The relative permeability and capillary pressures are used to characterise large-scale multiphase flow encountered in recovery of hydrocarbons. These parameters are acquired via special core flooding experiments. Reservoir engineers calculate these parameters from special core analysis (SCAL) module of reservoir simulation. However, core flooding is an expensive experiment and involves spending lot of time and efforts before Darcy law assumptions are achieved. Therefore, independent simulation of core flooding is necessary during which reservoir engineers can perform faster and simultaneous analysis of relative perms and capillary pressures of multiphase flow.
This paper presents 1-D black oil simulation of core flooding using Sendra software to get relative perms and capillary pressures. The approaches used in this study are four steps. In the first step, the results of core flooding were estimated at different correlations. In the second step, experimental data of core flooding for differential pressure and production versus time were referenced in the software. Then history matching was performed using estimated and experimental data of core flooding using different correlations. Based on this, the best fits of correlations were obtained for estimating both relative perms and capillary pressures. The benefits of this approach compared with other methods are that it saves time, user-friendly and faster. It is reliable for estimating relative permeability and capillary pressures at steady state or unsteady state, imbibitions or drainage process either in oil or gas recovery.
