UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION 5 

77 WEST JACKSON BOULEVARD 

CHICAGO, IL 60604c3590 

SEP 2 4 20'13 REPLY TO THEATTENTIONOF: 

CERTIFIED MAIL 7009 1680 0000 7674 5369 

RETURN RECEIPT REQUESTED 

Mr. Scott McDonald 

Project Manager 

Archer Daniels Midland Company 

4666 Faries Parkway 

Decatur, Illinois 62526 

WU-16J 

Subject: Request for Additional Information Regarding Archer Daniels Midland (ADM) 

Well CCS #2, United States Environmental Protection Agency Underground 

Injection Control (UIC) Permit Application #IL-115-6A-0001 

Dear Mr. McDonald: 

In order to complete our review of ADM's permit application, we need additional information 

described in the enclosures with this letter. The enclosures pertain to the following issues: 

Enclosure 1: The five required project plans 

Enclosure 2: ADM's request for the alternate post closure timeframe of 10 years 

Enclosure 3: Endangered Species List detennination 

Enclosure 4: List ofreferences missing from the original application. 

Please submit this information not later than 30 days from the receipt of this letter. 

Inquiries concerning the contents of the enclosure may be directed to Dana Rzeznik of my staff 

by telephone at (312) 353-6492 or by email to rzeznik.dana(a)epa.gov. 

Sincerely yours, 

Rebecca Harvey, Chief 

Underground Injection Control Branch 

cc: Mark Burau, ADM, with enclosures 

Stephen Nightingale, IEP A 

Enclosures 
Enclosure 1 

1 

Review of Plans Information in Archer Daniels Midland’s (ADM) Permit 

Application for CCS #2 and Request for Additional Information 

The Class VI Rule requires (at 40 CFR [Code of Federal Regulations] 146.84(b); 146.90; 146.92(b); 

146.93(a); and 146.94(a)) that Class VI owners or operators develop, submit, gain approval of, maintain 

and comply with a series of five project-specific plans1 that largely govern the operation, testing and 

monitoring, Area of Review (AoR) evaluation and reevaluations, well plugging and post-injection site 

care approach for a Class VI well –as they are incorporated into the permit as permit conditions. 

Understanding that your permit application was the first to be submitted to EPA following promulgation 

of the final regulations in December 2010, we acknowledge that the development of such plans may 

have presented certain challenges. 

In the interest of time and with a goal to facilitate the permitting process, we have made great strides in 

extracting the necessary and relevant information from the initial permit application (including your 

Injection Well Plugging Plan and Emergency and Remedial Response Plan), subsequent submittals (i.e., 

the revised AoR evaluation submitted in June 2012) and responses to Requests for Additional 

Information to put together the framework for all five plans. 

This document summarizes additional information needed to more fully understand your proposed 

approach and complete the development and evaluation of the Geologic Sequestration (GS) project 

plans for ADM’s CCS2 injection well. The requests and questions in this document will guide the 

development of plans that, when implemented, will meet all Class VI requirements, generate 

information needed to ensure Underground Sources of Drinking Water (USDW) protection, inform AoR 

reevaluations, and support a non-endangerment demonstration. Once we have received and 

incorporated the additional information you submit into the plan frameworks, we will submit them to 

you for your concurrence.2 

AoR and Corrective Action Plan 

To develop a complete AoR and Corrective Action Plan that complies with the Class VI Rule 

requirements at 40 CFR 146.84 and finalize the AoR evaluation for the administrative record, please 

submit the following: 

 A revised map that depicts the final AoR (40 CFR 146.82(a)(3)(i)): 

o See Attachment 1 and clarify whether the shape file or the information in Figure 5-2 of 

the June 2012 AoR evaluation chapter is the correct AoR; 

 An updated pressure front delineation using a method that accounts for the overpressured 

injection zone (40 CFR 146.84(b) and (c)); 

 Sensitivity analyses for residual aqueous and gas saturation (40 CFR 146.82(a)(21); 

 A description of the quantitative and qualitative triggers for an unscheduled reevaluation of the 

AoR (40 CFR 146.84(b)(2)(ii)); 

 Identification of wells in the most current AoR that were evaluated for purposes of compliance 

with 40 CFR 146.84(c)(2) and (3). 

 

1

 Area of Review and Corrective Action; Testing and Monitoring; Well Plugging; Post-Injection Site Care and Site 

Closure; Emergency and Remedial Response 

2

 Acknowledging that they are technically required to be prepared by the permit applicant. 
Enclosure 1 

2 

Testing and Monitoring Plan 

Quality Assurance and Surveillance Plan 

Please submit a quality assurance and surveillance plan for all required testing and monitoring pursuant 

to 146.90(k). 

Analysis of the CO2 Stream 

Does ADM have any historical data from the CO2 source facility to support its statement that the CO2 is 

pure, the content tends not to vary and that the CO2 stream analysis proposed to meet the requirements 

of 40 CFR 146.90(a) is appropriate? 

It would be beneficial to verify the constancy of the CO2 stream to confirm that no additional 

analytical parameters are needed in the CO2 stream analysis proposed to meet the 

requirements of 40 CFR 146.90(a). If such information does not exist at this time, a review could 

be done after injection has begun and if necessary the injectate monitoring plan may need to be 

revised to address changes. 

Continuous Monitoring of Flow, Pressure, Temperature and Volume of Injected CO2 and Monitoring of 

the Pressure in the Annulus between the Tubing and Casing 

Can ADM provide any information on the specific types of instruments that will be used to perform 

continuous monitoring to meet the requirements of 40 CFR 146.90(b)? 

While it is not necessary to identify particular instrument models in the plans, evaluating the 

specifications for the instruments before construction would help to ensure proper instrument 

selection and to avoid the need for replacing instrumentation after installation if the 

specifications should prove unsatisfactory for the required monitoring. 

How does ADM plan to calculate the volume of CO2 injected? 

On what basis did ADM select an annulus pressure change of more than 100 psi as the threshold for 

investigation? 

Typically in Region 5, a 3 percent annulus pressure change over a 60 minute test is used. 

Perhaps net changes in annulus pressure over a particular stretch of time might be more 

effective than an absolute psi pressure change. Another method would be net changes in a seal 

tank/surge tank that was connected to the annulus. This would allow for temperature based 

fluctuations into and out of the tank as long as it was showing no significant net gain or loss. 

Ground Water Monitoring above the Confining Zone 

Attachments 2 and 4 summarize EPA’s understanding of where ADM proposes to perform ground water 

monitoring to meet the requirements at 40 CFR 146.90(d). Can ADM confirm that the information in 

these attached tables is accurate? If it is inaccurate, please provide the correct and current information 

on the proposed ground water monitoring approach. 
Enclosure 1 

3 

How will ADM select the location of monitoring wells and how will monitoring at these locations provide 

sufficient information about any geochemical changes throughout the AoR? 

