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ATTACHMENT B: AREA OF REVIEW AND CORRECTIVE ACTION PLAN 

Facility Information

Facility name: Archer Daniels Midland, CCS#2 Well 

 IL-115-6A-0001 

Facility contact: Mr. Mark Burau, Plant Manager, 

4666 Faries Parkway, Decatur, IL, 

(217) 424-5750, mark.burau@adm.com

Well location: Decatur, Macon County, IL; 

39o53’08”, -89o53’19” 

Computational Modeling

Model Name and Authors/Institution 

ECLIPSE 300 (v2011.2) reservoir simulator with the CO2STORE module, Schlumberger. 

Description of Model 

Model Description

ECLIPSE 300 is a compositional finite-difference solver that is commonly used to simulate 

hydrocarbon production and has various other applications including carbon capture and storage 

modeling. The CO2STORE module accounts for the thermodynamic interactions between three 

phases: an H2O-rich phase (i.e., ‘liquid’), a CO2-rich phase (i.e., ‘gas’), and a solid phase, which 

is limited to several common salt compounds (e.g. NaCl, CaCl2, and CaCO3). Mutual solubilities 

and physical properties (e.g. density, viscosity, enthalpy, etc.) of the H2O and CO2 phases are 

calculated to match experimental results through a range of typical storage reservoir conditions, 

including temperature ranges between 12°C-100°C and pressures up to 60 MPa. Details of this 

method can be found in Spycher and Pruess (2005). Additional assumptions governing the phase 

interactions throughout the simulations are as follows:

• The salt components may exist in both the liquid and solid phases. 

• The CO2-rich phase (i.e., ‘gas’) density is obtained by using the Redlich-Kwong equation 

of state. The model was accurately tuned and modified as further described below 

(Redlich and Kwong, 1949). 

• The brine density is first approximated as pure water then corrected for salt and CO2

concentration by using Ezrokhi’s method (Zaytsev and Aseyev, 1992). 
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• The CO2 gas viscosity is calculated per the methods described by Vesovic et al. (1990) 

and Fenghour et al. (1999). 

The gas density was obtained using a modified Redlich-Kwong equation of state following a 

method developed by Spycher and Pruess, where the attraction parameter is made temperature 

dependent: 

P = � RTK

V − bmix� − � amix

TK

 1⁄2V(V + bmix)

�

where V is the molar volume, P is the pressure, TK is the temperature in Kelvin, R is the universal 

gas constant, and amix and bmix are the attraction and repulsion parameters. 

The transition between liquid CO2 and gaseous CO2 can lead to rapid density changes of the gas 

phase; the simulator uses a narrow transition interval between the liquid and gaseous density to 

represent the two phase CO2 region. 

Because the compression facility controls the CO2 delivery temperature to the injection well 

between 80°F and 120°F, the temperature of the injectate will be comparable to the reservoir 

formation temperature within the injection interval. Therefore, the simulations were carried out 

based on isothermal operating conditions. With respect to time step selection, the software 

algorithm optimizes the time step duration based on specific convergence criteria designed to 

minimize numerical artifacts. For these simulations, time step size ranged from 8.64x101 to 

8.64x105

 seconds or 0.001 to 10 days. In all cases, the maximum solution change over a time 

step is monitored and compared with the specified target. Convergence is achieved once the 

model reaches the maximum tolerance “sufficiently small change” for temperature and pressure 

calculation results on successive iterations. New time steps are chosen so that the predicted 

solution change is less than a specified target.

Description of AoR Delineation Modeling Effort 

The 3D geologic model developed for the injection simulations is based on the interpretation of a 

diverse collection of geological, geophysical, and petrophysical data acquired throughout the 

construction of the IBDP wells (CCS#1 and VW#1). Structurally, the model is also based on the 

interpretation of both two dimensional (2D) and three dimensional (3D) seismic survey data in 

conjunction with dipmeter log data acquired from the IBDP wells. Petrophysical and transport 

properties based on the interpreted well log data and the analysis of core samples recovered from 

the IBDP wells were then distributed throughout each layer in the geocellular model. 

The model implements porosity and permeability well logs from CCS#1, VW#1, and VW#2. 

