Quantification of multiphase flow in fractured permeable rocks is vital for hydrocarbon recovery, gas storage, and water resource management. Where fractures provide the permeability and the rock matrix provides the storage for oil and gas, fracture-matrix transfer has a decisive impact on recovery and capillary-driven transfer. However, while most modeling efforts assume a constant fracture aperture and fracture capillary pressure, in reality, fracture aperture and capillary pressure, pcf vary among fractures. Here we contrast and compare relative permeability curves obtained from constant aperture or constant capillary pressure, discrete fracture and matrix (DFM) models with more realistic ones taking variations into account. These models are constructed from line drawings of pervasively fractured layered rock mapped in meter- to kilometer-scale outcrops. Fracture aperture is obtained by mechanical modeling. Capillary pressure is computed from fracture aperture taking into account the wettability of the rock matrix.
An unsteady state approach is applied to the analysis of fracture-matrix ensemble relative permeability and ultimate recovery. Imbibition simulations are performed with the Finite Element-Centered Finite Volume Method (FECFVM). Globally flow-based upscaling is used to establish ensemble relative permeability curves between capillary and viscous limits.
The obtained fracture-matrix ensemble relative permeability curves show that ultimate recovery is 2-3 times higher in the water-wet than in the oil-wet case. With increasing wetting angle, counter-current-imbibition (CCI) rate decreases because the capillary pressure difference between small fractures that contribute the most to the fracture-matrix transfer area is very small. As the rock becomes oil wet, ensemble relative permeability curves steepen and matrix imbibition proceeds only over a very narrow saturation range.