GM (Geophysical Monitoring well) #2 terminates in the St. Peter and cannot be used to monitor 

conditions directly above the confining zone (i.e., in the Ironton-Galesville) near the injection 

well, where pressure conditions would be highest. Conversely, VW (Verification Well) #1, which 

will be approximately 2,800 feet away from the well, will be used to monitor the IrontonGalesville but not the St. Peter. A more robust monitoring scheme would extend GM #2 so that 

it can monitor the Ironton-Galesville. VW #2 is planned to monitor several depths within the Mt. 

Simon; ADM should explore the feasibility of instrumenting this well to collect fluid samples in 

both the Ironton-Galesville and the St. Peter. This expanded monitoring would also allow ADM 

to collect sufficient information to inform AoR reevaluations and a non-endangerment 

demonstration. ADM should also describe or confirm in the plan that it will have access to all 

monitoring well locations throughout the injection and post-injection phases. 

Why does ADM not plan to conduct any sampling in the Ironton-Galesville or St. Peter after baseline 

sampling is complete? 

The proposed program of baseline sampling in the Ironton-Galesville without further fluid 

sampling unless there are anomalous pressure or Reservoir Saturation Tool (RST) results does 

not meet the requirement to periodically monitor ground water quality and geochemical 

changes above the confining zone per 40 CFR 146.90(d). it is suggested that GM #2 and VW #2 

be appropriately instrumented and used for routine collection of fluid samples for geochemical 

analysis in the Ironton-Galesville (at a minimum) and the St. Peter (recommended) throughout 

the injection period. 

What anomalous results from the pressure or RST data would ADM expect to see in order to trigger 

additional sampling (beyond baseline) in the Ironton-Galesville and the St. Peter?

While RST logs would indicate if CO2 is leaking into the Ironton-Galesville, they would not 

indicate other changes such as an increase in total dissolved solids (TDS) or alkalinity. RST logs 

are not a substitute for required periodic ground water quality monitoring throughout the 

injection phase. 

How will ADM select the locations and depths of the monitoring wells in the shallow Pennsylvanian and 

Quaternary formations? 

Since AoR modeling is complete, Figure F1-1 (Nov. 2012), which shows approximate shallow 

ground water monitoring areas, should be refined to present the actual locations of these wells. 

How did ADM select the parameters to be monitored and on what basis did ADM conclude that these are 

adequate to detect fluid movement or mobilization of contaminants? Why is TDS not a proposed 

measured parameter? 

Additional analytes could include TDS, additional anions and cations, trace elements, and 

perhaps stable isotopes. Additional anions that could also be analyzed by the planned ion 

chromatography include sulfate and nitrate. Other cations that could be quantified using 

inductively coupled plasma spectrophotometry include: Al, Ba, Fe, K, Mg, K, Mn and Si. The 

trace elements As and Pb at a minimum could be included, as these are regulated under the 

Safe Drinking Water Act (SDWA). Stable isotopes might be considered as well; at least as a 

baseline on the CO2 stream and fluids in case there is a future need for such monitoring (radon222 analysis is proposed at the FutureGen site). Please note that, if baseline sampling and 
Enclosure 1 

4 

analysis identifies other parameters of concern, these should be incorporated into the final 

Testing and Monitoring Plan. 

How often does ADM plan to conduct ground water sampling and analysis? 

The plan should describe the frequency and dates of sampling; quarterly sampling throughout 

the injection period (as is proposed for the Pennsylvanian and Quaternary formations) is likely 

reasonable. ADM should also specify triggers for increased sampling (frequency or parameters) 

in the event of evidence that the USDWs may be affected by injection activities. 

How will ground water monitoring data be analyzed and what thresholds does ADM believe would 

indicate potential effects from injection activities? 

Mechanical Integrity Testing (MIT) 

How did ADM select intervals of 1, 3 and 5 hours after stopping injection to perform temperature logs to 

meet the requirements of 146.89(c)/146.90(e)? 

Typically logs are taken for periods of at least 12 hours after injection has stopped to ensure that 

conditions have stabilized. It may be useful to require additional runs at longer time periods, 

e.g., up to 12 hours post-cessation. This may be a good approach at least for the first MIT and 

may not be needed for subsequent tests if the first MIT results are satisfactory. 

Under what conditions would ADM run a pulsed neutron/RST or caliper log? 

It would be beneficial to discuss the situations or criteria that would warrant such additional 

logs (although the planned temperature log is sufficient to meet the Class VI requirements). 

Pressure Fall-Off Testing 

When does ADM plan to conduct a pressure fall-off test to meet the requirements of 146.90(f)? 

While the Class VI Rule requires pressure fall-off tests every five years, a test earlier than five 

years after injection begins may be appropriate since the proposed injection phase is only five 

years long and this frequency may not allow for any data collection during the injection phase or 

provide information to support an AoR reevaluation. ADM should also describe how it plans to 

evaluate the results of the test. 

Plume and Pressure-Front Monitoring 

Attachments 3 and 4 summarize EPA’s understanding of where ADM proposes to conduct monitoring to 

meet the plume and pressure front tracking requirements at 40 CFR 146.90(g). Can ADM confirm that 

this is accurate? If it is inaccurate, please submit revised information. 

Understanding this will help EPA evaluate whether the planned plume and pressure front 

tracking meets the Class VI Rule requirements. The Rule requires the use of direct methods to 

track the presence or absence of elevated pressure within the injection zone (40 CFR 

146.90(g)(1)). It also requires the use of indirect methods for the purpose of tracking the extent 

of the CO2 plume (40 CFR 146.90(g)(2)). On a project-specific basis, the UIC Program Director 

may require the use of direct methods to track the CO2 plume where indirect methods yield 
Enclosure 1 

5 

insufficient data. This data will also inform AoR reevaluations and a non-endangerment 

demonstration.

How will the proposed direct pressure monitoring at CCS #2 and VW #2 generate the data needed to 

verify the modeled predictions of plume and pressure front movement and meet the requirements at 40 

CFR 146.90(g)(1)? 

Please provide a description of when elevated pressures are expected to arrive at the different 

perforated intervals of VW #2 based on the AoR modeling results and how monitoring data will 

be generated to confirm these predictions. Also, provide maps of predicted pressure distribution 

at the project site at various times during the injection and post-injection phases (e.g., contours 

showing the predicted pressure differentials around the injection well) and a description of how 

the direct monitoring data may be used to confirm these predictions. 

How will seismic data be processed and analyzed to produce pressure estimates to meet the indirect 

pressure monitoring requirements at 40 CFR 146.90(g)(2)? 

