Determination of petro-physical properties of coal bed methane (CBM) reservoirs is essential in evaluating a potential prospect for commercial exploitation. In particular, coal fracture permeability and relative permeability of coal to gas and water are the most significant rock properties controlling the transport of natural gas and water to the wellbore. In this work, absolute and relative permeability of different coal samples were determined experimentally under steady-state flowing conditions. Multiphase flow tests were conducted using brine, helium as the flowing phases under different magnitudes of confining and pore pressures. Results indicate that effective stress (Confining pressure - average pore pressure) has a significant effect on both absolute and relative permeability of coal. As a result, relative permeability characteristics of CBM systems were found to be insufficiently represented as sole functions of fluid saturation. In addition, laboratory measurements were used to conduct field scale simulations of primary recovery from CBM systems using variable, stress-dependent relative permeabilities.


Producing methane from coal seams has been practiced for more than half a century and successful commercial exploitation of coal bed methane systems has been witnessed on a global scale, especially in the United States. It is estimated that the global methane reserves from coal seams can be up to 9,500 Tcf and in the US up to 3,000 Tcf (Olsen et al., 2003). Coal seams that are deep and uneconomical to mine are potential candidates for storage of CO2 due to their high affinity to adsorb CO2, thus enhancing methane recovery (Pekot & Reeves, 2003). For reservoir engineering applications coal seams are treated to be dual porosity in nature having a tight matrix and a well defined natural fracture or the cleat system. Coal seams undergo a multi-mechanistic depletion process (Ertekin at al., 1988) where gas desorbs and diffuses from the matrix into the natural fractures and from the natural fractures it flows to the wellbore. Generally, when gas desorbs from the coal micropores, the coal matrix shrinks which leads to an increase in permeability (Harpalani & Shraufnagel, 1990) and when gas adsorbs, the permeability decreases due to matrix swelling. In an Enhanced Coal Bed Methane Recovery/Sequestration setup where CO2 is injected to displace methane, it can be seen that adsorption and desorption of gases can occur simultaneously, leading to a multi-component sorption/desorption scenario (Katyal et al., 2007). Therefore the interaction of gases with the observed changes in coal permeability accompanied by shrinkage/swelling characteristic of coal is a complex phenomenon. Hence research interest has increased in the recent past to study and understand the behavior of different types of coals for long term reservoir monitoring and management. Among these, research investigations aimed at understanding the relative permeability characteristics of coal seams which primarily describes the flow of water and gas in the cleat or the natural fracture network has been very minimal (Dabbous et al., 1974; Reznik et al., 1974; Puri et al., 1991; Gash, 1991; Paterson et al., 1992; Hyman et al., 1992; Ham & Kantzas, 2011; Shen et al., 2011). Coal being a naturally fractured formation exhibits strong dependence of permeability on stress conditions (Palmer & Mansoori, 1996; Pan et al., 2010).

URTeC 1619221

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