Seismic inversion was performed on the 3D surface seismic cube resulting in a seismic porosity 

cube. This seismic porosity cube was integrated with logs to guide interpolation of porosity 

throughout the 3D model. For the Mt. Simon, the PorosityCube was sampled into the geomodel’s 

3D grid and was also used to describe lateral heterogeneity beyond the seismic survey’s 

footprint. A workflow was prepared to document log upscaling and property modeling. 
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In November 2011, injection of CO2 into CCS#1 began and, as of January 2014, approximately 

730,000 metric tons of CO2 have been injected. Operational data from this project was used to 

calibrate the reservoir model being used for both the IBDP and IL-ICCS projects. Data obtained 

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

Spinner data, i.e. injection profile logs in CCS#1, and reservoir saturation tools (RST) from both 

IBDP wells. These datasets have provided additional information to allow calibration of various 

reservoir parameters including intrinsic permeabilities, relative permeabilities, wellbore skin

values, vertical to horizontal permeability ratios, and rock compressibility. These calibrations 

allow the model to be updated periodically to improve the accuracy between the model 

prediction versus the actual result. 

Monitoring data used for pressure matching includes:

• Injection Rate; 

• Injection Bottom hole Pressure – real-time data collected from a down hole gauge in the 

injection well about 600 ft above the perforations; 

• Westbay multilevel ground water characterization and monitoring system pressures – 

real-time pressures located at specific zones in the verification well 1000 ft. north of the 

injection well. Five out of ten zones were used for model calibration; 

• Spinner Data-Flow partitioning between perforations – log run in injection well through 

March 2013; and

• RST Well Logs – CO2 saturations around CCS#1 and VW#1 – logs run through March 

2013. 

More detailed information on model inputs and assumptions is given in the following 

subsections. 

Model Inputs and Assumptions 

The geologic/hydrogeologic and operational information that serve as inputs to the model are 

described in the following subsections. 

Site Geology and Hydrology 

The Class VI well targets an injection zone in the Cambrian Mt. Simon Sandstone of the Illinois 

Basin (see coordinates above under “Facility Information”). Information on the injection and 

confining zones was collected during the drilling and testing of the nearby IBDP injection well 

CCS#1, as well as existing Illinois State Geological Survey (ISGS) studies and reports. Data 

from an ISGS database of core sample data and additional core sample analyses from sites within 

approximately 30–80 miles of the injection well were also used.

The Mt. Simon Sandstone is the first sedimentary unit overlying the Precambrian granitic 

basement rock. The depositional environment of the Mt. Simon has “commonly been interpreted 

to be a shallow, sub-tidal marine environment,” based on surface study of the upper Mt. Simon 
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or studies of Wisconsin or Ozark Dome outcrops. However, based on core sample and log 

analysis from the CCS#1 well, the upper Mt. Simon is interpreted to have been deposited “in a 

tidally influenced system similar to the reservoirs used for natural gas storage in northern 

Illinois,” while the basal 600 ft (the target injection zone) represents an “arkosic sandstone that 

was originally deposited in a braided river-alluvial fan system.” In this lower zone, “abundant 

amounts” of secondary porosity occur due to the dissolution of feldspar grains. 

Directly overlying the Mt. Simon Sandstone is the Cambrian Eau Claire Formation. Based on 

data from CCS#1, in the area of the injection well, the Eau Claire consists of a basal shale layer 

overlain by very fine-grained limestone interbedded with thin siltstone layers. The Eau Claire 

serves as a confining zone for gas storage projects elsewhere in the Illinois Basin. Two other 

regional shale units are identified as secondary confining zones—the Ordovician Maquoketa 

Formation and the Devonian New Albany Shale—though these units lie above the lowermost 

USDW. No resolvable faults or folds were identified in the injection or confining zones based on 

3D seismic data collected in 2011. 

Only limited data and modeling results are available on ground water flow in the deep Illinois 

Basin, which is based on modeling results from Gupta and Bair (1997). Flow patterns in the Mt. 

Simon are “influenced by the geologic structure with flow away from arches such as the 

Kankakee Arch and toward the deeper parts of the Illinois Basin.” In the model, an initial fluid 

pressure of 3,205 psi (at elevation -6,345 ft MSL), an initial temperature of 112oF (at elevation -

5,365 ft MSL; gradient 1oF/ft), and an initial salinity of 200,000 ppm were used. MSL is defined 

as mean sea level. 

The lowermost USDW is the Ordovician St. Peter Sandstone, based on TDS sampling of the 

upper St. Peter during the drilling of CCS#1. 

