Field-Project Designs for Carbon Dioxide Sequestration and

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Field-Project Designs for Carbon Dioxide Sequestration and Enhanced Coalbed Methane Production W. Neal Sams,† Grant Bromhal,‡ Sinisha Jikich,*,§ Turgay Ertekin,| and Duane H. Smith‡ National Energy Technology Laboratory, EG&G Technical Services, Morgantown, West Virginia 26507-0880, National Energy Technology Laboratory, United States Department of Energy, Morgantown, West Virginia 26507-0880, National Energy Technology Laboratory, Parsons Infrastructure, Morgantown, West Virginia 26507-0880, and Petroleum and Natural Gas Engineering, The Pennsylvania State University, University Park, Pennsylvania 16802 Received December 21, 2004. Revised Manuscript Received May 6, 2005

Worldwide concerns about global warming and possible contributions to it from anthropogenic carbon dioxide have become important during the past several years. Coal seams may make excellent candidates for CO2 sequestration; coal-seam sequestration could enhance methane production and improve sequestration economics. Reservoir-simulation computations are an important component of any engineering design before carbon dioxide is injected underground. We have performed such simulations for a hypothetical pilot-scale project in representative coal seams. In these simulations we assume four horizontal production wells that form a square, that is, two wells drilled at right angles to each other forming two sides of a square, with another pair of horizontal wells similarly drilled to form the other two sides. Four shorter horizontal wells are drilled from a vertical well at the center of the square, forming two straight lines orthogonal to each other. By modifying coal properties, especially sorption rate, we have approximated different types of coals. By varying operational parameters, such as injector length, injection well pressure, time to injection, and production well pressure, we can evaluate different production schemes to determine an optimum for each coal type. Any optimization requires considering a tradeoff between total CO2 sequestered and the rate of methane production. Values of total CO2 sequestered and methane produced are presented for multiple coal types and different operational designs.

Introduction Concern about the quantities of anthropogenic greenhouse gas emissions has grown steadily over the past few decades because of their potential for contributing to global warming. One of the most promising new technologies for reducing carbon dioxide emissions while allowing for continued fossil fuel use is carbon sequestration in coal seams. Because coal seams have proven to store large quantities of sorbed gases for millions of years, they exhibit significant potential for sequestration of carbon dioxide for the indefinite future.1 Conventional coalbed methane production technologies, which involve depressurizing the reservoir and removing in-place water, typically leave between 40 and * To whom correspondence should be addressed. E-mail: [email protected]. † National Energy Technology Laboratory, EG&G Technical Services. ‡ National Energy Technology Laboratory, U.S. Department of Energy. § National Energy Technology Laboratory, Parsons Infrastructure. | Petroleum and Natural Gas Engineering, The Pennsylvania State University. (1) Pagnier, H.; vanBergen, F.; van deVate, L.; Hills, L.; Bamber, W. Inventory of the potential of combined coalbed methane production carbon dioxide disposal in the Dutch subsurface. Proceedings, XIV International Congress on the Carboniferous and Permian (ICCP) 109, 1999.

80% of the methane behind.2-5 It may prove environmentally and commercially desirable, as well as technically possible, to inject carbon dioxide into coal seams for the simultaneous purposes of producing more coalbed methane and reducing atmospheric concentrations of carbon dioxide.6 Certain aspects of this possibility are the subject of this paper. The world’s first CO2-enhanced coalbed methane pilot was performed in the United States, in the Allison unit.7 (2) Stevens, S.; Schoeling, L.; Pekot, L. CO2 Injection for Enhanced Coalbed Methane Recovery: Project Screening and Design. Proceedings, International Coalbed Symposium, University of Alabama, Tuscaloosa, AL, May 3-7, 1999. (3) Gale, J.; Freund, P. Coal Bed Methane Enhancement with CO2 Sequestration Worldwide Potential. Environ. Geosci. 2001, 8(3), 210217. (4) Van Bergen, F.; Pagnier, H.; Schreurs, H. C. E.; Faaij, A. P. C.; Hamelink, C. N.; Wolf, K.-H. A. A.; Barandji, O. H.; Jansen, D.; Ruijg, G. J. Inventory of Potential for Enhanced Coalbed Methane Production with Carbon Dioxide Disposal in The Netherlands, Proceedings, International Coalbed Methane Symposium, Tuscaloosa, AL, May 1418, 2001. (5) Stevens S. H.; Spector, D.; Riemer, P. Enhanced Coalbed Methane Recovery Using CO2 Injection: Worldwide Resource and CO2 Sequestration Potential, Proceedings, SPE International Conference and Exhibition, Beijing, China, Nov 2-8, 1988. (6) Puri, R.; Yee, D. Enhanced Coalbed Methane Recovery, SPE paper 20732, Proceedings, 65th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, New Orleans, LA, Sept 23-26, 1990.

