0 200 400 600 800 1000 1200
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
insitu gas content, scf/ton
depth, feet UPRC-9 UPRC-1 UPRC-33
Fig. 4–11. Great Divide Basin—gas content vs. depth (all samples desorbed)
Nomenclature
a Mass fraction ash
C0 Initial sorbed gas concentration, cm3/g or scf/ton Ca Average sorbed gas concentration, cm3/g or scf/ton
Cb Sorbed gas concentration at the boundary, cm3/g or scf/ton CDa Dimensionless sorbed gas concentration
CF Smith and Williams correction factor [eq. (4.5)]
D Diffusion coefficient, cm2/min D/r2 Diffusivity, min–1
LTR Smith and Williams lost time ratio [eq. (4.3)]
m Slope of square root of time plot, cm3/min1/2 mm Mass fraction mineral matter
r Particle radius, cm S Mass fraction of sulfur
STR Smith and Williams surface time ratio [eq. (4.4)]
t Time, min
t25% Time to collect 25% of the total desorbed gas volume, min td Time for the chips to travel from the drillbit to the surface, min tD Dimensionless time
ts Time until sample sealing, min Vdes Desorbed gas, cm3
VL Lost gas, cm3
VLD Sum of lost plus desorbed gas, cm3
Vtot Smith and Williams total gas emitted, cm3 or scf
References
1. Bertard, C. B., Bruyet, B., and Gunther, J. 1970. Determination of desorbable gas concentration of coal (direct method).
International Journal of Rock Mechanics and Mining Sciences. V. 7. p. 43; and Kissell, F. N., McCulloch, C. M., and Elder, C. H.
1973. The Direct Method of Determining Methane Content of Coalbeds for Ventilation Design. U.S. Bureau of Mines. RI 7767.
2. Kissell, F. N., et al. 1973; Smith, D. M., and Williams, F. L. 1981. A new technique for determining the methane content of coal.
In Proceedings of the 16th Intersociety Energy Conversion Engineering Conference. New York: American Society of Mechanical Engineers. p. 1,272; Chase, R. W. 1979. A Comparison of Methods Used for Determining the Natural Gas Content of Coalbeds from Exploratory Cores. U. S. Dept of Energy. METC/CR-79/18; and 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, Australia, November 4–7.
3. Bertard, C. B., et al. 1970; and Kissell, F. N., et al. 1973.
4. Gas Research Institute. 1995. A Guide to Determining Coalbed Gas Content. GRI-94/0396. Chicago: Gas Research Institute.
5. Ibid.
6. Ulery, J. P., and Hyman, D. M. 1991. The modified direct method of gas content determination: Application and results. Paper 9163 in Proceedings of the 1991 International Coalbed Methane Symposium. Tuscaloosa: University of Alabama.
7. 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 1995 Joint Rocky Mountain Regional/Low Permeability Reservoirs Symposium, Denver, Colorado, March 20–22.
8. Gas Research Institute. 1995.
9. Ibid.
10. Ibid.
11. Standards Association of Australia. 1991. Australian Standard AS 3980: Guide to the Determination of Desorbable Gas Content of Coal Seams—Direct Method. North Sydney, NSW: Standards Association of Australia.
12. Saghafi, A., Williams, D. J., and Roberts, D. B. 1995. Determination of Coal Gas Content by Quick Crushing Method. CSIRO Investigation Rep. CET/IR391R.
13. Gas Research Institute. 1995.
14. Scott, A. R. 1994. Composition of coalbed gases. In Situ. V. 18 (no. 2). p. 185.
15. Ulery, J. P., and Hyman, D. M. 1991.
16. 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. Tuscaloosa: University of Alabama.
17. 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, New Orleans, Louisiana, September 23–26.
18. Bertard, C. B., et al. 1970; and Smith, D. M., and Williams, F. L. 1984. Diffusional effects in the recovery of methane from coalbeds. Society of Petroleum Engineers Journal. V. 24 (no. 5). p. 529.
19. Kissell, F.N., et al. 1973.
20. Mavor, M. J., et al. 1990.
21. Kissell, F. N., et al. 1973.
22. Mavor, M. J., et al. 1995.
23. Kissell, F. N., et al. 1973.
24. Bertard, C. B., et al. 1970.
25. Gas Research Institute. 1995.
26. Smith, D. M., and Williams, F. L. 1981.
27. Chase, R. W. 1979.
28. Lee, J., and Wattenbarger, R. A. 1996. Gas Reservoir Engineering. Richardson, Texas: Society of Petroleum Engineers.
29. Metcalfe, R. S. et al. 1991.
30. Gas Research Institute. 1995.
31. Mavor, M. J., et al. 1995.
32. 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 2000 SPE/CERI Gas Technology Symposium, Calgary, Alberta, April 3–5.
