Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B1 of 20 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 CO 2 STORE module accounts for the thermodynamic interactions between three phases: an H 2 O- rich phase (i.e. , ‘liquid’), a CO 2 - rich phase (i.e. , ‘gas’), and a solid phase, which is limited to several common salt compounds (e.g. NaCl, CaCl 2 , and CaCO 3 ). Mutual solubilities and physical properties (e.g. density, viscosity, enthalpy, etc.) of the H 2 O and CO 2 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 fo llows:

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

• The CO 2 - 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 CO 2 concentration by using Ezrokhi’s method (Zaytsev and Aseyev, 1992).Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B2 of 20 • The CO 2 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 = � RT K V − b mix � − � a mix T

K 1⁄2 V ( V + b mix ) �

where V is the molar volume, P is the pressure, T K is the temperature in Kelvin, R is the universal gas constant, and a mix and b mix are the attraction and repulsion parameters.

The transition between liquid CO 2 and gaseous CO 2 can lead to rapid density changes of the gas phase; the simulator use s a narrow transition interval between the liquid and gaseous density to represent the two phase CO 2 region.

Because the compression facility controls the CO 2 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 res pect 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 8.64x10 1 to 8.64x10 5 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 calculat ion 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 well s 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B3 of 20 In November 2011, injection of CO 2 into CCS#1 began and, as of January 2014, approximately 730,000 metric tons of CO 2 have been injected. Operational dat a 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 matchin g 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 – CO 2 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 operation al 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 a bove 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. Dat a 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 basem ent 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. SimonArea of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B4 of 20 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 zo ne) 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 lowe rmost 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).Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B5 of 20 Model Domain

The static geological model include s 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 ydirecti on, 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 x min 277,028.18 Coordinate of x max 408,692.78
Coordinate of y min 1,103,729.25 Coordinate of y max 1,235,364.89

Coordinate of z min - 6431.19 Coordinate of z max - 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 l ower 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B6 of 20 Confining Zone Porosity

T he 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 ide ntified 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B7 of 20 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 g eometrical 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 ).

Co nfining 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 MS L (-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 i n 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

.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B8 of 20 Operational Information

The proposed injection well, CCS#2, is part of the IL- ICC S project. The other CO 2 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 Z top Z bottom 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B9 of 20 Table 3 . Maximum injection pressure for CCS#1 and CCS#2.

Injectio n

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 E au 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. T he results are as f ollows:

• 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, w ith 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 10 of 20 AoR Pressure Front Delineation

To delineate the pressure front, the minimum or critical pressure (P i,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 P i,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:

P

i

, f = P u · ρ i ρ u + ρ i g · ( z u − z i )

Where:

P u = initial pressure of the lowermost USDW,
ρ i = fluid density of the injection zone,
ρ u = fluid density of the lowermost USDW, g = acceleration due to gravity,

z u = elevation of the lowermost USDW, and

z i = elevation of the injection zone.

Using this method, ADM calculated a P i,f value equal to 1 71 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 = ξ
2 ( z u − z i ) 2

This method estimates a pressure differen tial 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 approxi mately -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 t he 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 ofArea of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 11 of 20 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 k v /k h 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 12 of 20 Figure 4. History Matched Pressures at VW#1 for CCS#1, submitted February 2014.

RST well l ogs helped estimate the location, saturation, and thickness of the CO 2 column around the injection and verification wells. This information helped fine tune the end points of relative permeability curves which dominate the CO 2 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 (S w ), for the CO 2 -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 du ring imbibition, CO 2 drainage (krg) represents the relative permeability of CO 2 during drainage, and CO 2 imbibition (krg) represents the relative permeability of CO 2 during imbibition. Please note that drainage is defined as CO 2 replacing brine in the pores and imbibition is defined as brine replacing CO 2 in the pores.

Using the calibrated model, a predictive simulation was run to evaluate plume development and pressure perturbation during the course of injection.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 13 of 20 Figure 5 . Cal ibrated 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 14 of 20 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 verificationArea of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 15 of 20 well has been cased but n ot 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) . T he 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 we ll 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 eleva tion 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 previous ly 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 : T hree 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 16 of 20 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 Revi ew Reevaluation Plan and Schedule

ADM will take the following steps to evaluate project data and, if necessary, reevaluate the AoR. AoR reevaluation s will be performed during the injection and post-injection phases. ADM will:

• Review available monitoring da ta and compare it to the model predictions. ADM will analyze m onitoring 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 CO 2 plume migration is consistent with actual data. Specific steps of this review include:

o R eview ing available data on the position of the CO 2 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 CO 2 plume. A good correlation between the data sets will provide
str ong evidence in va lidating 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.

 Review ing downhole reservoir pressure data collected from various locations and intervals using a combination of surface and downhole
pressure gauges.

o Review ing ground water chemistry monitoring data taken in the shallow (i.e., in Quaternary and/or Pennsylvanian strata) monitoring wells, the St. Peter, and theArea of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 17 of 20 Ironton- Galesville to verify ing that there is no evidence of excursion of carbon dioxide or brines that represent an endangerment to any USDW s.

o R eview ing 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 Review ing any geologic data acquired since the last modeling effort , e.g., additional site characterization performed, updates of petrophysical properties from core analysis, etc . Identify ing whether any new data materially differ from modeling inputs/assumptions.

• Compare t he re sults of computationa l mod e ling used for AoR de lin ea tion to monito ring data coll ec ted. 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 monito ring data against the model ’s p re dicted properties (i.e., plume location, rate of movement, and p re ssu re 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 assu mptions or confirms model ed 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 t he 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 Revis ing the site conceptual model based on new site characterization, operational, or monitoring data.

o C alibrat ing the mo d el in order to minimize the differences between monitoring data and model simulations.

o Perform ing the AoR delineation as described the Computational Modeling Section of th is AoR and Corrective Action Plan.

• Review wells in any new ly identified areas of the AoR and apply corrective action to deficient wells. S pecific steps include:

o Identifying any n ew 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.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 18 of 20 o Determin ing 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 Perform ing 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 f iv e years during the injection and postinjection phases.

In addition, monitoring and operational data will be reviewed periodically (likely annual ly ) by ADM during the injection and post-injection phases. The reservoir flow model will be history matched aga inst 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 CO 2 plume as compared to the predicted CO 2 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 reeval uation. 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 CO 2 ; any detecti on of CO 2 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 CO 2 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 ftArea of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 19 of 20 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 CO 2 saturation that indicate the movement of CO 2 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.)

• De ep ground water constituent concentrations: Unexpected changes in fluid constituent concentrations that indicate movement of CO 2 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 poin t 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 differen ce 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, tempera ture, 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 indicate s 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 :

• S eismic 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 extend s vertically or horizontally beyond the predicted AoR

.Area of Revi ew and Corrective Action Plan for ADM CCS#2 Permit Number: IL

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- 0001 Page B 20 of 20 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 th is Plan.