Figure 1. Observed head in the Mt. Simon Sandstone. The red dot represents the location of CCS#1 

(potentiometric surface = 76 m/249 ft above mean sea level).
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Model Domain 

The static geological model includes the entire Mt. Simon and the overlying seal (the Eau 

Claire), spanning a 40 × 40 mile area. The final reservoir model was represented by a 146 × 146 

× 148 grid in a Cartesian system with 146 grid points in the x-direction, 146 grid points in the ydirection, and 148 grid points in the z-direction, for a total of 3,154,768 grid points. Model 

domain information is summarized in Table 1. 

Table 1. Model domain information.

Coordinate System State Plane

Horizontal Datum NAD27

Coordinate System Units ft

Zone Eastern

FIPSZONE 1,201 ADSZONE 3,776

Coordinate of xmin 277,028.18 Coordinate of xmax 408,692.78

Coordinate of ymin 1,103,729.25 Coordinate of ymax 1,235,364.89

Coordinate of zmin -6431.19 Coordinate of zmax -4290.78

Porosity 

Injection Zone Porosity

The total porosity of the injection zone was determined based on neutron and density logs of 

CCS#1, while effective porosity was determined from helium porosimetry on a “limited number” 

of core samples. The results of these methods compared well to each other, and so neutrondensity crossplot porosity was used to approximate effective porosity. For the injection interval 

of CCS#1 (-6,982 to -7,050 ft KB), the average effective porosity was found to be 21.0%. 

Within the AoR, KB is defined as Kelly Bushing which is approximately 682 ft above MSL. 

Additionally, the open-hole log based porosity was classified using Schlumberger Elemental Log 

Analysis (ELAN) as described in the CCS#1 Geophysical Log Descriptive Report. In the log 

analysis, the log analyst stated that the lower zone of the Mt. Simon has an average porosity of 

16.8%, though there are intervals where the porosity approaches 30%. 

Based on the analysis of log results from CCS#1, ADM identified three porosity/permeability 

zones within the Mt. Simon. These zones, with the average porosity and permeability values 

indicated by ADM, are illustrated in Figure 2. 

The lower zone of the Mt. Simon, extending from the base of the formation at -6,367 MSL (-

7,049 ft KB) to -5,738 ft MSL (-6,420 ft KB), is described as containing “the highest average 

porosity and quite good permeability.” The middle zone, extending from -5,738 ft MSL (-6,420 

ft KB) to -5,268 ft MSL (-5,950 ft KB), and the upper zone, extending from -5,268 ft MSL (-

5,950 ft KB) to the top of the Mt. Simon at -4,862 ft MSL (-5,544 ft KB), have lower porosities 

and permeabilities. 
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Confining Zone Porosity

The median porosity of the Eau Claire Formation is 4.7%, based on information from an ISGS 

database of UIC well core samples. 

Figure 2. Reproduced layers of the geologic model and average porosity/permeability values, as identified by 

ADM based on log analysis, along with the approximate perforated intervals of CCS#1 and CCS#2. Depths 

are shown with respect to mean sea level-MSL (and are equal to the Z-coordinates used in the model); they 

do not represent distances with respect to the kelly bushing. Horizontal distances are not to scale.
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Permeability

Injection Zone Permeability

ADM determined intrinsic permeability for areas of the injection zone based on available core 

analyses and CCS#1 well testing results, and developed a core porosity-permeability transform 

based on grain size to estimate permeability over intervals without core samples. From this 

method, ADM calculated a geometrical average intrinsic permeability of 194 mD for the CCS#1 

injection interval.

ADM also reported additional permeability values based on pressure transient analysis of data 

from CCS#1 pressure fall-off tests. Using PIE pressure transient software, ADM estimated 

permeability of 185 mD over 75 ft of vertical thickness in the injection zone. ADM also directly 

calculated permeability for this interval from core samples and well log analyses, with a result of 

182 mD. The CCS#1 well log reports an average permeability in the injection zone of 33 mD, 

though permeability in the perforated interval ranges from 60 mD to “several hundred” mD 

(Figure 2).

Confining Zone Permeability

While no core samples were taken from the shale zone of the Eau Claire at CCS#1, 12 plugs of 

upper interval Eau Claire (very fine sandstone, microcrystalline limestone, and siltstone) were 

available for testing. Average horizontal permeability for these sidewall rotary core samples was 

determined to be 0.000344 mD. However, the vertical permeability of the actual shale interval is 

expected to be much lower because vertical permeability of plugs “is generally lower than 

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

limestone, and siltstone.” Based on the analysis of log results from CCS#1, the Eau Claire, 

extending from the top of the Mt. Simon to -4,545 ft MSL (-5,227 ft KB), 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. 

