Conventional modeling of fractured reservoirs treats fracture-system
permeability and porosity as static (or pressure-dependent) data. Recent
attempts at coupling geomechanics focused on the permeability but used crude
empirical relations and treated the fluid flow as single porosity. This study
takes advantage of the joint-mechanics theory to develop general, rigorous
coupling between the fluid-flow equation and deformation of fractured media.
Both porosity and permeability coupling are considered.
The geomechanical part uses the equivalent-continuum approach, considering
both rock- and fracture-deformation properties. Multiple sets of fractures with
any dip and strike angle can be defined. The stiffness of fractures varies with
the effective stress according to a law typical for joints.
The main novelty of this work is that the geomechanics solution is
decomposed into matrix and fracture parts and used to compute their dynamic
porosity and permeability separately. This approach rigorously captures the
effect of fractured-media deformation on the dual-porosity-flow part of the
coupled system and allows the permeability and porosity variations to be based
on measurable joint properties. Generally, fracture deformations produce
changes of the permeability tensor in both magnitude and orientation, which in
turn influences reservoir flow and compaction behavior.
The main issue studied was the variation in the permeability of the fracture
system. The examples show that fracture deformation has a significant effect on
productivity or injectivity and that anisotropy of the permeability tensor
develops from deformation. The results provide an initiative for implementing
the case of full-tensor permeability.
Similar to other petroleum reservoirs, naturally fractured reservoirs can be
greatly influenced by the geomechanical behavior of rocks. However, under
similar conditions, the role of geomechanics is even more crucial because of
the presence of fractures, which may be more stress sensitive than the rock
matrix. These fractures are affected by stress disturbances because of fluid
production and/or injection, which results in the opening and closure and the
reorientation of fractures. These variations in geomechanical properties of
fractures affect their permeability (both magnitude and direction), which is a
controlling factor in the management of naturally fractured reservoirs.
To capture this behavior, it is inevitable to consider geomechanical factors
in the modeling of fluid flow in naturally fractured reservoirs. Acknowledging
a few attempts at coupling fluid-flow behavior in naturally fractured
reservoirs, dual-porosity models used in the industry fail to account for
deformability of rock and fractures. These models use simple pressure-dependent
relations for rock compressibility, while fracture permeabilities are typically
treated statically throughout the simulation of the entire reservoir life.
The theory of coupling geomechanics and reservoir engineering in fractured
rocks published in literature is built on the single-porosity poroelastic
theory of Biot (1941, 1955). In literature, different approaches have been
proposed to extend Biot’s single-porosity theory to dual-porosity models.
© 2008. Society of Petroleum Engineers
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- Original manuscript received:
14 December 2004
- Meeting paper published:
31 January 2005
- Revised manuscript received:
14 December 2006
- Manuscript approved:
18 March 2007
- Version of record:
25 February 2008