As with otherrequirements of the proposed rule, additional requirements under the proposedwaiver should be appropriate and sitespecific. For example, seismic plumetracking may not be possible in someinstances but other monitoring methodsmay provide sufficient protection of USDWs.5644811Due to the range of concerns andcomments related to theinjection depth requirements andthe nature of the suggestedwaiver approval procedure, EPAbelieves that adoption of anysuch injection depth waiverprocess, as previously described,should be at the discretion of theThere should not be a requirement for states to make special application toconduct a waiver program; the use of formations above the lowermost USDWshould be available where permit requirements can be met. States already havethe ability to impose more stringent requirements if they choose to do that.October 15, 2009Comments of the Carbon Sequestration Council24rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council CommentsUIC Program Director.5744811Some stakeholders areconcerned about the risksassociated with the use offormations other than deepsaline and depleted reservoirs(e.g., coal seams, basalts, etc.).EPA is seeking comment onwhether the waiver processshould apply to formations otherthan these.The Council has joined with other MSD participants to make specificrecommendations regarding these types of formations:“We agree that EPA has ample basis for adopting rules toregulate GS inhydrocarbon reservoirs and in deep saline formations under the SDWA. For thesetypes of geologic formations, there is awidespread technical consensus on how toassess and manage risks, what data is needed to characterize sites, how to selectsites, how to conduct injection operations, how tomodel the behavior of CO2inthe reservoir, and how to monitor project performance.“There is less technical support on the ability to conduct GS in basalts, coalseams, salt caverns, and shales. As compared with deep saline formations andhydrocarbon reservoirs, the trapping/containment mechanisms of CO2and/oroperational engineering involved in basalts,coal seams, salt caverns and shalesmay be significantly different and usingidentical regulatory language might notbe appropriate. In fact, it is not known atthis time whether GS (or even injectionin some cases) can be done at commercial scale in each of these types offormations – GS efforts in these formations are still in the experimental stage.Wells in basalts, coal seams, salt cavernsand shale formations should be treatedas experimental wells under Class V, recognizing that completing the process ofresearch, development and demonstration likely will require initial full scaleexperimental projects in addition to pilot projects.“Keeping these wells under Class V would allow EPA and the states to gainenough experience to develop suitable permitting requirements for such wells andto tailor those requirementsat both the pilot and commercial scales until theagencies are ready to regulate suchwells under an appropriate class.“To implement this approach, sections 144.6(f), 144.80(f), 146.5(f) and thedefinition of sequestration in 146.81should be revised. The proposed 144.15provision that the construction, operation or maintenance of any non-experimentalClass V GS well is prohibited should beretained, but only with the understandingOctober 15, 2009Comments of the Carbon Sequestration Council25rfvanvoorhees@bryancave.comNo. Page Issue Topic from EPA’s NODACarbon Sequestration Council Commentsthat this prohibition is not intended to limit the size or scale of any experimentalGS operation.” MSD Recommendation Letter May 14, 2009, Item 1.5844811-44812Additionally, the Agency isinterested in:1) Information on specific areasof the United States whereinjection depth and USDWdepth are of concern (includingformation depth, location, andassessed capacity; demonstratedconfinement and GS suitability;and, formation salinity/TDS) asdetermined by well-log analyses,cross sections, and formationfluid analyses; 2) Data,information, and evidence fromowners and operatorsconstructing and operatinginjection wells through existingCO2plumes to access resources(e.g., water, hydrocarbon, etc.)below the injection zone andwhether or not such operationsare safe and do not endangerUSDWs; and, 3) Strategies thatStates, Tribes, and regions areconsidering to managecompeting GS and resourceissues.As noted in our Comments, the Salt Creek EOR project in Wyoming, which has aUSDW below the injection zone, is anexcellent example of how industry canoperate CO2injection wells in an EOR context without endangering or limitingaccess to USDWs that are located belowthe injection zone. Accessing USDWsbelow a CCS site, while not trivial, does not present significant technologicalhurdles. Industry has the technologyto drill through over-pressured gasreservoirs which are analogous to CCS sites. There are some excellent examplesof off-shore technologies for drillingthrough salt formations and shallow gaspockets that involve the sametype of pressure issues that would be encounteredin drilling through a CCS site.October 15, 2009ReferencesApps, J. A., Zhang, Y., Zheng, L., Xu, T., and Birkholzer, J., 2009, Identification of thermodynamic controls defining theconcentrations of hazardous elements in potable ground waters and the potential impact of increasing carbon dioxide partial pressure,GHGT-9, Energy Procedia I, 1917-1924.Arnold, T., Bahr, J., and Fantucci, R., 1996, Paleohydrogeology of the Upper Mississippi Valley Zinc-Lead District,inSangster, D.F., ed., Carbonate-Hosted Lead-Zinc Deposits, Society of Economic Geologists Special Publication Number 4, p. 378-389.Bachu, S. and Watson T., Factors Affecting orIndicating Potential Wellbore Leakage, IEA GHG 3rdWellbore Integrity NetworkMeeting, Santa Fe, 2007.Chadwick, A., Arts, R., Bernstone, C., May, F., Thibeau, S.,and Zweigel, P., 2008, Best Practice for the Storage of CO2in SalineAquifers - Observations and Guidelines from the SACS and CO2STORE projects: Nottingham, UK, British Geological Survey,267pp. (British Geological Survey Occasional Publication, 14).Cooper, C., ed., 2009, A Technical Basis for Carbon Dioxide Storage: New York, ChrisFowler International, CO2Capture Project,86p.Duncan, I., Nicot, J. P., and Choi, J., 2009, Risk assessment for future CO2sequestration projects based on CO2enhanced oil recoveryin the U.S., GHGT-9, Energy Procedia I, 2037-2042 – presented atthe 9th International Conference on Greenhouse Gas ControlTechnologies (GHGT-9), Washington, D.C., November16-20, 2008. GCCC Digital Publication Series #08-03i.Duncker Romanak, K., 1997, Vadose-Zone Geochemistry of Playa Wetlands, High Plains, Texas,The University of Texas at Austin,Ph.D. dissertation, 273 p., 49 figs.Holloway, S., ed., 2003: Saline Aquifer CO2Storage project (SACS) - Best Practice Manual. - IEA Greenhouse Gas R&DProgramme, Report PH4/21, 53pp.Juanes, R., Spiteri, E.J., Orr, F.M., and Blunt, M.J., 2006, Impact of relative permeability hysteresis on geological CO2storage, WaterResource Research, Vol. 42, No. 12, W12418.Comments of the Carbon Sequestration Council26rfvanvoorhees@bryancave.comOctober 15, 2009Comments of the Carbon Sequestration Council27rfvanvoorhees@bryancave.comKoplos, J., 2007, A Review of Injection WellMechanical Integrity Testing Data and Implications for Geosequestration, IEA GHG 3rdWellbore 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 water resources formlong term CO2injection – laboratory andfield studies, GHGT-9, Energy Procedia I:1957-1964 – paper GCCC Digital PublicationSeries #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.U.S. DOE, 2009, Best Practices for: Monitoring, Verification, and Acounting of CO2Stored in Deep Geologic Formations, Office ofFossil 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 CO 2 

