Impact of Dual Matrix Porosity in Sandstone on Fluid Distribution and Flow Properties

In a deepwater sandstone reservoir in the Gulf of Mexico, mineralogy and petrographic studies show an alternating, sorted bimodal grain-size distribution and continuous clay coating. Saturation functions (i.e., capillary pressure and relative permeability) assuming a single-porosity system would introduce large errors in the modeling of fluid distribution and flow properties. A dual matrix porosity approach is presented to characterize core samples using a range of data from nuclear magnetic resonance to core measurements and petrography. The total porosity consists of contributions from macroporosities and mesoporosities, respectively. A dual-porosity capillary pressure model is developed using a modified Brooks-Corey function to properly describe the initial oil saturation distribution in both porosity systems. The capillary pressure model is then extended to model the imbibition process to assess the wettability condition. Numerical simulations are used to evaluate the impact of the saturation function on the oil-water displacement. This study demonstrates that heterogeneity greatly affects the fluid distribution and the wettability in the core scale. The contribution of the mesoporosity to the total flow varies and should be properly accounted for in reservoir simulations to model water development and production.