Pore network modeling of oil and water transport in nanoporous shale with mixed wettability

Abstract

Hydraulic fracturing is an effective means for the economic development of shale oil reservoirs. A large volume of water is introduced into the shale matrix during hydraulic fracturing, which leads to the subsequent oil-water two-phase flow in the shale reservoir. The fluid flow behaviors in shale are still ambiguous due to the nonnegligible nanoconfinement effect caused by the omnipresent nanoscale pores and the heterogeneities of mineral types, pore size and wettability of shale. In this study, both the single-phase and oil-water two-phase flow behaviors at pore-scale considering nanoconfinement effects, dual-wettability and pore space characteristic of shale reservoir were investigated using the pore network modeling (PNM) method. We constructed the three-dimension shale digital rock based on scanning electron microscope (SEM) images and extracted the pore network model. The modified single nanotube flow equations considering the adsorption and slip effects were incorporated with the shale pore network model to investigate the single-phase flow at different volumetric total organic content (TOC). Oil-water two-phase flow and relative permeability at different TOC in volume were computed by quasi-static method with consideration of nanoconfinement effect. Results indicated that the TOC and wettability are the primary factors affecting the single-phase flow in shale. Slip effect enhanced the flow capacities of both single-phase water and oil. The wettability effect on two-phase relative permeability curve was not as notable as that on single-phase flow. Oil-water two-phase relative permeability curves were significantly affected by TOC. The two-phase flow region narrows down with the increase of volume TOC, indicating more oil is trapped and thus cannot be displaced. This work provided important insights on pore-scale fluid transport behaviors in shale.