Jorge E.P. Monteagudo, SPE, ConocoPhillips; Adolfo A. Rodriguez, SPE,
ConocoPhillips; Horacio Florez, UTAustin
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
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.