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Permit Number: IL-137-6A-0001 (Well #1) 

 

ATTACHMENT B: AREA OF REVIEW AND CORRECTIVE ACTION PLAN 

Facility Information 

Facility Name: FutureGen 2.0 Morgan County CO2 Storage Site 

IL-137-6A-0001 (Well #1) 

Facility Contacts: Kenneth Humphreys, Chief Executive Officer, 

FutureGen Industrial Alliance, Inc., Morgan County Office, 

73 Central Park Plaza East, Jacksonville, IL 62650, 217-243-8215 

Location of Injection Well: Morgan County, IL; 26−16N−9W; 39.80111oN and 90.07491oW 

Computational Modeling 

Model Name: STOMP-CO2 (Subsurface Transport Over Multiple Phases-CO2) simulator

Model Authors/Institution: White et al. 2013; White and Oostrom 2006; White and McGrail 

2005/Pacific Northwest National Laboratory (PNNL)

Description of Model: 

The simulations conducted for this investigation were executed using the STOMP-CO2 

simulator (White et al. 2013; White and Oostrom 2006; White and Oostrom 2000). STOMP-CO2 

was verified against other codes used for simulation of geologic disposal of CO2 as part of the 

GeoSeq code intercomparison study (Pruess et al. 2002). 

Partial differential conservation equations for fluid mass, energy, and salt mass compose the 

fundamental equations for STOMP-CO2. Coefficients within the fundamental equations are 

related to the primary variables through a set of constitutive relationships. The salt transport 

equations are solved simultaneously with the component mass and energy conservation 

equations. The solute and reactive species transport equations are solved sequentially after the 

coupled flow and transport equations. The fundamental coupled flow equations are solved using 

an integral volume finite-difference approach with the nonlinearities in the discretized equations 

resolved through Newton-Raphson iteration. The dominant nonlinear functions within the 

STOMP-CO2 simulator are the relative permeability-saturation-capillary pressure (k-s-p) 

relationships. 

The STOMP-CO2 simulator allows the user to specify these relationships through a large variety 

of popular and classic functions. Two-phase (gas-aqueous) k-s-p relationships can be specified 

with hysteretic or nonhysteretic functions or nonhysteretic tabular data. Entrapment of CO2 with 

imbibing water conditions can be modeled with the hysteretic two-phase k-s-p functions. Twophase k-s-p relationships span both saturated and unsaturated conditions. The aqueous phase is 

assumed to never completely disappear through extensions to the s-p function below the residual 
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saturation and a vapor pressure lowering scheme. Supercritical CO2 has the function of a gas in

these two-phase k-s-p relationships. 

For the range of temperature and pressure conditions present in deep saline reservoirs, four 

phases are possible: 1) water-rich liquid (aqueous), 2) CO2-rich vapor (gas), 3) CO2-rich liquid 

(liquid-CO2), and 4) crystalline salt (precipitated salt). The equations of state express 1) the 

existence of phases given the temperature, pressure, and water, CO2, and salt concentration; 2) 

the partitioning of components among existing phases; and 3) the density of the existing phases. 

Thermodynamic properties for CO2 are computed via interpolation from a property data table 

stored in an external file. The property table was developed from the equation of state for CO2

published by Span and Wagner (1996). Phase equilibria calculations in STOMP-CO2 use the 

formulations of Spycher et al. (2003) for temperatures below 100°C and Spycher and Pruess 

(2010) for temperatures above 100°C, with corrections for dissolved salt provided in Spycher 

and Pruess (2010). The Spycher formulations are based on the Redlich-Kwong equation of state 

with parameters fitted from published experimental data for CO2-H2O systems. Additional 

details regarding the equations of state used in STOMP-CO2 can be found in the guide by White 

et al. (2013).

A well model is defined as a type of source term that extends over multiple grid cells, where the 

well diameter is smaller than the grid cell. A fully coupled well model in STOMP-CO2 was used 

to simulate the injection of supercritical CO2 (scCO2) under a specified mass injection rate, 

subject to a pressure limit. When the mass injection rate can be met without exceeding the 

specified pressure limit, the well is considered to be flow controlled. Conversely, when the mass 

injection rate cannot be met without exceeding the specified pressure limit, the well is considered 

to be pressure controlled and the mass injection rate is determined based on the injection 

pressure. The well model assumes a constant pressure gradient within the well and calculates the 

injection pressure at each cell in the well. The CO2 injection rate is proportional to the pressure 

gradient between the well and surrounding formation in each grid cell. By fully integrating the 

well equations into the reservoir field equations, the numerical convergence of the nonlinear 

conservation and constitutive equations is greatly enhanced. 

Model Inputs and Assumptions:

Conceptual Model 

Site Stratigraphy 

The regional geology of Illinois is well known from wells and borings drilled in conjunction with 

hydrocarbon exploration, aquifer development and use, and coal and commercial mineral 

exploration. Related data are largely publicly available through the Illinois State Geological 

Survey (ISGS)1

and the U.S. Geological Survey.2 In addition, the U.S. Department of Energy has 

sponsored a number of studies by the Midwest Geologic Sequestration Consortium3to evaluate 

subsurface strata in Illinois and adjacent states as possible targets for the containment of 

anthropogenic CO2.

 

1 http://www.isgs.uiuc.edu/

2 http://www.usgs.gov/

3 http://sequestration.org/
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To support the evaluation of the Morgan County site as a potential carbon storage site, a deep 

stratigraphic well was drilled and extensively characterized. The FutureGen 2.0 stratigraphic 

well, located at longitude 90.05298W, latitude 39.80681N, is approximately 1.24 mi (2 km) 

northeast of the planned injection site. The stratigraphic well reached a total depth of 4,826 ft 

(1,471 m) below ground surface (bgs) within the Precambrian basement (Figure 1). The well 

penetrated 479 ft (146 m) of the Eau Claire Formation and 512 ft (156 m) of the Mount Simon 

Sandstone. The stratigraphic well was extensively characterized, sampled, and geophysically 

logged during drilling. A total of 177 ft of whole core were collected from the lower Eau Claire 

Formation and upper Mount Simon Sandstone and 34 ft were collected from lower Mount Simon 

Sandstone and Precambrian basement interval. In addition to whole drill core, a total of 130 sidewall core plugs were obtained from the combined interval of the Eau Claire Formation, Mount 

Simon Sandstone, and the Precambrian basement. In Figure 2, cored intervals are indicated with 

red bars; rotary side-wall core and core-plug locations are indicated to the left of the lithology 

panel. Standard gamma ray and resistivity curves are shown in the second panel. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 1. Stratigraphic Column of FutureGen 2.0 Stratigraphic Well 
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Figure 2. Lithology, Mineralogy, and Hydrologic Units of the Proposed Injection Zone (Mount Simon, 

Elmhurst and Lower Lombard member) and Lower Primary Confining Zone (Upper Lombard), as 

Encountered Within the Stratigraphic Well 

Geologic Structures 

Two orthogonal two-dimensional (2D) surface seismic lines, shown in Figure 3, were acquired 

along public roads near the site and processed in January and February 2011. Surface seismic 

data were acquired as single-component data. The seismic data are not of optimal quality due to 

loss of frequency and resolution below a two-way time depth of about 300 milliseconds (ms), 

approximately coincident with the top of the Galena limestone at a depth of 1,400 ft. However, 

they do not indicate the presence of obvious faults or large changes in thickness of the injection 

or confining zones. Both profiles indicate a thick sequence of Paleozoic-aged rocks with a 

contact between Precambrian and Mount Simon at 640 ms and a contact between Eau Claire and 

Mount Simon at 580 ms. 

Some vertical disruptions, which extend far below the sedimentary basin, remain after 

reprocessing in 2012, but their regular spatial periodicity has a high probability of being an 

artifact during data acquisition and processing and is unlikely related to faults. 

No discernable faults have been identified on the 2D data within the immediate area. A small 

growth fault that affects the Mount Simon and Eau Claire formations is interpreted in the eastern 

part of the L201 profile at an offset 28,000 ft. This growth fault is more than 1.5 miles away 

from the outermost edge of the CO2 plume and does not extend far upward in the overburden. 

For these reasons, it is highly unlikely that it could affect the integrity of the injection zone. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 3. Locations of Two 2D Seismic Survey Lines, L101 and L201, Vertical Seismic Profile Locations, and 

the Knox Line Near the Proposed Morgan County CO2 Storage Site 

A three-component vertical seismic profiling (VSP) data set (Figure 3) was acquired in the 

FutureGen stratigraphic well in March 2013, and processed by Schlumberger Carbon Services. 

No discernable faults are present in the 15 short 2D seismic lines formed by the offset VSP 

locations. These lines represent a lateral interrogation extent of 800−1600 ft radially from the 

stratigraphic well. The high-resolution, low-noise VSP data also do not contain the vertical 

disruptions observed in the 2D surface seismic profiles (Hardage 20134). 

The ISGS recently shot a 120-mi long seismic reflection survey (the Knox Line) across central 

Illinois as part of a Department of Energy-sponsored research project to characterize rock units 

for geologic storage of CO2. The continuous east-west line extends from Meredosia to 

southwestern Champaign County (Figure 3). FutureGen Industrial Alliance, Inc., (FutureGen 

Alliance) acquired these data from the ISGS with the intention of reprocessing the data, if 

needed, to identify regional faults that might impact the proposed FutureGen 2.0 Morgan County 

CO2 Storage Site (FutureGen 2.0 Site). A review of the data by a geophysical expert on Illinois 

reflection seismic data5

, indicated that there was no discernable faulting west of Ashland, 

 

4

 Bob Hardage. Personal Communication with Charlotte Sullivan, August 1, 2013.

5

 John McBride. Personal Communication with Charlotte Sullivan, October 29, 2013.
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Illinois; and that current plans to reprocess the ISGS Knox line would not likely result in a 

greatly improved image. 

The closest known earthquake to the FutureGen 2.0 Site (Intensity VII, magnitude 4.8 – noninstrumented record) occurred on July 19, 1909, approximately 28 mi (45 km) north of the site; it 

caused slight damage. Most of the events in Illinois occurred at depths greater than 1.9 mi (3 

km). 

Conceptual Model Domain 

A stratigraphic conceptual model of the geologic layers from the Precambrian basement to 

ground surface was constructed using the EarthVision® software package. The geologic setting 

and site characterization data described in the Underground Injection Control (UIC) Permit 

Supporting Documentation and later in this section were the basis for the Morgan County CO2

storage site computational model. Borehole data from the FutureGen 2.0 stratigraphic well and 

data from regional boreholes and published regional contour maps were used as input data 

(Figure 4, step 1). There is a regional dip of approximately 0.25 degrees in the east-southeast 

direction (Figure 4, step 2). To define the numerical model domain, an expanded 100- by 100-

mi conceptual model was constructed to represent units below the Potosi dolomite interval, 

including the formations of Franconia, Ironton, Eau Claire (Proviso, Lombard, and Elmhurst), 

and Mount Simon. Each of these formation layers was further divided into multiple sub-layers 

based on the data from the stratigraphic well. The elevations of Franconia top, Mount Simon top, 

and Mount Simon Bottom were determined by EarthVision® based on borehole data and 

regional contour maps. The elevations of the interfaces between sub-layers were determined by 

the three bounding surfaces from EarthVision® and the stratigraphic well to make up the 

boundary-fitted stratigraphic layers of the computational model. The numerical model grid in 

the horizontal directions was designed to have constant grid spacing with higher resolution in the 

area influenced by the CO2 injection (3-mi by 3-mi area), with increasingly larger grid spacing 

moving out toward the domain boundaries. The conceptual model hydrogeologic layers were 

defined for each stratigraphic layer based on zones of similar hydrologic properties. The 

hydrologic properties (permeability, porosity) were deduced from geophysical well logs and 

side-wall cores. The lithology, deduced from wireline logs and core data, was also used to 

subdivide each stratigraphic layer of the model. Based on these data, the Mount Simon 

Sandstone was subdivided into 17 layers, and the Elmhurst Sandstone (member of the Eau Claire 

Formation) was subdivided into 7 layers (Figure 4). The Lombard and Proviso members of the 

Eau Claire Formation were subdivided respectively into 14 and 5 layers. The Ironton Sandstone 

was divided into four layers, the Davis Dolomite into three layers, and the Franconia Formation 

into one layer. Some layers (“split” label in Figure 4, step 2) have similar properties but have 

been subdivided to maintain a reasonable thickness of layers within the injection zone as 

represented in the computational model. The thickness of the layers varies from 4 to 172 ft, with 

an average of 26 ft. 

