This paper describes a three-dimensional numerical model for predicting the coalbed methane (CBM) production. The model describes single phase gas desorption from coal matrix, diffusion to the fracture and two-phase flow of gas and water in the natural fracture system as well as the permeability changes in coal which result from effective stress changes and matrix shrinkage due to gas desorption. The model was discretized by a finite difference method. The implicit pressure-explicit saturation (IMPES) method was used to solve the two-phase flow equations and gas desorption equation was solved implicitly.

The numerical model was validated by the field data from Qinshui basin in China. Based on the model, the impact of various reservoir and Langmuir isothermal adsorption parameters on the gas production was investigated.

The results show that the gas production rate of the coalbed methane predicted by this model is in good accordance with the field data. The permeability near the wellbore dramatically decreases as the reservoir pressure drops at the early production period while at the later production period, the permeability near the wellbore increases because of the matrix shrinkage. The permeability changes far away from the wellbore are not so remarkable. In addition, the gas production rate increases with the increased permeability, seam thickness and Langmuir pressure constant while it decreases with the increased porosity and Langmuir volume constant.

The numerical model can be used to predict and analyze the production performance of CBM reservoirs and the research results provide theoretical support for CBM production.

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