Geologic Suitability of Coal Deposits in the Northern Great Plains Region of the United States for CO 2 Sequestration Charles R. Nelson Energy & Environmental Research Center (EERC), University of North Dakota, Grand Forks, North Dakota, USA Abstract Coal-fired electricity-generating power plants in southeastern Montana and northeastern Wyoming, located in the north-central area of the United States, generate about 39.6 x 10 9 kg of CO 2 annually, which is emitted directly to the atmosphere. These power plants overlie or are proximal to large coal deposits in the Powder River Basin. These coal deposits are reservoirs for natural gas, which is a clear indication that the coal-bearing formations are capable of trapping gases for geologically long time periods. A bottom-up geologic evaluation was made of the CO 2 sequestration potential of a major coal deposit in the Powder River Basin. The CO 2 sequestration potential estimate for areas where the coal overburden thickness is >300 m is 6.2 x 10 12 kg. The coal resources that underlie these deep areas could sequester all the current annual CO 2 emissions from nearby power plants for the next 156 years. Keywords: CO 2, coal, geologic sequestration Introduction Carbon management, specifically the separation and capture of CO 2 at fossil energy-fueled electric power plants followed by geological sequestration, is viewed as the most important near-term strategy for achieving deep reductions in global atmospheric CO 2 emissions [1,2,3,4]. Unmineable coal deposits defined as coals that are too thin, too deep, or too unsafe to mine are potential geologic environments for CO 2 sequestration [5]. However, it is not expected that all coal deposits in a given region will be suitable for geologic CO 2 sequestration. Factors such as the annual CO 2 volume and transportation distance and the CO 2 injectivity, storage capacity and retention ability of the coal deposit will affect the matching of CO 2 source and geologic storage opportunities [5]. Coal-fired electricity-generating power plants in southeastern Montana and northeastern Wyoming, located in the north-central area of the United States, generate about 39.6 x 10 9 kg of CO 2 annually, which currently is emitted directly to the atmosphere [6]. Eleven new coal-fired power plants are currently under development or construction in Montana and Wyoming, which will significantly increase the future atmospheric CO 2 emission levels in this area [7]. The current power plants overlie or are located within 100 km of large deposits of subbituminous coal in the Powder River Basin (see Figure 1). This paper presents the results from an evaluation of the geologic suitability and CO 2 sequestration capacity of the subbituminous coal deposits in the Powder River Basin [8]. Coalbed Characteristics The Powder River Basin contains the largest deposit of coal resources of any basin in the continental United States [9]. The coal-bearing formations in this basin contain an estimated 1.18 x 10 15 kg of coal resources [10]. Surface mineable deposits of subbituminous coal are located along the margins of the basin (see Figure 1). A key indication that these coal deposits could be suitable geologic environments for CO 2 sequestration is that they are reservoirs for natural gas. The coalbed natural gas or methane (CBM) resources in the Wyoming portion of the Powder River Basin are estimated to total 1.25 x 10 12 m 3 [11]. The presence of a concentrated accumulation of natural gas in a geologic formation is a clear indication that it is capable of trapping gases for geologically long time periods. 1