ADM also cited a median permeability value of 0.000026 mD from the ISGS UIC core database. 

In addition, based on a set of core samples from a site approximately 80 miles to the north of the 

proposed Class VI location, 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). 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. 
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Operational Information 

The proposed injection well, CCS#2, is part of the IL-ICCS project. The other CO2 injection well 

on ADM’s property, IDBP well CCS#1, was completed in 2009. The AoR modeling accounts for 

both injection operations and the details are presented in Table 2. 

Table 2. Operating details for CCS#1 and CCS#2.

Injection 

Well

Location 

(Coordinates)

Model 

Coordinates (ft) Perforated 

Intervals

Perforated Interval 

(MSL) 

X Y X Y Ztop Zbottom

CCS#1 342,848.6 1,169,545.0 65,820.4 65,815.8 1 -6283 -6357

CCS#2 344,328.4 1,172,969.7 67,300.2 69,240.4 1 -6036 -6336

Injection 

Well

Wellbore 

Diameter (in)

Planned

Injection Period Injection 

Duration 

(years)

Injection Rate

(t/day) Start End

CCS#1 12.25 1-Jan-12 1-Jan-15 3 1000

CCS#2 12.25 1-Jan-15 1-Jan-20 5 3000

Fracture Pressure and Fracture Gradient

Injection Zone

A step rate test at CCS#1, in the interval of -7,025 ft KB to -7,050 ft KB was conducted to 

estimate the fracture pressure of the injection zone. The result from the uppermost perforation of 

CCS#1 (-7,025 ft KB) was 5,024 psig, corresponding to a fracture gradient of 0.715 psi/ft. Based 

on this result, ADM estimated the maximum injection pressure for CCS#1 as 3,995 psi based on 

the calculated fracture pressure at -6,345 ft MSL. As shown in Table 2, the elevation that 

corresponds to the top of the injection interval at CCS#1 is -6,283 ft MSL, which corresponds to 

a fracture pressure of 4,398.1 psi using the 0.7 psi/ft fracture gradient. Therefore, a maximum 

injection pressure of 3,958.29 psi at the top of the perforated interval (90% of the fracture 

pressure) is used for CCS#1. 

Using the same approach for CCS#2, the maximum injection pressure value is calculated to be 

4,500 psi at elevation -6,430 ft MSL. Similarly, the maximum injection pressure is calculated for 

the top of the injection interval, which corresponds to an elevation of -6,020 ft MSL. Based on 

the fracture gradient of 0.7, the maximum injection pressure at this point is calculated to be 

3,792.6 psi. These values are given in Table 3. 
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Table 3. Maximum injection pressure for CCS#1 and CCS#2.

Injection 

Well

Fracture 

Gradient

Maximum 

Injection 

Pressure (90% 

of fracture 

pressure) 

Submitted (psi)

Elevation 

Submitted 

Corresponding to 

Max. Injection P 

(ft MSL) 

Subsurface 

Elevation at 

the Top of the 

Perforated

Interval

(ft MSL)

Calculated Maximum 

Injection Pressure Used in 

this evaluation at the TOP 

of the perforated interval 

(psi) 

CCS#1 0.7 3995 -6345 -6283 3958.29

CCS#2 0.7 4500 -6430 -6020 3792.6

Confining Zone 

A “mini-frac” field test was used to determine in-situ fracture pressure in the confining zone. 

Fracture pressure results (from four short-term injection/fall-off test periods, 15 to 60 minutes 

each) ranged from 5,078 to 5,324 psig, corresponding to a fracture gradient ranging from 0.93 to 

0.98 psi/ft in the Eau Claire shale zone.

Initial Conditions

Fluid sampling and testing were conducted in April 2009 at CCS#1, including in-situ 

measurements of formation pressure and temperature and the collection of eight fluid samples at 

five depths. The results are as follows: 

• Temperature ranged from 119.8°F at -5,772 ft KB to 125.8°F at -6,912 ft KB. 

• Formation pressure ranged from 2,583 psi at -5,772 ft KB to 3,206 psi at -7,045 ft KB. 

• Fluid density ranged from 1,090 g/L to 1,137 g/L, with an average of 1,119 g/L (of the 

five samples taken).