10.1021/ef049667n CCC: $30.25 © 2005 American Chemical Society Published on Web 09/28/2005

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Sams et al. Table 1. Coal Properties and Operational Parameters property reservoir drainage area reservoir depth reservoir thickness coal cleat porosity lateral permeability (absolute) initial pressure coal bulk density time constant sorption vol. const. (CH4, CO2)* sorption press. const.(CH4, CO2)

Figure 1. Schematic of well pattern with internal injectors and outside producers; the quarter of the pattern used in the simulations is shaded differently.

Since then, field demonstrations of CO2 sequestration in subsurface coal seams have been started in several locations throughout the world. The RECOPOL (Reduction of CO2 emission by means of CO2 storage in coal seams in the Silesian Coal Basin of Poland) project recently has been started.8 This pilot field test is one of the first of its kind outside North America, and with the preceding research will help in understanding the process and its potential for CO2 reductions in Europe. In Canada, the Alberta Research Council (ARC) consortium has developed a pilot site at the Fenn Big Valley, with the objective to reduce greenhouse gas emissions by subsurface injection of CO2 into deep coalbeds, and to enhance coalbed methane recovery factors and production rates as a result of CO2 injection.9 In Japan, a multiwell, micropilot was developed for injecting CO2 in the Ishikari coal basin.10The National Energy Technology Laboratory of the U.S. Department of Energy (DOE), with joint industry support, has initiated a demonstration project for CO2 sequestration in an unmineable coal seam in West Virginia.11 This paper describes simulations that were not meant to match that project exactly, but which were suggested by it. The results of these simulations should be useful for that field site, and also give general information that will be useful for a variety of coal seam sequestration projects. Field Plan, Coal Properties, Simulator, and Simulations Field Project Plan. As illustrated by Figure 1, the West Virginia project plan calls for four horizontal (7) Reeves, S. R. Allison and Tiffany ECBM Pilots: Results of Reservoir Studies, Proceedings, Coal-Seq III Forum, Baltimore, MD, March 25-26, 2004. (8) Pagnier, H. RECOPOL-Reduction of CO2 emission by means of CO2 storage in coal seams in the Silesian Coal Basin of Poland, Proceedings, Coal-Seq III Forum, Baltimore, MD, March 25-26, 2004. (9) Mavor, M. J.; Gunter, W. D.; Robinson, J. R. Alberta Multiwell Micropilot Testing for CBM Properties, Enhanced Methane Recovery, and CO2 Storage Potential, Proceedings, SPE Annual Technical Conference and Exhibition, Houston, TX, Sept 26-29, 2004. (10) Komaki, H. CO2-Coal Sequestration Project in Japan, Proceedings, Coal-Seq III Forum, Baltimore, MD, March 25-26, 2004. (11) Cairns, G. Enhanced Coal Bed Methane (CBM) Recovery and CO2 Sequestration in an Unminable Coal Seam, Proceedings, Second Annual Conference on CO2 Sequestration, Alexandria, VA, May 5-9, 2003.

critical gas saturation critical water saturation initial water saturation initial mole fraction of gas (CH4, CO2) reservoir temperature wellbore radius skin coalface pressure at producers coalface pressure at injectors

