Investigation of Two-Phase and Three-Phase Relative Permeability in Different Rocks with Similar Pore Size Distribution

Abstract

AbstractRelative permeability (kr) function describes the comparative ease by which different fluids flow in a porous medium and plays an influential role in numerical simulation of petroleum reservoirs. Since, the measurement of relative permeability, especially three-phase ones, in laboratories is time consuming and expensive, much research has directed towards developing correlations for estimating the three-phase relative permeability values. One assumption used in reservoir simulation is that relative permeability curves of different rocks with similar lithology and pore size distribution depict identical behaviour if expressed against normalised (mobile) fluid saturations. This paper present the results of a study carried out to assess the validity of this assumption for two-phase and three-phase flow systems.A set of two-phase (oil/gas) and three-phase (oil/gas/water) unsteady-state coreflood experiments were conducted on two Clashach sandstone samples with permeabilities of 1000 mD and 65 mD. The relative permeability curves for each experiment were then obtained by mathematical modelling of the coreflood tests and matching the laboratory measured data.Comparison between the measured two-phase oil/gas kr of the two cores show that the relative permeability curves versus mobile (normalized) saturation for the 1000 mD core are close to that of the 65 mD rock. This demonstrates that in the absence of measured relative permeability data for a low permeability core, the available data for a higher permeability core with similar lithology can be used for the low permeability rock and vice versa. However, this was not the case for three-phase kr. Comparison of the three-phase relative permeability obtained for water, oil and gas in the two cores shows significant difference for the two cores even when plotted againest normalized saturations. Hence, the simulation of the coreflood experiment involving three-phase flow carried out on the 65 mD core using the relative permeabilities of the 1000 mD core led to highly erroneous predictions. These results reveal that three-phase kr of one rock is not representative of the fluid mobility in another rock. The main conclusion drawn from this study is that scaled three-phase relative permeability in different cores behaves thoroughly different even if their pore size distributions are very similar. The disagreement observed between relative permeability of the two rocks could be attributed to the different magnitude and variations of capillary forces being active during the governing multiphase flow events.