• TDS ranged from 164,500 ppm at -5,772 ft KB to 228,100 ppm at -7,045 ft KB, with an 

average of 196,700 ppm. 

For the initial conditions in the model, aqueous pressure was determined to be 3,205 psi at a 

reference elevation of -6,345 ft MSL. The initial temperature is 112°F at a reference elevation of 

-5,365 ft MSL, with a gradient of 1°F/100 ft. Salinity is spatially constant, at 200,000 ppm. 

Boundary Conditions

No-flow boundary conditions were applied to the upper and lower boundaries of the model, with 

the assumption that the reservoir and the caprock are continuous throughout the region. A pore 

volume multiplier of 1,000 was applied to each cell in the horizontal boundaries of the ECLIPSE 

model in order to simulate an extensive reservoir. The horizontal boundaries were selected as: 

hydrostatic initial conditions for the aqueous phase, no-flow conditions for the gas phase, and 

initial conditions for salt. 
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AoR Pressure Front Delineation

To delineate the pressure front, the minimum or critical pressure (Pi,f) necessary to reverse flow 

direction between the lowermost USDW and the injection zone—and thus cause fluid flow from 

the injection zone into the formation matrix—must be calculated. ADM calculated Pi,f using the 

method provided in the March 2011 draft of the UIC Program Class VI Well Area of Review and 

Corrective Action Evaluation Guidance, where the pressure front is given by: 

Pi,f = Pu ·

ρi

ρu

+ ρig · (zu − zi)

Where:

Pu = initial pressure of the lowermost USDW,

ρi = fluid density of the injection zone, 

ρu = fluid density of the lowermost USDW, 

g = acceleration due to gravity,

zu = elevation of the lowermost USDW, and 

zi = elevation of the injection zone. 

Using this method, ADM calculated a Pi,f value equal to 171 psi (1.18 MPa). 

As an alternative approach for estimating a critical pressure in the injection zone, in December 

2013, ADM applied a method developed and published by Nicot et al. (2008): 

ΔP

g = ξ2 (zu − zi)2

This method estimates a pressure differential that would displace fluid initially present in a 

hypothetical borehole into the lowermost USDW and is based on two assumptions: (1) 

hydrostatic conditions; and (2) initially linearly varying densities in the borehole and constant 

density once the injection zone fluid is lifted to the top of the borehole. 

ADM used the Nicot method to calculate the pressure differential based on an injection depth of 

-6,800 ft KB and a lowermost USDW depth of approximately -3,300 ft KB. The results yield an 

estimate of approximately 85.9 psi (0.59 MPa). 

Model Calibration 

The site model has been calibrated using operational data obtained from the IBDP project 

through January 2013. The IBDP injection rate was input into the simulation to calculate the 

bottom hole pressures and pressures at five different zones at the verification well. The simulated 

pressures compared to the observed pressures. Reservoir permeability and skin were the main 

parameters impacting the injection pressure calibration and were used as fitting parameters. 

Actual spinner data was used to set the fractions of the total injection between the two sets of 

perforations in the injection well. These data along with the simulation allowed for fine tuning of 
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the well bore skin values at respective perforations together with the permeability to match 

injection bottom hole pressure (Figure 3). 

Once the injection bottom hole pressure was calibrated, simulated pressures at five different 

zones at the verification well were fine-tuned calibrating the kv/kh ratio of the tight sections and 

compressibility of the reservoir rock (Figure 4). 

Figure 3. History Matched Injection Bottom Hole Pressure (BHP) for CCS#1, submitted February 2014.
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Figure 4. History Matched Pressures at VW#1 for CCS#1, submitted February 2014.

RST well logs helped estimate the location, saturation, and thickness of the CO2 column around 

the injection and verification wells. This information helped fine tune the end points of relative 

permeability curves which dominate the CO2 and brine flow in the reservoir. Figure 5 and 

Figure 6 show the relative permeability curves for the two reservoir rock types used to 

characterize the lower and middle Mt. Simon storage units. These figures show the relative 

permeability with respect to brine saturation (Sw), for the CO2-brine system during drainage and 

imbibition. Where: brine drainage (krw) represents the relative permeability of brine during 

drainage, brine imbibition (krw) represents the relative permeability of brine during imbibition, 

CO2 drainage (krg) represents the relative permeability of CO2 during drainage, and CO2

imbibition (krg) represents the relative permeability of CO2 during imbibition. Please note that 

drainage is defined as CO2 replacing brine in the pores and imbibition is defined as brine 

replacing CO2 in the pores. 