Based on knowledge of the regional and local geology, the Mount Simon Sandstone and the 

Elmhurst form the main part of the injection zone. However, the computational model results 

indicate that the Model Layer “Lombard 5” is the top unit containing a fraction of injected CO2

during the 100-year simulation. Based on these results, the lower part of the Lombard (layers 

Lombard 1 to 5 of the Computational Model), is considered to be part of the injection zone 
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(Figure 4). The top of the injection zone is set at 3,785 ft bgs (-3,153 ft elevation MSL) in the 

stratigraphic well. The upper part of the Lombard and the Proviso members form the primary 

confining zone. 

Figure 4, step 3, shows the numerical model grid for the entire 100- by 100-mi domain and also 

for the 3- by 3-mi area with higher grid resolution and uniform grid spacing of 200 ft by 200 ft. 

The model grid contains 125 nodes in the x-direction, 125 nodes in the y-direction, and 51 nodes 

in the z-direction for a total number of nodes equal to 796,875. The expanded geologic model 

was queried at the node locations of the numerical model to determine the elevation of each 

surface for the stratigraphic units at the numerical model grid cell centers (nodes) and cell edges. 

Then each of those layers was subdivided into the model layers by scaling the thickness to 

preserve the total thickness of each stratigraphic unit. Once the vertical layering was defined, 

material properties were mapped to each node in the model. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

 

Figure 4. Implementation of the Numerical Model: From the Geological Conceptual Model to the Numerical 

Model 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Processes Modeled 

Physical processes modeled in the reservoir simulations included isothermal multi-fluid flow and 

transport for a number of components (e.g., water, salt, and CO2) and phases (e.g., aqueous and 

gas). Isothermal conditions were modeled because it was assumed that the temperature of the 

injected CO2 will be similar to the formation temperature. Formation salinity is considered 

because salt precipitation can occur near the injection well in higher permeability layers as the 

rock dries out during CO2 injection. Porosity reduction due to salt precipitation is considered in 

the model. However, permeability reduction was not modeled because the salinity is relatively 

low in the injection formations at this site, resulting in low levels of salt precipitation. 

Injected CO2 partitions in the injection zone between the free (or mobile) gas, entrapped gas, and 

aqueous phases. Sequestering CO2 in deep saline formations occurs through four mechanisms: 1) 

structural trapping; 2) aqueous dissolution; 3) hydraulic trapping; and 4) mineralization. 

Structural trapping is the long-term retention of the buoyant gas phase in the pore space of the 

permeable formation rock held beneath one or more impermeable or near impermeable confining 

zones. Aqueous dissolution occurs when CO2 dissolves in the brine resulting in an aqueousphase density greater than the ambient conditions. Hydraulic trapping is the pinch-off trapping of 

the gas phase in pores as the brine re-enters pore spaces previously occupied by the gas phase. 

Generally, hydraulic trapping only occurs upon the cessation of CO2 injection. Mineralization is 

the chemical reaction that transforms formation minerals to carbonate minerals. In the Mount 

Simon Sandstone, the most likely precipitation reaction is the formation of iron carbonate 

precipitates. A likely reaction between CO2 and shale is the dewatering of clays. Laboratory 

investigations are currently quantifying the importance of these reactions at the Morgan County 

CO2 storage site. Based on its experiments, the FutureGen Alliance expects to see a small mass 

of precipitates (KCl, NaCl) forming near the injection well from the scCO2 displacement of 

water, and does not expect to see the formation of any significant carbonate precipitates in the 

year (or years) time scale. Iron does precipitate, but concentrations are too low (<0.6 mmol/L) 

relative to carbonate mass to be a precipitate issue. Simulations by others (White et al. 2005) of 

scCO2 injection in a similar sandstone (also containing iron oxides) shows that over significantly 

longer time scales (1000+ years), alumino silicate dissolution and alumino silicate precipitation 

incorporating significant carbonate (dawsonite) is predicted, as well as precipitation of some 

calcite. That predicted mineral trapping did permanently sequester 21 percent of the carbonate 

mass, thus decreasing scCO2 transport risk. Therefore, the simulations described here did not 

include mineralization reactions. However, the STOMP-CO2 simulator does account for 

precipitation of salt during CO2 injection. The CO2 stream provided by the plant to the storage 

site is no less than 97 percent dry basis CO2. Because the amount of impurities is small, for the 

purposes of modeling the CO2 injection and redistribution for this project, it was assumed that 

the injectate was pure CO2.
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Rock Properties 

Intrinsic Permeability 

Site Characterization Data 

Permeability in the sandstones, as measured in rotary side-wall cores and plugs from whole core, 

appears to be dominantly related to grain size and abundance of clay. In Figure 2, ELAN 

(Elemental Log Analysis)-calculated permeability (red curve) is in the third panel, along with 

two different lab measurements of permeability for each rotary side-wall core. Horizontal 

permeability (Kh) data in the stratigraphic well outnumber vertical permeability (Kv) data, 

because Kv could not be determined from rotary side-wall cores. However, Kv/Kh ratios were 

successfully determined for 20 vertical/horizontal siliciclastic core-plug pairs cut from intervals 

of whole core. Within the Mount Simon Sandstone, the horizontal permeabilities of the lower 

Mount Simon alluvial fan lithofacies range from 0.005 to 0.006 mD and average ratios of 

vertical to horizontal permeabilities range from 0.635 to 0.722 (at the 4,304 to 4,374 ft bgs depth 

or the elevation of -3,685 to -3,755 ft, Figure 2). Horizontal core-plug permeabilities range from 

0.032 to 2.34 mD at the 3,838 to 3,904 ft bgs depth (elevation of -3,219 to -3,285 ft); Kv/Kh

ratios for these same samples range from 0.081 to 0.833. 

The computed lithology track for the primary confining zone indicates the upward decrease in 

quartz silt and increase in carbonate in the Proviso member, along with a decrease in 

permeability. The permeabilities of the rotary side-wall cores in the Proviso range from 0.000005 

mD to 1 mD. Permeabilities in the Lombard member range from 0.001 mD to 28 mD, reflecting 

the greater abundance of siltstone in this interval, particularly in the lowermost part of the 

member. Whole core plugs and associated vertical permeabilities are available only from the 

lowermost part of the Lombard. Thin (few inches/centimeters), high-permeability sandstone 

streaks resemble the underlying Elmhurst; low-permeability siltstone and mudstone lithofacies 

have vertical permeabilities of 0.0004 to 0.465 mD, and Kv/Kh ratios of <0.0001 to 0.17. 

The ELAN geophysical logs indicated permeabilities are generally less than the wireline tool 

limit of 0.01 mD throughout the secondary confining zone. Two rotary side-wall cores were 

taken from the Franconia, and three side-wall cores were cut in the Davis member. Laboratorymeasured rotary side-wall core (horizontal) permeabilities are very low (0.000005 to 0.001 mD). 

The permeabilities of the two Franconia samples were measured with a special pulse decay 

permeameter; the sample from 3,140 ft bgs (-2521 ft elevation) has a permeability less than the 

lower instrument limit of 0.000005 mD. Vertical core plugs are required for directly determining 

vertical permeability and there are no data from the stratigraphic well for vertical permeability or 

for determining vertical permeability anisotropy in the secondary confining zone. However, 

Kv/Kh ratios of 0.007 have been reported elsewhere for Paleozoic carbonate mudstones (Saller et 

al. 2004). 
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Model Parameters

Intrinsic permeability data sources for the FutureGen 2.0 stratigraphic well include computed 

geophysical wireline surveys (CMR and ELAN logs), and where available, laboratory 

measurements of rotary side-wall cores (SWC), core plugs from the whole core intervals, 

hydrologic tests (including wireline [MDT]), and packer tests. For the Mount Simon and 

Elmhurst Sandstones model layers (3,838 to 4,418 ft bgs depth or elevation of -3219 to -3799 ft 

at the stratigraphic well), wireline ELAN permeability model permKCal produced by 

Schlumberger (red curve on Figure 2) was used. This model, calibrated by rotary side-wall and 

core-plug permeabilities, provides a continuous permeability estimate over the entire injection 

zone. This calibrated permeability response was then slightly adjusted, or scaled, to match the 

composite results obtained from the hydrologic packer tests over uncased intervals. For injection 

zone model layers within the cased well portion of the model, no hydrologic test data are 

available, and core-calibrated ELAN log response was used directly in assigning average model 

layer permeabilities. 

The hydraulic packer tests were conducted in two zones of the Mount Simon portion of the 

injection zone. The Upper Zone (3,934 ft to 4,180 ft bgs depth or -3,315 to -3,561 ft elevation) 

equates to layers 6 through 17 of the model, while the Lower Zone (4,186 ft to 4,498 ft bgs depth 

or -3,567 to -3,879 ft elevation) equates to layers 1 through 5. The most recent ELAN-based 

permeability-thickness product values are 9,524 mD-ft for the 246-ft-thick section of the upper 

Mount Simon corresponding to the Upper Zone and 3,139 mD-ft for the 312-ft-thick section of 

the lower Mount Simon corresponding to the Lower Zone. The total permeability-thickness 

product for the open borehole Mount Simon is 12,663 mD-ft, based on the ELAN logs. Results 

of the field hydraulic tests suggest that the upper Mount Simon permeability-thickness product is 

9,040 mD-ft and the lower Mount Simon interval permeability-thickness product is 775 mD-ft. 

By simple direct comparison, the packer test for the upper Mount Simon is nearly equivalent 

(~95 percent) to the ELAN-predicted value, while the lower Mount Simon represents only ~25 

percent of the ELAN-predicted value. 