Will the seismic surveys described in the permit application materials be used for indirect 

pressure-front monitoring as well as indirect CO2 plume monitoring? If these surveys will be 

used to provide indirect pressure data, please provide: 

 A detailed description of how time-lapse vertical seismic profile (VSP) surveys and surface 

seismic surveys will be used to provide sufficient temporal and spatial coverage for 

pressure-front tracking (pressure-front as identified based on the updated modeling 

methodology, or the area determined to experience any elevated pressures based on the 

modeling results) including the area that is predicted to have elevated pressures (given that 

time-lapse VSP surveys’ spatial coverage is indicated as 2,500 ft radius); 

 A detailed schedule for both types of surveys to ensure that model predictions can be 

verified; 

 A detailed description of surface seismic surveys and the data that they will generate for 

pressure measurements; and 

 A detailed description of time-lapse VSPs and the data that they will generate for pressure 

measurements. 

How will the data that will be generated by RST, time-lapse VSP surveys, and surface seismic surveys 

meet the indirect plume monitoring requirements at 40 CFR 146.90(g)(2)? 

The literature indicates that RST logging can be used to determine residual saturation of CO2

after injection. Will this be implemented? Will the RST results be used to capture breakthrough 

(i.e., into different zones within the Mt. Simon) for verifying the modeling predictions? Is it 

anticipated that annual RST logging during the injection phase will be frequent enough to 

capture this? 

According to the most recent permit application submission, “In the early stages of injection, 

time-lapse 3D VSPs will likely be used to image the developing CO2 plume.” What is the planned 

timing/frequency of these surveys? How will these surveys provide enough spatial coverage for 

tracking the overall plume? 

ADM states in the most recent permit application submission that, “At the end of the injection 

period, either a series of 2D surface seismic lines or a final time-lapse 3D surface seismic survey 

may be utilized to image the final plume.” What is the anticipated spatial extent of this seismic 

monitoring? Will it cover areas of the AoR not covered by other monitoring techniques (e.g., the 

southern part of the AoR, the fringes of the AoR)? 
Enclosure 1 

6 

Why does ADM not plan to directly monitor the plume within the injection zone? 

How will indirect plume monitoring provide sufficient information to verify the predicted 

modeling results? How will ADM use the baseline data collected from the injection zone? 

Well Plugging Plan 

What type of MIT does ADM plan to perform prior to plugging the injection well? 

The planned well plugging procedures mention neutron, ultrasonic, calipers and a cement bond 

log. While all these logs are useful and should be encouraged, the rule requires either a 

temperature log, noise log or tracer log after injection has ceased and before the well is plugged 

(40 CFR 146.92 (b)(2)). 

 

Post-Injection Site Care (PISC) and Site Closure Plan 

How does ADM plan to collect sufficient information on which to base the non-endangerment 

demonstration required at 40 CFR 146.93(b)? 

Based on the planned injection and post-injection monitoring programs described in the permit 

application, it does not appear that ADM plans to collect sufficient amounts and types of data 

(e.g., pressure monitoring and seismic surveys) over a large enough area of the AoR to support a 

non-endangerment demonstration at the end of the proposed PISC timeframe. (See the 

questions regarding the proposed testing and monitoring for further discussion of these 

concerns.) 

Additional information is needed to fully evaluate the PISC and Site Closure Plan and whether financial 

responsibility coverage for these activities is adequate. Please provide the following: 

 Pre-injection and predicted post-injection pressure differentials based on the revised AoR 

modeling (supported by a figure depicting the distribution of this pressure differential over the 

spatial extent of the model domain, e.g., contour plot); 

 The predicted plume and pressure front position at site closure, updated based on the revised 

AoR modeling; 

 Specific information on the depths of plugs and schematics based on the as-built monitoring and 

geophysical well(s); and 

 Additional information to evaluate the appropriateness of the 10-year alternative PISC 

timeframe is also needed; this is requested separately in the document “ADM’s CCS #2 Permit 

Application Alternative PISC Timeframe Demonstration Review”.
Enclosure 1 

7 

Emergency and Remedial Response Plan

Who does ADM plan to notify first of any events that may constitute an emergency, as required at 40 

CFR 146.94? 

It appears that ADM supervisors would be notified first, followed by notification of EPA after 

ADM has made a determination regarding the severity of the event. This could be as long as 24 

hours after the incident has occurred and does not meet the intent of the Class VI Rule’s 

notification requirements at 146.94(b)(3). It is recommended that any event that triggers an 

investigation (even if it does not turn out to constitute an emergency) be reported to EPA as 

soon as possible. 

What steps would ADM take in the event of an induced seismic event? 

The Emergency and Remedial Response Plan should address this possibility. 

Please also provide contact information for all responding personnel (e.g., name, phone number, email). 

In the event that the plan is implemented, current contact information for personnel would facilitate 

communications and prompt and appropriate responses. The list should also be provided to all involved 

parties and be readily available at the control center.
Enclosure 1 

8 

Attachment 1 

Comparison of the AoR submitted in June 2012 with the updated Section 5, Figure 5-2 (as shown in 

black and labeled “AoR_June2012”) with the AoR shape file that was submitted with the Input Advisor 

on February 8, 2013 (shown in yellow and labeled “AoR_poly”).
Enclosure 1 

9 

Attachment 2 

Proposed injection phase ground water monitoring activities for IL-ICCS/CCS #2 above the confining zone. “Reference” points to primary citations within 

ADM’s permit application materials, referred to by date: Jul. 2011 – original CCS #2 permit application, Dec. 2011 – original CCS #1 permit application, Nov. 

2012 – response to second request for additional information. 

Monitoring Category 

and Class VI Rule 

Citation

Monitoring 

Activity and 

Target Formation

Data 

Collection 

Location(s)

Spatial 

Coverage

Temporal Coverage 

(Inj. Phase) Reference Notes

Ground water 

monitoring above the 

confining zone 

[40 CFR 146.90(d)]

Quaternary and/or 

Pennsylvanian strata 

fluid sampling

Shallow 

wells Point locations (4) Quarterly Nov. 2012, App. F1

“Voluntary” sampling—

results will not be 

submitted with monitoring 

reports.

St. Peter fluid 

sampling GM #2 Point location None: baseline only Nov. 2012, App. F2

No data to be collected 

during the injection phase.

St. Peter pressure 

monitoring GM #2 Point location Not specified

Jul. 2011, p. 3C-4; 

Nov. 2012, App. 

F2

Schedule/frequency not 

specified.

Ironton-Galesville 

fluid sampling VW #1 Point location None: baseline only Nov. 2012, App. F3

No data to be collected 

during the injection phase.

