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Disclaimer 

This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

Introduction 

Organic matter in the Devonian gas shales has large surface areas similar to that found in coal. Coal seams are currently being investigated as potential sequestering sites for CO₂, the most important greenhouse gas [1]. Naturally occurring organic matter (kerogen) is a microporous material that possesses a very high surface area and hence sorption capacity for gas. The question is: can Devonian gas shales adsorb sufficient amounts of CO₂, that they might be significant targets for CO₂ sequestration?

The study area is primarily confined to the major gas-producing area of the Ohio Shale in the Big Sandy Gas Field, eastern Kentucky (Figure 1, main concentration of producing localities). As key wells and available samples are identified, wells in deep (at least 1,000 feet) and thick (at least 50 feet) areas will be included. Two Illinois Basin wells have also been sampled. Battelle has contributed drill cuttings through the Devonian shale from their deep AEP CO₂ seqestration project well in Mason County, W. Va.

The Ohio Shale is subdivided into seven recognizable units: Cleveland Shale, Three Lick Bed, Upper, Middle, and Lower Huron, Olentangy, and Rhinestreet. The Olentangy and Rhinestreet black shales correspond to the Java Formation of West Virginia, and thin and pinch out westward. A summary of reservoir data for the Big Sandy Gas Field is available in the "Atlas of Major Appalachian Gas Plays" [2]. Figure 2 shows is a west to east cross section sub-parallel to regional dip through the Big Sandy Gas Field that illustrates an eastward pinchout of the Cleveland and Upper Huron carbonaceous shale units into the gray Chagrin shale equivalents. The average completed interval exceeds 500 feet in thickness. Average porosity is 4.3 percent, with a maximum of 11 percent. Reservoir temperature averages 84°F, with an initial reservoir pressure of 800 psi or more. Current reservoir pressure averages 400 psi. Limited permeability data are available, but indicate less than 0.1 millidarcy of matrix permeability. Fracture permeability may exceed several hundred millidarcies.

Methods 

Drill cuttings on file at the Kentucky Geological Survey Well Sample and Core Library and sidewall cores are the main source of material for analysis. Unwashed sets of recently acquired drill cuttings were used to minimize weathering of material and to maximize volume of material for analysis.

To investigate any relation between organic content and CO₂ sorption capacity, total organic carbon content (TOC) was determined. For total organic carbon analyses, duplicate sample splits were crushed to a maximum particle size of 200 microns (–60 mesh): one split was run “as is;” another split was treated with 30 percent hydrochloric acid (HCl) for 12 to 24 hours to remove any carbonate minerals from the matrix.

To measure thermal maturity, mean random reflectance on dispersed vitrinite particles in the samples was determined on a Zeiss USMP incident light microscope calibrated using glass standards of known reflectance. Maximum vitrinite reflectance values can be estimated by multiplying the mean random measurements by 1.066 [3].

Adsorption analyses were performed using a high-pressure volumetric adsorption technique similar to that described by Mavor et al. [4]. Isotherms were measured on a custom-made apparatus. A known volume of gas within a reference cell is used to dose a sample cell. The amount of gas adsorbed in the sample cell is then determined, based on a change in pressure in the sample cell using the Real Gas Law (Peng Robinson equation of state). Following dosing of the sample cell, the pressure drops until equilibrium is reached. When equilibrium is reached, the sample is dosed at a higher pressure. Typically, 11 separate pressure points are selected and measured so that a Langmuir regression curve can be accurately generated. The reported CO₂ sorption capacity and corresponding pressure are calculated coefficients of the Langmuir model and are used to determine the sorption capacity at reservoir-appropriate pressures.

Schmoker [5] suggests a method to compute total organic carbon content from standard density logs acquired by the petroleum industry. The model assumes the shale consists of three main components: quartz-feldspar-mica, clay minerals, and organic matter. The density of a shale then is primarily a function of the weight percent of organic matter.

Laboratory investigation of methane displacement in the presence of CO₂ is being performed on whole rock core samples. In cooperation with Columbia Natural Resources, access to a well in Knott County, eastern Kentucky, was obtained for logging and collection of sidewall cores. The sidewall core plugs are being saturated with methane and will subjected to simulated injection of CO₂. Laboratory setup and analyses are similar to the standard procedure for obtaining adsorption isotherms. Additional sidewall core samples and an ECS log have recently been acquired from an Interstate Natural Gas well in Martin County, eastern Kentucky.