Appalachian Basin 4633 m × 4633 m (full grid) 915 m × 915 m (in-pattern) 427 m 0.6 m 0.10% 8 md 4.82 MPa 1400 kg/m3 1.16, 23.1, 46.3 days 15.2 SCM/tonne, 29.3 SCM/tonne 4.69 MPa, 1.9 MPa 0.0% 10.0% 40% 100%, 0% 45 °C 0.03 m 0.0 0.1, 0.34, 0.69 MPa 2.07 to 4.72 MPa

production wells, forming a square about 915 m on each side, i.e., two wells drilled at right angles to each other forming two sides of the square, with another pair of horizontal wells similarly drilled to form the other two sides. Four shorter horizontal wells drilled from a vertical well at the center of the rectangle form two straight lines orthogonal to each other. Primary production of methane and water is to be performed until a reservoir pressure of about 0.9 KPa is reached, after which CO2 will be injected through the center wells to displace methane, extending the reservoir’s production of methane and sequestering CO2. In general, horizontal wells provide connectivity with permeable reservoir locations, increase injectivity (compared to vertical wells), and increase production capabilities.12 In the planned well pattern, they also provide a measure of environmental safety by creating an outer perimeter beyond which CO2 should not flow. Properties of Appalachian Coals. The simulations described in this report are for a coal seam that is representative of those found in Appalachian basins.13 These basins are characterized by shallow coals of Mississippian and Pennsylvanian age located at depths less than 600 m. The Northern Appalachian basin consists of 43700 square miles in Pennsylvania, West Virginia, and Ohio. The main target coals are Waynesburg, Pittsburgh, Bakerstown, Freeport, and Kittanning. The Pittsburgh coals have drawn the most attention because of wide areal distribution, thickness, and gas content. Coal seam properties known to be important for sequestration and their values as used in this study are listed in Table 1; they include the Langmuir sorption pressure and volume, critical gas saturation, critical water saturation, permeability, porosity, initial pressure, and time constant. Swelling caused by carbon (12) Taber, J. J.; Seright, R. S. Horizontal Injection and Production Wells for EOR and Waterflooding, SPE paper 23953, Proceedings, SPE Permian Basin Oil and Gas Recovery Conference, Midland, TX, March 18-20, 1992. (13) Byrer, C. W.; Mroz, T. H.; Covatch, G. L. Coalbed Methane Production Potential in U. S. Basins, J. Pet. Technol. 1987, July, 821834.

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interchange of gases between cleats and sorption sites can become important both for sequestration and production. The diffusion (or sorption) time constant, τ, is a lumped parameter that incorporates both diffusion time and rate of sorption/desorption and is closely related to the cleat spacing in the coal. The time constant regulates the rate at which gas is released from the micropore to the cleat system by the following equations:

τ)

1 Dmi × a

(1)

5.7832 Rmi2

(2)

a) Figure 2. Plan view of coal seam showing cleat structure and matrix blocks. (Remner et al.30).

Figure 3. Schematic of methane flow dynamics in coal seams (Remner et al.30). CH4 desorbs from the solid coal, diffuses through the bulk matrix, and flows into and through the cleats. The pathway for CO2 sorption is exactly reversed.