Because no hydrologic test has been conducted in the Elmhurst Sandstone interval of the 

injection zone, a conservative scaling factor of 1 has been assigned to this interval, based on 

ELAN PermKCal data (The permeabilities used for this formation were the ELAN PermKCal 

values without applying a scaling factor). The sources of data for confining zones (Franconia to 

Upper part of the Lombard Formations) and the Upper part of the Injection zone (Lower part of 

the Lombard) are similar to those for the injection zone, with the exception that no hydrologic or 

MDT test data are available. ELAN log-derived permeabilities are unreliable below about 0.01 

mD (personal communication from Bob Butsch, Schlumberger, 2012). Because the average logderived permeabilities (permKCal wireline from ELAN log) for most of the confining zone 

layers are at or below 0.01 mD, an alternate approach was applied. For each model layer the core 

data were reviewed, and a simple average of the available horizontal Klinkenburg permeabilities 

was then calculated for each layer. Core samples that were noted as having potential cracks 

and/or were very small were eliminated if the results appeared to be unreasonable based on the 

sampled lithology. If no core samples were available and the arithmetic mean of the PermKCal 

was below 0.01 mD, a default value of 0.01 mD was applied (Lombard9 is the only layer with a 

0.01-mD default value). Because the sandstone intervals of the Ironton-Galesville Sandstone 

have higher permeabilities that are similar in magnitude to the modeled injection zone layers, the 

Ironton-Galesville Sandstone model layer permeabilities were derived from the arithmetic mean 
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of the PermKCal permeability curve. Because no hydraulic test has been conducted in the 

primary confining zone and the Upper part of the injection zone (Elmhurst Sandstone layers and 

lower part of the Lombard – Lombard 1 to Lombard 5), the scaling factor was assigned to be 100 

percent in this interval and the overburden formations. Figure 5 shows the depth profile of the 

horizontal permeability assigned to each layer of the model and actual values assigned are listed 

in Table 1. Figure 6 shows the distribution of horizontal and vertical permeability as it was 

assigned to the numerical model layers. 

Because the anisotropy of the model layers is not likely to be represented by the sparse data from 

the stratigraphic well, the lithology-specific permeability anisotropy averages from literature 

studies representing larger sample sizes were used for the model layers (Table 2 and Table 3). 

Figure 5. Vertical Distribution of the Horizontal Permeability in the Model Layers at the Stratigraphic Well 

Location 
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(a) (b)

Figure 6. Permeability Assigned to Numerical Model 1) Horizontal Permeability; b) Vertical Permeability 
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Table 1. Summary of the Hydrologic Properties Assigned to Each Model Layer. Depths and Elevations Correspond to the Location of the Stratigraphic 

Well 

Simulation -

CM22

Model Layer

Top 

Depth 

(ft bgs)

Top 

Elevation 

(ft MSL)

Bottom 

Elevation

(ft MSL)

Thickness 

(ft) Porosity

Horizontal 

Permeability

(mD)

Vertical 

Permeability

(mD)

Grain 

Density 

(g/cm3)

Compresibility

(1/Pa)

Secondary 

Conf. Zone

Franconia 3072.00 -2453 -2625 172 0.0358 5.50E-06 3.85E-08 2.82 7.42E-10

Davis-Ironton3 3244.00 -2625 -2649 24 0.0367 6.26E-02 6.26E-03 2.73 3.71E-10

Davis-Ironton2 3268.00 -2649 -2673 24 0.0367 6.26E-02 6.26E-03 2.73 3.71E-10

Davis-Ironton1 3292.00 -2673 -2697 24 0.0218 1.25E+01 1.25E+00 2.73 3.71E-10

IrontonGalesville4 3316.00 -2697 -2725 28 0.0981 2.63E+01 1.05E+01 2.66 3.71E-10

IrontonGalesville3 3344.00 -2725 -2752 27 0.0981 2.63E+01 1.05E+01 2.66 3.71E-10

IrontonGalesville2 3371.00 -2752 -2779 27 0.0981 2.63E+01 1.05E+01 2.66 3.71E-10

IrontonGalesville1 3398.00 -2779 -2806 27 0.0981 2.63E+01 1.05E+01 2.66 3.71E-10

Primary Confining Zone

Proviso5 3425.00 -2806 -2877 71 0.0972 1.12E-03 1.12E-04 2.72 7.42E-10

Proviso4 3496.00 -2877 -2891 14 0.0786 5.50E-03 5.50E-04 2.72 7.42E-10

Proviso3 3510.00 -2891 -2916 25 0.0745 8.18E-02 5.73E-04 2.77 7.42E-10

Proviso2 3534.50 -2916 -2926 10 0.0431 1.08E-01 7.56E-04 2.77 7.42E-10

Proviso1 3544.50 -2926 -2963 38 0.0361 6.46E-04 4.52E-06 2.77 7.42E-10

Lombard14 3582.00 -2963 -3003 40 0.1754 5.26E-04 5.26E-05 2.68 7.42E-10

Lombard13 3622.00 -3003 -3038 35 0.0638 1.53E-01 1.53E-02 2.68 7.42E-10

Lombard12 3657.00 -3038 -3073 35 0.0638 1.53E-01 1.53E-02 2.68 7.42E-10

Lombard11 3692.00 -3073 -3084 11 0.0878 9.91E+00 9.91E-01 2.68 7.42E-10

Lombard10 3703.00 -3084 -3094 10 0.0851 1.66E+01 1.66E+00 2.68 7.42E-10

Lombard9 3713.00 -3094 -3121 27 0.0721 1.00E-02 1.00E-03 2.68 7.42E-10

Lombard8 3739.50 -3121 -3138 17 0.0663 2.13E-01 2.13E-02 2.68 7.42E-10

Lombard7 3756.50 -3138 -3145 8 0.0859 7.05E+01 7.05E+00 2.68 7.42E-10

Lombard6 3764.00 -3145 -3153 8 0.0459 1.31E+01 1.31E+00 2.68 7.42E-10
Area of Review and Corrective Action Plan for FutureGen Alliance Page B16 of 46

Permit Number: IL-137-6A-0001 (well #1) 

 

Table 1. (contd) 

Model Layer

Top 

Depth 

(ft bgs)

Top 

Elevation 

(ft MSL)

Bottom 

Elevation

(ft MSL)

Thickness 

(ft) Porosity

Horizontal 

Permeability

(mD)

Vertical 

Permeability

(mD)

Grain 

Density 

(g/cm3)

Compresibility

(1/Pa)

Injection Zone

Lombard5 3771.50 -3153 -3161 9 0.0760 4.24E+02 4.24E+01 2.68 7.42E-10

Lombard4 3780.00 -3161 -3181 20 0.0604 3.56E-02 3.56E-03 2.68 7.42E-10

Lombard3 3800.00 -3181 -3189 8 0.0799 5.19E+00 5.19E-01 2.68 7.42E-10

Lombard2 3807.50 -3189 -3194 5 0.0631 5.71E-01 5.71E-02 2.68 7.42E-10

Lombard1 3812.50 -3194 -3219 26 0.0900 1.77E+00 1.77E-01 2.68 7.42E-10

Elmhurst7 3838.00 -3219 -3229 10 0.1595 2.04E+01 8.17E+00 2.64 3.71E-10

Elmhurst6 3848.00 -3229 -3239 10 0.1981 1.84E+02 7.38E+01 2.64 3.71E-10

Elmhurst5 3858.00 -3239 -3249 10 0.0822 1.87E+00 1.87E-01 2.64 3.71E-10

Elmhurst4 3868.00 -3249 -3263 14 0.1105 4.97E+00 1.99E+00 2.64 3.71E-10

Elmhurst3 3882.00 -3263 -3267 4 0.0768 7.52E-01 7.52E-02 2.64 3.71E-10

Elmhurst2 3886.00 -3267 -3277 10 0.1291 1.63E+01 6.53E+00 2.64 3.71E-10

Elmhurst1 3896.00 -3277 -3289 12 0.0830 2.90E-01 2.90E-02 2.64 3.71E-10

MtSimon17 3908.00 -3289 -3315 26 0.1297 7.26E+00 2.91E+00 2.65 3.71E-10

MtSimon16 3934.00 -3315 -3322 7 0.1084 3.78E-01 3.78E-02 2.65 3.71E-10

MtSimon15 3941.00 -3322 -3335 13 0.1276 5.08E+00 2.03E+00 2.65 3.71E-10

MtSimon14 3954.00 -3335 -3355 20 0.1082 1.33E+00 5.33E-01 2.65 3.71E-10

MtSimon13 3974.00 -3355 -3383 28 0.1278 5.33E+00 2.13E+00 2.65 3.71E-10

MtSimon12 4002.00 -3383 -3404 21 0.1473 1.59E+01 6.34E+00 2.65 3.71E-10

MtSimon11 4023.00 -3404 -3427 23 0.2042 3.10E+02 1.55E+02 2.65 3.71E-10

MtSimon10 4046.00 -3427 -3449 22 0.1434 1.39E+01 4.18E+00 2.65 3.71E-10

MtSimon9 4068.00 -3449 -3471 22 0.1434 1.39E+01 4.18E+00 2.65 3.71E-10

MtSimon8 4090.00 -3471 -3495 24 0.1503 2.10E+01 6.29E+00 2.65 3.71E-10

MtSimon7 4114.00 -3495 -3518 23 0.1311 6.51E+00 1.95E+00 2.65 3.71E-10

MtSimon6 4137.00 -3518 -3549 31 0.1052 2.26E+00 6.78E-01 2.65 3.71E-10

MtSimon5 4168.00 -3549 -3588 39 0.1105 4.83E-02 4.83E-03 2.65 3.71E-10

MtSimon4 4207.00 -3588 -3627 39 0.1105 4.83E-02 4.83E-03 2.65 3.71E-10

MtSimon3 4246.00 -3627 -3657 30 0.1727 1.25E+01 1.25E+00 2.65 3.71E-10

MtSimon2 4276.00 -3657 -3717 60 0.1157 2.87E+00 2.87E-01 2.65 3.71E-10

MtSimon1 4336.00 -3717 -3799 82 0.1157 2.87E+00 2.87E-01 2.65 3.71E-10
Area of Review and Corrective Action Plan for FutureGen Alliance Page B17 of 46

Permit Number: IL-137-6A-0001 (Well #1) 

 

Table 2. Lithology-Specific Permeability Anisotropy Averages from Literature 

Facies or Lithology Kv/Kh Reference

1. Heterolithic, laminated shale/mudstone/siltstone/sandstone 0.1 Meyer and Krause (2006)

2. Herringbone cross-stratified sandstone. Strat dips to 18 degrees 0.4 Meyer and Krause (2006)

3. Paleo weathered sandstone (coastal flat) 0.4 Meyer and Krause (2006)

4. Accretionary channel bar sandstones with minor shale laminations 0.5 Ringrose et al. (2005); 

Meyer and Krause (2006)

6. Alluvial fan, alluvial braided stream plain to shallow marine 

sandstones, low clay content 0.3 Kerr et al. (1999)

7. Alluvial fan, alluvial plain sandstones, sheet floods, paleosols, 

higher clay content 0.1 Hornung and Aigner (1999)

8. Dolomite mudstone 0.007 Saller et al. (2004)
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Table 3. Summary of the Kv/Kh Ratios Applied to Model Layers 

Model Layer Kv/Kh Applied to 

Model Layers(a)*

Kv/Kh 

Determined 

from Core 

Pairs(b)

Successfully 

Analyzed Core 

Pairs

Franconia carbonate 0.007 ND ND

Davis-Ironton 0.1 ND ND

Ironton-Galesville 0.4 ND ND

Proviso (Layers 4 and 5) 0.1 ND ND

Proviso ([carbonate] Layers 1 

to 3)

