Modeling of Geomechanics in Naturally Fractured Reservoirs

Modeling of Geomechanics in Naturally Fractured Reservoirs M. Bagheri; M. Bagheri U. of Calgary Search for other works by this author on: This Site Google Scholar A. Settari A. Settari U. of Calgary Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, January 2005. Paper Number: SPE-93083-MS https://doi.org/10.2118/93083-MS Published: January 31 2005 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Bagheri, M., and A. Settari. "Modeling of Geomechanics in Naturally Fractured Reservoirs." Paper presented at the SPE Reservoir Simulation Symposium, The Woodlands, Texas, January 2005. doi: https://doi.org/10.2118/93083-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Reservoir Simulation Conference Search Advanced Search AbstractConventional 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 joint mechanics theory to develop general, rigorous coupling between fluid flow equation and deformation of fractured media. Both porosity and permeability coupling is 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 resulting pseudo-continuum stiffness matrix equations were verified by comparing with models using explicit modeling of fractures and analytical anisotropic poroelasticity theory.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 captures rigorously 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.IntroductionSimilar to other petroleum reservoirs, naturally fractured reservoirs can be greatly influenced by geomechanical behavior of rocks. However, under similar conditions, the role of geomechanics is even more crucial owing to presence of fractures, which may be more stress sensitive than the rock matrix. These fractures are affected by stress disturbances due to fluid production and/or injection, which result in opening and closure, and reorientation of fractures. These variations in geomechanical properties of fractures, affect their permeability (both magnitude and direction), which is a controlling factor in management of naturally fractured reservoirs.To capture this behavior, it is inevitable to consider geomechanical factors in modeling of fluid flow in naturally fractured reservoirs. Acknowledging a few attempts on 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 entire reservoir life.Theory of coupling geomechanics and reservoir engineering in fractured rocks published in the literature is built on the single-porosity poroelastic theory of Biot [1–2]. In the literature, different approaches have been proposed to extend Biot's single porosity theory to dual porosity models.Valliappan and Khalili-Naghadeh [3] and Khalili-Naghadeh and Valliappan [4] accounted in their coupled dual porosity formulations for the effect of rock deformation on the pressure of both media. In these formulations various coefficients are involved and defined in terms of measurable physical parameters.Ghafouri and Lewis [5] developed a formulation for deformable porous media. In this formulation, the compressibility of fractures is assumed not to alter the compressibility of whole system and the effect of fracture pressure on total deformation was ignored.Chen et al. [6] proposed a new formation out of Biot's theory of poroelastisity for coupling geomechanics and fluid flow in deformable dual media. They added a term to account for the effect of pressure of the secondary porosity on volumetric strain, bulk volume and total pore volume. They derived the changes of individual fracture and matrix pore volumes in terms of total stress and the pressure of the individual medium. Their final governing equations were similar to those of Valliappan and Khalili-Naghadeh [3]. The main difference is the way that the coefficients are defined. Keywords: equation, porosity, aperture, spe 93083, flow in porous media, fluid dynamics, deformation, fracture, matrix, effective stress Subjects: Hydraulic Fracturing, Reservoir Characterization, Reservoir Fluid Dynamics, Reservoir geomechanics, Flow in porous media This content is only available via PDF. 2005. Society of Petroleum Engineers You can access this article if you purchase or spend a download.

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