dioxide sorption is widely believed to be important, and its possible engineering and economic effects have been explored elsewhere.14 Simulator. Figure 2 illustrates the conceptual structure of a coal seam and Figure 3 is the model for the methane flow in the simulator used for this study. Although the fractures comprise only a very small portion of the coal (typical values on the order of 0.22%), they contain the largest permeability, and therefore control the flow.1,6,15-19 During primary production methane desorbs (quickly) to the gasesous state, diffuses (slowly) through pores to the cleats, and undergoes convective flow through the cleats to the production wells. During sequestration carbon dioxide follows a reverse path: convective flow transports it from the injection well through the cleats, from which it slowly diffuses into the coal matrix and then is quickly sorbed by the coal. If this transport is slow compared to the rate of flow through the cleats, the time required for (14) Bromhal, G. S.; Gorucu, F. B.; Jikich, S.; Sams, W. N.; Ertekin, T.; Smith, D. H. Effects of Gas-Induced Shrinkage and Swelling on Economics for Sequestration of CO2 in Coal Seams, Proceedings, Fourth Annual Conference on Carbon Capture and Sequestration, Alexandria, VA, May 9-12, 2005. (15) Gash, B. W. Measurement of rock properties in coal for coalbed methane production, SPE paper 22909, Proceedings, 66th Annual Technical Conference and Exhibition SPE, Dallas, TX, Oct 6-9, 1991. (16) Gash, B. W. The effects of cleat orientation and confining pressure and cleat porosity, permeability, and relative permeability in coal, Proceedings, SPWLA/SCA Symposium, Oklahoma City, OK, June 15-16, 1992. (17) Rice, D. D.; Young, G. B. C.; Paul, G. W. Methodology for assessment on technically recoverable resources of coalbed gas; Technical Report on USGS website; certnetra.cr.usgs.gov/1995OGData/Coalgas/ COALGAS.pdf, 1995. (18) Harpalani, S.; Chen, G. Influence of gas production induced volumetric strain on permeability of coal. Geotech. Geol. Eng. 1997, 15, 303-325. (19) Somerton, W. H.; et al. Effect of stress on permeability of coal. Int. J. Rock Mech. Min. Sci., Geomech. Abstr. 1975, 12, 129-145.

where Dmi (m2/D) represents the micropore diffusion coefficient and a represents the shape factor for cylindrical matrix elements. Parameter Rmi (m) is taken as the cleat spacing. For smaller values of τ, the diffusion/ sorption process is faster. As illustrated below, when τ is sufficiently short, attainment of thermodynamic equilibrium is effectively instantaneous; but when large cleat spacings produce long values of τ, a significant portion of the reservoir may be far from equilibrium, thus reducing the amounts of carbon dioxide sequestered. The simulator used in this study PSU-COALCOMP, is a three-dimensional, finite difference, two-phase, dual-porosity, compositional simulator. The simulator models the sorption of gas using the Langmuir, Toth, or UNILAN correlations. This study uses the Langmuir correlation. The time constant is user-specified. The thermodynamic properties required by the simulator are calculated from the Peng-Robinson equation of state.20 This simulator has been compared with several other coalbed methane simulators in a recent comparison study.21 A fuller description of this model may be found elsewhere in the literature.22 Simulations. In a fully developed gas field the boundaries of the field are reasonably well-known; typically, a geometrically regular pattern of vertical wells is drilled and operated over the entire field. However, in this study a novel, single, isolated pattern of horizontal wells was examined for a field whose boundaries were not well-established, but presumably very large compared to the lengths of the external, horizontal wells. For this reason the coal seam was treated as essentially infinite in extent, with constant values of the reservoir parameters (Table 1) throughout the volume of the seam from which methane was produced. Because of symmetry within the pattern, all runs were performed on a quarter of the pattern (Figures 1 and 4). The initial grid was a 20 × 20 grid that represented a 610 m × 610 m region, which was onequarter of the pattern plus an external region about 150 (20) Peng, D. Y.; Robinson, D. B. A New Two-Constant Equation of State. Ind. Eng. Chem. Fundam. 1976, 15, 59-64. (21) Law, D. S.; Gunter, W. D. Numerical Model Comparison Study for Greenhouse Gas Sequestration in Coalbeds - History Match Results, Proceedings, Coal-Seq III Forum, Baltimore, MD, March 2526, 2004. (22) Manik, J.; Ertekin, T.; Kohler, T. E. Development and Validation of a Compositional Coalbed Simulator. J. Can. Pet. Technol. 2002, 41, 39-45.

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Once the 36 × 36 grid was established (Figure 4), a number of scenarios with different operational conditions were simulated. These simulations examined various combinations of injector well length, depressurization time, and well operating pressures. For the base case, 0.1 MPa coalface pressure was chosen for the production wells and 2.07 MPa coalface pressure for the injection wells. This case was run with a 195 day primary production period followed by injection from the center wells starting 1 day later. The runs continued until the concentration of CO2 at the production wells reached 10 mol %. This CO2 concentration changed rapidly once breakthrough began; hence, the results were relatively insensitive to the value of this parameter. Results Figure 4. Gridding used for the largest area simulated (with grid sizes in m); the quarter of the in-pattern area (upper left, in gray) has a much finer grid than the area external to the outside wells.