Ironton-Galesville 

pressure monitoring VW #1 Point location Continuous

Dec. 2011, § 3.2.6; 

Nov. 2012, App. 

F3
Enclosure 1 

10

Attachment 3

Proposed injection phase plume and pressure front monitoring activities for IL-ICCS/CCS #2. “Reference” points to primary citations within ADM’s permit 

application materials, referred to by date: Jul. 2011 – original CCS #2 permit application, Dec. 2011 – original CCS #1 permit application, Nov. 2012 –

response to second request for additional information. 

Monitoring 

Category and Class 

VI Rule Citation

Monitoring Activity and 

Target Formation

Data 

Collection 

Location(s)

Spatial 

Coverage

Temporal Coverage 

(Inj. Phase) Reference Notes

Plume Monitoring

Direct 

[40 CFR 

146.90(g)(1)]

Mt. Simon fluid sampling VW #2 Point location None: baseline only Nov. 2012, App. 

F4

No data to be collected 

during the injection phase.

Indirect 

[40 CFR 

146.90(g)(2)]

St. Peter RST logging

GM #2 Point location Annual Nov. 2012, App. 

F2

VW #2 Point location Annual Nov. 2012, App. 

F2

CCS #2 Point location Annual Nov. 2012, App. 

F2

Ironton-Galesville RST 

logging

VW #2 Point location Annual Nov. 2012, App. 

F3

CCS #2 Point location Annual Nov. 2012, App. 

F3

Mt. Simon RST logging

VW #2 Point location Annual Nov. 2012, App. 

F4

CCS #2 Point location Annual Nov. 2012, App. 

F4

Time-lapse VSP surveys 

(multiple formations) GM #2 2,500 ft radius “Early stages of injection” 

Nov. 2012, § 

6A.2.5

Schedule/frequency not 

specified.
Enclosure 1 

11

Monitoring 

Category and Class 

VI Rule Citation

Monitoring Activity and 

Target Formation

Data 

Collection 

Location(s)

Spatial 

Coverage

Temporal Coverage 

(Inj. Phase) Reference Notes

Surface seismic surveys 

(multiple formations)

Not 

specified Not specified “End of the injection period”

Nov. 2012, § 

6A.2.5

Schedule and details (e.g., 

type, extent of survey) not 

specified. Not clear if data 

will be collected during 

the injection phase.

Pressure-front Monitoring

Indirect 

[40 CFR 

146.90(g)(2)]

Time-lapse VSP surveys 

(multiple formations) GM #2 2,500 ft radius “Early stages of injection” 

Nov. 2012, § 

6A.2.5

Schedule/frequency not 

specified. Not clear if data 

will be analyzed to 

produce pressure 

estimates.

Surface seismic surveys 

(multiple formations)

Not 

specified Not specified “End of the injection period”

Nov. 2012, § 

6A.2.5

Schedule and details (e.g., 

type, extent of survey) not 

specified. Not clear if data 

will be collected during 

the injection phase. Not 

clear if data will be 

analyzed to produce 

pressure estimates.

Direct 

[40 CFR 

146.90(g)(1)]

Mt. Simon pressure and 

temperature monitoring

VW #2 Point location Continuous Nov. 2012, § 6B.2 

and App. F4

Location of VW #2 

relative to predicted 

pressure front movement 

is uncertain.

CCS #2 Point location Continuous Nov. 2012, § 

6A.2.5 and App. F4
Enclosure 1 

Page 12

Attachment 4 

Location of injection wells and deep monitoring wells at the ADM site, with the planned monitoring activities for 

the IL-ICCS/CCS #2 project for each applicable well. 
Enclosure 2 

Page 1 

Archer Daniels Midland (ADM) CCS #2 Permit Application 

Alternative Post-Injection Site Care (PISC) Timeframe Demonstration Review 

Summary: EPA requests that ADM submit a separate, complete, revised alternative PISC timeframe 

demonstration that addresses all the criteria at 40 CFR 146.93(c) and is based on the results of the most 

recent information submitted to EPA. 

Section I: Background and Context 

Summary of Relevant Class VI Requirements 

Pursuant to 40 CFR [Code of Federal Regulations] 146.93(c), the Underground Injection Control (UIC) 

Program Director may, in consultation with EPA, approve an alternative PISC timeframe other than the 

50-year default if an owner or operator can demonstrate during the permitting process that an 

alternative PISC timeframe is appropriate and ensures non-endangerment of USDWs. In order for such a 

request to be approved, an owner or operator must demonstrate, based on significant, site-specific data 

and information, including all data and information collected pursuant to 40 CFR 146.82 and 146.83, 

that the injection project will no longer pose a risk of endangerment to Underground Sources of 

Drinking Water (USDWs) at the end of the proposed alternative timeframe. 

The Class VI Rule, at 40 CFR 146.93(c)(1) and (2), specifies the information and analyses that must be 

provided by the applicant for this demonstration based on the Area of Review (AoR) delineation 

modeling results and on the site characterization data submitted. 

In addition to the information required at 40 CFR 146.93(c), the proposed testing and monitoring are 

critical to evaluating the appropriateness of an alternative PISC timeframe because the testing and 

monitoring data generated will be necessary for: 

(1) Confirming and verifying the results of the model predictions that are used for delineating 

the AoR and supporting the decision for an alternative PISC timeframe (e.g., during the 

periodic AoR reevaluations); and 

(2) Eventually evaluating and approving the non-endangerment demonstration prior to site 

closure, pursuant to 40 CFR 146.93(b)(3). 

Summary of Information Previously Submitted 

Section 9.1 of the original permit application (submitted in July 2011) requests a modified PISC 

timeframe of 10 years and notes that this PISC period is based on current monitoring and other sitespecific data (i.e., data available in July 2011) that demonstrate that the sequestered CO2 will no longer 

endanger USDWs at the end of the PISC period and will meet the requirements for an alternative PISC 

period as detailed in 40 CFR 146.93(c)(1) and (2). However, this alternative PISC timeframe 

description/demonstration was based on the initial AoR delineation efforts (also submitted in July 2011 

with the original permit application) and was not updated to reflect any subsequent submissions or 

analyses. Specifically, Section 9 has not been updated to reflect the revised AoR delineation modeling 

materials submitted in and after June 2012 and site characterization information submitted in January 
Enclosure 2 

Page 2 

2012. Furthermore, the demonstration provided in Section 9, does not address all the criteria at 40 CFR 

146.93(c)(1) and (2). 

Conclusion

To comply with the Class VI Rule requirements, EPA requests that ADM submit a separate, complete, 

revised alternative PISC timeframe demonstration that addresses all the criteria at 40 CFR 146.93(c) and 

is based on the results of the most recent information including the modeling approach used to 

delineate the final AoR. 

