Simulation of the Effects of Shrinkage and Swelling on Coal Seam Sequestration and Coalbed Methane Production

Transcription

1 0418 Simulation of the Effects of Shrinkage and Swelling on Coal Seam Sequestration and Coalbed Methane Production Grant S. Bromhal, 1 W. Neal Sams, 2 Sinisha Jikich, 3 Turgay Ertekin, 4 and Duane H. Smith 1 1 National Energy Technology Laboratory, U.S. Department of Energy, Morgantown, WV 2 National Energy Technology Laboratory, EG&G, Morgantown, WV 3 National Energy Technology Laboratory, Parsons, Morgantown, WV 4 Petroleum and Natural Gas Engineering, The Pennsylvania State University, University Park, PA Abstract Increasing levels of carbon dioxide and other greenhouse gases in the atmosphere have caused great concern in several countries and world organizations over the past decade. Coal seam sequestration is one of the most promising near-term technologies for reducing atmospheric carbon dioxide levels because of 1) the proximity of coal seams to many power plants, 2) the economic benefits of concomitant natural gas production and carbon sequestration, and 3) the fact that coal seams trap most of the sequestered CO 2 in the sorbed form, which seems to be safer for long-term storage. One recent question regarding injection of carbon dioxide into coal seams is the effects of injected carbon dioxide on gas flow rates and production and injection capacities. Most methane in coal seams can be found sorbed to the bulk coal matrix in its natural state. When gas is produced from coal, it desorbs and causes the coal matrix to shrink by reducing the overall solid matrix volume. As the coal shrinks, the fraction of void space increases, which typically causes an increase in permeability and thereby, gas flow rates. However, because carbon dioxide sorbs onto coal, the introduction of CO 2 into a coal seam will cause matrix swelling and reduce permeability and gas flow rates. Recently, theories have been advanced that relate cleat permeability to gas pressure or concentration and effective stress on the solid matrix (14,15). Several reservoir simulators have incorporated this information into their overall set of flow equations to allow for the modeling of shrinkage and swelling in coal seams. We have recently modified PSU- COALCOMP, a state-of-the-art coal bed methane simulator, to include shrinkage and swelling using either the Palmer-Mansoori or Sawyer et al. model. With these models, we were able to assess the effects of swelling on methane production rates and CO 2 injection rates for a coal seam sequestration project. In earlier work, we studied the amount of methane that could be produced and the amount of carbon dioxide that could be sequestered in an eastern coal seam through the use of horizontal wells (4) without accounting for coal shrinkage or swelling. For the work in this paper, we simulated a project with a similar well design a square pattern, 3000 ft 2, fully enclosed by horizontal production wells, with horizontal injection wells in the

2 center but we included shrinkage and swelling effects. We have varied both the length of the injection wells and the injection pressures, and compared the new results to the results from our earlier study. Additionally, we have varied the values of the Palmer- Mansoori equation inputs (elastic modulus and strain function constants) across a reasonable range to determine the effects of shrinkage and swelling on coals with different geomechanical properties. Introduction A carbon sequestration and technology roadmap (1) was developed at the National Energy and Technology Laboratory (NETL) to address greenhouse gas mitigation. Greenhouse gases can be captured and stored in underground reservoirs. There are several types of underground reservoirs where CO 2 can be stored: depleted oil and gas reservoirs, saline formations, shales with high organic content, unminable coals, and others. Unminable coal seams are considered as very attractive potential storage media for CO 2. The injection of CO 2 in coalbeds is one of the more efficient geologic sequestration options, because while CO 2 is stored, the recovery of coalbed methane is accelerated. The process of displacing the remaining methane by CO 2 after the primary production of methane is referred to as enhanced coal bed methane (ECBM) recovery. NETL is cofunding through a cooperative agreement a 7-year CO 2 sequestration/ecbm project to evaluate methane recovery and CO 2 adsorption and storage in an unminable coal seam in northern West Virginia. The project uses horizontal injectors and producers (2). The well pattern consists of four 3000-ft horizontal wells, forming a square perimeter, and four horizontal wells that radiate from the center of the pattern orthogonal to the perimeter wells, forming a plus sign within the pattern. Horizontal wells are used because they provide high connectivity with the cleat system of the coal seam, thereby improving production and injection performance. The authors of this work have previously examined the performance of this well configuration in a series of papers (3-8). These papers served to identify reservoir and operational parameters that have an important effect on project performance. As expected, the length of the injectors was found to control the aerial sweep of the injected fluid, while the average reservoir pressure was found to determine the amount of both the displaced and displacing chemical species that remain sorbed in place at the end of the project. The diffusion time constant was found to be unimportant if it is much less (about an order of magnitude less) than the total injection time. In our previous work the absolute permeability of the cleat structure was considered to be constant. The conductivity of the cleat structure can vary in two ways. The first is the variation due to saturation of flowing phases, gas and brine, and is well known (in the oil and gas industry) as a relative permeability effect. This effect is a characteristic of a coal seam and is incorporated into the transport formulation using the available coal specific relative permeability relationship. The second, effect on the conductivity of a coal is due to effective stresses within the coal seams (9), where the effective stress represents the difference between the total stress and pore fluid pressure. In coal seams the effective