0.007 ND ND

Lombard Total Interval 0.1 0.029 12

Lombard (Layer 7) 0.1 .098 2

Lombard (Layer 6) 0.1 0.003 2

Lombard (Layer 5) 0.1 ND ND

Lombard (Layer 4) 0.1 0.016 2

Lombard (Layer 3) 0.1 0.064 2

Lombard (Layer 2) 0.1 0.009 1

Lombard (Layer 1) 0.1 0.104 3

Elmhurst Total Interval 0.4 0.06 4

Elmhurst (Layer 7) 0.4 ND ND

Elmhurst (Layer 6) 0.4 0.023 1

Elmhurst (Layer 5) 0.1 ND ND

Elmhurst (Layer 4) 0.4 0.902 1

Elmhurst (Layer 3) 0.1 ND ND

Elmhurst (Layer 2) 0.4 0.022 1

Elmhurst (Layer 1) 0.1 0.037 1

Mt. Simon (Layer 17) 0.4 0.233 2

Mt. Simon (Layer 16) 0.1 ND ND

Mt. Simon (layer 13) 0.4 0.643 2

Mt. Simon (Layers 12, 14, and 

15)

0.4 ND ND

Mt. Simon (Layer 11, 

Injection) zone)

0.5 ND ND

Mt. Simon (Layers 6, 7, 8, 9, 

10)

0.3 ND ND

Mt. Simon (Layers 1, 2, 3, 4, 

5)

0.1 ND ND

(a) Value from literature, referenced in the Supporting Documentation of the UIC permit application

(b) Geometric mean of successful core pairs.
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Porosity

Total (or absolute) porosity is the ratio of void space to the volume of whole rock. Effective 

porosity is the ratio of interconnected void space to the volume of the whole rock. As a first step 

in assigning porosity values for the FutureGen 2.0 numerical model layers, Schlumberger ELAN 

porosity log results were compared with laboratory measurements of porosity as determined 

from SWC and core plugs for specific sampling depth within the Mount Simon. The 

Schlumberger ELAN porosity logs examined include PIGN (Gamma-Neutron Porosity), PHIT 

(Total Porosity), and PIGE (Effective Porosity). The PIGN and PIGE wireline log surveys use 

different algorithms to identify clay- or mineral-bound fluid/porosity in calculating an effective 

porosity value. SWC porosity measurements are listed as “total porosity,” but their measurement 

can be considered to be determinations of “effective porosity,” because the measurement 

technique (weight measurements of heated/oven-dried core samples) primarily measures the 

amount of “free” or connected pore liquid contained within the SWC sample as produced by the 

heating process. It should be noted that the SWC porosity measurements were determined under 

ambient pressure conditions. 

In Figure 2, neutron- and density-crossplot porosity is shown in the fourth panel, along with labmeasured porosity for core plugs and rotary SWC. An available porosity measurement data set 

for a conventional Mount Simon Sandstone core-plug sample taken near the top of the formation 

(depth of 3,912 ft bgs or elevation of -3,293 ft) indicates only minor changes in porosity for 

measurements taken over a wide range in pressure (i.e., ambient to 1,730 psi). This suggests that 

ambient SWC porosity measurements of the Mount Simon may be representative of in situ 

formation pore pressure conditions. The ELAN porosity log results generally underestimate the 

SWC porosity measured values. As a result of the poor visual correlation of the PIGE survey 

results with SWC measurements, this ELAN log was omitted from subsequent correlation 

evaluations. To aid in the correlations, the gamma ray survey log (GR) was used as a screening 

tool for development of linear-regression correlation relationships between ELAN log responses 

and SWC porosity measurements. This helps account for the shale or clay content that can cause 

the inclusion of “bound water” porosity. To assign model layer porosities, the regression model 

relationships used to calibrate the ELAN measurement results (Figure 7) were applied to the 

ELAN survey results over the formational depths represented by the Mount Simon (3,904 to 

4,416 ft bgs depth or -3,285 to -3,797 ft elevation) and overlying Eau Claire-Elmhurst member 

(3,838 to 3,904 ft bgs depth or -3,219 to -3,285 ft elevation) based on the gamma response 

criteria. The ELAN survey results are reported at 0.5-ft depth intervals. For stratigraphic units 

above the Elmhurst and/or depth intervals exhibiting gamma readings >64 API units, the uncalibrated, average ELAN log result for that depth interval was used. An average porosity was 

then assigned to the model layer based on the average of the calibrated ELAN values within the 

model layer depth range. Figure 8 shows the depth profile of the assigned model layer porosities 

based on the average of the calibrated ELAN values. The actual values assigned for each layer 

are listed in Table 1. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 7. Comparison of SWC Porosity Measurements and Regression-Calibrated ELAN Log Porosities: ≤64 

Gamma API Units 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 8. Vertical Distribution of Porosity in the Model Layers at the Stratigraphic Well Location 

Rock (Bulk) Density and Grain Density 

Grain density data were calculated from laboratory measurements of SWCs. The data were then 

averaged (arithmetic mean) for each main stratigraphic layer in the model. Only the Proviso 

member (Eau Claire Formation) has been divided in two sublayers to be consistent with the 

lithology changes. Figure 9 shows the calculated grain density with depth. The actual values 

assigned to each layer of the model are listed in Table 1. Grain density is the input parameter 

specified in the simulation input file, and STOMP-CO2 calculates the bulk density from the 

grain density and porosity for each model layer. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 9. Vertical Distribution of the Grain Density in the Model Layer at the Stratigraphic Well Location 

Formation Compressibility

Limited information about formation (pore) compressibility estimates is available. The best 

estimate for the Mount Simon Sandstone (Table 4) is that back-calculated by Birkholzer et al. 

(2008) from a pumping test at the Hudson Field natural-gas storage site, found 80 mi (129 km) 

northeast of the Morgan County CO2 storage site. The back-calculated pore-compressibility 

estimate for the Mount Simon Sandstone of 3.71E−10 Pa−1 was used as a spatially constant value 

for their basin-scale simulations. In other simulations, Birkholzer et al. (2008) assumed a porecompressibility value of 4.5E−10 Pa−1 for aquifers and 9.0E−10 Pa−1 for aquitards. Zhou et al. 

(2010) in a later publication used a pore-compressibility value of 7.42E−10 Pa−1

for both the Eau 

Claire Formation and Precambrian granite, which were also used for these initial simulations 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

(Table 4). Because the site-specific data are limited to a single reservoir sample, only these two 

published values have been used for the model. The first value (3.71E-10 Pa−1) has been used for 

sands that are compressible because of the presence of porosity. The second value (7.42E-10 

Pa−1) is assigned for all other rocks that are less compressible (dolomite, limestone, shale, and 

rhyolite). Table 1 lists the hydrologic parameters assigned to each model layer. 

Table 4. Formation Compressibility Values Selected from Available Sources 

Hydrogeologic Unit Formation (Pore) Compressibility, Pa-1

Franconia 7.42E-10 Pa1

Davis-Ironton 3.71E-10 Pa-1

Ironton-Galesville 3.71E-10 Pa-1

Eau Claire Formation (Lombard and Proviso) 7.42E-10 Pa-1

Eau Claire Formation (Elmhurst) 3.71E-10 Pa-1

Mount Simon Sandstone 3.71E-10 Pa-1

Constitutive Relationships 

Capillary Pressure and Saturation Functions

Capillary pressure is the pressure difference across the interface of two immiscible fluids (e.g., 

CO2 and water). The entry capillary pressure is the minimum pressure required for an immiscible 

non-wetting fluid (i.e., CO2) to overcome the capillary force and enter pore space containing the 

wetting fluid (i.e., saline formation water). Capillary pressure data determined from site-specific 

cores were not available at the time the model was constructed. However, tabulated capillary 

pressure data were available for several Mount Simon gas storage fields in the Illinois Basin. The 

data for the Manlove Hazen well (FutureGen Alliance 2006) were the most complete. Therefore, 

these aqueous saturation and capillary pressure values were plotted and a user-defined curve 

fitting was performed to generate Brooks-Corey parameters for four different permeabilities 

(Figure 10). These parameters were then assigned to layers based on a permeability range as 

shown in Table 5.
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 10. Aqueous Saturation Versus Capillary Pressure Based on Mercury Injection Data from the Hazen 

No. 5 Well at the Manlove Gas Field in Champagne County, Illinois 

Table 5. Permeability Ranges Used to Assign Brooks-Corey Parameters to Model Layers 

Permeability (mD) Psi Lambda ()

Residual Aqueous 

Saturation

< 41.16 4.116 0.83113 0.059705

41.16 to 231 1.573 0.62146 0.081005

231 to 912.47 1.450 1.1663 0.070762

> 912.47 1.008 1.3532 0.044002

The Brooks-Corey (1964) saturation function is given as 

where Sew is effective aqueous saturation, Pc is capillary pressure, Pe is gas entry pressure, and λ 

is the pore-size distribution parameter. Combined with the Burdine (1953) relative permeability 

model, the relative permeability for the aqueous phase, krw, and that for the non-aqueous phase, 

krn, are 

Values for the residual aqueous saturation (Srw) and the two other parameters used in the BrooksCorey capillary pressure-saturation function (i.e., the non-wetting fluid entry pressure and a 

pore-size distribution parameter) were all obtained by fitting mercury (Hg) intrusion-capillary 

pressure data from the Manlove gas storage site in Champaign County. The fitting was applied 

after scaling the capillary pressures to account for the differences in interfacial tensions and 

contact angles for the brine-CO2 fluid pair, relative to vapor-liquid Hg used in the measurements. 





 



otherwise

PP if PP

S

ce ec

ew 1

)/(



/23 

)(



rw

 SK ew )1()1(

2  /21 

rn ew

 SSK ew
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Permit Number: IL-137-6A-0001 (Well #1) 

 

This approach has the major advantage that the three fitted parameters are consistent as they are 

obtained from the same original data set. The use of consistent parameter values is not the norm 

for brine-CO2 flow simulations in the Mount Simon Sandstone. 

The Srw values used in the modeling (Table 2) are indeed lower than the values found in the 

literature. The FutureGen Alliance was aware of these differences but opted to use a consistent 

data set for all retention parameter values instead of selecting parameter values from different 

data sources. An additional reason for using this approach is the considerable uncertainty in Srw

values for Mt. Simon rock in the literature. In general, using a lower Srw value for the injection 

zone will possibly result in a somewhat smaller predicted CO2 plume size and a smaller spatial 

extent of the pressure front compared to using a higher value of Srw. Variation of Srw in the 

confining zone (cap rock) likely has relatively little impact on CO2 transport and pressure 

development owing to the typically much lower permeability of this zone relative to the 

underlying formation. 

Gas Entry Pressure 

No site-specific data were available for gas entry pressure; therefore, this parameter was 

estimated using the Davies (1991) developed empirical relationships between air entry pressure, 

Pe, and intrinsic permeability, k, for different types of rock: 

Pe = a kb

where Pe takes the units of MPa and k the units of m

2

, a and b are constants and are summarized 

below for shale, sandstone, and carbonate (Davies 1991; Table 3 ). The dolomite found at the 

Morgan County site is categorized as a carbonate. The Pe for the air-water system is further 

converted to that for the CO2-brine system by multiplying the interfacial tension ratio of a CO2-

brine system βcb to an air-water system βaw. An approximate value of 30 mN/m was used for βcb

and 72 mN/m for βaw.

Table 6. Values for Constants a and b for Different Lithologies 

Shale Sandstone Carbonate

a 7.60E-07 2.50E-07 8.70E-07

b -0.344 -0.369 -0.336

CO2 Entrapment

The entrapment option available in STOMP-CO2 was used to allow for entrapment of CO2 when 

the aqueous phase is on an imbibition path (i.e., increasing aqueous saturation). Gas saturation 

can be free or trapped: 

sg = 1 - sl = sgf + sgt

where the trapped gas is assumed to be in the form of aqueous occluded ganglia and immobile. 