33. Mavor, M. J., et al. 1995.
34. Ibid.
35. Ulery, J. P., and Hyman, D. M. 1991.
36. Ibid.
37. Nelson, C. R., et al. 2000.
38. Mavor, M. J., et al. 1995.
39. Rightmire, C. T., Eddy, G. E., and Kirr, J. N. 1984. Coalbed Methane Resources of the United States, AAPG Studies in Geology Series
#17. Tulsa: American Association of Petroleum Geologists.
40. Donovan, W. S. 2000. Mudlogging method calculates coalbed gas content. Oil & Gas Journal. February 14, 2000. p. 64.
41. Diamond, W. P., and Schatzel, S. J. 1998. Measuring the gas content of coal: A review. International Journal of Coal Geology. V. 35 (nos. 1–4). p. 311.
42. Gas Research Institute. 1995.
43. Mavor, M. J., et al. 1995.
44. Mavor, M. J., Pratt, T. J., Nelson, C. R., and Casey, T. A. 1996. Improved Gas-In-Place Determination for Coal Gas Reservoirs.
Paper SPE 35623. Presented at the Gas Technology Symposium, Calgary, Alberta, April 28–May 1.
45. Ibid.
46. Waechter, N. B. 2003. Personal communication.
47. Kelso, B. S., Leel, W. G., Jr., and Carr, D. L. 1991. Coalbed methane resource and producibility potential of the Rock Springs Formation, Great Divide Basin, Wyoming. In Coalbed Methane of Western North America. Schwochow, S. D., Murray, D. K., and Fahy, M. F., eds. Denver: Rocky Mountain Association of Geologists. p. 201.
48. Ibid.
49. Gas Research Institute. 1995.
5
Introduction
Perhaps one of the most distinguishing elements of coals is their storage of gas by sorption. Sorption, the attachment of gas molecules to the solid surface of the coal matrix by van der Waals forces, controls coal reservoir behavior much as free gas physics dictates conventional reservoir depletion. Uptake of gas molecules to the coal matrix is sometimes labeled adsorption, while release of gas from the surface is sometimes described as desorption. In a coal deposit, sorbed gas molecules carpet the coal matrix, forming a monolayer on the surface with a density approaching that of liquid methane. As a result, the coal can store more gas by sorption on the matrix than by compression in the cleats. Coals typically contain more gas per unit volume than sandstone reservoirs at the same temperature and pressure. Sorption is a very effective method of storing gas, resulting in equivalent sandstone porosities on the order of 20% or more.
The amount of gas sorbed by a coal depends on pressure. The gas content–pressure relation for a given coal cannot be predicted from coal properties nor determined by wireline logs and must, therefore, be measured in the laboratory. Various equations have been fit to gas content–pressure data over time, but the most successful is that of Langmuir. While fitting gas content and pressure data to the Langmuir equation is straightforward, measurement of that data in the lab is time consuming and relatively expensive. The question of how many such experiments must be done to characterize a given seam, a given play, or a given basin must be addressed.
The amount of gas sorbed by a coal also depends on temperature. Transformation of the sorption capacity of a given coal measured at one temperature to another is frequently useful in exploration plays, as well as advantageous in reconciling lab data measured at off-reservoir temperatures.
Gas generated by a coal can escape over geologic time, leaving the coal holding less gas than it theoretically could. This condition, termed undersaturation, has strong economic ramifications and can be quantified by combining sorption characteristics of the given coal with desorption test results and reservoir pressure.
The opposite case, called oversaturation, where a coal appears to hold more gas than is predicted from laboratory measurements, is a physical impossibility. Reasons for such a situation are discussed.
Coals often hold a mixture of gases that is predominantly methane. Assuming this mixture to be only methane allows simplification of the sorption physics, but knowledge of the sorption behavior of the other constituent gas is required for some aspects of coal gas reservoir engineering. Single-component gas content–pressure data are used to predict sorption behavior of the gas mixture rather than measuring sorption behavior of the specific combination of gases.