Modeling Multiphase Fluid Flow in Unconventional Reservoirs

Abstract

A hydrocarbon reservoir is defined as unconventional when it requires special completion techniques outside the conventional ones. In particular, tight gas, shale gas and shale oil reservoirs are unconventional due to their very low or ultra low permeability. To allow oil and gas production, the formation has to be fractured injecting fluids at high pressures. Fluid injection increases the pore pressure and, consequently, the effective stress in rocks. In this way, a set of fractures are generated creating pathways where hydrocarbons can flow to a producing well. To simulate fracture propagation, a breakdown pressure criterion is applied: during injection, once pore pressure becomes greater than a breakdown value on a certain cell, that cell is fractured increasing permeability and porosity values. The objective of this work is to test a simple numerical model of hydraulic fracture generation in unconventional reservoirs that combines a multiphase flow simulator with the breakdown pressure criterion. The multiphase flow through porous media is described by the well-known Black-Oil formulation, which uses as a simplified thermodynamic model, the PVT data: formation volume factors and gas solubility in oil and water. The numerical solution is obtained applying an IMPES (IMplicit Pressure Explicit Saturation) finite difference technique. The multiphase flow simulator is used to model the fracture propagation in a tight gas reservoir. In the examples we consider a very low permeability porous media with natural fractures located in the same plane. We analyze the hydraulic fracture advance in that plane and its interaction with natural fractures.