The potential effective trapped gas saturation varies between zero and the effective maximum 

trapped gas saturation as a function of the historical minimum value of the apparent aqueous 

saturation. No site-specific data were available for the maximum trapped gas saturation, so this 

value was taken from the literature. Suekane et al. (2009) used micro-focused x-ray CT to image 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

a chip of Berea Sandstone to measure the distribution of trapped gas bubbles after injection of 

scCO2 and then water, under reservoir conditions. Based on results presented in the literature, a 

value of 0.2 was used in the model, representing the low end of measured values for the 

maximum trapped gas saturation in core samples. 

Formation Properties 

Fluid Pressure 

An initial fluid sampling event from the Mount Simon formation was conducted on December 

14, 2011, in the stratigraphic well during the course of conducting open-hole logging. Sampling 

was attempted at 22 discrete depths using the MDT tool in the Quicksilver Probe configuration 

and from one location using the conventional (dual-packer) configuration. Pressure data were 

obtained at 7 of the 23 attempted sampling points, including one duplicated measurement at a 

depth of 4,034 ft bgs or elevation of -3415 ft (Table 7). 

Figure 11 shows the available regional potentiometric surfaces for the Mount Simon Sandstone. 

The figure contains pre-development hydraulic head measurements (e.g., before widespread 

pumping from the Mount Simon Sandstone, particularly in Northern Illinois) and simulation 

results for predicting the post-development (i.e., 1980) potentiometric surface. As shown in 

Figure 11, data are sparse around the area of the FutureGen 2.0 Site, and it is situated in an area 

where the regional gradients are very low and the flow directions are not constrained (pre- or 

post-development). For these reasons, a regional horizontal flux for the Mount Simon Sandstone 

was not specified in the computational model.

Vertical flow potential at the FutureGen 2.0 Site was evaluated based on an analysis of discrete 

pressure/depth measurements obtained within the pilot characterization borehole over the depth 

interval of 1,134 to 4,249 ft bgs depth (-515 to -3,630 ft elevation). The results indicate that there 

is a positive head difference in the Mount Simon that ranges from 47.8 to 61.6 ft above the 

calculated St. Peter observed static hydraulic head condition (i.e., 491.1 ft above MSL). This 

positive head difference suggests a natural vertical flow potential from the Mount Simon to the 

overlying St. Peter if hydraulic communication is afforded (e.g., an open communicative well). It 

should also be noted, however, that the higher head within the unconsolidated Quaternary aquifer 

(~611 ft above MSL), indicates a downward vertical flow potential from this surficial aquifer to 

both the underlying St. Peter and Mount Simon bedrock aquifers. The disparity in the calculated 

hydraulic head measurements (together with the significant differences in formation fluid 

salinity) also suggests that groundwater within the St. Peter and Mount Simon bedrock aquifers 

is physically isolated from one another. This is an indication that there are no significant conduits 

(open well bores or fracturing) between these two formations and that the Eau Claire forms an 

effective confining layer. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 11. Approximate Pre-Development Potentiometric Surface (a) for the Mount Simon Aquifer (from 

Young 1992, modified from Mandel and Kontis 1992) and (b) Simulated 1980 Freshwater Head in 

the Mount Simon Aquifer showing Impact of Withdrawals in Northern portion of Illinois 

(Mandel and Kontis 1992) 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

Table 7. Pressure Data Obtained from the Mount Simon Formation Using the MDT Tool Where the 

Red Line Delimits the Samples Within the Injection Zone 

Sample Number Sample Depth (ft bgs) Absolute Pressure (psia)

7 4,116 1,828

8 4,117 1,827.7

9 4,096.5 1,818.3

11 4,034 1,790.2

17 4,034 (duplicated) 1,790.3

21 4,234.5 1,889.2

22 4,232 1,908.8

23 4,249 1,896.5(a)

(a) Sample affected by drilling fluids (not representative)

Temperature

The best fluid temperature depth profile was performed on February 9, 2012, as part of the static 

borehole flow meter/fluid temperature survey that was conducted prior to the constant-rate 

injection flow meter surveys. Two confirmatory discrete probe depth measurements that were 

taken prior to the active injection phase (using colder brine) corroborate the survey results. The 

discrete static measurement for the depth of 3,698 ft bgs (elevation of -3,079 ft) was 95.9°F. The 

second discrete static probe temperature measurement is from the MDT probe for the successful 

sampling interval of 4,034 ft bgs depth (elevation of -3,415 ft). A linear-regression 

temperature/depth relationship was developed for use by modeling. The regression data set 

analyzed was for temperature data over the depth interval of 1,286 to 4,533 ft bgs (elevation of -

667 to -3,914 ft). Based on this regression, a projected temperature for the reference datum at the 

top of the Mount Simon (3,904 ft bgs depth or -3,285 ft elevation) of 96.60°F is indicated. A 

slope (gradient) of 6.72 10-3 °F/ft and intercept of 70.27°F is also calculated from the regression 

analysis. 

Brine Density 

Although this parameter is determined by the simulator using pressure, temperature, and salinity, 

based on the upper and lower Mount Simon injection zone tests, the calculated in situ injection 

zone fluid density is 1.0315 g/cm3.

Salinity and Water Quality

During the process of drilling the well, fluid samples were obtained from discrete-depth intervals 

in the St. Peter Formation and the Mount Simon Formation using wireline-deployed sampling 

tools (MDTs) on December 14, 2011. After the well had been drilled, additional fluid samples 

were obtained from the open borehole section of the Mount Simon Formation by extensive 

pumping using a submersible pump. The assigned salinity value for the Mount Simon (upper 

zone) 47,500 ppm is as indicated by both the MDT sample (depth 4,034 ft bgs or elevation of -


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Permit Number: IL-137-6A-0001 (Well #1) 

 

3,415 ft) and the multiple samples collected during extensive composite pumping of the open 

borehole section. 

A total of 20 groundwater samples were collected between October 25 and November 10, 2011, 

including duplicate samples and blanks (Dey et al. in press as of 2013). General water-quality 

parameters were measured along with organic and major inorganic constituents. Values of pH 

ranged from 7.08 to 7.66. Values for specific conductance ranged from 545 to 1,164 μS/cm, with 

an average of 773 μS/cm. Values of Eh ranged from 105 to 532 mV with an average of 411 mV. 

Values of dissolved oxygen (DO) ranged from below detection limit to 3.3 mg/L O2. Most 

dissolved inorganic constituent concentrations are within primary and secondary drinking water 

standards. However, the constituent concentration in water is elevated with respect to iron (Fe), 

manganese (Mn), nitrate (NO3), and the total dissolved salt (TDS). In some cases these 

constituents exceed the U.S. Environmental Protection Agency (EPA) secondary standards. 

Fracture Pressure in the Injection Zone 

At the time the computational model was developed, no site-specific hydraulic fracturing tests 

had been conducted in the stratigraphic well and no site-specific fracture pressure values were 

available for the confining zone and the injection zone. Other approaches (listed below) have 

thus been chosen to determine an appropriate value for the fracture pressure. 

 Triaxial tests were conducted on eight samples from the stratigraphic well. Samples 3 to 

7 are located within the injection zone. Fracture gradients were estimated to range from 

0.647 to 0.682 psi/ft, which cannot directly be compared to the fracture pressure gradient 

required for the permit. Triaxial tests alone cannot provide accurate measurement of 

fracture pressure. 

 Existing regional values. Similar carbon storage projects elsewhere in Illinois (in Macon 

and Christian counties) provide data for fracture pressure in a comparable geological 

context. In Macon County (CCS#1 well at Decatur), about 65 mi east of the FutureGen 

2.0 Site, a fracture pressure gradient of 0.715 psi/ft was obtained at the base of the Mount 

Simon Sandstone Formation using a step-rate injection test (EPA 2011a). In Christian 

County, a “conservative” pressure gradient of 0.65 psi/ft was used for the same injection

zone (EPA 2011b). No site-specific data were available. 

 Last, the regulation relating to the “Determination of Maximum Injection Pressure for 

Class I Wells” in EPA Region 5 is based on the fracture closure pressure, which has been 

chosen to be 0.57 psi/ft for the Mount Simon Sandstone (EPA 1994). 

Based on these considerations, a fracture pressure gradient of 0.65 psi/ft was chosen. The EPA 

Geologic Sequestration Rule requires that “Except during stimulation, the owner or operator 

must ensure that injection pressure does not exceed 90 percent of the fracture pressure of the 

injection zone(s) so as to ensure that the injection does not initiate new fractures or propagate 

existing fractures in the injection zone(s)...” Therefore, a value of 0.585 psi/ft (90 percent of 

0.65 psi/ft) was used in the model to calculate the maximum injection pressure permitted. 
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Permit Number: IL-137-6A-0001 (Well #1) 

 

In November and December 2013, hydraulic tests were conducted in the Mount Simon 

Sandstone and in the Precambrian basement. The first results of these tests verify that the 

fracture gradient used in the model for the injection zone remains conservative and appropriate. 

Site Evaluation of Mineral Resources 

Other subsurface geochemical considerations include the potential for mineral or hydrocarbon 

resources beneath the proposed CO2 storage site. While no significant mineral deposits are 

known to exist within Morgan County, natural gas has been recovered in the region, including at 

the Prentice and Jacksonville fields located within several miles of the stratigraphic well. ISGS 

oil and gas website data indicate that the Prentice Field contained more than 25 wells drilled 

during the 1950s; re-exploration occurred in the 1980s. Both oil and gas have been produced 

from small stratigraphic traps in the shallow Pennsylvanian targets, at depths of 250 to 350 ft (75 

to 105 m) bgs. It is important to note that gas produced from these wells may contain around 16 

percent CO2 (Meents 1981). More than 75 wells have been drilled in the Jacksonville Field. Gas 

was discovered in the Jacksonville Field as early as 1890 (Bell 1927), but most oil and gas 

production from the Prentice and Jacksonville fields occurred between the late 1920s and late 

1980s. The most productive formations in the Illinois Basin (lower Pennsylvanian and 

Mississippian siliciclastics and Silurian reefs) are not present in Morgan County. Only two 

boreholes in the vicinity of the Prentice Field and five boreholes near the Jacksonville Field 

penetrate through the New Albany Shale into Devonian and Silurian limestone. Cumulative 

production from the Prentice and Jacksonville fields is not available, and both fields are largely 

abandoned. The Waverly Storage Field natural-gas storage site in the southeast corner of Morgan 

County originally produced oil from Silurian carbonates. This field no longer actively produces 

oil, but since 1954 it has been successfully used for natural-gas storage in the St. Peter and the 

Galesville/Ironton Sandstone formations (Buschbach and Bond 1974). 

The nearest active coal mine is approximately 10 mi (16 km) away in Menard County and does 

not penetrate more than 200 ft (61 m) bgs (ISGS 2012). A review of the known coal geology 

within a 5-mi (8-km) radius of the proposed drilling site indicates that the Pennsylvanian coals, 

the Herrin, Springfield, and Colchester coals, are very thin or are absent from the project area 

(ISGS 2010, 2011; Hatch and Affolter 2008). During continuous coring of a shallow 

groundwater monitoring well located immediately adjacent to the stratigraphic well, only a 

single thin (5-ft [1.5-m]) coal seam was encountered at about 200 ft (61 m) depth.