3 stress is influenced by initial confining stress, fluid pressure changes, and shrinkage/swelling in the coal matrix. Tables 1 and 2 summarize the essential physical properties assigned to the copal seam in our previous and current investigations. The dependence of permeability to confining pressure in oil and gas bearing sandstone was documented early in the work of Dobrynin (10). Later, McKee et al. (11) investigated stress-dependent permeability and porosity for coal and other geologic formations and developed a relationship showing an exponential decrease of permeability with increasing effective confining stress. The coal matrix shrinks during primary production of methane as methane desorbs from coal, increasing cleat width. The injection of CO 2 into a coal seam during a ECBM/CO 2 sequestration project will cause matrix swelling and reduce cleat spacing, and consequently permeability and gas flow rate. Harpalani and Schraufnagel (12) conducted a coal matrix shrinkage study on a coal sample of interest to coalbed methane recovery, from the Piceance Basin. They reported a shrinkage coefficient of 6.2*10-6 psi -1. Seidle (13) measured coal matrix shrinkage coefficients at reservoir conditions using coal samples from the San Juan Basin. He reported ratios of cleat porosity and permeability at other pressures, to cleat porosity at initial pressure. Porosity changes due to matrix shrinkage were found to be in the range, while fractional permeability changes due to matrix shrinkage were found to be in the range. The coal sample was subjected to a methane cycle up to 2000psi, followed by a helium cycle, and lastly to a CO 2 cycle up to 900 psi. Palmer and Mansoori (14) developed a more comprehensive model for the stress dependent permeability including both stress effects and matrix shrinkage in the same equation. Their model also predicts pore volume compressibility, which is not constant, as commonly assumed previously. A model study on the effects of matrix shrinkage on permeability was also developed by Sawyer (15) and was incorporated into the COMET coalbed methane reservoir simulator of Advanced Resources International (ARI). Pekot and Reeves (16) presented a comparative study, applying the Palmer and Mansoori and Sawyer models. They concluded that the two models provide equivalent results for the most common coalbed methane (CBM) reservoir conditions. Shi and Durucan (17) improved their permeability model developed for primary CBM recovery by adding the effect of shrinkage and swelling associated with multicomponent gas adsorption and desorption. However, the resulting permeability model was not validated, due to the lack of representative field data. In this study, the Palmer-Mansoori model was implemented in PSU-COALCOMP, a state-of-the-art coal bed methane simulator (18), to include matrix shrinkage and swelling. We address the influence of operating parameters such as injector length and injection pressure on the amounts of CO 2 sequestered and methane recovered for isotropic and anisotropic cases, using a range of elastic moduli typical for coal formations. Then, we