Using the calibrated model, a predictive simulation was run to evaluate plume development and 

pressure perturbation during the course of injection. 
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Figure 5. Calibrated Relative Permeability Curves – Type 1 LL Mt. Simon, submitted February 2014.

Figure 6. Calibrated Relative Permeability Curves - Type 3 UL Mt. Simon, submitted February 2014.
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Computational Modeling Results 

The map below presents the AoR based on the modeling results. 

Figure 7. Map of the AoR as delineated by the reservoir model simulation.

Corrective Action Plan and Schedule

An estimated 215 wells are located within the vicinity of the AoR and evaluated and submitted to 

EPA by ADM in February 2014. 

Tabulation of Wells within the AoR 

Wells within the AoR

The only existing wells within the AoR which currently penetrate the caprock (Eau Claire 

Formation) are the IBDP injection, IBDP verification well, and the IL-ICCS verification well

(aka CCS#1), VW#1, and VW#2. CCS#1 was drilled in 2009. VW #1 was drilled in 2010. 

VW#2 was drilled in 2011. The IBDP wells are currently in operation. The IL-ICCS verification 
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well has been cased but not completed. Well construction records have been provided to 

USEPA. Illinois EPA is currently the regulatory agency monitoring the IBDP well operations 

under a Class I (non-hazardous) Underground Injection Control (UIC) permit (No. UIC-012-

ADM). The IL-ICCS VW#2 is permitted by the Illinois DNR as a monitor test well (No.3205). 

The latest estimate shows that a total of 215 wells are located within the vicinity of the proposed 

well. Water wells (157 of 215 wells) are the most common well type. The domestic water wells 

have depths of less than 60 m (200 ft). Other wells include stratigraphic test holes, non-domestic 

water wells, and oil and gas wells. All wells within the 4 townships-area of the injection well site 

were also identified (total of 3,761 wells). Information regarding these wells was provided as a 

supplement to the permit application (available in an electronic format). 

Ten oil and gas wells are located within approximately 2.4 km (1.5 miles) of the injection well 

location. The closest well is located in the northeast quarter of Section 5, T16N, R3E. This well 

(API number 121150061800) was drilled as a gas well in 1933 and was -27 m (-88 ft KB) deep. 

There is no record of this well being plugged. This well was likely collecting naturally occurring 

methane from the Quaternary sediments. The other 9 wells are located in Section 5, T16N, R3E 

or Section 28 and Section 29, T17N, R3E. The deepest of these oil wells is API number 

121150054700, located in the northwest quarter of Section 28. This well was drilled into the 

Lower Devonian and was -714 m KB (-2,344 ft KB) deep. 

Like other areas with humid climates (Freeze and Cherry, 1979), the water table in central 

Illinois is expected to reflect the elevation of the land surface. Steady-state ground water flow 

modeling for the IBDP site indicates that shallow ground water flows toward the east and 

southeast toward the Sangamon River and Lake Decatur. 

Wells Penetrating the Confining Zone [from Section 5.5.2]

With the exception of the injection and verification wells previously detailed, there are no known 

wells within the area of review that penetrate deeper than -762 m KB (-2,500 ft KB). The depth 

to the top of the injection zone (Mt. Simon Sandstone) is -1,690 m KB (-5,545 ft KB). Therefore, 

there are only three known wells that penetrate the uppermost injection zone. 

• Operating Wells: Three wells penetrating the uppermost injection zone are known to be 

in use within the AoR. The IBDP wells (CCS#1 and VW#1) began injection operation in 

November 2011. The IL-ICCS verification well (VW#2) has been drilled and cased but 

not completed. 

• Properly Plugged and Abandoned wells: No wells deeper than -762 m KB (-2,500 ft KB) 

are known to have been plugged and abandoned within the AoR. 

• Temporarily Abandoned Wells: No wells deeper than -762 m KB (-2,500 ft KB) are 

known to have been temporarily abandoned within the AoR. 
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No plugging affidavits are provided, as the IBDP wells are currently in use. 

If any of these wells are taken out of service prior to initiating injection, ADM will provide 

information to EPA to confirm that they have been properly plugged to ensure USDW protection 

pursuant to requirements at 40 CFR Part 146.

Wells Requiring Corrective Action

Based on information about the wells in existence at the time of permit issuance, no corrective 

action is required prior to initiation of injection. 

Plan for Site Access

Not applicable.

Justification of Phased Corrective Action

Not applicable.

