Relative permeability measurement and two-phase flow visualization in micromodels of vugular porous media

Close to 50% of the world's oil and gas reserves are held in naturally fractured carbonate reservoirs. In addition to the presence of fractures, vugs at different scales and distributions are scattered throughout the porous matrix. These cavities cause fluid flow characteristics to significantly differ from those of conventional homogeneous pore structure reservoirs and bring the need to evaluate equivalent petrophysical properties of the heterogeneous medium. In this study, a microfluidic approach is used to determine water and oil relative permeability curves and phase distribution in two-dimensional micromodels of vugular porous media. Steady-state water–oil injection experiments were performed at different fractional flows, while monitoring the dynamics of the pressure drop and visualizing the fluid displacement at the pore scale. Live-image acquisition through fluorescence microscopy made it possible to examine the evolution of the saturation of water and oil phases. A direct comparison between the relative permeability curves of well-characterized vugular porous media and their porous matrix showed that the incorporation of vugs leads to (i) higher equivalent absolute permeability, especially with longer cavities and higher vug density, (ii) increased oil occupancy in the porous matrix, due to less efficient water invasion into the porous matrix, and (iii) higher relative permeability to water, which flows preferentially through the vugular space. These results are consistent with the oil-wet nature of micromodels, since the vugs offer less capillary resistance to the flow of the non-wetting phase.