4 compare the results with previous simulations to determine the influence of shrinkage/swelling on the efficiency of the sequestration project. Incorporation of Shrinkage and Swelling in PSU-COALCOMP Numerical Simulator PSU-COALCOMP is a two-phase, multi-dimensional, dual porosity compositional coalbed methane reservoir simulator. It was developed within the Petroleum and Natural Gas Engineering program of The Pennsylvania State University by Manik and Ertekin (18). The code treats the multi-component sorption that takes place within the coal matrix. The multi-component sorption model uses the Peng-Robinson (19) equation of state and the ideal adsorbate solution (IAS) theory to calculate the required thermodynamic functions. Three different models are provided for the sorption isotherms within the code: Langmuir, Toth, and UNILAN. The Langmuir is a two-constant model, while the other two are three-constant models. The gas/water flow within the cleat system is simulated by the standard two-phase Darcy model based on relative permeabilities. Laboratory and field data demonstrate that coal matrix shrinkage causes changes of cleat and fracture system porosity that can have a serious effect on coal reservoir permeability. Due to changes in permeability the methane recovery and injectivity of CO 2 will be affected. The following two matrix shrinkage and swelling models have been incorporated into PSU-COALCOMP: Model I: ARI, Sawyer, et al. (15) pi φ = φi [ 1 + c p ( p pi )] cm ( 1 φi ) ( C Ci ) C i Model II: Palmer and Mansoori, (14) Am K bp bpi φ = φ + + i 1 p pi c0 1 φi M 1+ bp 1+ bp 1 K A m = + f 1 β, M M 1 ν ( )( ) M = E, 1+ ν 1 2ν ( ) i and M 1+ ν K =, 3 1 ν where c m = matrix shrinkage compressibility, psi -1. C = reservoir gas concentration, e.g. SCF/ton C i = initial reservoir gas concentration, e.g., SCF/ton c p = pore volume compressibility, psi -1.

5 c 0,b = parameters of Langmuir curve match to volumetric strain change f = fraction, [0,1] K = constrained axial modulus, psi. M = bulk modulus, psi. E = Young s modulus, psi ν = Poisson s ratio p i = the reservoir initial pressure, psi. β = grain compressibility, psi -1. φ = porosity, fraction. = initial porosity, fraction. φ i After values of porosities are calculated from one of the expressions given above, new permeability values are obtained from k k i 3 φ =. φi Through this equation, it is assumed that permeability and porosity values are linked to each other through a cubic relationship. An option was added to select between the two shrinkage and swelling models. Physical Properties of Coal Physical properties of coal change considerably from one coal seam to another. They also change within the seam. The grade, type, and rank of the coal are generally used for coal classification. The rank, representing the maturation level, most influences the mechanical properties of coal. In the Palmer and Mansoori model, changes in porosity and permeability depend heavily on the axial and bulk modulus of coal. However, these moduli can be calculated from Young s modulus (E) and Poisson s ratio (ν). These primary material constants are generally listed in tables that characterize physical properties of various formations. The literature contains several sources of these characteristic constants for coal (20-28). The American Society for Testing and Materials (ASTM) ranks coals (20) into four classes that it passes through during its maturation: lignite, sub bituminous, bituminous, and anthracite. Further subgrouping expands the listing to 13 groups (21). There are certain parameters that determine the coal rank. One of them is the carbon content, which can be reported on a dry, ash-free (daf) basis. Coalbeds are organic formations but contain about % inorganic material. Table 3 lists experimental, elastic data for coals as summarized by Berkowitz (22) and reported by different investigators (23-26). In Table 3 Young s modulus ranges from less than 1*10 10 dyne/cm 2 to greater than 14*10 10 dyne/cm 2 (equivalent to to psi). Table 3 indicates that Young s modulus is relatively insensitive to coal rank for