Results to Date 

Twenty-six samples have been collected from seven wells, including sidewall cores and electron capture spectroscopy and lithodensity logs from the Columbia Natural Resources No. 24752 Elkhorn Coal Corporation well in Knott County and the Interstate Natural Gas No. 3 John Jude Heirs well in Martin County. The New Albany shale has been sampled in two wells in Indiana and the Lower Huron has been sampled in the Battelle No. 1 AEP (Mountaineer power plant) in West Virginia. Data for completed analyses are presented in Table 1.

Adsorption isotherms for these samples are presented in Figure 3. The Langmuir volume and pressure data reported in Table 1 must be compared on a uniform pressure basis by formation. These summary data are shown in Table 2. A cross plot of the observed TOC and the gas storage volume at a specified pressure (400 psia) is shown in Figure 4. This linear relationship can be used to calculate CO₂ storage capacity from TOC data. Figure 5 is a cross plot of gamma-ray and density data from one well. The cross plot demonstrates the model proposed by Schmoker [5]. The most clastic units (in this case, the Berea overlying the Ohio Shale) are in a cluster below 150 API gamma-ray units and between densities of 2.5 and 2.8 grams per cubic centimeter (g/cm³). Gray shales cluster generally above 150 API gamma-ray units at densities between 2.6 and 2.8 g/cm³. Black shales tend to vary between 150 and 450 API gamma-ray units and densities between 2.3 and 2.7 g/cm³. Using Schmoker’s method to estimate TOC from density logs and the relation between TOC and CO₂ storage capacity, CO₂ storage is being estimated from density log data. Correlation between CO₂ capacity from isotherms and that calculated from density logs is being tested.

Preliminary Interpretation and Conclusions 

Initial estimates of CO₂ sequestration capacity have been calculated using selected data. The sequestration volume of the Lower Huron was estimated using areal distribution and thickness data from Dillman and Ettensohn [9] and indicate 91 x 1012 cubic feet (2.6 x 1012 cubic meters) of CO₂ could be sequestered in the Lower Huron. Assuming 30 percent of this theoretical saturation, approximately 1.6 billion tons (1.5 billion metric tonnes) of CO₂ could be sequestered. Using a GIS technique, estimated initial CO₂ sequestration capacity of the Devonian shale in Kentucky is 27.7 billion tons (25.1 billion metric tonnes) (Figure 6) in shale at least 1,000 feet deep and 50 feet thick.

Preliminary data indicate that black, organic-rich gas shales can serve as targets for sequestration of significant volumes of anthropogenic CO₂. The more carbonaceous black shales are the most likely reservoirs and the less organic gray shales may serve to seal the reservoirs. At Kentucky's current rate of power plant emissions, the organic-rich, black shale in the state could sequester more than 300 years' worth of that carbon. Enhanced production of natural gas displaced by the injected CO₂ would contribute to a long-term increase in the supply of that resource.

Acknowledgments 

This research is sponsored by the National Energy Technology Laboratory, U.S. Department of Energy, contract DE-FC26-02NT41442.

References 

1. IEA Coal Research, 1999, CO₂ reduction—Prospects for coal. London, IEA Coal Research, 84 p.

2. Boswell, R., 1996, Play Uds: Upper Devonian black shales, in Roen, J.B. and B.J. Walker, eds. Atlas of Major Appalachian gas plays. West Virginia Geologic and Economic Survey, Publication V-25, p. 93–99.

3. Ting, F.T.C., 1978, Petrographic Techniques in Coal Analysis, in Karr, C., Jr. (ed). Analytical Methods for Coal and Coal Products. Academic Press, v. 1, pp. 3-26.

4. Mavor, M.J., L.B. Owen, and T.J. Pratt, 1990, Measurement and evaluation of isotherm data. Proceedings of the 65th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, SPE 20728, p. 157-170.

5. Schmoker, J. W., 1993, Use of formation-density logs to determine organic-carbon content in Devonian shales of the western Appalachian Basin and an additional example based on the Bakken Formation of the Williston Basin, in J. B. Roen, and R. C. Kepferle, eds. Petroleum geology of the Devonian and Mississippian black shale of eastern North America. U. S. Geological Survey Bulletin 1909, U.S. Government Printing Office, p. J1-J14.

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