Section II: Instructions to Guide Demonstration Revisions 

In the interest of time and with the goal to facilitate the development of the revised alternative PISC 

timeframe demonstration, we have evaluated the information submitted in Section 9 of the original 

permit application for each criterion under 40 CFR 146.93(c)(1) and (2), and extracted the necessary and 

relevant information from the initial permit application, subsequent submittals, and responses to 

Notices of Deficiency. 

The following sections of this document evaluate a 10-year alternative PISC timeframe against the 

requirements of the Class VI Rule (shown in bold italics), describe what was submitted for the original 

PISC timeframe demonstration in July 2011 and discuss the updated data submitted in subsequent 

documents (i.e., the new AoR delineation modeling information submitted in June 2012 and the data 

submitted with the Input Advisor in January 2013). It also evaluates how the most up-to-date 

information may support a request for a 10-year alternative PISC timeframe and identifies the additional 

information needed to support a full evaluation of the appropriate PISC timeframe. EPA encourages the 

use of the information below in as much as it supports development of a complete alternative PISC 

timeframe demonstration. However, if ADM has additional or alternative information to support 

compliance with 40 CFR 146.93(c), such information may also be submitted in response to this request. 

To facilitate the comparison of information submitted at different times, ADM’s submittals will be 

referenced by their respective dates: 

 July 2011: ADM’s original permit application submission

 January 2012: ADM’s first revision to the permit application

 June 2012: ADM’s revised AoR delineation modeling submission

 January 2013: ADM’s Input Advisor submission

40 CFR 146.93(c)(1) A demonstration of an alternative post-injection site care timeframe must include 

consideration and documentation of: 

(i) The results of computational modeling performed pursuant to delineation of the area of review 

under § 146.84; 

Please provide a discussion of how the proposed testing and monitoring activities will be used to 

verify and update the site characterization and modeling information. 

Section 9.1.3 of the July 2011 permit application states “The results of computational modeling 

of the project (Section 5.4 of this application) indicate that the sequestered CO2 will not migrate 
Enclosure 2 

Page 3 

above the Mt. Simon Sandstone” in response to this criterion (p. 9-3). The section to which this 

statement refers is the older version of the AoR delineation modeling section, which later was 

completely revised and replaced with the June 2012 submittal. 

The modeling results presented in the June 2012 document and the Input Advisor submittals 

can be used to support this part of the alternative PISC timeframe demonstration. The crosssectional views presented by ADM in the revised modeling description (June 2012, Figs. 5-6 

through 5-17) predict that the CO2 plume will remain in the lower zone of the Mt. Simon, below 

about 5,600 ft beneath the surface, approximately 43 years after the end of injection into CCS 

#2 (June 2012, p. 5-24). 

However, these results strongly depend upon the completeness, accuracy, and quality of site 

characterization and modeling results. Therefore, a discussion of how the proposed testing and 

monitoring activities will be used to verify and update the site characterization and modeling 

information is also needed. 

 (ii) The predicted timeframe for pressure decline within the injection zone, and any other zones, 

such that formation fluids may not be forced into any USDWs; and/or the timeframe for pressure 

decline to pre-injection pressures; 

Please submit a description of pressure decline within the injection zone and in the confining zone 

based on the new AoR delineation modeling results in the form of pressure distributions at specific 

elevations and times (e.g., at the start of injection, at the end of injection, and a series of 

distributions indicating dissipation and the necessary timeframe). 

Section 9.1.3 of the July 2011 permit application (p. 9-3) includes the following information in 

support of this criterion: “The formation pressure at the injection well is predicted to decline 

rapidly within the first 4 years following injection (formation pressure pre-injection = 2,840 psia, 

immediately following injection = 3,340 psia, 4 years post-injection = 2,950 psia). Fifty years 

post-injection, the formation pressure is predicted to be 2,860 psia. Furthermore, the increase 

in the injection formation pressure at the edge of the AoR is expected to be less than 185 psi at 

the cessation of injection, less than 110 psi 4 years later, and continues dropping to less than 10 

psi at the end of fifty years.”

In the February 2013 Input Advisor submission, ADM submitted an initial aqueous pressure in 

the injection zone of 3,205 psi at a reference elevation of -6,345 ft. Because the reference 

elevation was not provided in the July 2011 submission, it is not clear how this initial aqueous 

pressure compares to the information given above. 

Based on the revised modeling results, the pressure buildup in the system may be expected to 

stay below a critical level (compared to fracture pressure) and dissipate within 4–6 years 

following the cessation of injection at CCS #2. In the AoR modeling results (June 2012, Figs. 5-6 

through 5-17), pressure declines to near-pre-injection levels approximately 4 years after 

injection ends, and the predicted extent of the pressure front is smaller than the extent of the 

CO2 plume. 
Enclosure 2 

Page 4 

(iii) The predicted rate of carbon dioxide plume migration within the injection zone, and the 

predicted timeframe for the cessation of migration; 

Please provide information on the predicted rate of migration within the injection zone. 

In the original alternative PISC timeframe demonstration, the rate of plume migration or the 

predicted timeframe for the cessation of migration were not discussed with respect to the 

alternative PISC timeframe. However, as shown in Figures 5-6 through 5-18 of the June 2012 

AoR submission, nearly all plume migration occurs by Year 18 of the simulation (11 years after 

injection ends), with minimal movement continuing through Year 50 of the simulation. It is 

stated that “From this figure it can be seen that the plume growth during the 32 year period 

is minimal indicating the plume has become stable” (June 2012, p. 5-10). 

Therefore, the predicted rate of migration within the injection zone must be specifically 

provided as part of the demonstration for alternative PISC timeframe.

(iv) A description of the site-specific processes that will result in carbon dioxide trapping including 

immobilization by capillary trapping, dissolution, and mineralization at the site; 

Please provide an updated discussion of the site-specific processes that will result in CO2 trapping or 

immobilization based on the June 2012 AoR delineation modeling results. 

This criterion is briefly described in the original AoR submission as follows: “A second notable 

observation [in the figures displaying the model results] is that the brine displaced ahead of the 

advancing CO2 plume created by the injection into CCS #2 not only distorts the shape of the 

plume around CCS #1, but also sweeps away mobile CO2 from the nearest edges of the plume, 

leaving behind a ‘shadow’ of residually-trapped CO2. This affect [sic] is most apparent when 

comparing the Year 3 and Year 7 cross-sectional views in Figure 5-8. The CO2 that is residually 

trapped as a result of the encroaching brine is depicted in light-blue, or the 0.2 – 0.25 range in 

the CO2 saturation color bar. This residually-trapped CO2 is immobilized by capillary forces and 

can be seen to persist through the remaining cross-sectional images in Figure 5-8, suggesting 

long-term storage in the lower Mt. Simon” (July 2011, p. 5-5; Jan. 2012, p. 5-6). 

