Simulating Naturally Fractured Reservoirs Using a Subdomain Method

Abstract

ABSTRACT A subdomain formulation for modeling naturally fractured reservoirs is presented. "Representative Matrix Blocks" are subdivided into rectangular rings and layers to enhance pressure and saturation gradient resolution within the blocks. Improved description of matrix capillary and gravity forces can be achieved through this formulation. A three phase coupled implicit algorithm incorporates pressure dependent gas/oil capillary pressure，fracture permeability, and fracture porosity. Segregated and dispersed fracture fluid options are given, and field-scale simulations of primary depletion, water injection and gas injection are presented. Naturally fractured simulations with matrix block discrefcizafcion can yield significantly different production forecasts from those without internal discretization. Quarter five-spot, low permeability waterfloods show differences in cumulative oil recovery as large as 35 percent. For small blocks, or moderate matrix permeability, differences in simulated oil rate are less than 10 percent. The dependence of gas/oil capillary pressure on pressure is shown by example to have a large effect on oil production rate. Jones' relations17 between pressure and fracture porosity and permeability lead to modest changes in oil rate when compared with constant fracture properties. At early times fracture permeability reduction decreases oil rates, while fracture porosity variation leaves oil rates unaffected. Segregated fluid flow in the fractures leads to smaller matrix/fracture fluid transfer rates, and hence lower oil recovery. A dispersed water phase in the fracture is exposed to larger matrix surface area, creating additional opportunity to exchange itself with oil contained within the matrix block.