Relative Permeability of Oil-Water Systems in Fractures

The objective of this study was to develop an understanding of the relative permeability of oil-water systems in fractures. Presently, two-phase flow behavior through propped and unpropped fractures is poorly understood, and due to this fact, reservoir modeling using numerical simulation for the domain that contains fractures typically makes use of straight-line relative permeability and zero capillary pressure in the fractures; however there have been several studies demonstrating that both viscous and capillary-dominated flow can be expected in naturally fractured reservoirs, where non-linear fracture relative permeabilities must be used to accurately model these reservoirs. The experimental measurements conducted in this study were done using downhole core from the Wolfcamp Shale formation in the Permian Basin. The core sections used for this study consisted of two-thirds slabbed, four inch diameter core. Test specimens were then cut from each core specimen and subsequently fractured or saw cut to generate a fracture along each sample. The samples were then conditioned in formation oil at reservoir temperature for 30 days prior to any testing. The oil-water relative permeability was measured following the steady state method. Formation oil and reconstituted brine with and without surfactants were used as the test fluids. All measurements were conducted at reservoir temperature and at representative effective fracture closure stress. Instantaneous measurements of pressure, flow rate and density were recorded throughout the entire duration of each experiment. Fluid saturations within the fracture were calculated using the mass continuity equation. The data from the experimental measurements was analyzed using Darcy’s law, and a clear relationship between relative permeability and saturation was observed. The calculated relative permeability curves closely follow the generalized Brooks-Corey correlation for oil-water systems. Furthermore, there was a significant difference in the relative permeability curves between the oil-water only systems and the oil-water-surfactant systems. The calculated relative permeability curves were then used as inputs to a numerical simulation model constructed in Eclipse Reservoir Simulator from Schlumberger. The domain represents a small symmetry section within a stimulated reservoir volume of a hydraulically fractured well consisting of 450 cubic feet containing a natural fracture joint set as well as a propped hydraulic fracture section. Results from the numerical simulation indicate the potential for surfactant additives to significantly improve initial oil production rates as well as 500 day cumulative oil production by as much as 36% and 16% respectively