6 carbon contents up to 92-93%. The values rise rapidly only among more or less fully developed anthracites, which have carbon contents greater than 92%. Rogers (27) presented in his book a plot developed by van Krevelen, (28) which illustrates the change of Young s modulus with carbon content. It can be recognized in the plot that Young s modulus remains constant, around 6*10 5 psi up to 91 % carbon content. Thus, both Berkowitz s and van Krevelen s data support the conclusion that Young s modulus remains constant at around 6*10 5 psi for the bituminous rank coals. Coals of the bituminous class are of the greatest interest for sequestration, because the physical and mechanical properties of the coal at this rank are optimum. Palmer and Mansoori (14) gave values of Poisson s ratios of 0.2 for a San Juan coal core and 0.39 for the Large- Scale San Juan Basin, and Young s moduli of 3.3*10 5 psi and 12.1*10 5 psi. Recently, Stutz et al. (29) listed a Young s modulus of 5*10 5 psi, and a Poisson s ratio of 0.2 for Ferron Coal in the Helper field near Price, Utah. Consequently, in our study we used the range of values listed in Table 2. Methodology Using the PSU-COALCOMP simulator, we simulated injection of CO 2 into a coal seam with concomitant methane production. In line with earlier work (4), we used a well pattern consisting of four horizontal wells surrounding a square area of 3000ft x 3000ft and two horizontal wells of varying lengths placed at the center of the square in a plus configuration. The properties of the coal seam and operating parameters were as shown in Table 1. During primary production, which lasted for 115 days, methane was produced from all wells. Then, the wells were shut in for one day and the external wells continued as producers while the internal plus pattern wells were converted to injectors of carbon dioxide. Once the concentration of CO 2 in the produced stream became greater than 10%, the project was assumed complete. The simulations were designed to mimic the behavior of a single square within an extended pattern of many squares; that is, methane was produced only from within (and CO 2 sequestered only within) the boundaries of the external, production wells. We completed several simulations, changing the injector length, sorption time constant, permeability anisotropy ratio, Young s modulus, and Poisson s ratio. For these simulations, the parameter values were all used as shown in Table 1, except that the value of Young s modulus was 4.5x10 5 psi, and the Poisson ratio was either 0.32 (simulations labeled K1) or 0.39 (simulations labeled K2). These numbers are well within the ranges of values that others have used, as described above. Other elastic properties are as shown in Table 2, and are the same values as those used by others (14,16). For representative values of Young s modulus and Poisson s ratio, the total amounts of CO 2 sequestered and methane produced were compared to the results from simulations without shrinkage and swelling incorporated, all other variables being equal. Several other runs were made to study the sensitivity of methane production and CO 2 sequestration to the values of the mechanical parameters, so that a large range of Young s modulus and Poisson s ratio were used (see Table 2). All runs with shrinkage and swelling used the Palmer-Mansoori option in the PSU-COALCOMP code.

7 Results Figures 1-2 show the amounts of carbon dioxide sequestered and methane produced for the base cases, where shrinkage and swelling are not included. In these simulations, we varied the injector length for isotropic (Fig. 1) and anisotropic (Figs. 2) coal seams. (For the anisotropic case, the injectors in the direction of the highest permeability were held constant at 500ft while the other injectors lengths were varied.) Simulations were run at two different sorption time constants. In Figures 3-4, simulations were performed for the same circumstances, except that shrinkage and swelling were included. Two different sets of geomechanical properties labeled as K1 and K2 were used (see the descriptions given earlier). For the lower sorption time constant (5.8 days) and an isotropic coal seam, there were a few differences between the inelastic case and the elastic cases. Inclusion of shrinkage and swelling in the simulations reduced both the amount of methane produced and the amount of CO 2 sequestered. The lower Young s modulus cases gave the lowest volumes. However, the percent change in the optimum CH 4 volumes were only about 5%, while the change for CO 2 was on the order of 10%. The permeability increases more during the production phase for the lower Young s modulus, so more methane is removed during that phase. However, possibly because the CO 2 stream is less diluted by the methane, it reaches its 10% concentration in the production stream more quickly for the lower υ case, and therefore the total methane removed is lower. Interestingly, if one continues the simulation past the project end time, the rate of methane production increases noticeably for the elastic cases, suggesting that for a larger pattern, these results may differ both qualitatively and quantitatively. Additionally, for the elastic cases, at the lower injector lengths, the amount of methane that was produced actually declined with decreasing injector length (i.e., a maximum occurred at around 400 ft injectors); for the inelastic case, no maximum was found above 200 ft. In the inelastic case, the shorter injectors had produced higher methane volumes, because it took longer for breakthrough of CO 2 to occur during the injection phase and there was better sweep efficiency. In the elastic case, the shortest (300 ft) injectors simulated did not bring the pressure in the reservoir down so far as some of the longer injectors; therefore, the coal permeability did not increase as much due to elastic properties, and the amount of methane produced during the production phase was lower than for the longer injectors. For the longer sorption time constant (~58 days) used, again the amount of both the CH 4 and CO 2 decreased with the assumption of coal elasticity, and the greater difference occurred with the lower Poisson s ratio. The percentage decreases were a bit higher for the larger time constant approximately 7% for methane and 25% for CO 2. Again, the project time was shorter for the elastic coal seam. There were no maxima for methane production for the larger time constant. However, for shorter injectors, increasing the injection pressure had opposing effects on CO 2 sequestration, depending on whether the coal was elastic or not, as can be seen in Fig. 4b. In the inelastic case, the highest injection pressure gave the best sequestration, but in the elastic case, the highest injection pressure gave the worst sequestration. This is because there was a tradeoff between the