Figure 5. Total amount of methane produced after 730 days for differently sized external regions (MMSCM ) 106 standard m3).

m on each side. A sequence of runs then was performed using progressively larger grids, up to an external region of 1860 m per side (Figure 4). For the purpose of determining the size of the simulation grid, all wells were initially produced at a coalface pressure of 0.1 MPa. After 195 days, the interior wells were shut in and production from the external wells continued until a total elapsed time of 730 days was reached. At that point the run was terminated and the total methane production was recorded. The time of 195 days was chosen because preliminary runs indicated that by that time the pressure at all points within the pattern had fallen below the value (0.9 MPa) specified in the field project plan. It was first necessary to ensure that the simulation grid were large enough to include all of the seam outside the pattern from which methane could be produced. The first part of the study thus dealt with the selection of a grid sufficiently large to include this area. Results from these simulations may be found in Figure 5, which illustrates the total amount of methane produced after 730 days for different lateral extents of coal seam. The curve was relatively flat when the half-width of the area was between 1250 and 1860 m, indicating that the 36 × 36 grid had sufficient extent, even if project times somewhat exceeded 730 days.

Effects of injector lengths, primary production time, production and injection pressures, and the time constant are examined in the following sections. Except for the last section “Time Constant”, the value of the time constant was fixed at 1.16 day (100000 s) in all of the results. The injection well pressure was 2.07 MPa and the production well pressure was 0.1 MPa in the sections “Injector Lengths” and “Primary Production Time”; in the “Time Constant” section the production well pressure was 0.69 MPa (and the injection well pressure was variable). Values of the other input parameters were fixed for all of the computations; they are listed in Table 1. Injector Lengths. The effects of injection well lengths of 30.5-305 m on project time, total methane produced, and amount of carbon dioxide sequestered are shown in Figure 6. The project time and the amount of methane produced both decreased monotonically as the injector well length was increased, suggesting that for these parameters a vertical injector without horizontal wells might be best. However, the amount of carbon dioxide sequestered was maximum for injector lengths of about 200 m. It should be emphasized that, with the isolated well pattern chosen for the DOE co-funded field project and used in this study, sequestered carbon dioxide is confined to inside the pattern, but methane is produced from both inside and outside the pattern. Total methane production and project time are highly correlated because more methane is produced from outside the pattern as project lifetime is extended. In a full field-development project with many repeated patterns, all production would be in-pattern methane; and for all injector well lengths total methane production would follow the same trend as the carbon dioxide retained. Thus, while the tradeoffs between sequestration and methane production implied by Figure 6 are “real” for the demonstration project, for a large-scale project of repeated well patterns, horizontal injectors of about 200 m length would be best for both sequestration and production of methane. However, the project lifetime would be slightly shorter because once carbon dioxide appeared in the production wells, out-of-pattern methane would not be available to dilute the carbon dioxide concentration in the methane/carbon dioxide mixture of (in-pattern) produced gas. For the isolated well pattern of this study, the CO2 produced with the methane was approximately 198000


Figure 6. (a) Production time, (b) methane produced, and (c) CO2 retained as a function of injector length (MMSCM ) 106 standard m3).

m3, except for the 91.4, 60.9, and 30.5 m injector lengths, for which the amounts of CO2 produced were 226000, 259000, and 316000 m3, respectively. Thus, while injection was continued until the CO2 concentration in the produced gases reached 10 mol %, the total amount of CO2 produced was less than 1 mol % of the total amount of methane produced. In a large field project in which additional patterns were brought online sequentially, equipment to separate the produced CO2 would probably not be needed even if injections were continued until the produced CO2 concentrations from individual patterns reached 10 mol % and exceeded pipeline limits because the CO2 from these patterns could be diluted with gas from other patterns at which CO2 breakthrough had not yet occurred. Primary Production Time. All else equal, shorter production times would usually be better because they speed revenue streams, reduce operating costs, and reduce lead times to sequestration. Hence, the series of runs illustrated by Figure 6 was repeated with shorter primary production periods of 115 and 85 days, respectively. Results of the two latter modes of operation are shown in Figure 7 in which amounts of methane produced and carbon dioxide sequestered are again plotted vs length of the injector wells. We observe that for primary production periods of 85-195 days the total amounts of methane produced were virtually identical; the amount of carbon dioxide sequestered varied by 5% at most, and even less for optimum well lengths. The 183-213 m injectors resulted in the maximum amount of CO2 sequestered regardless of the primary


