Use of Experimental and Simulation Results for Estimating Critical and Optimum Water Injection Rates in Naturally Fractured Reservoirs

Abstract

Abstract This paper describes the experimental and simulation studies to determine critical and optimum injection rates during waterflooding in the naturally fractured reservoirs of the Spraberry Trend Area. The experimental study was performed using artificially fractured cores at reservoir temperature (138°F) and 500 psia confining pressure. Based on the experimental results, an equation to determine the critical water injection rate (maximum injection rate at which the capillary imbibition is not effective) was developed to scale up laboratory results to field dimensions. We found that capillary imbibition transfer is not only a function of matrix permeability and maximum matrix capillary pressure but also a function of other matrix properties, such as wettability, porosity, matrix area and water viscosity. Two field cases using this scale-up equation are presented. The optimum injection rate (the injection rate at which the capillary imbibition and viscous forces are balanced) for different well configurations cannot be determined from laboratory experiments; therefore, a reservoir simulation was employed. A 40-acre pilot was developed by utilizing a commercial dual-porosity simulator. Three different injection schemes were applied for four vertical and two horizontal injection wells, with constant injection rate and two different cyclic injection rate schemes. The numerical results show that four vertical injection wells at the optimum injection rate could yield higher oil production than two horizontal injection wells at the optimum injection rate. Use of a cyclic injection rate could restore reservoir pressure and increase oil recovery in the Spraberry Trend Area. The findings of this study could be useful to solve the problem of early water breakthrough, one of common problems of waterflooding in all naturally fractured reservoirs.