8 amount of CO 2 sorbed per unit volume and the sweep efficiency of the injected gas. When the sorption time constant is small or negligible, the higher the pressure, the greater the amount of CO 2 contained in each gram of coal; so, since the coal holds so much more CO 2 per unit of swept area, the overall amount sequestered is higher. However, when the sorption time constant is high, the CO 2 flows through the coal faster than it diffuses into the coal matrix, the sweep for the higher injection pressures is not very good, and there is not as much sorbed methane per unit area of coal to balance the effects of sweep. This is most true for longer injectors. In the comparison of elastic vs. inelastic coal, the difference is probably due to one of changes of permeability around the injection well. As CO 2 is sorbed onto the coal and the coal matrix swells, the cleat porosity and permeability around the injection well decrease. Therefore, the constant pressure injection rate of CO 2 decreases with time, and the overall amount of CO 2 injected is lower. When the effects of high sorption time constant and coal swelling combine, this causes higher injection pressures to give poorer performance, despite the greater amount of CO 2 sorbed per unit coal. For an anisotropic coal seam with permeability ratio 2:1, the differences between the elastic and inelastic cases were less than for an isotropic seam, as can be seen in Figures 5-8. As for the isotropic coals, the elasticity of the coals seems to bring the curves closer together, implying that the injection pressure has less of an effect. Again, for the higher sorption time constant, the lowest injection pressure gave the best sequestration. However, it appears that the optimum injector lengths were the same for both inelastic and elastic coals for the well pattern and operating conditions considered. Finally, some simulations were performed to study the sensitivity of methane production and carbon sequestration to elastic properties of coal: specifically, Poisson s ratio and Young s modulus. Figures 9-10 show the plots of methane produced and carbon dioxide sequestered vs. Poisson s ratio at different values of Young s modulus for reasonable values of coal parameters and operating conditions: permeability ratio 2:1, injection pressure 500 psi, longer injection well length 800 ft, and sorption time constant ~58 days. All other parameters were the same as in Table 1, except the cleat porosity, which was varied from 0.5% to 1.0%. Poisson's ratio was varied from 0.2 to 0.4 in increments of 0.05, and Young s modulus was varied from 5.0 x 10 5 to 1.0 x From Figures 9-10, it can be seen clearly that the amounts of both methane produced and carbon dioxide sequestered increased with increasing Poisson s ratio and with decreasing Young s modulus. For the situations studied here, the magnitude of the differences was not very great. In Figure 9, for the 0.5% cleat porosity, the percent difference between the lowest and highest amounts of methane produced was around 8%, while for CO 2, it was around 10%. For the larger cleat porosity, the effects of the elastic properties were less, with again about an 8% change for methane, but only a 4% change for CO 2. It should also be noted here that for larger patterns, the effects of elastic properties may be greater. Conclusions

9 Although the overall sensitivity of production and sequestration volumes to the variation in elastic properties was not very large, a number of notable conclusions have come from this study: 1. In all cases, the amounts of carbon dioxide sequestered and methane produced were lower when the elastic properties of coal were included; therefore, excluding these properties will overestimate the benefits of a project. 2. The greatest differences between elastic and inelastic coal simulations were in the isotropic case, when percent changes were as high as 7% for CH 4 produced and 25% for CO 2 sequestered.. 3. For elastic coal seams with long sorption time constants, lower injection pressures produced the better results. This was different from inelastic seams, where higher injection pressures were more effective. 4. For the isotropic coal seam studied, when the sorption time constant was short, the shortest injectors did not give the best methane recovery; there was a maximum at around 400 ft. 5. For the seam properties and operating conditions studied in the 2:1 permeability ratio case, the percentage change due to variation in elastic properties was fairly small (<10%). 6. As Poisson s ratio increased, the amount of CH 4 produced and CO 2 sequestered increased. As Young s modulus decreased, the amount of CH 4 produced and CO 2 sequestered increased. References: 1. National Energy Technology Laboratory, Carbon Sequestration Technology Roadmap and Program Plan, U.S. Department of Energy, March 12, Cairns, G.: Enhanced Coal Bed Methane (CBM) Recovery and CO 2 Sequestration in an Unminable Coal Seam, proceedings, Second Annual Conference on CO 2 Sequestration, Alexandria, VA, May 5-9, Sams, W.N., Bromhal, G., Jikich, S.A., Odusote O., Ertekin, T., Smith, D.H.: Reservoir Simulations for Enhanced Coalbed Methane Production/Coal-Seam Sequestration of Carbon Dioxide, Proceedings, Pittsburgh Coal Symposium, Pittsburgh, PA, September 23-26, Bromhal, G., Sams, W.N., Jikich, S.A., Odusote, O., Ertekin, T, and Smith, D.H.: Reservoir Simulation of the Effects of Anisotropy on ECBM Production. CO 2 Sequestration with Horizontal Wells, Proceedings, 2003 International Coalbed

