Phase-field simulation of counter-current spontaneous imbibition in a fractured heterogeneous porous medium

Abstract

Spontaneous imbibition is well-known to be one of the most effective processes of oil recovery in fractured reservoirs. However, the detailed pore-scale mechanisms of the counter-current imbibition process and the effects of different fluid/rock parameters on this phenomenon have not yet been deeply addressed. This work presents the results of a new pore-level numerical study of counter-current spontaneous imbibition, using coupled Cahn–Hilliard phase field and Navier–Stokes equations, solved by a finite element method. A 2D fractured medium was constructed consisting of a nonhomogeneous porous matrix, in which the grains were represented by an equilateral triangular array of circles with different sizes and initially saturated with oil, and a fracture, adjacent to the matrix, initially saturated with water and supported by low rate water inflow. Through invasion of water into the matrix, oil drops were expelled one by one from the matrix to the fracture, and in the matrix, water progressed by forming capillary fingerings, with characteristics corresponding to the experimental observations. The effects of wettability, viscosity ratio, and interfacial tension were investigated. In strongly water-wet matrix, with grain contact angles of θ < π/8, different micro-scale mechanisms were successfully captured, including oil film thinning and rupture, fluids’ contact line movement, water bridging, and oil drop detachment. It was notified that there was a specific grain contact angle for this simulated model, θ = π/4, above it, matrix oil recovery was negligible by imbibition, while below it, the imbibition rate and oil recovery were significantly increased by decreasing the contact angle. In simulated mixed wet models, water, coming from the fracture, just invaded the neighboring water-wet grains; the water front was stopped moving as it met the oil-wet grains or wide pores/throats. Increasing water-oil interfacial tension, in the range of 0.005-0.05 N/m, resulted in both higher rate of imbibition and higher ultimate oil recovery. Changing the water-oil viscosity ratio (M), in the range of 0.1–10, had a negligible effect on the imbibition rate, while due to co-effects of capillary fingering and viscous mobility ratio, the model with M = 1 had relatively higher ultimate oil recovery.