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Abstract
We investigate the coupled flow/geomechanics behavior of naturally fractured permeable rocks. Model and simulation of these processes is very challenging due to the multi-scale nature of the problems and the strong coupling that exists between flow and mechanical behaviors. We present a numerical procedure for the simulation of two-phase immiscible and compressible flow coupled to mechanical deformation in two-dimensional discrete-fractured porous media. To achive this coupling, we implemented an iterative procedure between the flow and the mechanical deformation simulations in which the fluid pressure in the fracture is used as boundary condition at fracture walls. The deformation problem is solved by discretizing the poroelastic equilibrium equations following a Galerkin Finite Element approach, while the flow part was solved using the discrete fracture control volume method. For the flow simulation fractures are assumed to be n-1 dimensional elements where n is the dimension of the overall problem. We considered continuity in capillary pressure and the implied discontinuity in saturation. The model introduces a coupling between mechanical behavior and flow properties by relating absolute permeabilities to the fracture deformation. This approach allows us to study the effects of the coupling on the oil recovery in stress sensitive fractured porous media. We present results for the simulation of synthetic cases to illustrate some of the geomechanical effects that may arise during oil recovery in fractured reservoirs.

Introduction
Numerical simulation of multiphase flow in stress sensitive fractured-hydrocarbon formations is of high interest in hydrocarbon production. Waterflooding performance in naturally-fractured media highly depends on the coupled effects of flow and stress. Economical recovery from tight gas formations relies on the formation and propagation of hydraulic fractures. Thermal recovery of oil sands by SAGD process produces rock dilation that needs to be accounted for reliable
production forecast (Collins, 2007).

Fractured-porous media are composed of rock matrix and fractures. Often the rock matrix provides the storage, and in singlephase flow, fractures provide the fluid flow path. On the other hand, it is well known that in multi-phase flow in fractured media, the flow path of a phase is affected by capillary, gravity, diffusion/dispersion, and viscous forces (Firoozabadi and Hauge, 1990; Firoozabadi and Ishimoto, 1994; Hoteit and Firoozabadi, 2008b, 2009; Monteagudo and Firoozabadi, 2007b).

Several discrete fracture models have evolved over the past years (Bastian et al., 2000; Geiger et al., 2003; Hoteit and Firoozabadi, 2008a, b, 2009; Karimi-Fard and Firoozabadi, 2003; Kim and Deo, 1999; Kim and Deo, 2000). However, to the best of our knowledge, geomechanical effects have never been accounted for in discrete fracture simulators.

In rock masses with low porosity and low permeability, the flow is mainly due to the system of interconnected fractures through the rock mass. The connectivity of fractures and their individual permeability are the main factors that affect hydraulic behavior of the rock mass. The permeability of a fracture is a function of the void geometry between fracture walls which, at the same time, is affected by the state of stress of the surrounding rock (Zeng et al., 2010). It is well known that the
permeability of fractures under the normal stress (tensile fractures) tend to close under in-situ conditions, while fractures under shear stress remain open due to dilation. The prediction of the permeability of fractures under shear stresses, and understanding the effects of perturbations of the stress field inducing small shear displacements, are of the essential in the assessment of the hydraulic response of a fractured reservoir. Experimental work seems to support the hypothesis that only fractures undergoing shear stresses are able to respond hydraulically.