10 Methane Symposium, Tuscaloosa, AL, May 7-8, Sams, W.N, Bromhal, G., Jikich, S.A., Odusote, O., Ertekin, T., Smith, D.H.: Simulating Carbon Dioxide Sequestration/ECBM Production in Coal Seams: Effects of Coal Properties and Operational Parameters, paper SPE 78691, presented at the SPE Eastern Regional Meeting, Lexington, KY, October 23-26, Sams, W.N., Bromhal, G., Jikich, S. A., Odusote, O., Ertekin, T, and Smith, D.H.: Using Reservoir Simulation to Evaluate the Effect of Uncertainties in Reservoir Properties on the Design of a Pilot Project for Sequestration of Carbon Dioxide and Enhanced Coalbed Methane Production, Proceedings, 2003 International Coalbed Methane Symposium, Tuscaloosa, AL, May 7-8, 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 Other Coal Properties paper SPE 84423, presented at the SPE National Meeting, Denver, CO, October 5-8, Sams, W.N, Bromhal, G., Jikich, S.A., Ertekin, T., Smith, D.H.: Design and Operational Considerations of a Pilot Project for Sequestration of Carbon Dioxide and Enhanced Coalbed Methane Production in an Eastern Coal Seam, to be presented at the 2004 International Coalbed Methane Symposium, Tuscaloosa, AL, May 5-6, Gray, I.: Reservoir Engineering in Coal Seams: Part 1 The Physical Process of gas storage and Movement in Coal Seams, SPE Reservoir Engineering Journal, February 1987, pp Dobrynin, V.M.: Effect of Overburden Pressure on Some Properties of Sandstones, Society of Petroleum Engineering Journal, December 1962, pp McKee, C.R., Bumb, A.C., Koenig, R.A.: Stress Dependent Permeability and Porosity of Coal and Other geologic Formations, SPE Formation Evaluation Journal, March 1988, pp Harpalani, S., Schraufnagel, R.A.: Influence of Matrix Shrinkage and Compressibility on Gas Production From Coalbed Methane Reservoirs, paper SPE 20729, Proceedings, SPE Annual Technical Conference, New-Orleans, LA, September Seidle, J.P, Huitt, L.G.: Experimental Measurement of Coal Matrix Shrinkage Due to Gas Desorption and Implications for Cleat Permeability Increases, Proceedings, International Meeting on Petroleum Engineering, Beijing, China, November, Palmer, I. and J. Mansoori.: How Permeability Depends on Stress and Pore

11 Pressure in Coalbeds: A New Model, paper SPE 36737, Proceedings, SPE Annual Technical Conference, Denver, CO, 3-6 October, Sawyer, W. K., G. W. Paul, and R. A Schraufnagel: Development and Application of a 3D Coalbed Simulator, paper CIM/SPE , Proceedings of the Petroleum Society CIM, Calgary, June, Pekot, L.J., Reeves, S.R.: Modeling the Effects of Matrix Shrinkage and Differential Swelling on Coalbed Methane Recovery and Carbon Sequestration, Proceedings of 2003 International Coalbed Methane Symposium, Tuscaloosa, AL, 5-9 May, Shi, J.Q., Durucan, S. Modeling of Enhanced Methane Recovery and CO 2 Sequestration in Deep Coal Seams: the impact of Coal matrix Shrinkage/ Swelling on Coal Permeability Proceedings of 2003 International Coalbed Methane Symposium, Tuscaloosa, AL, May 7-8, Manik, J., Ertekin, T., Kohler, T. E.: "Development and Validation of a Compositional Coalbed Simulator," Journal of Canadian Petroleum Technology, Vol. 41, No. 4, April 2003, pp Peng, D.Y.; Robinson, D.B.: A New Two-Constant Equation of State, Ind. Eng. Chem. Fundam: 15,.1976, ASTM D (Proximate Analysis). 21. Stach E. et al.:. Textbook of Coal Petrology, 3 rd ed., p. 42. Borntraeger, Stuttgart and Berlin, Berkowitz, N.: An Introduction to Coal Technology, p.87 Academic, New York. 23. Heywood, H. Proceedings, Conference, Ultrafine Structures, Coals Cokes p 172. BCURA, London, Morgans, W. T. A and Terry, N. B. Fuel 37, 201 (1958) 25. Schuyer, J., Dikstra, H. and van Krevelen, D. W. Fuel 33, 409 (1954) 26. Bangham, D. H and Maggs, F. A. P.: Proceedings, Conference, Ultrafine Structures, Coals Cokes Rogers, R. E. Coalbed Methane: Principles and Practice. p.296, Prentice Hall, Englewood Cliffs, N.J., Van Krevelen, D.W. Coal. Coal Science and Technology 3, New York: Elsevier Scientific Publishing Co., Stutz, H.L., Victor, D.J., Fisher, M.K., Griffin, L.G., Weijers,L., Calibrating

