Sometimes measured gas contents are higher than those calculated from an isotherm and initial reservoir pressure, resulting in apparent oversaturation of the coal. It is physically impossible for a coal deposit to be oversaturated with gas but quite possible to have an erroneous conception of gas storage in the coal. Slight degrees of apparent oversaturation are not all that rare in practice and are usually due to routine errors in desorption tests and/or laboratory measurements. Significant apparent oversaturation, on the order of 10% or more of the total gas content, is usually due to the presence of strongly sorbing gases, such as ethane or CO2, in the gas mixture sorbed on the coal.
An example of apparent oversaturation is shown in figure 5–25, based on data from Mavor et al.70 Measured gas content and the methane isotherm are on a daf basis, and the coal appears to contain roughly 50% more gas than would be expected from the isotherm. However, the produced gas included significant CO2. When the daf CO2 isotherm is included, as seen in figure 5–26, the apparent oversaturation is understood to be simply sorption of a two-component gas mixture. The isotherms and gas content are from the Southern Ute 5-7 example discussed above, and the sorbed gas contains nearly 40% CO2.
Fig. 5–26. Apparent oversaturation, CO2 and methane isotherms—San Juan Basin
Nomenclature
a = ash mass fraction
b = alternative Langmuir pressure constant, psia–1 or MPa–1 Bgi = the initial gas formation volume factor, ft3/scf
E = characteristic energy, psi-ft3/lb-mole n = a small integer, typically between 1 and 4 nc = number of component gases in gas mixture p = pressure, psia, MPa, or atm
pc = critical pressure, atm
pd = desorption pressure, psia or MPa pi = initial reservoir pressure, psia
pL = Langmuir pressure constant, psia or MPa
pLj = component j Langmuir pressure constant, psia or MPa ps = saturation vapor pressure, atm
R = universal gas constant, psi-ft3/lb-mole-deg-R Sgi = initial gas saturation, decimal
T = temperature, deg R
Tc = critical temperature, deg R
Tnbp = normal boiling point temperature, deg R V = gas content, scf/ton or cc/gm
Vj = component j gas content, scf/ton or cc/gm VL = Langmuir volume constant, scf/ton or cc/gm
VLdaf = dry, ash-free Langmuir volume constant, scf/ton or cc/gm VLis = in-situ Langmuir volume constant, scf/ton or cc/gm VLj = component j Langmuir volume constant, scf/ton or cc/gm w = equilibrium moisture mass fraction
W = sorbed gas volume, cc/gm W0 = volume of micropores, cc/gm yj = component j free gas mole fraction Greek
β = sorbate affinitiy coefficient, dimensionless ϕeq = equivalent sandstone porosity, decimal ρB = bulk coalbed density, gm/cc
References
1. Testa, S. M., and Pratt, T. J. 2003. Sample preparation for coal and shale gas resource assessment. Paper 0356. In Proceedings of the 2003 International Coalbed Methane Symposium. May 5–9. Tuscaloosa: University of Alabama; and Pratt, T. J., and Baez, L. R. G.
2003. Critical data requirements for coal and gas shale resource assessment. Paper 0367. In Proceedings of the 2003 International Coalbed Methane Symposium. May 5–9. Tuscaloosa: University of Alabama.
2. Mavor, M. J., Owen, L. B., and Pratt, T. J. 1990. Measurement and Evaluation of Coal Sorption Isotherm Data. Paper SPE 20728.
Presented at the 65th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, New Orleans, Louisiana, September 23–26; Arri, L. E., Yee, D., Morgan, W. D., and Jeansonne, M. W. 1992. Modeling Coalbed Methane Production with Binary Gas Sorption. Paper SPE 24363. Presented at the SPE Rocky Mountain Regional Meeting, Casper, Wyoming, May 18–
21; and Greaves, K. H., Owen, L. B., McLennan, J. D., and Olszewski, A. 1993. Multi-component gas adsorption-desorption behavior of coal. Paper 9353. In Proceedings of the 1993 International Coalbed Methane Symposium. Tuscaloosa: University of Alabama.
3. Arri, L. E., et al. 1992.
4. Ibid.
5. Hall, F. E., Zhou, C., Gasem, K. A. M., Robinson, Jr., R. L., and Yee, D. 1994. Adsorption of Pure Methane, Nitrogen, and Carbon Dioxide and Their Binary Mixtures on Wet Fruitland Coal. Paper SPE 29194. Presented at the SPE Eastern Regional Conference
& Exhibition, Charleston, West Virginia, November 8–10.
6. Yee, D., Seidle, J. P., and Hanson, W. B. 1993. Gas sorption on coal and measurement of gas content. Chapter 9 in Hydrocarbons from Coal, AAPG Studies in Geology #38. Law, B. E., and Rice, D. D., eds. Tulsa: American Association of Petroleum Geologists.
