QGC

Abstract: Coalbed-methane (CBM) reservoirs are naturally fractured formations, comprising both permeable fractures and matrix blocks. The interaction between fractures and matrix presents a great challenge for the forecast of CBM reservoir performance. In this work, a dual-permeability model was applied to study the parameter sensitivity on the CBM production, because the dual-permeability model incorporates not only the influence from matrix and fractures but also that between adjacent matrix blocks. The mass exchange between two systems is defined as a function of desorption time constant at the standard condition, coal matrix porosity, and the difference of gas pressure between two systems. Correspondingly, gas diffusivity in matrix is considered as a variable and represented by a function of shape factor, gas desorption time, and reservoir pressure. These relations are integrated into a fully coupled numerical model of coal geomechanical deformation and gas desorption/gas flow in both systems. This numerical approach demonstrates the important nonlinear effects of the complex interaction between matrix and fractures on CBM production behaviors that cannot be recovered without rigorously incorporating geomechanical influences. This model was then used to investigate the sensitivity of CBM extraction behavior to different controlling factors, including gas desorption time constant, initial fracture permeability, fracture spacing, swelling capacity, desorption capacity, production pressure, and fracture and matrix porosities. Modeling results show that the peak magnitudes of gasproduction rate increase with initial fracture permeability, sorption and swelling capacities, and matrix porosity, and decrease with gas desorption time constant and production pressure. These results also show dramatic increase in gas-production efficiency with decreasing magnitudes of fracture spacing. The comparison of the transient contributions of the desorbed gas and the free phase gas from the matrix system to gas production shows that the free phase gas plays the dominant role at the early stage, but diminishes when the adsorption phase gas takes over the dominant role, indicating the necessity of incorporating free phase gas impact in simulation models. The numerical model was also applied to match the history data from a gas-production well. A better matching result than that for the single-permeability model demonstrates the potential capability of the dual-permeability model for the forecast of CBM production.

Abstract: Drill Stem Testing (DST) is a primary means of evaluating skin and permeability of exploration and appraisal wells. It is no exception in the case of Coal Seam Gas (CSG) reservoirs. A modified form of DST is routinely used by the CSG industry in this region (Queensland, Australia) as a low cost means of getting skin, permeability and pressure information for these land based wells which have to be mass-drilled given the nature of these coal seam reservoirs and the well productivity. In this paper we review about 450 individual DSTs with a variable permeability and skin values. Observed high skin and permeability values from many of these wells called for better understanding of these parameters in conjunction with core and log data. About 50 wells in the subject study were cored. Image logs were run in addition to routine openhole wireline log suite. Some of the abnormal (very high) skin and permeability values could be explained from detailed analysis of these logs. Examples of DST, log and core data reconciliation have been reviewed. Various studies have been conducted to understand root causes of the observed high skin values. Well interference tests have been conducted to understand horizontal permeability anisotropy and reservoir continuity. This DST, log and core assisted reservoir characterisation has opened the way for completion optimisation for more than 6000 wells to be drilled in the Surat Basin, Queensland, Australia.