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Abstract
This paper presents a coupled geomechanics and compositional model and applies it to the oil and gas recovery process. An equation of state compositional simulator called the General Purpose Adaptive Simulator (GPAS), developed at the University of Texas at Austin, which uses a finite difference method for the solution of its governing partial differential equations (PDEs), is iteratively coupled with a geomechanics model that is developed using a finite element method in this research. An elastic constitutive model is applied to represent deformation behaviors of rocks in the geomechanics model. Porosity is selected as the coupling parameter between two coupled models. The unknowns located on nodes and block-centers in the two models are evaluated using an area weighting technique
The proposed model has been implemented on the Linux PC clusters for solving 2D compositional reservoir problems considering geomechanics effects. These results indicate that the geomechanics-coupled compositional reservoir simulator developed in this study can be used to complete simulations for stress-dependent or stress-sensitive reservoirs.

Introduction
It has been more than twenty years since researchers realized the importance of geomechanics for hydrocarbon production in stress-sensitive or stress-dependent reservoirs, e.g. reservoir subsidence, well-bore stability, sand production, pipe crash, etc. Geomechanics plays an important role in stress-sensitive fields. Examples of such fields are Venice (Italy), Latrobe Valley (Victoria, Australia), the Wairakei Geothermal field (New Zealand), the Valhall field (North Sea, Norway), the Ekofisk field (North Sea, Norway), Bolivar Coast (Venezuela), Wilmington field (Long Beach, California, USA), and the South Belridge field (Kern Country, California, USA). Coupled geomechanics simulators are very useful tools for evaluating and analyzing oil and gas production from stress-sensitive fields.
Two elements, fluid (water, oil, and gas) and solid (porous rock), reside in the same reservoir. The porous medium serving as a skeleton may contain oil, gas, and water in its pores. There are many interactions between its associated seepage field (i.e. rock compressibility, permeability, and porosity etc.) and the in situ stress field (i.e., rock stress, strain, and displacement). Reservoir subsidence is caused by depletion of underground fluid during production from stress-sensitive or stress-dependent reservoirs, such as highly compactable reservoirs, low-permeability reservoirs, chalk reservoirs, unconsolidated (soft or oil) sands, a cyclic steam recovery of heavy oil, etc. The subsidence problem has motivated reservoir engineers to investigate the interactions between the fluid and the deformable solid in recent decades. The subsidence is considered as not only a positive for the production, which is a hydrocarbon driver with compaction of the porous volume, but also as a negative, which can lead to sand production, pipe crashes, wellbore casing damage, and even well failure.

For such reservoirs, interactions between the seepage field and the in situ stress field are complex, and affect hydrocarbon recovery. A coupled geomechanics and fluid-flow model can capture these relations between fluid and solid and thereby present more precise history matchings and predictions for better well planning and reservoir management decisions. A traditional reservoir simulator cannot adequately or fully represent the ongoing coupled fluid-solid interactions during production. Many researchers have studied multiphase models coupled with geomechanics models over the past fifteen years.