Figure 1 Map showing the location and areal extent of the Powder River Basin, the net overburden thickness for the Wyodak-Anderson coal zone, and the locations of surface coal mines and coalbed natural gas wells. The Powder River Basin is the largest coal-producing and second largest coalbed natural gas-producing area in the United States [12,13]. Figure 1 shows the locations of the coalbed natural gas wells in the Powder River Basin. In 2004, coalbed natural gas production from this basin totalled 9.6 x 10 9 m 3 from 13,880 wells [8,11]. The ability to extract natural gas from a formation is a clear indication that the permeability properties of the formation may be suitable for the large-scale injection of CO 2. The injectivity of CO 2 is dependent on the coal permeability. Coals contain naturally occurring microfractures, called cleats, which provide the permeability pathways for bulk fluid flow. Coal seam permeability typically ranges between 0.1 and 10 millidarcies. When a coal seam is flooded with CO 2, swelling of the coal occurs as a result of the adsorption of CO 2. The swelling causes the cleat aperture widths to decrease, which causes the permeability and CO 2 injectivity of the coal to decrease [3,5]. The permeability of the subbituminous coal in the Powder River Basin ranges from tens of millidarcies to more than a darcy [11]. This very high initial bulk coal permeability may have a mitigating effect on any swelling induced permeability and CO 2 injectivity losses during CO 2 flooding. The success of geologic CO 2 sequestration as a large-scale carbon management strategy is critically dependent on the ability of the geologic sinks to confine the injected CO 2 for hundreds to thousands of years. CO 2 is a buoyant gas so its natural tendency is to migrate upward to the top of an injection zone. CO 2 is soluble in water so it can also migrate as a solute in moving ground water [1,3,5]. 2
Formations used for geologic CO 2 sequestration should be overlain by an impermeable cap rock layer, such as shale, that does not contain transmissive faults or fractures [1,3,5]. Analysis of the affects of coalbed natural gas production on groundwater aquifers in the Powder River Basin indicate that shale layers overlying the coalbed reservoirs act as barriers to vertical CH 4 and water migration [5,14]. This is a clear indication that the coal-bearing formations are overlain by an effective permeability barrier, which would limit the potential for vertical CO 2 leakage as either a gas phase fluid or solute. CO 2 Sequestration Capacity Analysis Overburden thickness is one of the critical geologic properties affecting the suitability of any coal deposit for geologic CO 2 sequestration. Only areas where the overburden thickness is too great for economical mining would be potential sites for geologic CO 2 sequestration [3,5,6]. Surface mining is used to recover coal in the Powder River Basin. The maximum overburden thickness limit for economical surface mining in the Powder River Basin is 150 m [6]. The CO 2 sequestration capacity analysis focused on the Wyodak-Anderson coal zone, which contains the largest coal resource in the Powder River Basin and is also the main target of surface mining and coalbed natural gas resource exploitation. The overburden and net coal thickness of the Wyodak- Anderson coal zone range from 0 to 760 m and from 0.5 to 46 m, respectively [15]. The Wyodak- Anderson coal zone contains an estimated 5 x 10 14 kg of subbituminous coal resources [15] and 0.57 x 10 12 m 3 of coalbed natural gas resources [8,11]. Geologic models in the form of continuous grid surfaces of the overburden and net thickness of the Wyodak-Anderson coal zone were created using data obtained from well logs and isopach maps [8,11]. Overburden and net coal thickness values of 150 m and 3 m, respectively, were used as screening criteria for identifying areas with suitable geologic properties for CO 2 sequestration [8]. Figure 1 indicates that only a very small area in Montana meets the 150 m overburden thickness criterion. Therefore, no CO 2 sequestration potential estimates were calculated for any areas in Montana underlain by the Wyodak-Anderson coal zone. In coal deposits, the CO 2 is trapped or sequestered by physical adsorption. The hydrostatic pressure controls the CO 2 adsorption and retention process. The CO 2 sequestration capacity of a coal deposit depends on the amount of coal, the hydrostatic pressure of the coal zone, and the CO 2 storage capacity of the coal [3,5,8]. The volume of CO 2 that could potentially be sequestered in the Wyodak-Anderson coal zone was estimated using Equation 1. A value of 1.33 g/cm 3 was used for the subbituminous coal density [8,11]. CO 2 SP = (A x h x ρ x SC CO2 ) (1) Where: A = Area (m 2 ) h = Net coal thickness (m) ρ = Density (g/cm 3 ) SC CO2 = CO 2 Storage capacity (cm 3 /g, in situ mass basis) CO 2 SP = CO 2 Sequestration potential (m 3 ) The CO 2 storage capacity estimates were made using the Langmuir isotherm model, which is a numerical model that describes the relationship between the gas storage capacity and pressure [5,8]. The CO 2 isotherms of the Wyodak-Anderson subbituminous coal exhibit variability as a function of the coal seam depth. To account for this variability, the Wyodak-Anderson coal zone was subdivided into two depth intervals, and a separate CO 2 Langmuir isotherm equation was formulated for each interval. 3