Initial Conditions 

The injection zone is assumed to be under hydrostatic conditions with no regional or local flow 

conditions. Therefore the hydrologic flow system is assumed to be at steady state until the start 

of injection. To achieve this with the STOMP-CO2 simulator one can either run an initial 

simulation (executed for a very long time period until steady-state conditions are achieved) to 

generate the initial distribution of pressure, temperature, and salinity conditions in the model 

from an initial guess, or one can specify the initial conditions at a reference depth using the 

hydrostatic option in the STOMP-CO2 input file, allowing the simulator to calculate and assign 

the initial conditions to all the model nodes. Site-specific data were available for pressure, 

temperature, and salinity, and therefore the hydrostatic option was used to assign initial 

conditions. A temperature gradient was specified based on the geothermal gradient, but the initial 
Area of Review and Corrective Action Plan for FutureGen Alliance Page B31 of 46

Permit Number: IL-137-6A-0001 (Well #1) 

 

salinity was considered to be constant for the entire domain. A summary of the initial conditions 

is presented in Table 8. 

Table 8. Summary of Initial Conditions 

Parameter Reference Depth (ft bgs) Elevation (ft) Value

Reservoir Pressure 4,034 -3,415 1,790.2 psi

Aqueous Saturation 1.0

Reservoir Temperature 3,904 -3,285 96.6 °F

Temperature Gradient 0.00672 °F/ft

Salinity 47,500 ppm

Boundary Conditions 

Boundary conditions were established with the assumption that the injection zone and confining 

zone are continuous throughout the region and that the underlying Precambrian unit is 

impermeable. Therefore, the bottom boundary was set as a no-flow boundary for aqueous fluids 

and for the CO2-rich phase. The lateral and top boundary conditions were set to hydrostatic 

pressure using the initial condition with the assumption that each of these boundaries is distant 

enough from the injection zone to have minimal to no effect on the CO2 plume migration and 

pressure distribution. 

Wells within the Survey Area 

A detailed survey was completed over a 25 mi2

(65 km2) area, termed the “Survey Area.” This 

area is centered on the proposed injection location (labeled as “Injection Site”) and encompasses 

the predicted maximum extent of the CO2 plume (Figure 12). Wells, surface bodies of water and 

other pertinent surface features, administrative boundaries, and roads within the Survey Area are 

shown in Figure 12. There are no subsurface cleanup sites, mines, quarries, or Tribal lands 

within this area. The Survey Area is near the center of the AoR (Figure 15). 

A total of 129 wells are located within the Survey Area. However, no well but the FutureGen 

Alliance’s stratigraphic well penetrates the injection zone (Mount Simon Sandstone and the 

lower Eau Claire [Elmhurst Sandstone Member and lower portion of the Lombard Member]), the 

confining zone (Upper portion of Lombard Member and Proviso Member of the Eau Claire 

Formation), or the secondary confining zone (Franconia Dolomite). 

Shallow domestic water wells with depths of less than 50 ft (15 m) are the most common well 

type within the Survey Area. Five slightly deeper water wells were identified that range in 

depths from 110 ft (33 m) to 405 ft (123 m). Other wells include stratigraphic test holes, coal 

test holes, and oil and gas wells. 

Twenty four of the 129 wells in the Survey Area are identified with only a general location 

(center of a section) in the ISWS database. These wells are included in Table 9 but are not shown 

on the map. 

A general survey of the AoR outside the Survey Area was conducted by reference of publicly 

available information. Maps of existing water wells, oil and gas wells, miscellaneous wells, coal 

mines, surface water, and geologic structures were submitted to complete the permit 

requirements. 
Area of Review and Corrective Action Plan for FutureGen Alliance Page B32 of 46

Permit Number: IL-137-6A-0001 (Well #1) 

 

There are 4,386 water wells and 740 oil and gas wells within the AoR, but only two of these 

penetrate the confining zone. These two wells identified in the AoR are approximately 16 miles 

from the injection site, but they are adequately plugged.
Area of Review and Corrective Action Plan for FutureGen Alliance Page B33 of 46

Permit Number: IL-137-6A-0001 (well #1) 

 

Table 9. List of Wells Located Within the Survey Area 

Map ID API Number ISWS ID

Latitude 

NAD1983

Longitude 

NAD1983

Public Land Survey 

System

Total 

Depth ft

Elev 

ft

Completion 

Date Owner

Well 

Num Well Type Status

Confining Zone 

Penetration 

Well

0 121372213200 39.806064 -90.052919 T16n,R9w,Sec 25 4812 633 TBD FutureGen Industrial Alliance, Inc. 1 Monitoring Active Yes

1 121372118200 116519 39.778074 -90.078443 T15N,R9W,Sec 2 25 19780712 A.A. Negus Estate 1 Water Private Water Well No

4 121370018700 115778 39.811025 -90.065241 T16N,R9W,Sec 25 115 Beilschmidt, William H. Water No

8 121370028500 115740 39.800661 -90.078386 T16N,R9W,Sec 26 127 1950 Martin, L. E. 1 Water No

9 115741 39.800661 -90.078386 T16N,R9W,Sec 26 127 Martin, L. E. Water No

10 121372128600 115779 39.801129 -90.07342 T16N,R9W,Sec 26 25 19781213 Martin, Marvin & Jean 1 Water Private Water Well No

14 115763 39.792894 -90.078875 T16N,R9W,Sec 35 28 E Clemons Water No

15 115764 39.792894 -90.078875 T16N,R9W,Sec 35 25 B Sister Water No

16 115765 39.792837 -90.060294 T16N,R9W,Sec 36 35 J M Dunlap Water No

17 121370051100 39.792893 -90.078984 T16N,R9W,Sec 35 1056 643 O'Rear, Judge 1 Oil & Gas / Water No

18 121370009900 39.808545 -90.06614 T16N,R9W,Sec 25 1530 630 19391001 Beilschmidt, Wm. 1 Oil & Gas Dry and Abandoned, No Shows No

19 121370023500 39.779153 -90.077325 T15N,R9W,Sec 2 338 644 19231101 Conklin 1 Oil & Gas Dry and Abandoned, No Shows No

20 121370023600 39.781298 -90.075082 T15N,R9W,Sec 2 348 646 19231101 Conklin 2 Oil & Gas Dry and Abandoned, No Shows No

21 121370023700 39.778057 -90.080754 T15N,R9W,Sec 3 342 645 19231001 Harris, A. J. 1 Oil & Gas Gas Producer No

22 121370023900 39.7779 -90.080756 T15N,R9W,Sec 3 334 644 19231107 Harris, A. J. 3 Oil & Gas Gas Producer No

25 121370036300 39.805251 -90.075597 T16N,R9W,Sec 26 1205 19670330 Martin 1 Oil & Gas Dry and Abandoned, No Shows No

26 121370036301 39.805251 -90.075597 T16N,R9W,Sec 26 1400 19731029 Martin 1 Oil & Gas Junked and Abandoned, Plugged No

27 121372088500 39.800861 -90.073017 T16N,R9W,Sec 26 302 630 Coal Test No

115735 39.807386 -90.060378 T16N,R9W,Sec 25 27 Beilschmidt, William H. Water No

115736 39.807386 -90.060378 T16N,R9W,Sec 25 30 W R Fowler Water No

115737 39.807386 -90.060378 T16N,R9W,Sec 25 28 Mason Water No

115739 39.807478 -90.079049 T16N,R9W,Sec 26 25 C H Matin Water No

115738 39.807478 -90.079049 T16N,R9W,Sec 26 22 T Gondall Water No

115650 39.807193 -90.041413 T16N,R8W,Sec 30 19 1930 R Allison Water No

115651 39.792765 -90.041512 T16N,R8W,Sec 31 28 W J Huston Water No

115652 39.792765 -90.041512 T16N,R8W,Sec 31 28 E Robinson Water No

116450 39.777005 -90.052023 T15N,R9W,Sec 1 25 A Harris Water No

116453 39.776968 -90.070521 T15N,R9W,Sec 2 32 A Harris Water No

116451 39.776968 -90.070521 T15N,R9W,Sec 2 22 W R Conklin Water No

116452 39.776968 -90.070521 T15N,R9W,Sec 2 30 B Negus Water No

116454 39.77688 -90.088996 T15N,R9W,Sec 3 28 C Negus Water No

116455 39.77688 -90.088996 T15N,R9W,Sec 3 30 L B Trotter Water No

115727 39.821881 -90.078925 T16N,R9W,Sec 23 30 D Flinn Water No

115728 39.821881 -90.078925 T16N,R9W,Sec 23 30 Hazel Dell School Water No

115729 39.821881 -90.078925 T16N,R9W,Sec 23 35 K Haneline Water No

115733 39.821811 -90.060168 T16N,R9W,Sec 24 30 J L Icenagle Water No

115734 39.821811 -90.060168 T16N,R9W,Sec 24 30 G Lewis Water No

115775 39.821811 -90.060168 T16N,R9W,Sec 24 200 1944 E C Lewis Water No

115742 39.807531 -90.097566 T16N,R9W,Sec 27 23 J Stewart Water No

115743 39.807531 -90.097566 T16N,R9W,Sec 27 23 l J Stewart Water No

115761 39.792917 -90.097513 T16N,R9W,Sec 34 28 T Harrison Water No

115762 39.792917 -90.097513 T16N,R9W,Sec 34 30 J Mahon Water No
Area of Review and Corrective Action Plan for FutureGen Alliance Page B34 of 46

Permit Number: IL-137-6A-0001 (well #1) 

 

Map ID API Number ISWS ID

Latitude

(NAD 83)

Longitude

(NAD 83)

Public Land Survey 

System

(PLSS)

Total 

Depth 

(ft)

Elevation 

(ft)

Completion 

Date Owner Well # Well Type Status

Confining 

Zone 

Penetration 

Well

2 121372155200 237387 39.815638 -90.084967 T16N,R9W,Sec 23 41 19920313 Nickel, Gerald 1 Water Private Water Well No

3 121372182100 300966 39.815638 -90.084967 T16N,R9W,Sec 23 46 19971104 Nickel, Gerald & Diane 1 Water Private Water Well No

13 121372173400 297871 39.811987 -90.07805 T16N,R9W,Sec 26 37 19960213 Keltner, Dale Water Private Water Well No

23 121370024000 39.780186 -90.094859 T15N,R9W,Sec 3 402 642 19230101 Trotter, L.B. 1 Oil & Gas Dry and Abandoned, No Shows No

24 121372097800 39.776078 -90.080727 T15N,R9W,Sec 3 327 632 0 Harris Unknown / other Unknown, Plugged No

28 115642 39.82166 -90.041238 T16N,R8W,Sec 19 25 1870 W W Robertson Water No

38 116456 39.776761 -90.107843 T15N,R9W,Sec 4 30 Rayburn Water No

39 116457 39.776761 -90.107843 T15N,R9W,Sec 4 32 Greene Water No

40 115725 39.821959 -90.097446 T16N,R9W,Sec 22 18 K Brown Water No

41 115726 39.821959 -90.097446 T16N,R9W,Sec 22 30 E C Trotter Water No

52 115640 39.836203 -90.022343 T16N,R8W,Sec 17 25 J H Hubbs Water No

53 115641 39.83617 -90.041154 T16N,R8W,Sec 18 32 1850 H Robinson Water No

54 115643 39.821671 -90.022214 T16N,R8W,Sec 20 26 1900 S Weinfeldt Water No

55 115644 39.821671 -90.022214 T16N,R8W,Sec 20 30 1904 Robinson Water No

56 115649 39.807149 -90.022402 T16N,R8W,Sec 29 26 M Walbaum Water No

57 115653 39.793 -90.022 T16N,R8W,Sec 32 18 Beggs Water No

58 121372070800 116522 39.77156 -90.0878 T15N,R9W,Sec 3 50 19770320 Linebarger, David Water No