production time. Evidently the variation in total methane production for different production times is very small because the variation in total project length is much less than the variation in the length of the primary production period. The volume of carbon dioxide (and moles of carbon) sequestered are about one-fourth the volume of methane (and moles of carbon) produced by the project. Production and Injection Pressures. For Figures 6 and 7 the coalface production pressure was 0.1 MPa and the injection pressure was 2.07 MPa. The 0.1 MPa coalface pressure represented the absolute open flow rate; the effects of a restricted production rate, with the production pressure at 0.344 MPa, also were examined. Additionally, we studied the effects of a different injection pressure. Figure 8 compares results for (i) the 0.344 MPa coalface pressure and 2.07 MPa injection pressure and (ii) the case where the production pressure was 0.1 MPa and the injection pressure was 2.76 MPa with (iii) the case of the previous sections, in which the production pressure was 0.1 MPa and the injection pressure was 2.07 MPa. An intermediate case (iv), in which the injection pressure of 2.07 MPa was increased to 2.76 MPa after 365 days is also illustrated in Figure 8. Other examples, in which the production well pressure was 0.69 MPa and various injection well pressures were used, are presented in the next section. In Figure 8 there was virtually no difference in the amount of methane produced between the 2.07 MPa/ 0.1 MPa and the 2.07 MPa/0.344 MPa cases. The 2.76 MPa/ 0.1 MPa case produced significantly less methane. The amount of methane produced when the injection pressure was increased from 2.07 to 2.76 MPa was nearly the same as when the injection pressure was held at a constant 2.76 MPa. The effects of injection pressure were opposite for production and sequestration. The case where the injection pressure was a constant 2.76 MPa as well as the case where the injection pressure was increased from 2.07 to 2.76 MPa (with the production pressure fixed at 0.1 MPa) resulted in much greater sequestration than when the injection pressure was a constant 2.07 MPa. The production pressure of 0.344 MPa (with the production pressure constant at 2.07 MPa) significantly increased the amounts of carbon dioxide sequestered for all but the longest, least favorable injection well lengths compared with a production pressure of 0.1 MPa. Time Constant. In this section effects of time constants of 23.1 and 46.3 days, as well as of 1.16 days, are examined. Figures 9, 10, and 11 compare the effects of these values of the time constant on the amounts of methane produced and carbon dioxide sequestered for different injection pressures and injector well lengths. Increasing injection pressure with a fixed production pressure causes an increased pressure gradient across the pattern, resulting in a more rapid fluid flow rate through the cleats. For the smallest time constant used in this study (1.16 days), the sorption/diffusion process was so rapid relative to the characteristic time for cleat flow that the sorption/diffusion process could be ignored and only the sweep and the reservoir pressure were important in determining the performance of the process. Thus, for a fixed injector length, there was a

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Figure 7. Effect of different primary production times for multiple injector lengths on (a) methane produced and (b) carbon dioxide retained (MMSCM ) 106 standard m3).

monotonic increase with injection pressure in the amount of CO2 sequestered (Figure 9a). For the middle time constant (23.1 days) the injection time was sufficiently long that for the shorter injectors the amount of CO2 sequestered increased with increasing injection pressure in a manner similar to that for the shortest time constant. However, for longer injectors (274.3 and 305 m) the amount of CO2 sequestered initially rose slowly with injection pressure and then leveled off or even declined with increasing injection pressure (Figure 9b); the injection time at the higher pressures was only a small multiple of the time constant, and a significant portion of the swept reservoir was still far from equilibrium at the end of the project.