However, trapping is not discussed in the revised AoR submission from June 2012 or in any 

other subsequent permit application materials, and an updated discussion on the site-specific 

processes that will result in CO2 trapping or immobilization based on the June 2012 AoR 

delineation modeling results should be provided. It is expected that capillary trapping and 

dissolution are the major mechanisms that affect the CO2 mobility in the injection zone. 

(v) The predicted rate of carbon dioxide trapping in the immobile capillary phase, dissolved phase, 

and/or mineral phase; 

Please provide a discussion of the predicted amounts for dissolved and trapped phases of CO2 as a 

fraction of the total amount injected. 

See above; this does not appear to be specifically discussed in the permit application. The 

information submitted for the previous criterion should be supported by a discussion of the 

predicted amounts for dissolved and trapped phases of CO2 as a fraction of the total amount 
Enclosure 2 

Page 5 

injected at the end of a 10-year PISC period and at the end of the 52-year simulation period (i.e., 

corresponding to about a 45-year PISC timeframe). 

(vi) The results of laboratory analyses, research studies, and/or field or site-specific studies to 

verify the information required in paragraphs (iv) and (v) of this section; 

Please describe any laboratory analyses, research studies, and/or field or site-specific studies 

relevant to the predicted CO2 trapping. 

This is not specifically discussed or addressed in any of the submittals and must be discussed 

with respect to the alternative PISC timeframe. 

(vii) A characterization of the confining zone(s) including a demonstration that it is free of 

transmissive faults, fractures, and micro-fractures and of appropriate thickness, permeability, and 

integrity to impede fluid (e.g., carbon dioxide, formation fluids) movement; 

Please provide current, relevant information on the suitability of the confining zones as described in 

the sections below. 

In Section 9.1.3 of the July 2011 permit application, it is stated that “The hydrogeologic and 

seismic characterization for the project site indicates that the Eau Claire Formation, the primary 

seal above the Mt. Simon, does not contain any faults and has permeability sufficiently low to 

impede CO2 migration to overlying formations” (pp. 9-3 and 9-4). 

In Section 2.2 of the January 2012 permit application revision, it is reported that 3D seismic 

reflection data collected for the Illinois Basin – Decatur Project (IDBP)/CCS #1 project indicate 

that there are no resolvable faults in the Eau Claire. In Section 2.5, an assessment of the Eau 

Claire’s lithology, geomechanical properties, permeability and hydraulic conductivity, with sitespecific information primarily based on CCS #1 core analysis was provided. It was also noted that 

“gas storage projects in the Illinois Basin confirm that the Eau Claire is an effective seal in the 

northern and central portions of the Basin” (Jan. 2012, p. 2-18). One diagrammatic cross section 

of Cambrian strata through central Illinois (Jan. 2012, Fig. 2-20) was provided, which is intended 

to demonstrate that the Eau Claire has “a [regionally] laterally persistent shale interval above 

the Mt. Simon and is expected to provide an excellent seal” (Jan. 2012, p. 2-18), though this is 

difficult to determine based on the scale and quality of the image. 

According to the information submitted, in the area of the proposed injection well, the Eau 

Claire consists of an approximately 200 ft thick basal shale layer overlain by approximately 300 ft 

of very fine-grained limestone interbedded with thin siltstone layers (Jan. 2012, p. 2-19). Tests 

of sidewall rotary core samples from the upper limestone/siltstone unit indicate an average 

vertical permeability of 0.000344 mD; the average vertical permeability for the lower shale unit 

is expected to be “much lower” as “vertical permeability on plugs is generally lower than 

horizontal permeability and shale permeability is generally much lower than sandstone, 

limestone, and siltstone” (Jan. 2012, p. 2-20). Based on the analysis of log results from CCS #1, 

the 317 ft thick Eau Claire is described as having “only a few small intervals of less than a few 

feet that have any permeability greater than 0.1 mD,” which “do not appear to be continuous” 

(Jan. 2012, p. K-5). 
Enclosure 2 

Page 6 

Moving to regional data, a state database of injection well core samples was reviewed and a 

median permeability value of 0.000026 mD for the Eau Claire was found, with a median porosity 

of 4.7% (Jan. 2012, p. 2-21). A set of core samples from a gas storage field approximately 80 

miles to the north of the proposed Class VI location was also described. Of the 110 analyses 

conducted, most were in the range of < 0.001 to 0.001 mD, with five in the range of 0.100 to 

0.871 mD (the maximum value in the data set). It is stated that this “indicates that even the 

more permeable beds in the Eau Claire Formation are expected to be relatively tight and tend to 

act as sealing lithologies” (Jan. 2012, p. 2-21). Core analysis data from another gas storage field, 

37 miles to the northeast of the proposed site, with vertical Eau Claire shale permeabilities of 

less than 0.1 mD (Jan. 2012, p. 2-18) were also cited. 

The information submitted in various sections of the permit application and subsequent updates 

as summarized above, along with a new brief discussion of how this information will be verified 

with the proposed testing and monitoring activities, would be sufficient to support the required 

criteria at 40 CFR 146.9(c)(1)(vii) for characterizing the confining zone(s) for the alternative PISC 

timeframe demonstration. 

(viii) The presence of potential conduits for fluid movement including planned injection wells and 

project monitoring wells associated with the proposed geologic sequestration project or any other 

projects in proximity to the predicted/modeled, final extent of the carbon dioxide plume and area 

of elevated pressure; 

Please provide current, relevant information on potential conduits for fluid movement as described in 

the sections below. 

In Section 9.1.3 of the July 2011 permit application, it is stated that, “Potential conduits of CO2

migration above the Mt. Simon are limited to the IBDP injection and verification wells or the ILICCS injection and verification wells, all of which will be constructed, monitored, and plugged in 

a manner that will minimize the potential for any such migration and meets the requirements of 

40 CFR Part 146” (p. 9-4). 

In the June 2012 AoR delineation submission, this finding is repeated and it is reiterated that the 

evaluation of all identified wells within a 3.2 km (2.0 mile) radius of the ICCS site showed no 

other wells in this area that penetrate the Eau Claire Formation (pp. 5-24 and 5-25). 

The construction plans for the verification well and geophysical wells, which include the use of 

CO2- resistant materials in the lower half of the wells, indicate that these wells would not 

become conduits for unacceptable fluid movement. 

Identification of the current, relevant information is needed and should be included in the 

revised demonstration. 

 (ix) A description of the well construction and an assessment of the quality of plugs of all 

abandoned wells within the area of review; 

No additional information is needed. 