59 121372118300 116520 39.769673 -90.080523 T15N,R9W,Sec 3 42 Harris, Frank R. Water Private Water Well No

60 121372070700 116521 39.769673 -90.080523 T15N,R9W,Sec 3 40 harris F R Water No

61 116458 39.777 -90.126 T15N,R9W,Sec 5 30 Gary S. B. Water No

62 116464 39.761 -90.126 T15N,R9W,Sec 8 30 Cleray W Water No

63 116465 39.761 -90.126 T15N,R9W,Sec 8 40 Coons A Water No

64 116466 39.761 -90.107 T15N,R9W,Sec 9 30 Wallbaum W M Water No

65 116467 39.761 -90.107 T15N,R9W,Sec 9 35 Trotter l B Water No

66 227314 39.761 -90.107 T15N,R9W,Sec 9 40 Carl Shinnall #1 Water No

67 116468 39.761 -90.089 T15N,R9W,Sec 10 30 Orear R Water No

68 121372070900 116525 39.765755 -90.080645 T15N,R9W,Sec 10 40 Linebarger D Water No

69 116469 39.761 -90.07 T15N,R9W,Sec 11 30 Collins W Water No

70 116470 39.761 -90.07 T15N,R9W,Sec 11 32 Lockhart G Water No

71 116393 39.776799 -90.032936 T15N,R8W,Sec 6 25 1923 Water No

72 116394 39.776799 -90.032936 T15N,R8W,Sec 6 28 C Smith Water No

73 121372116800 116436 39.784526 -90.041604 T15N,R8W,Sec 6 54 19770226 Becker, Carl J. 1 Water Livestock Watering Well No

74 121372116900 116435 39.784526 -90.041604 T15N,R8W,Sec 6 43 19781010 Becker, Carl J. 1 Water Private Water Well No

75 121372117000 116434 39.782453 -90.041567 T15N,R8W,Sec 6 27 19761213 Smith, Lloyd E. 1 Water Livestock Watering Well No

76 121372161900 39.766277 -90.041266 T15N,R8W,Sec 7 26 Walpole, Ron Water No

77 116395 39.763 -90.033 T15N,R8W,Sec 7 30 Water No

78 115696 39.836221 -90.059875 T16N,R9W,Sec 13 25 V R Mc Clure Water No
Area of Review and Corrective Action Plan for FutureGen Alliance Page B35 of 46

Permit Number: IL-137-6A-0001 (well #1) 

 

Map ID API Number ISWS ID

Latitude

(NAD 83)

Longitude

(NAD 83)

Public Land Survey 

System (PLSS)

Total 

Depth 

(ft)

Elevation 

(ft)

Completion 

Date Owner Well # Well Type Status

Confining 

Zone 

Penetration 

Well

79 115697 39.836221 -90.059875 T16N,R9W,Sec 13 27 U B Fox Water No

80 115698 39.836221 -90.059875 T16N,R9W,Sec 13 27 G W Lewis Water No

81 115699 39.836362 -90.078662 T16N,R9W,Sec 14 30 J Parrat Water No

82 115700 39.836362 -90.078662 T16N,R9W,Sec 14 28 C W Lewis Water No

83 115701 39.836362 -90.078662 T16N,R9W,Sec 14 28 J W Parrat Water No

84 115702 39.836362 -90.078662 T16N,R9W,Sec 14 32 J Hodgeson Water No

85 121372203900 356742 39.830101 -90.102984 T16N,R9W,Sec 15 47 20030910 Lomar Hager Construction Water Private Water Well No

86 115703 39.836486 -90.097369 T16N,R9W,Sec 15 24 G Noulty Water No

87 115704 39.836486 -90.097369 T16N,R9W,Sec 15 30 L Lamkaular Water No

88 115705 39.836486 -90.097369 T16N,R9W,Sec 15 35 E E Hart Water No

89 115706 39.8365 -90.116151 T16N,R9W,Sec 16 23 S Jumper Water No

90 115707 39.8365 -90.116151 T16N,R9W,Sec 16 25 H Wester Water No

91 115722 39.821967 -90.116263 T16N,R9W,Sec 21 30 T J Ward Water No

92 115724 39.821967 -90.116263 T16N,R9W,Sec 21 30 C Trotter Water No

93 216249 39.821967 -90.116263 T16N,R9W,Sec 21 28 1934 Wm Noulty Water No

94 121370028400 39.822767 -90.073164 T16N,R9W,Sec 23 405 19540301 Keltner 1 Water No

95 121372155100 237377 39.820978 -90.077895 T16N,R9W,Sec 23 42 19920414 Allen, John D. 1 Water Private Water Well No

96 121372207600 365042 39.822764 -90.075515 T16N,R9W,Sec 23 46 20040715 Burton, Larry Water Private Water Well No

97 121372128400 115776 39.826288 -90.058992 T16N,R9W,Sec 24 40 19760220 Robinson, Leroy A. 1 Water Private Water Well No

98 121372128500 115777 39.828869 -90.059535 T16N,R9W,Sec 24 37 19781214 Romine, Buddy 1 Water Private Water Well No

99 121372211600 420169 39.813876 -90.103667 T16N,R9W,Sec 27 35 20060809 Donnan, Jeff Water Private Water Well No

100 115744 39.807541 -90.116512 T16N,R9W,Sec 28 110 Noah B Fox Water No

101 115745 39.807541 -90.116512 T16N,R9W,Sec 28 28 Noah B Fox Water No

102 115746 39.807541 -90.116512 T16N,R9W,Sec 28 30 C Holdbrook Water No

103 115723 39.807541 -90.116512 T16N,R9W,Sec 28 28 W Noulty Water No

104 121372203000 348692 39.806645 -90.122622 T16N,R9W,Sec 28 42 Kendra Swain Water No

105 115759 39.792956 -90.116724 T16N,R9W,Sec 33 30 H Swain Water No

106 115760 39.792956 -90.116724 T16N,R9W,Sec 33 28 L L Hart Water No

107 121372155000 39.822856 -90.119949 T16N,R9W,Sec 21 Spradlin, Jack Water No

108 121370011400 39.833775 -90.10777 T16N,R9W,Sec 16 385 616 19551101 Wolfe, Eliz 1 Oil & Gas Dry and Abandoned, No Shows, Plugged No

109 121370011500 39.80091 -90.040421 T16N,R8W,Sec 30 420 635 19560101 Beilschmidt 1 Oil & Gas Dry and Abandoned, No Shows, Plugged No

110 121370011600 39.815108 -90.028322 T16N,R8W,Sec 20 365 610 19551201 Robinson, Howard 1 Oil & Gas Dry and Abandoned, No Shows, Plugged No

111 121370018900 39.825408 -90.062536 T16N,R9W,Sec 24 200 19440101 Lewis, E. C. Oil & Gas Dry Hole No

112 121370024100 39.769077 -90.111454 T15N,R9W,Sec 4 580 Rayborn 1 Oil & Gas Gas Producer No

113 121370044200 39.770193 -90.110273 T15N,R9W,Sec 4 350 Rayburn 1 Oil & Gas Gas Producer No

114 121372086900 39.769679 -90.098565 T15N,R9W,Sec 4 301 Coal Test No

115 121370024200 39.778927 -90.119618 T15N,R9W,Sec 5 423 Green, Laura & Effie 1 Oil & Gas Gas Producer No

116 121370024600 39.764523 -90.098492 T15N,R9W,Sec 9 293 Baxter 2 Oil & Gas Dry and Abandoned, Gas Shows No

117 121372094800 39.767065 -90.11144 T15N,R9W,Sec 9 325 Beilschmidt 1 Oil&Gas Temporarily Abandoned No

118 121372105200 39.763524 -90.104346 T15N,R9W,Sec 9 Leinberger 2 Oil&Gas Permit to Drill Issued No

119 121370007900 39.766464 -90.091366 T15N,R9W,Sec 10 295 Dunlap 8 Oil & Gas Gas Producer No

120 121372084800 39.766422 -90.065678 T15N,R9W,Sec 11 243 Coal Test No

121 121370030900 39.806625 -90.105838 T16N,R9W,Sec 27 324 610 19591001 Fox, Lyman 1 Oil & Gas Dry and Abandoned, No Shows, Plugged No

122 121370033200 39.788212 -90.03349 T16N,R8W,Sec 31 323 641 19271001 Corrington 1 Oil & Gas Dry and Abandoned, No Shows No
Area of Review and Corrective Action Plan for FutureGen Alliance Page B36 of 46

Permit Number: IL-137-6A-0001 (well #1) 

 

Map ID API Number ISWS ID

Latitude

(NAD 83)

Longitude

(NAD 83)

Public Land Survey 

System (PLSS)

Total 

Depth 

(ft)

Elevation 

(ft)

Completion 

Date Owner Well # Well Type Status

Confining 

Zone 

Penetration 

Well

123 121370062300 39.828772 -90.06935 T16N,R9W,Sec 24 814 624 19700701 #MA-3 Stratigraphic or 

Structure Test

Structure Test, Plugged No

124 121372068000 39.792709 -90.039363 T16N,R8W,Sec 31 142 641 19700518 Flynn, Robert Coal Test No

125 121372088400 39.829096 -90.098826 T16N,R9W,Sec 22 318 621 0 Coal Test No

126 121372088600 39.801122 -90.108499 T16N,R9W,Sec 28 301 621 0 Coal Test No

127 121372067800 39.814431 -90.023514 T16N,R8W,Sec 20 130 610 19700507 Newberry, Lucille Coal Test No

128 121372086000 39.83138 -90.055009 T16N,R9W,Sec 13 301 619 0 Coal Test No
Area of Review and Corrective Action Plan for FutureGen Alliance Page B37 of 46 

Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 12. Wells Located Within the Survey Area 
Area of Review and Corrective Action Plan for FutureGen Alliance Page B38 of 46 

Permit Number: IL-137-6A-0001 (Well #1) 

 

Proposed Operating Data (Operational Information) 

Figure 13 and Figure 14 show the well design for the representative case for the refined area of 

the model domain in plan view, in 3D view, and in cross section view, respectively. Injection 

into four lateral wells with a well-bore radius of 4.5 in. was modeled with the lateral leg of each 

well located within the best layer of the injection zone to maximize injectivity. Only the noncased open sections of the wells are specified in the model input file because only those sections 

are delivering CO2 to the formation. The well design modeled in this case is the open borehole 

design 6, therefore part of the curved portion of each well is open and thereby represented in the 

model in addition to the lateral legs. The orientation and lateral length of the wells, as well as 

CO2 mass injection rates, were chosen so that the resulting modeled CO2 plume would avoid 

sensitive areas. The coordinates of the screened portion of the injection wells are shown in Table 

10. The injection rate was assigned to each well according to the values in Table 11 for a total 

injection rate of 1.1 MMT/yr for 20 years. A maximum injection pressure of 2,252.3 psi (2,237.6 

psig) was assigned at the top of the open interval (depth of 3,850 ft bgs or an elevation of -3,220

ft), based on 90 percent of the fracture gradient described in Section 3.5 (0.65 psi/ft).