The CO 2 Langmuir isotherm equation used for the 150-365-m depth interval is shown in Equation 2, and Equation 3 was used for the >365-m depth interval [8]. SC CO2 = {32.7 x [P h / (P h + 4.48)]} (2) Where: SC CO2 = {34.4 x [P h / (P h + 4.27)]} (3) P h = Initial hydrostatic pressure (MPa) The estimate of the initial hydrostatic pressure was based on the midpoint coal seam depth. In the Wyodak-Anderson coal zone there is a roughly linear relationship between the coal seam depth and the initial hydrostatic pressure [8,11]. This relationship is shown in Equation 4. P h = [(0.0084 x D) 0.4] (4) Where: D = Midpoint coal seam depth (meters) An engineering safety factor was included in the CO 2 sequestration potential estimates. The physical CO 2 adsorption process is reversible. CO 2 desorption and leakage out of the sink is a potential risk because the hydrologic pressure in coal deposits could undergo natural variation over geologically long time periods [16]. In order to minimize the risk of CO 2 desorption and leakage, the total injected CO 2 volume should be less than the CO 2 storage capacity of the coal. The engineering safety factor set the maximum sorbed-phase CO 2 volume at a value where CO 2 desorption would not begin until there was a 20% reduction in the hydrostatic pressure [8]. The temperature and pressure of the formation affects the phase of the CO 2 interacting with the coal. Above its critical point temperature of 31 o C and pressure of 7.4 MPa, CO 2 is a dense, supercritical fluid [1,3]. Supercritical CO 2 may interact differently with coal than normal gaseous CO 2 [16]. Flowing supercritical CO 2 through a subsurface coal seam might result in drying of the coal, which, in turn, would alter its CO 2 storage capacity [3,5]. Thus determining if supercritical CO 2 conditions could occur is important when areas are evaluated for CO 2 sequestration. The subsurface temperature and maximum pressure in the areas where the Wyodak-Anderson coal zone is potentially suitable for geologic CO 2 sequestration range from 16 o to 38 o C and up to ~7.4 MPa, respectively [8]. This envelope of temperature and pressure conditions indicates a predominantly normal gaseous state for any CO 2 injected or sequestered in the Wyodak-Anderson coal zone. Results Table 1 and Figure 2 show coal resource and CO 2 sequestration potential estimates for the Powder River Basin s Wyodak-Anderson coal zone. The CO 2 sequestration capacity estimate is 7.2 x 10 12 kg (3.9 x 10 12 m 3 ). Roughly 85% of the total CO 2 sequestration capacity (6.2 x 10 12 kg) is in areas where the overburden thickness is >300 m. The coal resources that underlie these deep areas could sequester all the current annual CO 2 emissions from nearby electric power plants for the next 156 years. The geologic factors that control natural gas accumulation and mobility in a subsurface coal deposit are similar to those that would control CO 2 injectivity into, and its long-term retention in, a subsurface coal deposit. The Powder River Basin s Wyodak-Anderson coal zone contains natural gas, is very permeable, and is overlain by an impermeable shale layer. These characteristics suggest that this coal-bearing formation would be a favorable geologic environment for CO 2 sequestration. 4
