Capillary fluid transfer between fractures and water-wet siliciclastic rock potentially is a vital contributor to achieving a high recovery from water flooding of Nelson’s Type II Naturally Fractured Reservoirs (NFRs) where the rock matrix contains most of the hydrocarbon volume, but the fractures provide the fluid pathways. This transfer, however, is restricted to the subset of fractures that is reached by the injected water. Using a discrete fracture network model and a control volume finite element reservoir simulator, I compute the fracture surface area Af,sw(sw) where such a transfer occurs as a function of the pore volume of water injected into the fractured domain. This parameter has a nonlinear functional as proven by simulating a large number of meso-scale models with stochastically generated sets of well interconnected fractures. The simulation setup is constant rate water injection and constant pressure production. Fracture fluid transport is simulated with the Fourar-Lenormand two phase relative permeability models and affected by fracture-matrix fluid exchange modelled through nonlinear transfer functions. The fracture permeability is based on stress dependent fracture apertures. Results show that the wetted portion of the fracture-matrix interface Area, Af,sw(sw), is affected not only by the viscosity contrast of injected and displaced fluid, but also by matrix capillary pressure responsible for the magnitude and time dependence of counter-current imbibition. The effects of this transfer on the shape and velocity of propagation of the displacement front in the fracture network are shown. The derived Af,sw(sw) serves as a new scaling parameter for fracture-matrix transfer in dual continuum models, potentially enhancing the predictive capabilities of this simulation approach.