Production Data Analysis of Single-Phase (Gas) CBM Wells
- Christopher R. Clarkson (Burlington Resources Canada) | R. Marc Bustin (U. of British Columbia) | John P. Seidle (Sproule Associates Limited)
- Document ID
- Society of Petroleum Engineers
- SPE Gas Technology Symposium, 15-17 May, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 5.5.8 History Matching, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 5.6.9 Production Forecasting, 4.1.4 Gas Processing, 5.8.2 Shale Gas, 3.3.1 Production Logging, 5.8.3 Coal Seam Gas, 5.7.1 Estimates of resource in place, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control, 5.1.1 Exploration, Development, Structural Geology, 5.4.2 Gas Injection Methods, 5.6.4 Drillstem/Well Testing, 4.5 Offshore Facilities and Subsea Systems, 5.7 Reserves Evaluation, 5.6.3 Pressure Transient Testing, 4.3.4 Scale, 5.8.1 Tight Gas
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Coalbed methane (CBM) reservoirs commonly exhibit two-phase flow (gas+water) characteristics, however commercial CBM production is also possible from single-phase (gas) coal reservoirs, as demonstrated by the recent development of the Horseshoe Canyon coals of western Canada. Commercial single-phase CBM production also occurs in some areas of the low-productivity Fruitland Coal, south-southwest of the high-productivity Fruitland Coal Fairway in the San Juan Basin, and in other CBM-producing basins of the continental United States. Production data of single-phase coal reservoirs may be analyzed using traditional techniques commonly used for conventional reservoirs. Complicating application, however, is the complex nature of coal reservoirs; coal gas storage and transport mechanisms differ substantially from conventional reservoirs. In addition, single-phase coal reservoirs may display multi-layer characteristics, dual porosity behavior, permeability anisotropy etc.
The current work illustrates how traditional single-well analysis techniques, such as type-curve and pressure transient analysis, may be altered to analyze single-phase (un-stimulated and hydraulically-fractured) CBM wells. Examples of how reservoir inputs to the type-curves and subsequent calculations are modified to account for CBM reservoir behavior are given. This paper demonstrates, using simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from production data analysis of coal reservoirs only if appropriate reservoir inputs (i.e. desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve and pressure-transient analysis methods for production data analysis are not used in isolation for reservoir property estimation, but rather as a starting point for single- and multi-well reservoir simulation, which is then used to history-match and forecast coal well production (ex. reserves assignment).
Coal reservoirs have the potential for permeability anisotropy because of their naturally-fractured nature, which may complicate production data analysis. To study the effects of permeability anisotropy upon production, a 2-D, single-phase, numerical CBM reservoir simulator was constructed to simulate single-well production assuming various permeability anisotropy ratios. Only large permeability ratios (>16:1) appear to have a significant effect upon single-well production characteristics.
Multi-layer reservoir characteristics may also be observed with coal reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve and pressure transient analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multi-layer CBM (+sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multi-layer) production in the simple 2-layer case.
Coal gas (CBM) reservoirs differ substantially from conventional gas reservoirs due to unique gas storage and transport mechanisms. Unlike conventional (sand or carbonate) reservoirs, coals act as source rocks and reservoirs to gas, and the primary gas storage mechanism is through adsorption within the microporous organic fraction, although some gas storage may occur in the free gas state (compressed in pore space), within the larger pores (macropores) and fractures. CBM reservoirs are often naturally-fractured, and may be modeled as dual (fracture+matrix porosity), or even triple porosity (fracture, matrix free- and adsorbed gas) reservoirs. Gas transport mechanisms vary, depending upon the scale and location within the reservoir. For example, gas transport at the scale of the matrix between natural fractures may be due to the mechanism of diffusion whereas Darcy flow occurs in the fracture system. Single or two-phase (gas and water) flow can exist in these reservoirs, and hence relative permeability characteristics can be important.
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