3D View Plan View

Figure 13. Operational Well Design for Representative Case Scenario as Implemented in the 

Numerical Model (with lateral legs of the injection wells shown in red and the cross section 

lines shown in yellow) 

 

 

6

 Despite the models use of an open-hole design, the actual proposed construction is a cased hole with perforations. 
Area of Review and Corrective Action Plan for FutureGen Alliance Page B39 of 46 

Permit Number: IL-137-6A-0001 (Well #1) 

 

Figure 14. Cross Sections of CO2 Injection Wells

Table 10. Coordinates (NAD1983 UTM Zone 16N) of Open Portions of the Injection Wells 

Coordinate 1(ft) Coordinate 2(ft) Coordinate 3(ft) Coordinate 4(ft)

x y z x y z x y z x y z

Well1 777079 14468885 -3220 777263 14468901 -3330 777592 14468929 -3387 779086 14469060 -3394

Well2 776898 14468571 -3220 776976 14468404 -3330 777116 14468105 -3388 778172 14465839 -3396

Well3 776617 14468578 -3220 776530 14468416 -3330 776375 14468124 -3382 775202 14465917 -3377

Well4 776451 14468829 -3220 776267 14468813 -3330 775938 14468785 -3377 774444 14468654 -3368
Area of Review and Corrective Action Plan for FutureGen Alliance Page B40 of 46 

Permit Number: IL-137-6A-0001 (Well #1) 

 

Table 11. Mass Rate of CO2 Injection for Each of the Four Lateral Injection Wells 

Well Length of Lateral leg (ft) Mass Rate of CO2 Injection (MMT/yr)

Injection well #1 1,500 0.2063

Injection well #2 2,500 0.3541

Injection well #3 2,500 0.3541

Injection well #4 1,500 0.1856

Computational Modeling Results

At the end of the simulation period, 100 years, most of the CO2 mass occurs in the CO2 -rich (or 

separate) phase, with 20 percent occurring in the dissolved phase. Note that residual trapping 

begins to take place once injection ceases, resulting in about 15 percent of the total CO2 mass 

being immobile at the end of 100 years. The CO2 plume forms a cloverleaf pattern as a result of 

the four lateral injection-well design. The plume grows both laterally and vertically as injection 

continues. Most of the CO2 resides in the Mount Simon Sandstone. A small amount of CO2

enters into the Elmhurst and the lower part of the Lombard. When injection ceases at 20 years, 

the lateral growth becomes negligible but the plume continues to move slowly, primarily 

upward. Once CO2 reaches the low-permeability zone in the upper Mount Simon it begins to 

move laterally. There is no CO2 entering the confining zone. The maximum extent of the CO2

plume, at 22 years, is in the center of Figure 15. 

Pressure Front Delineation

As shown in Figure 16, the calculated hydraulic heads from the pressures and fluid densities 

measured in the Mount Simon Sandstone during drilling of the stratigraphic well range from 47.8 

to 61.6 ft higher than the calculated hydraulic head in the lowermost USDW (St. Peter 

Sandstone). Based on these measurements, it was expected that the equation 1 suggested in the 

EPA AoR Guidance document (EPA 2013) for determination of the pressure front AoR would 

not be applicable for the FutureGen 2.0 Site since it would be in the “over-pressured” category. 

Thus alternative methods for assessment of the impacts of the pressure front would be needed for 

the “over-pressured” case at the FutureGen 2.0 Site. 
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Figure 15. FutureGen Area of Review inclusive of the CO2 plume and the area of elevated pressure 

delineated as the 10 psi contour at 60 years 
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Figure 16. Observed Hydraulic Head Comparison between the Unconsolidated Quaternary Aquifer, St. Peter 

Sandstone, and Mount Simon Sandstone within the FutureGen Stratigraphic Well 

Alternative approaches considered for delineation of an AoR inclusive of an area of elevated 

pressure 

The FutureGen Alliance considered the applicability of and evaluated the project using an 

analytical solution (Cihan et al., 2011; 2013) and a range of other approaches (Table 13). The 

objective of these analyses was to assess, calculate, and account for critical pressure, which is the 

pressure great enough to mobilize fluids up an open conduit (i.e., an artificial penetration, fault, 

or fracture) from the injection zone into the overlying USDW. Methods evaluated are presented 

in Table 13. 

Table 13. Methods Evaluated for Pressure Front Delineation

Approach Results

AoR Guidance Equation 1 Not applicable

Nicot (2008) 13.76 psi

Birkholzer (2011) 9.65 psi

Cihan (2011): Assuming thief zones Plume-sized AoR

Cihan (2011) Conservative: Assuming no thief zones Large AoR
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Pressure delineated AoR 

Each of the pressure front analysis methodologies evaluated by the FutureGen Alliance (Table 

13) are mathematical approximations applicable under prescribed conditions and subjected to 

simplifying assumptions. The simplified critical pressure calculations based on the open conduit 

concept are not applicable under site conditions because the ambient conditions in the lowermost 

USDW at the FutureGen site are under-pressured relative to the reservoir. Although the open 

conduit approaches are not strictly applicable under FutureGen site conditions, results from these 

conservative and protective approaches were used by EPA to delineate the pressure front AoR as 

the maximum extent of the 10 psi contour of pressure differential during the life of the project, 

which occurs 60 years after injection commences and is shown in Figure 15.

Corrective Action Plan and Schedule 

No wells have been identified within the AoR that require corrective action. 

Area of Review Reevaluation Plan and Schedule 

Reevaluation Cycle 

The FutureGen Alliance will reevaluate the AoR on an annual basis for the first 5 years 

following the initiation of injection operations (Figure 17). After the fifth year of injection, the 

AoR will be updated at a minimum of every 5 years as required by 40 CFR 146.84(b)(2)(i). An 

annual reevaluation in the first 5 years is intended to account for any operational variation during 

the startup period. 

Some conditions will warrant reevaluation prior to the next scheduled cycle. To meet the intent 

of the regulations and protect USDWs, the following six conditions will warrant reevaluation of 

the AoR: 

1. 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. 

Action: The computational model will be calibrated to match measured pressures. Model 

outputs that calculate the change in AoR will be provided to EPA. 

2. 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) within the Ironton 

Formation immediately above the confining zone (ACZ1 and ACZ2 wells). The Student’s ttest statistical procedure will be used to compare background (baseline) with observed 
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results. The Testing and Monitoring Plan provides extended information regarding how 

pressure, temperature, and fluid conductivity will be monitored within the Ironton Formation. 

Action: In the event that hydrochemical/physical parameter trends suggest that leakage may 

be occurring, either the computational model or other models will be used to understand the 

observational parameter behavior. 

3. 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. 

Action: Injection wells suspected of mechanical integrity issues will be shut down and the 

cause of the pressure deviation determined. Mechanical integrity testing will be conducted 

and the computational model will be updated with mechanical integrity results to determine 

the severity and extent of the loss of containment. The Testing and Monitoring Plan provides 

extended information about the mechanical integrity tests that will be conducted in the 

injection wells. 

4. Departure in Anticipated Surface Deformation Conditions: Surface deformation 

measurements that indicate an asymmetric or otherwise heterogeneous evolution of the 

injection zone pressure front, resulting in larger than predicted surface deformation outside 

the CO2 plume. Areal surface deformation will be monitored using several technologies 

including differential synthetic aperture radar interferometry (DInSAR), which is a radarbased method that can measure very small changes in ground-surface elevation linked to 

pressure variations at depth. The area surveyed will extend beyond the predicted maximum 

extent of the CO2 plume. If a measurable rise in the ground surface occurs outside the 

predicted extent, the AoR will be re-evaluated. The Testing and Monitoring Plan provides 

extended information about surface deformation monitoring. 

Action: The computational model will be calibrated to match observed pressures if they vary 

from the predicted deformation/pressure calculations. 

5. Seismic Monitoring Identification of Subsurface Structural Features: Seismic 

monitoring data indicate the possible presence of a fault or fracture near the CO2 injection 

zone in the sedimentary cover or in the basement (concentration of microearthquakes of 

M<<1 in elongated clusters). The Testing and Monitoring Plan provides extended 

information about the microseismic monitoring network. 

Action: The cause of the indicated microseismicity patterns will be evaluated. In 

conjunction, various operational parameters will be tested using the computational model to 

determine if the microseismic activity can be controlled to acceptable levels 

6. Seismic Monitoring Identification of Unexpected Plume Pattern: Seismic monitoring 

data indicate a CO2 plume migration outside the predicted extent. The observation of 

microearthquakes (M<<1) may also help define the actual shape of the maximum pressure 

field associated with the plume extensions. 
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Action: The computational model will be calibrated to match the location of observed 

microseismicity patterns indicative of plume extensions. 

7. Other triggers for reevaluation may include: facility operating changes; new injection 

activities or other deep wells added in the AoR; new owner/operators; new site 

characterization data; a seismic event or other emergency; and unexpected changes in rate, 

direction, and extent of plume/pressure front movement.

Reevaluation Strategy 

If any of these conditions occurs, the FutureGen Alliance will reevaluate the AoR to comply with 

requirements at 40 CFR 146.84 as described below. Ongoing direct and indirect monitoring data, 

which provide relevant information for understanding the development and evolution of the CO2

plume, will be used to support reevaluation of the AoR. These data include: 1) the chemical and 

physical characteristics of the CO2 injection stream based on sampling and analysis; 

2) continuous monitoring of injection mass flow rate, pressure, temperature, and fluid volume; 

3) measurements of pressure response at all site monitoring wells; and 4) CO2 arrival and 

transport response at all site monitoring wells based on direct aqueous measurements and 

selected indirect monitoring method(s). The FutureGen Alliance will compare these 

observational data with predicted responses from the computational model and if significant 

discrepancies between the observed and predicted responses exist, the monitoring data will be 

used to recalibrate the model (Figure 17). In cases where the observed monitoring data agree 

with model predictions, an AoR reevaluation will consist of a demonstration that monitoring data 

are consistent with modeled predictions. As additional characterization data are collected, the site 

conceptual model will be revised and the modeling steps described above will be repeated to 

incorporate new knowledge about the site. 

The FutureGen Alliance will submit a report notifying the UIC Program Director of the results of 

this reevaluation within 90 days of detection. At that time, the FutureGen Alliance will either: 

1) submit the monitoring data and modeling results to demonstrate that no adjustment to the AoR 

is required; or 2) modify its Corrective Action, Emergency and Remedial Response, and other 

plans to account for the revised AoR. All modeling inputs and data used to support AoR 

reevaluations will be retained by the FutureGen Alliance for the period of the project. 

To the extent that the reevaluated AoR is different from the one identified in this supporting 

documentation, the FutureGen Alliance will identify all active and abandoned wells and 

underground mines that penetrate the confining zone (the Eau Claire Formation) in the 

reevaluated AoR and will perform corrective actions on those wells. As needed, the FutureGen 

Alliance will revise all other plans, such as the Emergency and Remedial Response Plan, to take 

into account the reevaluated AoR and will submit those plans to the UIC Program Director for 

review and approval. 

Note that seismic events are covered under the Emergency and Remedial Response Plan. A 

tiered approach to responding to seismic events will be based on magnitude and location. A 

notification procedure is provided in that plan. 
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Figure 17. AoR Correction Action Plan Flowchart