For the longest time constant (46.3 days) used in the study, the amount of CO2 sequestered either leveled off or declined with increasing injection pressure for all injector lengths (Figure 9c). At the highest injection pressure, the injection time for the 305 m injectors was less than two time constants. Thus, for this case none of the reservoir was at equilibrium when injection stopped. Contrarily, the time constant had little effect on the amount of methane produced during the life of the project (Figure 10). This was largely because much of the methane produced was from outside of the pattern. The in-pattern methane curves would have shown only a slight decrease with increasing injection pressure



Figure 8. (a) Methane produced and (b) CO2 retained for different injector lengths at different production and injection well pressures (MMSCM ) 106 standard m3).

reflecting the higher pressure in the unswept region; but because of the large amounts of methane produced from outside the pattern, the total amount of methane produced was directly related to the total project lifetime, which went up monotonically with shorter injectors and lower pressure differences. Figure 11 shows more directly the effects of time constant on the amount of carbon dioxide sequestered and methane produced. Clearly, for the values used in the study, the time constant had very little effect on the amount of methane produced, while as τ increased the amount of CO2 sequestered decreased and the curves changed shape away from a straight line. Discussion Many factors affect sequestration in coal seams and enhanced production of coalbed methane.23-25 Among these are sorption isotherms26 and any anisotropy of the coal permeability.27 Cleat permeability and seam thickness are very important properties of coal because they may determine the profitability of a coal seam seques-

tration project.28,29 However, Eastern coal seams often are very thin; for them the thickness of the seam has little effect on the flow patterns because gravitational effects are small, and thickness effects need not be studied in any detail. For example, doubling the thick(23) White, C. M.; Smith, D. H.; et al. Sequestration of Carbon Dioxide with Concomitant Enhanced Coalbed Methane RecoverysA Review. Energy Fuels 2005, 19, 659-724. (24) Odusote, O.; Smith, D. H.; Bromhal, G.; Ertekin, E.; Jikich, S. A.; Sams, W. N. A Parametric Study of The Effects of The Coal-Seam Properties on Carbon Dioxide Sequestration, Proceedings 2002 Pittsburgh Coal Conference, Sept 23-27, 2002. (25) Gorucu, F. B.; Ertekin, T.; Bromhal, G.; Smith, D. H.; Sams, W. N.; Jikich, S. Development of a Neuro-simulation Tool for Coalbed Methane Recovery and CO2 Sequestration. Proc. International Coal Bed Methane Symposium, Tuscaloosa, AL, May 18-19, 2005. (26) Bromhal, G.; Sams, W. N.; Jikich, S.; Smith, D. H. Simulation of CO2 Sequestration in Coal Beds: The Effects of Sorption Isotherms. Chem. Geol. 2005, 217, 201-211. (27) Smith, D. H.; Sams, W. N.; Bromhal, G.; Jikich, S.; Ertekin, T. Simulating Carbon Dioxide Sequestration/ECBM Production in Coal Seams: Effects of Permeability Anisotropies and Diffusion Time Constant. Soc. Pet. Eng. Reserv. Eng. Eval. 2005, 8(2), 156-163. (28) Bromhal, G.; Jikich, S. A.; Sams, W.; Ertekin, T.; Smith, D. Optimizing Economics for Sequestering CO2 in Coal Seams with Horizontal Wells, Proceedings, Third Annual Conference on Carbon Capture and Sequestration, Alexandria, VA, May 5-9, 2004.

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Figure 9. CO2 sequestered vs injector pressure for different injector lengths and for (a) τ ) 1.16 days, (b) τ ) 23.1 days, and (c) τ ) 46.3 days (MMSCM ) 106 standard m3).