### Geological Storage and Groundwater Resources: Water Quality Effects

Caused by CO 2 

### Intrusion into Shallow Groundwater , Technical Report 2008, Earth

Sciences Division, Lawrence Be rkeley National Laboratory.



## Observations

Stated project goal :

o Develop a general understanding of the poten tial vulnerability of United States

potable groundwater resources in the event of CO 2 

### leakage into potable aquifers.



### Major tasks :

o Developed comprehensive geochemical mode l representing what are presented as

“typical” conditions in ma ny freshwater aquifers

o Conduct systematic reactive transpor t study to quantify effects of CO 2 

### 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 le vel and contains many uncertainties.

o The conclusion that As may exceed the maximum contaminant level

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

o Conclusions could be viewed as i ssues that might warrant further

investigation through fiel d-scale experimentation, but cannot reasonably

be viewed as evidence of eminent risk posed by CO 2 

### 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 CO 2 

### 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 wa s exceptionally broad, which required

broad assumptions to be made. C onclusions from the study should be

viewed as theoretical geochemical r eactions that might warrant further

investigation under circumstances where site characteristics and

operational experience indicate a signifi cant potential for leakage, rather

than evidence that eminent risks are posed by CO 2 

### 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 mine ralogy, trace element mineralogy and

groundwater analyses into a theoretica l aquifer condition. Any conclusion

derived from the study is fictive. So me 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 CO 2 

### 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 CO 2 

### 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 de nsities 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. Th is lower percentage would

effectively reduce the potential for initial arsenic

mobilization, but would ensu re potential for long-term

adsorption of arsenic and limiting arsenic aqueous

concentrations below the MCL.

 When the arsenopyrite solubi lity 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 pa rtial pressures of CO 2 

### (g) may result in As

concentrations exceeding the MCL prior to additional CO 2 

### (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 mi neral hosts in typi cal aquifers are

the same as those found in coal and or e 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 limita tion. Although the authors make a

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

that there is enough information avai lable to make th e entire modeling

effort worthwhile.

o Thermodynamic analysis of water samples :

o Assessing the saturation state and sol ubility of various mineral phases

relies heavily upon accurate reconstruction of initial in situ pH and

carbonate species distribu tion, specifically pCO 2 

### (g). The authors point out

numerous complications with pH and initial pCO 2 

### (g) reconstruction - a

common problem with deep and shallo w aquifer characte rization. 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. A ny 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 compli cations 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 44805Issue 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 44806Issue 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 beenless 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 NODAThe 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 monitoringprogram 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 traceelements 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 conditionsfavorable 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 andbelieves 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 44808Issue 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 onpermitting 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 appropriateprotections 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 WellsComment: 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 CommentsThere 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 44809Issue 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 theinjection 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 determinationwhether 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 bedemonstrated 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, EPAanticipates 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 agreementreached 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 1090Comment 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 44810Issue 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 applicationand 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 CO2geosequestration". 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 NODAThe 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 waiversare 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 andremedial 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 waiverrequirement.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 theprovisions 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 44811Issue 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 CommentsSuch 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 offormations 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 gaspockets 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 exceptionallybroad, 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 additionalUSDW 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 theAoR 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 routinepressure 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 that0.5 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 fieldand 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 anyrelevant 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.