12 Coal Bed Methane Fracture geometry in the Helper Utah field Using Treatment Well Tiltmeters, paper SPE 77443, Proceedings, SPE Annual Technical Conference, San Antonio, TX, 29September-2 October 2002.

13 Table 1. Parameters of coal seam used in simulation study. Table 1: Default system (Base case) Property Appalachian Basin Reservoir Drainage Area 3000ft. x 3000ft. Reservoir Thickness 2ft Coal-cleat Porosity 0.1% Lateral Permeability (absolute) 8md (face); 4,8 md (butt) Initial Pressure 700 psia Rock Density 1.4 g/cm 3 Micropore diffusion coefficient 3.95E-05 ft 2 /day Cleat/Fracture Spacing 0.5 in Sorption time constant 5.8 days, 58 days Sorption Volume constant (CH 4, CO 2 ) 600 SCF/ton, 1500 SCF/ton Sorption Pressure constant (CH 4, CO 2 ) 700 psia, 300 psia Sorption Saturation Pressure 800psia (saturated condition) Critical Gas Saturation 0.0 % Critical Water Saturation 10.0% Initial Water Saturation 40% Initial Mole Fraction of Gas (CH 4, CO 2 ) 100%, 0% Reservoir Temperature 113 o F Wellbore Radius 0.5 ft Horizontal well length 300 ft ft Skin 0.0 Coalface Pressure at Producers 100 psia Coalface Pressure at Injectors 300 psia 700 psia

14 Table 2. Values of Young s modulus, Poisson s ratio, and cleat porosity used to study the sensitivity of production and sequestration results to elastic properties of coal. Mechanical Property Young s Modulus (psi) 5.0x10 5 ; 7.5x10 5 ; 1.0x10 6 Poisson s ratio 0.2; 0.25; 0.3; 0.35; 0.4 Cleat porosity 0.5%; 1.0% b c f 0.5 β, grain compressibility, 0.0

15 Table 3. Young s modulus for different coal types from Berkowitz (22) Heywood Anthracite no.1 Anthracite no.2 Bituminous coal ( bright, UK) Bituminous coal ( dull, UK) Bituminous coal (Illinois) Cannel coal Morgan and Terry Anthracite (average value) Bituminous coal (average value) Schuyer et al; carbon, % daf Bangham and Maggs; carbon, % daf E (*10 10 dyne/cm 2 ) Parallel to Perpendicular to bedding plane bedding plane

16 Inj pressure=300psia Inj pressure=400psia Inj pressure=500psia Inj pressure=600psia Inj pressure=700psia Methane Produced (MMSCF) (a) Carbon Dioxide Retained (MMSCF) Inj pressure=300psia Inj pressure=400psia Inj pressure=500psia Inj pressure=600psia Inj pressure=700psia 170 (b) Figure 1. Shows amount of (a) methane produced and (b) carbon dioxide sequestered for an inelastic coal with isotropic permeability. The sorption time constant is approximately 5.8 days. Length of central injectors is varied systematically for multiple injection pressures.

