The most important and difficult aspect of modeling a naturally fractured reservoir is the correct calculation of the exchange of fluids between the matrix rock and the surrounding fractures. Several authors have published alternative techniques for handling this problem over the past few years. However, because each of these alternatives has some limitations, a new and more general technique has been developed. This new technique is used to simulate matrix/fracture exchange with special emphasis on the gravity forces included in the exchange terms. The exchange terms and the gravity forces within the exchange terms simulate the behavior of a single matrix block surrounded .by fractures that may contain several different fluids. The gravity forces are internally calculated as functions of saturation. This technique has been incorporated into a new three-dimensional (3D), threephase, fully implicit model for simulating fluid flow in a naturally fractured reservoir. The description of the porous medium might include highly fractured, microfractured, and nonfractured regions. Several examples explain the use of a new naturally fractured reservoir model and the essential differences between the new approach and those used in earlier naturally fractured reservoir models. IntroductionThe numerical simulation of naturally fractured reservoirs is a subject that has been described extensively in the literature of the oil industry for the last 25 years.In the initial work done, the primary goal of the simulation of fractured systems was to study pressure behavior during well tests. This was based primarily on the analytical solutions obtained by Barenblatt et at. l and Warren and Root Z for describing singlephase flow near a wellbore in a naturally fractured reservoir. Their work was based on the concept of a fractured continuum filled with noncontinuous matrix blocks. Warren and Root also delivered a one-dimensional (ID) radial model, which Kazemi 3 later extended to study two-dimensional (2D) flow during a well test. Further developments were made by Iffly et at.,4 Yamamoto et at.,5 Kleppe and Morse, 6 and others, but these models were used either to match laboratory results or to study the behavior of a single matrix block.More recently, more complex problems have been studied with full-field reservoir models. Our interest in this paper is the study of fractured reservoirs with full-field models.Examples are presented that show some of the differences between a new fractured reservoir model and other models described in the literature. Comparisons are also made that point out some of the complexities of fractured reservoir simulation and the potential problems with the use of a single-porosity approach to study various types of fractured reservoir behavior.One of the first papers to describe a fractured reservoir simulator that could be applied to full-field model studies was by Saidi 7 and was concerned with the simulation of the very highly fractured reservoirs in Iran. This model represented the fracture system as a ...

Most of oil reservoirs operated by Total in West African deep offshore are multi layered highly unconsolidated sands. Burial depths, below the mud line, ranges from 500 to 2500mTVD. Sea water injection is done for pressure maintenance in deviated and horizontal wells equipped with sand control. Polymers injection for EOR and PWRI are also practiced. In theory, the very high permeability of soft sand reservoirs should allow injecting in matrix mode at high rates with small differential pressure. In reality, declining injectivity over time requires injecting in non-matrix mode, at much higher pressures than anticipated, hence the concerns about the confinement of the injection. The mechanisms of injectivity restoration by increasing the pressure in soft sands and the subsequent risks of cap rock failure have to be understood. Their incorporation in modeling tools is crucial for predicting the operating pressure range and designing the surface and wells facilities accordingly. Standard tensile fracturing models commonly applied to consolidated reservoir rocks do not seem to be adapted to soft materials which behavior is dominated by shear failure and resulting in dilation. This paper will present modeling approaches aimed at predicting the responses of soft sands and of the cap rock to produced water injection taking into account the coupling between geomechanics, flow and formation damage. Field observations are presented and confronted with model predictions.