A number of laboratory studies on coalbed methane (CBM) have provided data for the relative permeability of coal to gas and water, which are needed to analyze CBM reservoirs, particularly in numerical simulation.

The relative permeability curves of coal to gas and water are determined using the two methods used in the petroleum reservoir engineering, namely, the steady or unsteady state displacement methods. In most cases, the unsteady state displacement method is used because this method is relatively fast to carry out. In this method, the non-wetting fluid is displaced by the wetting fluid, and the effluent production and pressure history are used to back out the relative permeability of coal to gas and water.

One of the problems encountered in the displacement methods is the question of coal wettability. Many researchers studying this area have considered that coal is water-wet. However, it is a well-known fact that a large amount as much as 95% of methane is adsorbed on the internal surface of coal matrix. Therefore, coal could be regarded at least as initially gas-wet. The wettability of coal will depend on the flow characteristics of coal, that is, whether methane flows in the matrix. This paper investigates a number of wettability of coal scenarios and discusses the approaches used by various investigators, for instance, pre-heating the coal sample before any testing, and using a non-adsorbable gas, pointing out their limitations from the viewpoint of CBM reservoir simulation. The likely dependence of relative permeability of coal on flow pressure is also addressed.


The earliest studies in numerical simulation of CBM date back to 1970's (Price and Abdalla, 1972). At the time, the principal objective was degasification of coal seams for mine safety to keep coal mining safe from explosions rather than CBM production to use as an unconventional gas resource. Since then, there has been continued research in CBM simulation as most of the simulators used for CBM production were often based on conventional (sandstone) reservoir models that have been modified to accommodate coal properties.

In recent years, advanced simulators that are specific to CBM reservoirs have been developed to incorporate CBM reservoir parameters such as the relative permeability, which controls the well and the reservoir performance.

The objective of this paper is to examine the past relative permeability measurement studies and identify problems posed by coal compared to typical reservoir rocks such as sandstone and carbonates.


Coal is "the black rock that burns" (Land and Rice, 1993). It is defined as a readily combustible rock that contains more than 50% by weight and more than 70% by volume of carbonaceous material including inherent moisture formed by compaction and induration (hardening of sediment) of various altered plant remains. The type of plant materials, degree of metamorphism, and the range of impurity characterize coal (Bates and Jackson, 1980). A coal seam is a bed of coal, and the natural gas or methane produced from coal seams is referred to as coalbed methane (CBM).

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