17 Methane Produced (MMSCF) Inj pressure=300psia Inj pressure=400psia Inj pressure=500psia Inj pressure=600psia Inj pressure=700psia 110 (a) Carbon Dioxide Retained (MMSCF) Inj pressure=300psia Inj pressure=400psia Inj pressure=500psia Inj pressure=600psia Inj pressure=700psia (b) Figure 2. Shows amount of (a) methane produced and (b) carbon dioxide sequestered for an inelastic coal with isotropic permeability. The sorption time constant is approximately 58 days. Length of central injectors is varied systematically for multiple injection pressures.

18 Methane Produced (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Carbon Dioxide Sequestered (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Figure 3. Shows amount of (a) methane produced and (b) carbon dioxide sequestered for an inelastic coal with isotropic permeability. The sorption time constant is approximately 5.8 days.

19 Methane Produced (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Carbon Dioxide Sequestered (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Figure 4. Shows amount of (a) methane produced and (b) carbon dioxide sequestered for an inelastic coal with isotropic permeability. The sorption time constant is approximately 58 days.

20 (a) Methane Produced (MMSCF) Inj Pressure=300psia Inj Pressure=400psia Inj Pressure=500psia Inj Pressure=600psia Inj Pressure=700psia Carbon Dioxide Sequestered (MMSCF) Inj Pressure=300psia Inj Pressure=400psia Inj Pressure=500psia Inj Pressure=600psia Inj Pressure=700psia (b) Figure 5. Shows amount of (a) methane produced and (b) carbon dioxide sequestered when permeability anisotropy ratio is 2:1 and the sorption time constant is approximately 5.8 days. Length of longest injector (in direction of lower permeability) is varied systematically for multiple injection pressures.

21 (a) Methane Produced (MMSCF) Inj Pressure=300psia Inj Pressure=400psia Inj Pressure=500psia 20 Inj Pressure=600psia Inj Pressure=700psia Carbon Dioxide Sequestered (MMSCF) Inj Pressure=300psia Inj Pressure=400psia Inj Pressure=500psia Inj Pressure=600psia Inj Pressure=700psia (b) Figure 6. Shows amount of (a) methane produced and (b) carbon dioxide sequestered when permeability anisotropy ratio is 2:1 and the sorption time constant is approximately 58 days. Inelastic. Length of longest injector (in direction of lower permeability) is varied systematically for multiple injection pressures.

22 Methane Produced (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Carbon Dioxide Sequestered (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Figure 7. Shows amount of (a) methane produced and (b) carbon dioxide sequestered when permeability anisotropy ratio is 2:1 and the sorption time constant is approximately 5.8 days. Elastic. Length of longest injector (in direction of lower permeability) is varied systematically for multiple injection pressures.

23 Methane Produced (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Carbon Dioxide Sequestered (MMSCF) inj pressure=300psi, K1 inj pressure=400psi, K1 inj pressure=500psi, K1 inj pressure=600psi, K1 inj pressure=700psi, K1 inj pressure=300psi, K2 inj pressure=400psi, K2 inj pressure=500psi, K2 inj pressure=600psi, K2 inj pressure=700psi, K Figure 8. Shows amount of (a) methane produced and (b) carbon dioxide sequestered when permeability anisotropy ratio is 2:1 and the sorption time constant is approximately 58 days. Elastic. Length of longest injector (in direction of lower permeability) is varied systematically for multiple injection pressures.

24 Methane produced (MMSCF) E=5.0e5 psi E=7.5e5 psi E=1.0e6 psi Poissons ratio CO2 sequestered (MMSCF) E=5.0e5 psi E=7.5e5 psi E=1.0e6 psi Poissons ratio Figure 9. Shows amount of (a) methane produced and (b) carbon dioxide sequestered as a function of Poisson ratio for different values of E, when permeability anisotropy ratio is 2:1 and the sorption time constant is approximately 58 days. Cleat porosity is 0.5%.

25 Methane produced (MMSCF) E=5.0e5 psi E=7.5e5 psi E=1.0e6 psi Poissons ratio CO2 sequestered (MMSCF) E=5.0e5 psi 244 E=7.5e5 psi E=1.0e6 psi Poissons ratio Figure 10. Shows amount of (a) methane produced and (b) carbon dioxide sequestered as a function of Poisson ratio for different values of E, when permeability anisotropy ratio is 2:1 and the sorption time constant is approximately 58 days. Cleat porosity is 1.0%.

26