As there are apparently no abandoned deep wells in the AoR, this criterion does not apply. 
Enclosure 2 

Page 7 

(x) The distance between the injection zone and the nearest USDWs above and/or below the 

injection zone; and 

Please provide current, relevant information on the distance between the injection zone and the 

nearest USDWs as described below. 

In Section 9.1.3 of the July 2011 permit application, it is stated that, “The Mt. Simon Sandstone 

is nearly 7,000 feet below the lowermost USDW, and there are three confining formations (New 

Albany Shale, Maquoketa Formation, Eau Claire Formation) between the injection zone and the 

lowermost USDW” (p. 9-4). 

As the alternative timeframe submission has not been updated since July 2011, the submitted 

materials consider the lowermost USDW to be the Pennsylvanian bedrock rather than the St. 

Peter Sandstone. The vertical distance between the base of the St. Peter and the top of the Mt. 

Simon is approximately 2,000 ft rather than 7,000 ft; this distinction is particularly important to 

note because the vertical distance between the injection zone and lowermost USDW is a factor 

in the pressure front calculations. In addition, the New Albany and the Maquoketa lie above the 

St. Peter in the stratigraphic column and so they cannot serve as confining formations between 

the injection zone and the lowermost USDW. 

Identification of the current, relevant information is needed and should be included in the 

revised demonstration. 

(xi) Any additional site-specific factors required by the Director. 

No additional information is needed. 

Not applicable at this time. 

(2) Information submitted to support the demonstration in paragraph (c)(1) of this section must meet 

the following criteria: 

(i) All analyses and tests performed to support the demonstration must be accurate, reproducible, 

and performed in accordance with the established quality assurance standards; 

Please provide a description of the quality assurance standards for all analyses and tests performed 

to support the alternative PISC timeframe demonstration. 

This criterion was not addressed in Section 9. However, most of the data used for the alternative 

PISC demonstration are site characterization data and the modeling information. A description 

of the quality assurance standards used is needed. 

(ii) Estimation techniques must be appropriate and EPA-certified test protocols must be used 

where available; 

Please describe how all estimation techniques used to support the alternative PISC timeframe 

demonstration were appropriate and used EPA-certified test protocols. 
Enclosure 2 

Page 8 

See above; this does not appear to be specifically discussed in the permit application. A 

description is needed. 

(iii) Predictive models must be appropriate and tailored to the site conditions, composition of the 

carbon dioxide stream and injection and site conditions over the life of the geologic sequestration 

project; 

Please submit a description of how the AoR delineation that supported the alternative PISC 

timeframe demonstration was appropriate to the site conditions and the carbon dioxide stream. 

The AoR delineation model appears to be consistent with the requirements under 40 CFR 

146.84. A description is needed. 

(iv) Predictive models must be calibrated using existing information (e.g., at Class I, Class II, or 

Class V experimental technology well sites) where sufficient data are available; 

Please describe how the models were calibrated and how proposed testing and monitoring activities 

will generate the necessary information to confirm/verify the modeling results. 

This criterion also doesn’t appear to be addressed in the original permit application. In the June 

2012 AoR delineation updates, it is indicated that operational and monitoring data from the 

IDBP/CCS #1 project were used for calibrating the reservoir model (p. 5-5). Data obtained 

(injection well bottom hole pressure data, multi-zone pressure data from VW #1, injection 

profile logs from CCS #1, and data from reservoir saturation tools) were used to calibrate various 

parameters including intrinsic permeabilities, relative permeabilities, wellbore skin, vertical to 

horizontal permeability ratios, and rock compressibility. A description is needed for this 

demonstration which also includes how proposed testing and monitoring activities will generate 

the necessary information to confirm/verify the modeling results and the site characterization 

information used. 

(v) Reasonably conservative values and modeling assumptions must be used and disclosed to the 

Director whenever values are estimated on the basis of known, historical information instead of 

site-specific measurements; 

Please describe how reasonably conservative values and modeling assumptions were used to support 

the alternative PISC timeframe demonstration. 

This criterion is not specifically discussed in the demonstration, though the majority of 

input/calibration data for the model are site-specific (i.e., from the IDBP/CCS #1 project). A 

description is needed for this demonstration. 

(vi) An analysis must be performed to identify and assess aspects of the alternative post-injection 

site care timeframe demonstration that contribute significantly to uncertainty. The owner or 

operator must conduct sensitivity analyses to determine the effect that significant uncertainty 

may contribute to the modeling demonstration. 

Please submit sensitivity analyses for residual aqueous saturation values. 
Enclosure 2 

Page 9 

This has not been provided by the permit applicant. The residual aqueous saturation values used 

in the AoR modeling effort are relatively high compared to the values that are reported in the 

literature for the Mt. Simon Sandstone and indicate zero aqueous permeability at moderate 

aqueous saturations. It is recommended that ADM submit a set of sensitivity analyses for these 

values since the source of this information was not discussed in great detail in the submittals. 

(vii) An approved quality assurance and quality control plan must address all aspects of the 

demonstration; and, 

Please submit a quality assurance and quality control plan for all analyses that support the 

alternative PISC timeframe demonstration.

A brief quality assurance statement as part of the monitoring plan submissions was provided in 

the original submittal. No quality assurance information has been submitted specifically with 

regard to data on which the alternative PISC timeframe request is based. 

(viii) Any additional criteria required by the Director. 

No additional information is needed. 

Not applicable at this time. 
Enclosure 3 

In accordance with 40 CFR 144.4 (c), the U. S. Environmental Protection Agency (EPA) is required to 

comply with the Endangered Species Act (ESA) when issuing permit decisions. Therefore, when 

considering a permit application or extension, the UIC Branch must consider the potential impacts from 

the new or existing injection well to endangered species present in the area. In order to determine 

whether an injection well will adversely impact endangered and threatened species, the UIC branch must 

have location-specific ecological information, such as the presence of certain vegetation, soils or surface 

water bodies. The U.S. Fish and Wildlife Service has listed the following in Macon County: 

Macon 

Field Office to 

Contact: U.S. Fish 

and Wildlife Service 

Rock Island Illinois 

Field Office

1511 47th Avenue

Moline, Illinois 61265 

(309) 757-5800

e:mail 

RockIsland@fws.gov

FAX: 309-757-5807 

Indiana bat 

(Myotis 

sodalis)

Endangered Caves, mines 

(hibernacula); 

Small stream 

corridors with well 

developed riparian 

woods; upland 

forests (foraging)

Eastern prairie 

fringed orchid

(Platanthera 

leucophaea)

Threatened Mesic to wet 

prairies 

As a result, we are requiring the following information to be submitted in each permit application. 

a. A summary of the critical habitat which, if present, may support one of the above-listed 

species. Detailed information on critical habitat can be found at the following web address: 

http://www.fws.gov/midwest/endangered/section7/s7process/lifehistory.html.

b. A survey of the surface vegetation, soils, topography and hydrologic features in the action 

area in sufficient detail to address the presence or absence of critical habitat for any 

endangered, threatened, or candidate species. This will include descriptions such as “mature 

mixed forest”, “plowed field” or “stabilized dunes”, and may also include specific trees or 

plants listed as critical to a species. 

c. A description of the action area for the well and associated surface facilities. This will 

include dimensions of the affected area, such as the clearing in which the well is located, 

length of road or pipeline to be built, etc., as well as the extent of disruption of the area. For 

example, an existing well with no construction plan will be less disruptive than a proposed 

well, and a proposed well in an open, plowed field will be less disruptive than one which 

requires some clearing of forest. 

