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Petrographic work on thin sections from rock samples collected in tight gas sandstones of the western Canada sedimentary basin (WCSB) shows that the sandstones are composed of intergranular, microfracture and slot, and isolated noneffective porosities. The petrographic observations of these triple-porosity rocks have led to a petrophysical interpretation with the use of a triple-porosity model. Tight gas reservoirs are very complex heterogeneous systems that have been evaluated in the past mostly with single-porosity models. We propose that these types of reservoirs can be represented better by triple-porosity models for more rigorous quantitative petrophysical characterization. The triple-porosity model discussed in this paper fits the petrographic observations very well, leading to a more rigorous characterization of effective and noneffective porosity. The petrographic and core-calibrated triple-porosity model is then used for well-log interpretation of those wells when these data are not available. The result is a reasonable quantitative characterization of the tight gas reservoir that can be used for improving hydraulic-fracturing design, flow-units determination, reservoir engineering, and simulation studies. The data can be determined at room conditions and simulated conditions of net stress. It is concluded that honoring with a triple-porosity model the different types of porosities observed in thin sections and cores leads to more-rigorous and -useful petrophysical interpretations that can be linked to gas productivity. [ABSTRACT FROM AUTHOR]

Coalbed-methane (CBM) reservoirs commonly exhibit two-phase-flow (gas plus water) characteristics; however, commercial CBM production is 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 with techniques commonly applied to conventional reservoirs. Complicating application, however, is the unique nature of CBM reservoirs; coal gas-storage and -transport mechanisms differ substantially from conventional reservoirs. Single-phase CBM reservoirs may also display complex reservoir behavior such as multilayer characteristics, dual-porosity effects, and permeability anisotropy. The current work illustrates how single-well production-data-analysis (PDA) techniques, such as type curve, flowing material balance (FMB), and pressure-transient (PT) analysis, may be altered to analyze single-phase CBM wells. Examples of how reservoir inputs to the PDA techniques and subsequent calculations are modified to account for CBM-reservoir behavior are given. This paper demonstrates, by simulated and field examples, that reasonable reservoir and stimulation estimates can be obtained from PDA of CBM reservoirs only if appropriate reservoir inputs (i.e., desorption compressibility, fracture porosity) are used in the analysis. As the field examples demonstrate, type-curve, FMB, and PT analysis methods for PDA are not used in isolation for reservoir-property estimation, but rather as a starting point for single-well and multiwell reservoir simulation, which is then used to history match and forecast CBM-well production (e.g., for reserves assignment). CBM reservoirs have the potential for permeability anisotropy because of their naturally fractured nature, which may complicate PDA. To study the effects of permeability anisotropy upon production, a 2D, 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. Multilayer reservoir characteristics may also be observed with CBM reservoirs because of vertical heterogeneity, or in cases where the coals are commingled with conventional (sandstone) reservoirs. In these cases, the type-curve, FMB, and PT analysis techniques are difficult to apply with confidence. Methods and tools for analyzing multilayer CBM (plus sand) reservoirs are presented. Using simulated and field examples, it is demonstrated that unique reservoir properties may be assigned to individual layers from commingled (multilayer) production in the simple two-layer case. [ABSTRACT FROM AUTHOR]