CBM reservoir engineering is a branch of petroleum engineering.
Since the 1980s, when it initially evolved as a branch from traditional reservoir engineering, coalbed methane reservoir engineering has become established in much the same way as the coalbed methane industry has emerged as an independent sub-set of the traditional petroleum industry. Coal beds are characterized by their dual porosity: they contain both primary (micropore and mesopore) and secondary (macropore and natural fracture) porosity systems. Flow through the secondary porosity system is dominated by Darcy flow, which relates flow rate to permeability and pressure gradient. The primary porosity contains the vast majority of the in-place gas volume, while the secondary porosity system provides the conduit for fluid flow to the well-bore. Primary porosity gas storage is dominated by adsorption. The primary porosity system is relatively impermeable due to the small pore size. Mass transfer for each gas molecular species is dominated by diffusion, which is driven by the concentration gradient. The permeability measured by transient tests is mainly attributed to the properties of the cleats. Previous researchers have established the basic theory for coalbed methane geology and reservoir engineering, especially the relationship of reservoir storage capacity to geothermal history and the mechanism of fluid migration in the coal reservoir. These studies provide a basis for the present study of the effect of coal type and rank on seam or reservoir permeability.