Comparison of Computation Methods for CBM Performance

Abstract

Abstract Coalbed methane (CBM) production is somewhat complicated and has led to numerous methods of approximating production performance. Many CBM reservoirs go through a dewatering period before significant gas production occurs. The production process, with dewatering, adsorption of gas in the matrix and molecular diffusion within the matrix, can be difficult to model. Several authors have presented different approaches involving the complex features related to adsorption and diffusion to describe the production performance for coalbed methane wells. Various programs are now commercially available to model production performance for CBM wells, including reservoir simulation, semi-analytic and empirical approaches. Programs differ in their input data, description of the physical problem and calculation techniques. This paper presents comparative results of several available programs using different test cases (vertical fractured wells and horizontal wells). Introduction The flow mechanics of coalbed methane (CBM) production have some similarities to the dual porosity system. Figure 1 compares the actual reservoir and its idealization model where the matrix and the cleat systems can be differentiated. Also, three sets of normal parallel fractures are shown (face cleats, butt cleats and bedding plane fractures). CBM models are characterized as a coal/cleat system of equations. Most of the gas is stored in the coal blocks. Gas storage is dominated by adsorption according with Equation (1). Equation 1 (available in full paper) Adsorbed gas content, Gc, is calculated with the Langmuir equation, as follows: Equation 2 (available in full paper) Gas desorbs in the coal block and then drains to the fracture system by molecular diffusion (Fick's law rather than Darcy's law). The drainage rate (Fick's law) from the coal block can be expressed using Equation (3): Equation 3 (available in full paper) For Equation (3), q* represents drainage rate per volume of reservoir. For CBM reservoir modelling, sorption time is related to the transfer shape factor, s, and the diffusivity term, Dc. Sorption time, t, expresses the diffusion process by means of Equation (4): Equation 4 (available in full paper) By definition, t is the time at which 63.2% of the ultimate drainage occurs when maintained at constant surrounding pressure and temperature. The typical production profile for a CBM well is shown in Figure 2. The production behaviour exhibits only water production from the cleat system at the beginning (flow through the cleat system is governed by Darcy's law). Then, due to the reduction in formation pressure, gas starts to desorb from the matrix creating a concentration gradient, and gas and water flow through the cleat system. The water rate decreases and the gas rate increases until the gas peak is reached (the gas production behaviour in this stage is dominated by diffusion). Finally, when depletion in the reservoir is significant, the gas rate declines. Several authors have presented different approaches to describe the production performance for coalbed methane wells. Zuber et al.(1) pointed out that history matching analysis can be used to determine CBM reservoir flow parameters and predict performance by using a simulator modified to include storage and flow mechanisms.