Pressure-transient responses of naturally fractured reservoirs modeled using the multistencils fast-marching method

The multistencils fast-marching (MFM) method can model the effects of natural fractures on the spatiotemporal evolution of drainage volume in a naturally fractured reservoir caused by a production/injection well. Using a pseudosteady-state geometric approximation, the evolution of drainage volume is transformed into the pressure-transient (PT) response of the production/injection well. In this paper, we investigate the sensitivities of the modeled PT response to fracture characteristics, such as fracture length, fracture compressibility, fracture conductivity, angle of fracture orientation, fracture volume fraction in the reservoir, and fracture distribution. In doing so, we identify diagnostic signatures for pressure-transient analysis (PTA) for a vertical well in a naturally fractured reservoir. The fracture volume fraction, fracture conductivity, and nearest location of natural fracture can be determined using the newly proposed PTA. Gaussian distributions of fracture dimensions and orientation do not affect the PT response. For various realizations of random fracture distributions, the shape of the pressure-derivative curve and its decline rate are indicative of the distribution of natural fractures in the reservoir. Such an extensive numerical study of the effects of fracture characteristics on the PT response is possible because of the implementation of the fast-marching (FM) method for modeling the approximate time-varying drainage volume and the subsequent geometric approximation of the drainage volume for computing the PT response. Copyright © 2020 Society of Petroleum Engineers.