Table 1 CO 2 sequestration potential estimates for the Wyodak-Anderson coal zone. Depth Interval Coal Resources a CO 2 Capacity a,b 150 300 m 1.61 x 10 14 kg 0.58 x 10 12 m 3 1.07 x 10 12 kg >300 m 1.97 x 10 14 kg 3.32 x 10 12 m 3 6.17 x 10 12 kg Total 3.58 x 10 14 kg 3.90 x 10 12 m 3 7.24 x 10 12 kg a Estimates are for areas where the net coal thickness is 3 m and depth is 150 m. b 20% pressure decrease required before CO 2 desorption starts. Figure 2 Isopach map showing the CO 2 sequestration potential of the Wyodak-Anderson coal zone in the Powder River Basin. Acknowledgment This research was conducted by the Plains CO 2 Reduction (PCOR) Partnership project funded by the U.S. Department of Energy s (DOE s) Phase I Regional Carbon Sequestration Partnership Program (DOE Cooperative Agreement No. DE-PS26-03NT41982). 5
List of References [1] Bachu S, Stewart S. Geological sequestration of anthropogenic carbon dioxide in the Western Canadian Sedimentary Basin suitability analysis. J Can Petroleum Technol 2002;41(2):32-40. [2] Bruant RG Jr., Guswa AJ, Celia MA, Peters CA. Safe storage of CO 2 is deep saline aquifers. Environ Sci Technol 2002;36(11):240A-45A. [3] White CM, Straziser BR, Granite EJ, Hoffman JS, Pennline HW. Separation and capture of CO 2 from large stationary sources and sequestration in geological formations coalbeds and deep saline aquifers. J Air & Waste Manage Assoc 2003;53:645-715. [4] Pacala S, Socolow R. Stabilization wedges solving the climate problem for the next 50 years with current technologies. Science 2004;305:968-972. [5] White CM, Smith DH, Jones KL, Goodman AL, Jikich SA, LaCount RB, et al. Sequestration of carbon dioxide in coal with enhanced coalbed methane recovery-a review. Energy Fuels 2005;19 (3):659-724. [6] Stricker GD, Flores RM. Potential carbon dioxide sequestration and enhanced coalbed methane production in the Powder River and Williston Basins. Proceedings 28th International Technical Conference on Coal Utilization & Fuel Systems, Clearwater, Florida, 9-13 March 2002; 15 p. [7] Kosstrin HM, Beck RW. IGCC plants: risks and rewards. Platts Insight, McGraw-Hill; 2005; 10:22-3. [8] Nelson CR, Steadman EN, Harju JA. Geologic CO 2 sequestration potential of the Wyodak- Anderson coal zone in the Powder River Basin. Energy & Environmental Research Center (EERC), University of North Dakota, Grand Forks, North Dakota; 2005: U.S. DOE Cooperative Agreement No. DE-PS26-03NT41982, www.netl.doe.gov/technologies/carbon_seq/partnerships/ phase I/pdf/work_products/PCOR-12.pdf. [9] Nelson CR. North American coalbed methane resource map. GTI-01/0165. Gas Technology Institute, Des Plains, Illinois, 2001; 1 p. [10] Choate R, Johnson CA, McCord JP. Geologic overview, coal deposits, and potential for methane recovery from coalbeds-powder River Basin. In: Rightmire CT, Eddy GE, Kirr JN, editors. Coalbed methane resources of the United States, Tulsa, Oklahoma: American Association of Petroleum Geologists; 1984, p. 335-351. [11] Nelson CR. Geologic assessment of the natural gas resources in Powder River Basin Fort Union Formation coal seams. Paper 0506, Proceedings 2005 International Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama, 16-20 May 2005, 14 p. [12] Energy Information Administration (EIA). Annual coal report. Office of Coal, Nuclear, Electric, and Alternative Fuels, Washington, D.C., DOE/EIA-0584; 2002, 68 p. [13] Wood JH, Grape SG, Green RS, Zeinalpour RM. U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 2003 Annual Report. Energy Information Administration (EIA), Office of Oil and Gas, Washington, D.C., DOE/EIA-0216; 2004, 47 p. [14] Zander RA. Development, environmental analysis, and mitigation of coal bed methane activity in the Powder River Basin of Wyoming. Paper 9932, Proceedings of the 1999 International Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama, 3-7 May 1999, p. 47-57. [15] Ellis MS, Gunther GL, Ochs AM, Roberts SB, Wilde EM, Schuenemeyer JH, et al. Coal resources, Powder River Basin. 1999 Resource assessment of selected tertiary coal beds and zones in the northern Rocky Mountains and Great Plains Region, U.S. Geological Survey Professional Paper 1625A, Chapter PN, 28 p. [16] Pashin JC, McIntyre MR. Defining the supercritical phase window for CO 2 in coalbed methane reservoirs of the Black Warrior Basin-implications for CO 2 sequestration and enhanced coalbed methane recovery. Paper 0316, Proceedings 2003 International Coalbed Methane Symposium, The University of Alabama, Tuscaloosa, Alabama, 5-9 May 2003, 12 p. 6