This information must be certified in accordance with 40 CFR 144.32(d). EPA recommends that this 

information be gathered in consultation with an ecologist, botanist, or other environmental professional. 
Enclosure 3 

If critical habitat is present, the permit is not automatically denied. EPA, in conjunction with the U.S. 

Fish and Wildlife Service, will examine more detailed information to determine the presence of 

endangered species in the area and the likelihood of negative impact to the species. Past experience has 

shown that very few projects pose any disturbance to endangered species in Region 5, and we do not 

expect this to change. We appreciate your cooperation in protecting these important species from 

endangerment and extinction. 
Enclosure 4 

References still needed for ADM permits 

It is only necessary to provide the portions of a cited material that is the basis of support for the 

statement in the application. 

ICCS; IL-115-6A-0001; CCS #2 

Page Citation

*2-2 Leetaru, H., 2011. Personal communication, Illinois State Geological Survey

*2-5 Morse, D.G., and H.E. Leetaru, 2005. Reservoir characterization and three-dimensional 

models of Mt. Simon Gas Storage Fields in the Illinois Basin: Illinois State Geological Survey, 

Circular 567, 72 p. CD-ROM.

2-13 Southeastern Wisconsin Regional Planning Commission and Wisconsin Geological and 

Natural History Survey, 2005. A Regional Aquifer Simulation Model for Southeastern 

Wisconsin, Southeastern Wisconsin Regional Planning Commission Technical Report 41: 143.

*2-13 Zimmerman, R.W., 1991. Compressibility of sandstones, Elsevier Publishing Co., Amsterdam.

2-18 Larson, K.R., 1965. Exhibit 25: Core Analyses. In the matter of the Application of the

Peoples Gas Light and Coke Company for an order and certificate of convenience and 

necessity to develop, construct, operate and maintain the Mahomet Storage Field in 

Champaign and Piatt Counties, Illinois Commerce Commission, Docket No. 51416 

[Unpublished data, a copy of which is available for inspection at the Library of the Illinois 

State Geological Survey, Champaign IL].

*2-21 Illinois State Geological Survey Mt. Simon database

2-25 Buschbach, T.C., 1964. Cambrian and Ordovician Strata of Northeastern Illinois, Illinois State 

Geological Survey, Report of Investigations 218, 90 p.

*2-29 Illinois State Geological Survey, 2006. Directory of Coal Mines in Illinois, Logan County, 10 p.

*2-29 Illinois State Geological Survey, 2006. Directory of Coal Mines in Illinois, Macoupin County, 17 

p.

*2-30 Various years, Illinois Annual Oil Field Reports, Illinois State Geological Survey

*2-31 Byers, D., 2011. Personal communication, Illinois State Geological Survey

*2-31 Kolata, D.R., 2005. Bedrock Geology of Illinois, Illinois State Geological Survey Illinois Map 14: 

1:500,000.

*2-31 Loyd, O,B. and W.L. Lyke, 1995. Ground Water Atlas of the United States, Segment 10: 

Illinois, Indiana, Kentucky, Ohio and Tennessee, United States Geological Survey Hydrologic 

Investigations Atlas 730-K, 30 p

*2-31 V. Smith, personal communication, Schlumberger Carbon Services, 2011

*3A-16 Robinson, J. 2003. Personal communication, Franklin Well Services, Lawrenceville, Illinois

*3A-16 Howard, G. C. and C.R. Fast. 1970. Hydraulic Fracturing, New York Society of Petroleum 

Engineers of AIME, 210 p.

*5-29 Bethke, C. M. (2006). The Geochemist's Workbench (Release 6.0) Reference Manual. Golden, 

CO: Rockware, Inc.

*5-29 Zaytsev, I. D., & Aseyev, G. G. (1992). Properties of Aqueous Solutions of Electrolytes. Boca 

Raton, FL: CRC Press

6A-15 Arts, R., and P. Winthaegen, 2005, Monitoring Options for CO2 Storage. In Carbon Dioxide 

Capture for Storage in Deep Geologic Formations, Volume 2. Eds. D.C. Thomas and S.M. 

Benson. Amsterdam: Elsevier, 2005.1001-1013.

App H Hvorslev, M.J., 1951. Time lag and soil permeability in ground-water observations, 

Waterways Experiment Station Bulletin No. 36, U.S. Army Corps of Engineers, Vicksburg, 
Enclosure 4 

Mississippi, 50 p.

App H Jorgensen, D.G., 1995. The Ratio Method of Estimating Water Resistivity and TDS from 

Resistivity Logs, Ground Water 34(3): 519-522.

App H Moye, D.G., 1967. Diamond drilling for foundation exploration, Civil Engineering 

Transactions 9: 95-100.

App H Pryor, W.A., 1956. Quality of Groundwater Estimated from Electric Resistivity Logs, Illinois 

State Geological Survey Circular 215, 15 p.

App H Schnobelen, D.J., E.F. Bugliosi, and N.C. Krothe, 1995. Delineation of a Saline Groundwater 

Boundary from Borehole Geophysical Data, Ground Water 33(6):965-976.

*Items marked with an asterisk are also cited in the application for CCS #1. If the citation is referencing 

the same information, it need only be submitted once and noted that it applies to both. 

IBDP; IL-115-6A-0002; CCS #1 

Page Citation

3-52 Bourgoyne, A.T. Jr., Scott, S.L., Regg, J.B., 1999, “Sustained Casing Pressure in Offshore 

Producing Wells”,OTC (SPE) Paper 11029

3-52 Goodwin, K.J., and Crook, R.J., 1992, “Cement Sheath Stress Failure”, SPE Paper 20453

3-52 Sabins, F., 2004, “MMS Project: Long-Term Integrity of Deepwater Cement Systems 

Under Stress/Compaction Conditions, Summary Report,”

3-52 Teodoriu, C., Reinicke, K.M., Fitcher, C., Wehling, P., 2010, “Investigations on casingcement interaction with applications to gas and CO2 storage wells,” SPE Paper 131336