Modeling of Geomechanics in Naturally Fractured Reservoirs
- Mohammad A. Bagheri (Sproule) | Antonin Settari (U. of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- February 2008
- Document Type
- Journal Paper
- 108 - 118
- 2008. Society of Petroleum Engineers
- 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.2.2 Geomechanics, 4.1.2 Separation and Treating, 4.3.4 Scale, 3 Production and Well Operations, 5.5 Reservoir Simulation, 4.1.5 Processing Equipment, 2.2.2 Perforating, 5.8.6 Naturally Fractured Reservoir, 5.1.5 Geologic Modeling, 5.3.4 Integration of geomechanics in models, 5.3.2 Multiphase Flow, 5.1 Reservoir Characterisation, 1.2.3 Rock properties
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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.
|File Size||3 MB||Number of Pages||11|
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