In Brazil, highly fractured carbonate rocks compose most pre-salt reservoirs. During oil production, the reservoir permeability evolves as fractures deform and fail in shear. Thus, a realistic description of those natural fractures is essential to establish an accurate interpretation of reservoir behavior. Several numerical approaches have been developed adopting either explicit or implicit representation of natural fractures. The former is appropriate for handling dominant fractures. However, depending on the complexity of fracture networks, the explicit representation can be unfeasible for numerical modelling. The implicit representation includes the effect of fractures through continuum approaches. This paper estimates the hydro-mechanical behavior of a fractured carbonate reservoir through the finite element method using some of the main approaches for fracture representation. For explicit fracture representation, we use zero-thickness interface elements, while for the implicit representation, we consider the dual porosity/dual permeability model. We compare the borehole pressure during the first years of production obtained while using each approach. The results show that the fully coupled zero-thickness interface model provides accurate estimates particularly in the presence of dominant fractures. However, the explicit approach is computationally expensive owing to the difficulties associated to model building and required mesh refinement. On the other hand, the dual-porosity/dual-permeability models are very attractive in terms of efficiency and computational cost. However, the dual-porosity/dual-permeability model is more appropriate for fractured porous media with a connected fracture system. Finally, this paper provides a better understanding of some of the main approaches for fracture representation and their applications in reservoir geomechanics.

1. INTRODUCTION

The Brazilian pre-salt fields are composed of extremely heterogeneous carbonate formation. Those carbonate reservoirs are located below 2000 m water and 3000 m of rock formation, which includes a salt layer with different thicknesses (Beltrao et al. 2009). Tectonic movements are responsible for the development of fractures in rock formations. The connectivity of those fracture creates complex networks, which dominate the fluid flow pattern and mechanical behavior in many reservoirs (Zimmerman and Main 2004). Pre-existent fractures can be open or sedimented (closed fracture). Open natural fractures play as conduits that increase the permeability of the porous media, while sedimented natural fractures act as barriers changing the fluid flow behavior.

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