7. Hall, F. E., et al. 1994.
8. Hall, F. E., et al. 1994.
9. Ibid.
10. Ibid.
11. Levine, J. R. 1993. Coalification: The evolution of coal as source rock and reservoir rock for oil and gas. In Hydrocarbons from Coal, AAPG Studies in Geology #38. Law, B. E., and Rice, D. D. eds. Tulsa: American Association of Petroleum Geologists.
12. Testa, S. M., and Pratt, T. J. 2003.
13. Joubert, J. I., Grein, C. T., and Beinstock, D. 1973. Sorption of methane in moist coal. Fuel. V. 52. pp. 181–195; and Joubert, J. I., Grein, C. T., and Beinstock, D. 1974. Effect of moisture on the methane capacity of American coals. Fuel. V. 53. pp. 186–191.
14. Joubert, J. I., et al. 1974.
15. Yee, D., et al. 1993.
16. Joubert, J. I., et al. 1974.
17. Yee, D., et al. 1993.
18. Hall, F. E., et al. 1994.
19. Metcalfe, R. S., Yee, D., Seidle, J. P., and Puri, R. 1991. Review of Research Efforts in Coalbed Methane Recovery. Paper SPE 23025.
Presented at the SPE Asia-Pacific Conference, Perth, Western Australia, November 4–7.
20. Hall, F. E., et al. 1994.
21. Metcalfe, R. S., et al. 1991.
22. Gan, H., Nandi S. P., and Walker, P. L., Jr. 1972. Nature of the porosity in American coals. Fuel. V. 51. p. 272–277; and Bustin, R.
M., and Clarkson, C. R. 1999. Free gas storage in matrix porosity: A potentially significant coalbed resource in low rank coals.
Paper 9956 in Proceedings of the 1999 International Coalbed Methane Symposium. May. Tuscaloosa: University of Alabama.
23. Mavor, M. J., et al. 1990.
24. Mavor, M. J., et al. 1990; Arri, L. E., et al. 1992; and Hall, F. E., et al. 1994.
25. Levine, J. R. 1993.
26. Mavor, M. J., et al. 1990; Arri, L. E., et al. 1992; and Hall, F. E., et al. 1994.
27. Bustin, R. M., and Downey, R. A. 2002. Gas-in-place in the Powder River Basin: Coal Cores—Why Do Them? Some Field Results, Comparisons, and Suggestions. Rocky Mountain Association of Geologists 2002 Coalbed Methane Symposium, Denver, June 19.
28. Boxho, J., Stassen, P., Mücke, G., Noack, K., Jeger, C., Lescher, L., Browning, E., Dunmore, R., and Morris, I. 1980. Firedamp Drainage Handbook for the Coal Mining Industry in the European Community. Coal Directorate of the Commission of the European Communities. Essen: Verlag Glückauf GmbH. pp. 28–30.
29. Hofer, L. J. E., Bayer, J., and Anderson, R. B. 1966. Rates of Adsorption of Methane on Pocahontas and Pittsburgh Seam Coals. U.S.
Bureau of Mines Report of Investigation 6750.
30. Bustin, R. M., and Downey, R. A. 2002.
31. Ettinger, I. L., Lidin, G. D., Dimitiev, A. M., and Shaupachina, E. S. 1958. Systematic Handbook for the Determination of the Methane Content of Coal Seams from the Seam Pressure of the Gas and the Methane Capacity of Coal. Moscow: National Coal Board. Translation No. A1606/SEH.
32. Yee, D., et al. 1993.
33. Hofer, L. J. E., et al. 1966.
34. Clarkson, C. R., Bustin, R. M., and Levy, J. H. 1997. Application of the mono/multilayer and adsorption potential theories to coal methane adsorption isotherms at elevated temperature and pressure. Carbon. V. 35 (no. 12). p. 1,689.
35. Agarwal, R. K., and Schwarz, J. A. 1988. Analysis of high pressure adsorption of gases on activated carbon by potential theory.
Carbon. V. 26 (no. 6). p. 873.
36. Kapoor, A., Ritter, J. A., and Yang, R. T. 1989. On the Dubinin-Radushkevich equation for adsorption in microporous solids in the Henry’s law region. Langmuir. V. 5. p. 1,118.
37. Bustin, R. M., and Downey, R. A. 2002.
38. Ibid.
39. Earlougher, R. C., Jr. 1977. Advances in Well Test Analysis. Society of Petroleum Engineers Monograph 5. Dallas: Society of Petroleum Engineers.
40. Bustin, R. M., and Downey, R. A. 2002.
41. Ibid.
42. Ibid.
43. Metcalfe, R. S., et al. 1991.
44. Mavor, M. J., et al. 1990.
45. Nelson, C. R., Hill, D. G., and Pratt, T. J. 2000. Properties of Paleocene Fort Union Formation Canyon Seam Coal at the Triton Federal Coalbed Methane Well, Campbell County, Wyoming. Paper SPE 59786. Presented at the SPE/CERI Gas Technology Symposium, Calgary, Alberta, April 3–5.