Area of Review Reevaluation Plan and Schedule

ADM will take the following steps to evaluate project data and, if necessary, reevaluate the AoR. 

AoR reevaluations will be performed during the injection and post-injection phases. ADM will:

• Review available monitoring data and compare it to the model predictions. ADM will 

analyze monitoring and operational data from the injection well (CCS#2), the monitoring 

and geophysical wells, other surrounding wells, and other sources to assess whether the 

predicted CO2 plume migration is consistent with actual data. Specific steps of this 

review include:

o Reviewing available data on the position of the CO2 plume and pressure front 

(including pressure and temperature monitoring data and RST saturation and 

seismic survey data). Specific activities will include:

 Correlating data from time-lapse RST logs, time-lapse VSP surveys, and 

other seismic methods (e.g., 3D surveys) to locate and track the movement 

of the CO2 plume. A good correlation between the data sets will provide 

strong evidence in validating the model’s ability to represent the storage 

system. Also, limited 2D and 3D seismic surveys may be employed to

determine the plume location at specific times. 

 Reviewing downhole reservoir pressure data collected from various 

locations and intervals using a combination of surface and downhole 

pressure gauges. 

o Reviewing ground water chemistry monitoring data taken in the shallow (i.e., in 

Quaternary and/or Pennsylvanian strata) monitoring wells, the St. Peter, and the 
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Ironton-Galesville to verifying that there is no evidence of excursion of carbon 

dioxide or brines that represent an endangerment to any USDWs. 

o Reviewing operating data, e.g., on injection rates and pressures, and verifying 

that it is consistent with the inputs used in the most recent modeling effort. 

o Reviewing any geologic data acquired since the last modeling effort, e.g., 

additional site characterization performed, updates of petrophysical properties 

from core analysis, etc. Identifying whether any new data materially differ from 

modeling inputs/assumptions. 

• Compare the results of computational modeling used for AoR delineation to monitoring 

data collected. Monitoring data will be used to show that the computational model 

accurately represents the storage site and can be used as a proxy to determine the 

plume’s properties and size. ADM will demonstrate this degree of accuracy by 

comparing monitoring data against the model’s predicted properties (i.e., plume 

location, rate of movement, and pressure decay). Statistical methods will be employed 

to correlate the data and confirm the model’s ability to accurately represent the storage 

site. 

• If the information reviewed is consistent with, or is unchanged from, the most recent 

modeling assumptions or confirms modeled predictions about the maximum extent of 

plume and pressure front movement, ADM will prepare a report demonstrating that, 

based on the monitoring and operating data, no reevaluation of the AoR is needed. The 

report will include the data and results demonstrating that no changes are necessary. 

• If material changes have occurred (e.g., in the behavior of the plume and pressure front, 

operations, or site conditions) such that the actual plume or pressure front may extend 

beyond the modeled plume and pressure front, ADM will re-delineate the AoR. The 

following steps will be taken:

o Revising the site conceptual model based on new site characterization, 

operational, or monitoring data. 

o Calibrating the model in order to minimize the differences between monitoring 

data and model simulations. 

o Performing the AoR delineation as described the Computational Modeling 

Section of this AoR and Corrective Action Plan. 

• Review wells in any newly identified areas of the AoR and apply corrective action to 

deficient wells. Specific steps include:

o Identifying any new wells within the AoR that penetrate the confining zone and 

provide a description of each well’s type, construction, date drilled, location, 

depth, record of plugging and/or completion. 
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o Determining which abandoned wells in the newly delineated AoR have been 

plugged in a manner that prevents the movement of carbon dioxide or other fluids 

that may endanger USDWs.

o Performing corrective action on all deficient wells in the AoR using methods 

designed to prevent the movement of fluid into or between USDWs, including the 

use of materials compatible with carbon dioxide. 

• Prepare a report documenting the AoR reevaluation process, data evaluated, any 

corrective actions determined to be necessary, and the status of corrective action or a 

schedule for any corrective actions to be performed. The report will be submitted to EPA 

within one year of the reevaluation. The report will include maps that highlight 

similarities and differences in comparison with previous AoR delineations. 

• Update the AoR and Corrective Action Plan to reflect the revised AoR, along with other 

related project plans, as needed. 

AoR Reevaluation Cycle

ADM will reevaluate the above described AoR every five years during the injection and postinjection phases. 

