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Several investigators have reported coal permeability decreases with increasing stress, but no conceptual model has been advanced to explain this effect. To better understand the permeability of stressed coal, a theoretical and experimental program was undertaken. A common naturally fractured reservoir geometry, a collection of matchsticks, was extended to stressed coalbeds and tested against laboratory measurements using samples from the San Juan and Warrior Basins. Good agreement was obtained between theoretical behavior and laboratory data. Equations are presented for converting laboratory measured stress-permeability data to (a) in-situ permeability as a function of depth of burial in a basin, and (b) to reservoir permeability during coalbed depletion.Coal cleat compressibility, analogous to pore volume compressibility of conventional reservoirs, has historically been difficult and expensive to measure and the results of such measurements are often ambiguous. A method is presented for calculating cleat volume compressibility from stress permeability experiments, resulting in considerable savings of both time and money. Stress-permeability and cleat volume compressibility results reported here are compared with those published in the literature.Evidence in the literature indicates that coal matrix shrinks when gas is desorbed, increasing cleat permeability. Assuming a matchstick geometry and using a coal matrix shrinkage coefficient reported in the literature, the increase in cleat permeability due to matrix shrinkage was calculated. The increase in permeability due to matrix shrinkage during depletion is compared with the decrease in permeability due to increased stress.References and illustrations at end of paper.

PUBLICATION RIGHTS RESERVED PUBLICATION RIGHTS RESERVED THIS PAPER IS TO BE PRESENTED AT THE INTERNATIONAL TECHNICAL MEETING JOINTLY HOSTED BY THE PETROLEUM SOCIETY OF CIM AND THE SOCIETY OF PETROLEUM ENGINEERS IN CALGARY, JUNE 10 TO 13, 1990. DISCUSSION OF THIS PAPER IS INVITED. SUCH DISCUSSION MAY BE PRESENTED AT THE MEETING AND WILL BE CONSIDERED FOR PUBLICATION IN CIM AND SPE JOURNALS IF FILED IN WRITING WITH THE TECHNICAL PROGRAM CHAIRMAN PRIOR TO THE CONCLUSION OF THE MEETING. Abstract The recovery of gas from coalbeds is a two-step process. First, the gas diffuses through the matrix process. First, the gas diffuses through the matrix then, secondly, it flows through the cleats to the wellbore. If the release of gas fro. the matrix to the cleats is very rapid compared to the flow of gas. and water in the cleats, the desorption kinetics are relatively unimportant in modeling coalbed methane production. If the coal is well cleated, it can be production. If the coal is well cleated, it can be assumed for engineering purposes that the gas desorbs instantaneously fro. the matrix to the cleat when the pressure in the cleat decreases. This assumption alloys the adsorption of gas on the surface of she coal to be modeled as gas dissolved in an immobile oil. Conventional reservoir simulators can then be used for coalbed-methane modeling purposes. The solution gas-oil ratio of this immobile purposes. The solution gas-oil ratio of this immobile "pseudo" oil is calculated from the Langmuir adsorption isotherm constants and coalbed properties. Additional modest modifications are required in the data describing the porosity and gas-water relative permeability curves to account for the presence of permeability curves to account for the presence of the "pseudo" oil. No code modification is required. This concept has been used with several different simulators to successfully model both single well and 3-D, multiwell coalbed methane problems. A coal well simulation using this method and COMETPC, a simulator developed by ICF-Lewin, are compared. Introduction Coalbeds are naturally fractured, low pressure, water saturated gas reservoirs. While some free gas may exist in a coal deposit, the majority of the gas is sorbed on the surface of the coal matrix. When water is removed from the natural fractures of the coal, the pressure is reduced and gas is released from the matrix into the fractures. Once in the fractures, the gas flows to the wellbore. Thus coal degasification is a two-step process: desorption of gas from the coal matrix followed by flow through the fractures. The slower of these two processes will control the rate of gas production from a coal. For engineering purposes, gas production can be approximated by mathematics which focus on the dominant process. If the rate of gas desorption from the matrix is very slow compared to the rate of fluid transport in the fractures, diffusion equations need to be incorporated into a conventional simulator to describe gas production. If the release of gas from the matrix is very rapid compared to the time scale of fluid flow in the cleats, gas production can be modeled by Darcy's law only. PREVIOUS STUDIES OF CHARACTERISTIC DIFFUSION TIMES PREVIOUS STUDIES OF CHARACTERISTIC DIFFUSION TIMES Times required for various coals to desorb gas have been reported in the literature. P. 118-1 P. 118-1

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Summary 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. Introduction Commercial single-phase (gas) CBM production has been demonstrated recently in the Horseshoe Canyon coals of western Canada (Bastian et al. 2005) and previously in various basins in the US; there is currently a need for advanced PDA techniques to assist with evaluation of these reservoirs. Over the past several decades, significant advances have been made in PDA of conventional oil and gas reservoirs [select references include Fetkovich (1980), Fetkovich et al. (1987), Carter (1985), Fraim and Wattenbarger (1987), Blasingame et al. (1989, 1991), Palacio and Blasingame (1993), Fetkovich et al. (1996), Agarwal et al. (1999), and Mattar and Anderson (2003)]. These modern methods have greatly enhanced the engineers' ability to obtain quantitative information about reservoir properties and stimulation/damage from data that are gathered routinely during the producing life of a well, such as production data and, in some instances, flowing pressure information. The information that may be obtained from detailed PDA includes oil or gas in place (GIP), permeability-thickness product (kh), and skin (s), and this can be used to supplement information obtained from other sources such as PT analysis, material balance, and reservoir simulation.