46. Mavor, M. J., et al. 1990.
47. Nelson, C. R., et al. 2000.
48. Mavor, M. J., et al. 1990.
49. Ibid.
50. Ibid.
51. Ibid.
52. Ibid.
53. Metcalfe, R. S., et al. 1991; and Mavor, M. J., et al. 1990.
54. Metcalfe, R. S., et al. 1991.
55. Mavor, M. J., et al. 1990.
56. Rightmire, C. T., Eddy, G. E., and Kirr, J. N., eds. 1984. Coalbed Methane Resources of the United States. Tulsa: American Association of Petroleum Geologists.
57. Cox, D. O. 2001. Presentation to the Denver Section of the Society of Petroleum Evaluation Engineers. January 22.
58. Crockett, F., and Meyer, J. 2001. Update and Revision of Interim Drainage Report on Coalbed Methane Development and Drainage of Federal Land in the South Gillette Area, Campbell and Converse Counties, Wyoming T. 40–50 N., R 70–75 W. February 12.
Casper: Wyoming Bureau of Land Management.
59. Cox, D. O. 2001.
60. Ibid.
61. Mavor, M. J., et al. 1990.
62. Ibid.
63. Pratt, T. J., and Baez, L. R. G. 2003.
64. Arri, L. E., et al. 1992.
65. Ibid.; Harpalani, S., and Pariti, U. M. 1993. Study of Coal Sorption Isotherms Using a Multicomponent Gas Mixture. Paper 9356.
Presented at the International Coalbed Methane Symposium, University of Alabama, Tuscaloosa, Alabama, May 17–21; and Mavor, M. J., Pratt, T. J., and Nelson, C. R. 1995. Quantitative Evaluation of Coal Seam Gas Content Estimate Accuracy. Paper SPE 29577. Presented at the SPE Rocky Mountain Regional/Low-Permeability Reservoir Symposium, Denver, Colorado, March 20–22.
66. Arri, L. E., et al. 1992.
67. Ibid.; Harpalani, S., and Pariti, U. M. 1993; and Mavor, M. J., et al. 1995.
68. Arri, L. E., et al. 1992.
69. Mavor, M. J., et al. 1995.
70. Ibid.
71. Ibid.
6
Introduction
The ability of water and gas to flow through coal deposits varies greatly, not only from basin to basin but within a given seam and over the course of depletion. The ease with which a fluid moves through the interconnected pores and fissures of a rock is termed permeability. Of the various units used to quantify permeability, millidarcies is the most common for coals, just as for conventional reservoirs. The natural fractures, or cleats, running through a coal deposit are several orders of magnitude more permeable than the coal matrix (millidarcies or tens of millidarcies versus microdarcies) and control fluid movement through it. Coal seams are extremely heterogeneous reservoirs whose permeability depends not only on geological age, coal rank, and purity, but also on gas and water saturations, in-situ stresses, and sorbed gas content. Permeability of a coal deposit to gas and water depends on the interplay of these three influences.
For reservoir engineering purposes, permeability is often divided into absolute and relative permeabilities.
Absolute permeability is a property of the coal and not the fluids flowing through it, but it does, however, depend on stress and sorbed gas content. Laboratory measurement of absolute coal permeability is difficult and often yields different values from field-derived estimates of permeability of the seam from which the laboratory sample was obtained. Most coals contain both free gas and water, with the saturations of each varying areally and over the course of depletion. Interference between the two phases affects mobility of each. Relative permeability of gas or water is the ratio of the permeability of that phase relative to permeability when only a single phase is present.
Relative permeability of a phase depends on saturation of that phase. Coal gas-water relative permeabilities have been measured in laboratories, estimated from algebraic equations, and determined from history matching well performance with reservoir simulators.
Coals of all ages and ranks are fragile rocks, with little mechanical strength compared to conventional reservoir rocks. Even using the procedures discussed below, only the stronger samples will survive; the weaker ones will fragment. With face cleats better developed than butt cleats, coal cleat networks are visually anisotropic.
Flow behavior parallel to these cleat directions as well as perpendicular to the bedding planes thus is intuitively expected to be distinct. Cores, of course, are nominally cut vertically, with the result that both permeability and gas-water relative permeabilities measured in the laboratory reflect vertical flow characteristics (perpendicular to the bedding planes) rather than horizontal (parallel to the bedding planes). Differences in vertical flow characteristics of mechanically strong laboratory samples and those of horizontal flow in in-situ deposits are to be expected.
Laboratory-measured permeability anisotropies reported by Gash et al. included a 2:1 contrast in face and butt cleats and a 100:1 contrast between face cleat and vertical permeability.1 The same 2:1 ratio of face cleat to butt cleat permeabilities was observed in an interference test in San Juan coals.2 Horizontal permeability anisotropy of 17:1 was reported from an interference test in the Warrior Basin on the basis of soft type curve matches.3 Young et al. found horizontal permeability larger than vertical permeability by a factor of 42 through