A Practical Approach to Determination of Imbibition Gas-Water Relative Permeability

Abstract

Laboratory data developed from flooding gas-filled sandstone cores containing an irreducible wetting phase can be correlated with absolute permeability and used to approximate gas and water relative permeability permeability and used to approximate gas and water relative permeability at selected saturations. The technique furnishes a set of data allowing relative permeability to be approximated for any permeability range used to characterize the reservoir. Introduction Gas-water relative permeability data are required in mathematical models to predict the advance of water into a gas zone, the residual gas saturation in the water-encroached zone, and in some instances, the gas-water ratios for a given water saturation. Laboratory measurement of these data for a range of increasing water saturations requires steady-state testing at elevated mean pressure in the core and X-ray scanning capabilities. The required steady-state and X-ray equipment, and, hence, data, are currently not available to most engineers needing gas-water relative permeability information. Because of the favorable water-gas viscosity ratio of about 50 that exists in the laboratory tests, displacement of gas by water injection results in pistonlike movement of the fluids. Hence, there is pistonlike movement of the fluids. Hence, there is no subordinate gas and water production over a wide water-saturation range from which unsteady-state relative permeability can be calculated. However, the waterflood tests furnish end-point values on the gas and water relative permeability curves, as well as the residual (trapped) gas saturation following water displacement. Samples selected for laboratory testing should cover permeability and porosity ranges and rock types found in permeability and porosity ranges and rock types found in the reservoir. Before using the relative permeability information in engineering calculations, the end-point data must be correlated. Values then can be assigned from the correlations to each rock type, or to statistically determined permeability ranges representative of the reservoir. In certain cases, these correlations furnish all the information required, since many models of water displacing gas assume piston-like displacement in the reservoir, with only gas flowing above the rising water-gas level and water flowing below this level. In other cases, it is necessary to develop gas and water relative permeability data at intermediate saturations between terminal values. Since relative permeability curves reflect pore geometry, fluid-rock permeability curves reflect pore geometry, fluid-rock wetting characteristics, and the direction of saturation change, any technique selected to furnish these data must simulate the actual reservoir conditions. In some situations, water-oil relative permeability data can be normalized, related to the measured gas and water end-point values, and then used to approximate the gas and water relative permeability at intermediate saturations. The normalization permeability at intermediate saturations. The normalization technique and variations of it have evolved as engineers have been faced with resolving difficulties in combining water-oil relative permeability data to yield average curves, or data compatible with water saturations determined from capillary pressure tests. Combining the normalized water-oil data with pressure tests. Combining the normalized water-oil data with measured gas-water end-point values is a new variation of this old theme. Water-oil relative permeability data may not be available for normalization, or may not be suitable if they represent less than a strongly water-wet condition that is usually assumed representative when water displaces gas. JPT P. 199