Résumé -Géomécanique en simulation de réservoir : méthodologies de couplage et étude d'un cas de terrain -Cette publication traite de la modélisation des effets géomécaniques induits par l'exploitation des réservoirs et de leur influence sur les écoulements de fluide dans les réservoirs. Ces effets géomécaniques peuvent être relativement conséquents dans le cas des réservoirs faiblement consolidés et des réservoirs fracturés. Les principaux mécanismes couplés intervenant lors de la production de ces réservoirs, ainsi que les méthodes permettant de les modéliser, sont présentés. Le comportement géomécanique d'un cas réel est ensuite étudié. Un simulateur couplé -ATH2VIS -est utilisé afin de quantifier les effets géomécaniques induits par l'exploitation d'un réservoir carbonaté fortement hétérogène et compartimenté. Ce simulateur met en oeuvre un couplage explicite et gère les échanges de données entre le simulateur de réservoir ATHOS TM développé à l'IFP et le simulateur de géomécanique VISAGE TM (VIPS Ltd. 2001). Le résultat des simulations couplées indique que la modification de l'équilibre mécanique du milieu se traduit par une localisation de la déformation sur certaines failles en fonction de leur orientation et des variations de pression et de température dans leur voisinage. Il est également observé que seule une partie de la faille atteint le seuil de déformation plastique. Au cours de l'analyse couplée, le tenseur de déformation plastique sur les plans de faille est traduit en variation de la transmissibilité de la faille afin d'améliorer la représentation des écoulements dans le réservoir et de faciliter le calage des historiques de production. Abstract -Geomechanics in Reservoir Simulation

Generally, in classical reservoir studies, the geomechanical behavior of the porous medium is taken into account by the rock compressibility. Inside the reservoir simulator, the rock compressibility is assumed to be constant or to vary with the pressure of the oil phase. It induces some changes in the porosity field.During the depletion phase or the cold-water injection of highpressure/high-temperature (HP/HT) reservoirs, the stress state in and around a reservoir can change dramatically. This process might result in rock movements such as compaction, induced fracturing, and enhancement of natural fractures and/or fault activation, which continuously modify the reservoir properties such as the permeabilities and the fault transmissibilities.Modifications of such parameters strongly affect the flow pattern in the reservoir and ultimately the recovery factor.To capture the link between flow and in-situ stresses, it becomes essential to conduct coupled reservoir-geomechanical simulations.This paper compares the use of five types of approach for the reservoir simulations:• A classical approach with rock compressibility using only a reservoir simulator.• A loose coupled approach between a reservoir simulator (finite volumes) and a geomechanical simulator (finite elements). At given user-defined steps, the hydrocarbon pressures calculated by the reservoir simulator are transmitted to the geomechanical tool, which computes the actual stresses and feeds back iteratively the modifications of the petrophysical properties (porosities and permeabilities) to the reservoir simulator.• A one-way coupling: this approach is a simplification of the loose coupled approach in that the modifications are not fed back to the reservoir simulator.• A simplified approach using permeability and porosity multipliers inside a reservoir simulator. These multipliers are userdefined curves and vary with the pressure of the oil phase. This approach uses only a reservoir simulator.• A coupled approach in which the structural and the flow unknowns (displacement, pressure, and saturations) are solved simultaneously.These approaches are compared for two validation cases and two field cases described in the following.

Summary A fracture-acidizing treatment of carbonate formations can be considered successful when a relatively good fracture conductivity remains after treatment. To reach such a goal, an uneven etching of the fracture by acid is expected, so that channels are created that maintain the fracture hydraulically open even after "mechanical" closure, and therefore enhance productivity. Residual conductivity is the consequence of uneven etching of the surface, but the way this etching occurs in the field is not well understood and therefore poorly described. We thus propose in this paper an experimental method aiming at defining a methodology to investigate and quantitatively characterize how acid injection conditions affect the fracture surfaces, and how fracture conductivity can be estimated from the so-created surface topography. The statistical investigation of surface topography associated with acidizing experiments proposed in this paper, offers the possibility to evaluate the best fluid formulation and flow rate for a given formation type under well conditions. The field application of this method is evident, since it provides a new and interesting tool for selecting fluid and forecasting the behavior of the fracture after an acid fracturing job. Introduction Acid fracturing is a classical treatment used in carbonate formations to improve well productivity. To reach that aim, acid is injected either at a pressure sufficient to fracture the formation or into an already hydraulically induced fracture. As acid flows along the fracture, it dissolves portions of the fracture faces, generally in a non-uniform manner, so that conductive channels are created that remain "hydraulically" open even after "mechanical" closure. The treatment is thus as successful as the so created fracture is long and conductive. The efficient length of the fracture in a given formation is determined by injection conditions (flow rate), injection fluid composition, acid-formation reactivity (acid spending) and acid fluid loss (or leakoff) from the fracture into the formation. On the other hand, the mechanisms and the conditions that give a conductive acid fracture are poorly evidenced and described in the literature. Acid composition and fluid injection sequences are essential parameters in the design of an acid fracturing treatment. The two jobs described in Table 1, performed on two wells on the ABK field, provide clear evidence of the influence of acid formulation and alternating stages on residual fracture conductivity. Though these treatments were performed in nearly the same formations (dolomites). evaluation of post treatment performance displays (Table 1) a better efficiency of the first job. 61% of the injected acid indeed contributed to the etching, whereas for the second job, the major part of the injected volume was lost in the formation because of leakoff effects and consecutive wormholes formation, leading to a worse residual fracture conductivity. Leakoff by decreasing the acid available for the etching of the fracture faces, reduces the treatment efficiency. The need to control acid fluid loss, and the consecutive formation of channels perpendicular to the main flow (wormholes) led to many studies aiming at identifying the mechanisms of wormhole creation. These studies show that depending on injection rate, three different wormholing mechanisms are identified. Though fluid losses can not be avoided in acid fracturing, these studies enable a better understanding of the way acid is consumed through leakoff depending on the fluid rate, and therefore the way they can be reduced. The third important factor affecting fracture geometry is acid spending during injection. Acid spending is mainly controlled by the acid - rock reactivity, that in turns depends on many factors such as injection conditions, acid concentration, composition, formation composition, temperature, fracture width. On the field, success of an acid fracturing job is evaluated from post treatment performances.

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