Analysis of Coalbed Methane Production by Reservoir and Geomechanical Coupling Simulation

Abstract

An overview of coalbed methane (CBM) reservoir characteristics, its unique production mechanisms, and the influence of geomechanical processes on these production mechanisms are discussed from a reservoir engineering point of view. Models have been developed to predict changes in cleat porosity and permeability with in situ conditions (stress, pressure, gas sorption, and temperature). Explicit-sequential coupling simulations are conducted for conventional CBM depletion production. The study shows that during production, coal matrix shrinkage due to methane desorption results in an increase of permeability within coal seams in most regions close to the producer even though the mean effective stresses increase. The predicted production rate and cumulative production from explicit-sequential coupling simulations are higher than that from conventional simulations. The developed models also allow coalbed permeability anisotropy to be considered. Introduction Worldwide coalbed methane (CBM) reserves have been estimated at 84 ~ 262 trillion m3 (2,980 ~ 9,260 trillion ft3)(1). The majority of these CBM reserves are mainly located in Russia (17 ~ 113 trillion m3), Canada (6 ~ 76 trillion m3), China (30 ~ 35 trillion M3), Australia (8 ~ 14 trillion m3), and USA (11 trillion m3)(1). In the United States, CBM accounted for 10% of dry gas reserves and 8% of dry gas production in 2003(2). In other countries, such as China, Canada, and Australia, CBM projects are attracting more and more attention by resource companies. The production methods of CBM include conventional pressure depletion production and enhanced coalbed methane (ECBM) recovery. At present, CBM is mainly recovered by the former method. In ECBM, gases such as N2, CO2, or flue gas are injected to displace methane and maintain coalbed pressure. This recovery method is still in its infancy with only two field-scale ECBM projects (one injected N2 and the other injected CO2)(3), and one singlewell pilot project(4) worldwide. Productivity evaluation and prediction are important steps in the development of CBM reservoirs. Because gas storage mechanisms in coal seams (mainly adsorbing on the walls of pores) are different from that in conventional gas reservoirs (compressed in pores), conventional reservoir simulators generally do a poor job in predicting CBM production. Over the past decade, many models have been developed to characterize CBM production processes (5–7). Commercial simulators for CBM production can be categorized into two types: modified conventional black oil simulators and modified compositional simulators. With the recognition of the stress dependency of coal permeability and porosity and shrinkage/swelling of the coal matrix due to desorption/adsorption, some simulators have been modified to accommodate these characteristics(3). However, in these simulators the influence of in situ stresses is simplified with an analytic model or a monotonic relation between the permeability ratio and pressure changes. Durucan et al. developed a finite element model to simulate the in situ stress changes near wellbores and coupled the stress changes with fluid flow simulation by characterizing dynamic changes in permeability(8).

Empirical and numerical approaches for geomechanical characterization of coal seam reservoirs

“…Geomechanically, the same joint-matrix system has a primary influence on the mechanical behaviour of the coal. During production/injection processes changes in pressure, gas content and gas composition lead to changes in effective stress which in turn lead to changes in permeability and porosity (Gu and Chalaturnyk, 2005) as well as change the conditions for borehole stability. To account for these changes and conditions through simulation accurate deformation and strength parameters are needed.…”

Analysis on Production of Coal Bed Methane Considering the Change in Permeability of Coal Rock

“…Therefore, compared with the flow process of traditional underground water and oil resources, the migration of coal bed gas is more complex, it includes process of diffusion of gas in the coal matrix, and seepage process in fracture system. At the same time, different flow characteristics in different mobile phases, the escaping and diffusion process can be described by the Langmuir isotherm adsorption equation and the Fick's diffusion law [19], the flow process in cracks can be described by Darcy and non Darcy's law, accompanied by deformation of reservoir and molecular diffusion effects of gas. As we did not consider the changing of the temperature during the simulation, the process we simulated was set as isothermal.…”

Adsorption-induced permeability change of porous material: a micromechanical model and its applications

“…Particularly, the former can be completely determined for an ideal microstructure with monosized spherical pores, and the latter can be modified by some kinds of isothermal adsorption such as Langmuir isothermal adsorption, which result in the determination of both Eqs. (11) and (12). However, in most cases, the functional form of the specific surface area is rather ambiguous due to the complicated micro-and macrostructure of porous material.…”

“…On the permeability issue, several permeability models for coal have been proposed by Palmer and Mansoori, Shi and Durucan [27,35], and Gu and Chalaturnyk [12] to characterize the evolution of coal permeability. By assuming that the coal matrix blocks connected by coal matrix bridges and considering the couple interaction between them, a new permeability model for coal was recently developed by Liu et al [21].…”