The main method to predict and manage petroleum reservoirs is numerical simulation in which, traditionally, the only geomechanical parameter is rock compressibility. Usually it is adopted one single and constant value for the whole model. During exploitation, though, reservoir-rock deforms, causing porosity and permeability variation. While the first effect may not be well predicted by rock compressibility, the second is simply kept constant. Besides that, each facies has its own stress-strain behavior. Even though reservoir simulation models are very sensitive to compressibility values, it is not treated with the proper relevance: it is usually used as a matching parameter and, when special petrophysical experiments are not available, it is a common practice to use porosity and facies based correlations to determine reservoir compressibility. The compressibility may be used to represent geomechanics in three different forms:

  • in conventional reservoir simulation, in a simplified way of representing geomechanics;

  • in pseudo-coupling, in which the rock compressibility behavior may be taken to reservoir simulation through tables that correlate pore pressure to porosity and permeability multipliers and

  • in two-way coupling simulation, in which the compressibility may be one of the coupling parameters. The aim of this work is to show the importance of rock compressibility in reservoir simulation and to propose a better way of representing it in numerical models based on laboratory experiments.

1. Introduction

Numerical simulation is the main method to predict and manage petroleum reservoirs in which, traditionally, rock compressibility is the only geomechanical parameter. Usually one single value for the whole model is adopted, even though the reservoir rock is composed by different facies. Besides this simplifying assumption, this parameter is kept constant. During exploitation, though, the reservoir-rock deforms, and each facies should behave according to its own characteristics.

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