Figure 10. Methane produced vs injector pressure for different injector lengths for (a) τ ) 1.16 days, (b) τ ) 23.1 days, and (c) τ ) 46.3 days (MMSCM ) 106 standard m3).

ness of the seam assumed for this study (while keeping all other parameter values the same) would simply double the amount of carbon that could be sequestered in the seam. Similarly, time scales inversely with permeability, except only for large τ and relatively rapid

flow rates when the scaling relationship with permeability breaks down. Three properties that interact to affect the performance of the sequestration process are (1) the sweep efficiency, as determined by well geometry, (2) the

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Figure 11. Plots of (a) CO2 sequestered and (b) methane produced vs injector pressure for 152.4 m injectors and different time constants (MMSCM ) 106 standard m3).

reservoir pressure, and (3) the degree of departure from chemical equilibrium between the gases and the coal. For the pattern studied, a short time constant, and low injection pressure, injector lengths of approximately 183 m produce optimal sweep efficiency. Increasing CO2 partial pressure increases the equilibrium amount of CO2 sorbed per unit of coal. The degree of departure from equilibrium is determined by the sorption time constant and flow rate. The concentration of sorbed CO2 reaches 63% of its equilibrium value in one time constant after the CO2 front passes; it requires three time constants for the CO2 to reach 95% of its equilibrium value. When the injection time is of the order of the time constant, there exist large portions of the swept area of the reservoir that are far from equilibrium. This significantly reduces the amount of CO2 sequestered. Conclusions The purpose of this study was to determine, for a well pattern that had been chosen for a field project, which operational parameters are important to adjust for coals with different physical properties, with the intent of (29) Jikich, S.; Bromhal, G.; Sams, W.; Gorucu, F.; Ertekin, T.; Smith, D. Economics for Enhanced Coalbed Methane (ECBM) and CO2 Sequestration, paper SPE 91391, Proceedings, SPE Eastern Regional Meeting, Charleston, WV, Sept 15-17, 2004. (30) Remner, D. J.; Ertekin, T.; King, G. R. A Parametric Study of the Effects of Coal Seam Properties on Gas Drainage Efficiency, paper SPE 13366, Proceedings, SPE Eastern Regional Meeting, Charleston, WV, Oct 30-Nov 2, 1984.

maximizing the amount of carbon dioxide sequestered in the coal seam. Our work focused on τ (the time constant for diffusion and sorption), on well pressures, and on injector lengths. Generally, we found that, for shorter time constants (1.16 days and 23.1 days), as injection pressure was increased, the amounts of CO2 sequestered increased regardless of the length of the injection wells (with the exception of 305 m injectors and a time constant of 23.1 days). However, for larger time constants (J50 days), increasing injection pressure in the longer injectors decreased performance; but, for shorter injectors, increasing injection pressure continued to improve performance, albeit slightly. For the range of time constants studied here, the amount of methane always decreased with increasing injection pressure. We found that injector length can have a significant effect on carbon sequestered. For almost all of the conditions studied, we determined that an injector length between 90 and 180 m would give the maximum carbon dioxide sequestered. This length is substantially shorter than the 305 m injector length that has been proposed for this pattern with 915 m production wells. Our results also clearly show tradeoffs, which are inherent in coal seam sequestration, between using higher or lower well pressures. The higher the injection well pressure, the more CO2 can be sorbed by the coal; however, higher pressures also decrease injection lifetime, resulting in less methane production. Also, the


shorter the lifetime of injection, the more negative the effect of diffusion time on sequestration. These results suggest that the best mode of operation for sequestration may be to produce methane and inject CO2 initially at fairly low pressures, then at the end of methane production shut in the production wells (or greatly increase their pressure) and pump in CO2 at high rates through the injectors. In summary, for an isolated pattern of the type that has been proposed for a field test and the coal properties assumed in this study: 1. Injector length is an important parameter for determining the amount of CO2 sequestered and other aspects of project performance. 2. For a 915 m square pattern, 180 m appears to be the optimum length for a wide range of operational policies and maximizes the quantity of carbon dioxide sequestered.


3. Once the reservoir pressure has dropped sufficiently to permit CO2 injection, delaying the start of injection has little effect on the performance of the project. This is especially true for the optimal injector lengths. 4. Longer project lifetimes result in greater methane production. 5. Higher average reservoir pressures result in greater CO2 sequestration. 6. Higher production well pressures (at fixed injection pressure) reduce the pressure gradients, resulting in a longer project life and also more CO2 sequestered. 7. Higher injection pressures (at fixed production pressure) increase gradients, resulting in a shorter project life, but a greater volume of CO2 sequestered. EF049667N

Field-Project Designs for Carbon Dioxide Sequestration and

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