Fine Grid Simulation of Two-Phase Flow in Fractured Porous Media

Abstract

SPE Members Abstract Numerical reservoir simulation commonly divides naturally fractured reservoirs into matrix and fracture systems. The high permeability fractures are usually entirely responsible for flow between blocks and flow to the wells. The flow in these fractures is modeled using Darcy's law and its extension to multiphase flow by means of relative permeabilities. The influence and measurement of fracture relative permeability for two-phase flow in fractured porous media have not been studied extensively. Transfer of fluids between the matrix and fractures is known to be one of the most important mechanisms of fluid movement in these reservoirs. Therefore, matrix/fracture fluid transfer, matrix and fracture two-phase flow, and interactions among them must be better understood for accurate simulation of oil recovery from naturally fractured reservoirs. Experimental and numerical work on two-phase flow in fractured porous media has been initiated. The process considered is oil displacement by water in fractured porous media. Fine grid simulations of two-phase flow through a fractured core were performed in order to design the experiments and to study the effects of several key variables. These variables included fracture relative permeability, matrix/fracture capillary pressure, and matrix wettability. This paper presents the results obtained from the sensitivity analysis using fine grid simulations. The numerical computations show that fracture relative permeabilities and wettability become important only at low capillary numbers. A dimensionless capillary number at which the fracture relative permeabilities become an important factor was estimated to be 20. The concept of a limiting capillary number may be extended to determine when fracture relative permeabilities are of influence in field scale simulations of naturally fractured reservoirs. Fracture capillary pressure was observed to have a negative effect on water imbibition, reducing the efficiency of the oil recovery. At high capillary numbers, i.e. when capillary forces are more important, water moves faster inside the matrix than in the fracture which results in high oil recovery. At lower capillary numbers, i.e. when viscous forces are more important, water channels rapidly through the fracture with a low recovery efficiency. Comparison of simulations of similar fractured and unfractured systems shows that at high capillary numbers the recovery is higher for the fractured core. At low capillary numbers the unfractured core exhibits higher recovery. Introduction Dual-porosity, dual-permeability formulations are commonly used to model multiphase flow in naturally fractured reservoirs (NFR). The discretized flow equations for this type of model are as follows: (1) where the subscript denotes a given phase (oil, gas or water), m denotes matrix, and f stands for fracture. P. 605^