In addition, monitoring and operational data will be reviewed periodically (likely annually) by 

ADM during the injection and post-injection phases. The reservoir flow model will be history 

matched against the observed parameters measured at the monitoring wells. Pressure will be 

monitored as described in the Testing and Monitoring Plan. The time lapse pressure monitoring 

data will be compared to the model predicted time lapse pressure profiles. ADM will provide a 

brief report of this review to the UIC Program Director and discuss the findings. 

If data suggest that a significant change in the size or shape of the actual CO2 plume as compared 

to the predicted CO2 plume and/or pressure front is occurring or there are deviations from 

modeled predictions such that the actual plume or pressure front may extend vertically or 

horizontally beyond the modeled plume and pressure front, ADM will initiate an AoR 

reevaluation prior to the next scheduled reevaluation. Such deviations may be evidenced by the 

results of direct or indirect monitoring activities including MIT failures or loss of MI; observed 

pressure and saturation profiles; changes in the physical or chemical characteristics of the CO2; 

any detection of CO2 above the confining zone (e.g., based on hydrochemical/physical 

parameters); microseismic data indicating slippage in or near the confining zone or microseismic 

data within the injection zone that indicates slippage and propagation into the confining zone; or 

arrival of the CO2 plume and/or pressure front at certain monitoring locations that diverges from 

expectations, as described below. 

Triggers for AoR Reevaluations Prior to the Next Scheduled Reevaluation 

Unscheduled reevaluation of the AoR will be based on quantitative changes of the monitoring 

parameters in the deep monitoring wells, including unexpected changes in the following 

parameters: pressure, temperature, neutron saturation, and the deep ground water (> 3,000 ft 
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below KB) constituent concentrations indicating that the actual plume or pressure front may 

extend beyond the modeled plume and pressure front. These changes include:

• Pressure: Changes in pressure that are unexpected and outside three (3) standard 

deviations from the average will trigger a new evaluation of the AoR. 

• Temperature: Changes in temperature that are unexpected and outside three (3) standard 

deviations from the average will trigger a new evaluation of the AoR. 

• RST Saturation: Increases in CO2 saturation that indicate the movement of CO2 into or 

above the confining zone will trigger a new evaluation of the AoR unless the changes are 

found to be related to the well integrity. (Any well integrity issues will be investigated 

and addressed.) 

• Deep ground water constituent concentrations: Unexpected changes in fluid constituent 

concentrations that indicate movement of CO2 or brines into or above the confining zone 

will trigger a new evaluation of the AoR unless the changes are found to be related to the 

well integrity. (Any well integrity issues will be investigated and addressed.)

• Exceeding Fracture Pressure Conditions: Pressure in any of the injection or monitoring 

wells exceeding 90 percent of the geologic formation fracture pressure at the point of 

measurement. This would be a violation of the permit conditions. The Testing and 

Monitoring Plan provides discussion of pressure monitoring. 

• Exceeding Established Baseline Hydrochemical/Physical Parameter Patterns: A 

statistically significant difference between observed and baseline hydrochemical/physical 

parameter patterns (e.g., fluid conductivity, pressure, temperature) immediately above the 

confining zone. The Testing and Monitoring Plan provides extended information 

regarding how pressure, temperature, and fluid conductivity will be monitored. 

• Compromise in Injection Well Mechanical Integrity: A significant change in pressure 

within the protective annular pressurization system surrounding each injection well that 

indicates a loss of mechanical integrity at an injection well.

• Seismic Monitoring Identification of Subsurface Structural Features: Seismic 

monitoring data that indicates the presence of a fault or fracture in or near the confining 

zone or a fault or fracture within the injection zone that indicates propagation into the 

confining zone. The Testing and Monitoring Plan provides extended information about 

the microseismic monitoring network.

An unscheduled AoR reevaluation may also be needed if it is likely that the actual plume or 

pressure front may extend beyond the modeled plume and pressure front because any of the 

following has occurred: 

• Seismic event greater than M3.5 within 8 miles of the injection well; 

• If there is an exceedance of any Class VI operating permit condition (e.g., exceeding the 

permitted volumes of carbon dioxide injected); or 

• If new site characterization data changes the computational model to such an extent that 

the predicted plume or pressure front extends vertically or horizontally beyond the 

predicted AoR. 
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ADM will discuss any such events with the UIC Program Director to determine if an AoR 

reevaluation is required. 

If an unscheduled reevaluation is triggered, ADM will perform the steps described at the 

beginning of this section of this Plan.