Résumé -Impact des hétérogénéités sur la production d'huiles lourdes mobiles par SAGD -L'augmentation de la demande en pétrole et l'existence de réserves conséquentes en huiles lourdes et bitumes vont motiver, dans les prochaines décennies, un effort important pour développer les réservoirs non conventionnels. Dans ce cadre, la production par drainage gravitaire soutenu par une injection de vapeur (SAGD) est une technique très prometteuse pour extraire les huiles lourdes des réservoirs épais et de forte perméabilité. Les tests pilotes conduits sur champ à ce jour ont souligné l'influence des hétérogénéités sur le développement de la chambre induite par l'injection de vapeur. Cette étude présente les résultats d'une analyse numérique visant à apprécier l'impact des hétérogénéités sur la quantité d'huile produite par SAGD dans des réservoirs contenant des huiles lourdes mobiles. Une population de modèles de réservoir contenant 0, 10, 15 ou 20 % d'argile a été générée aléatoirement. Puis, la production par SAGD a été simulée pour chacun de ces modèles. Il apparaît que l'influence des lentilles d'argile dépend de leurs positions par rapport aux paires de puits, la configuration la plus préjudiciable étant celle où les lentilles argileuses se situent entre le puits injecteur et le puits producteur. En outre, on observe qu'on obtient la moitié, le tiers et le quart seulement du volume produit cumulé pour le modèle homogène après 3 ans de SAGD lorsque les proportions d'argile sont respectivement de 10, 15 et 20 %. Parallèlement, on montre que le CSOR passe de 2 pour le modèle homogène à 3 pour les modèles avec 20 % d'argile. Abstract -Heterogeneity Impact on SAGD Process Performance in Mobile Heavy Oil Reservoirs -The increasing oil demand and the significant amount of heavy oil/bitumen reserves will motivate a huge effort on the development of heavy oil reservoirs in the next decades. Within this framework, Steam Assisted Gravity Drainage (SAGD) is a very promising technique to produce heavy oil from thick and high permeability reservoirs. The small scale field tests conducted up to now highlighted the influence of heterogeneities on the development of the steam chamber involved in SAGD. This work presents a numerical investigation of the effects of heterogeneity on

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In addition to standard oil recovery methods by depletion, various fluids (water, nitrogen or many types of gas) can be injected from the surface in order to produce the trapped oil. Among all gas, air is the most convenient one since it presents the advantage of being available everywhere. Therefore air injection can be an economical alternative for pressure maintenance of fractured reservoirs as it avoids re-injecting a valuable associated gas and/or generating or importing a make-up gas. A major contribution of this technique is that the oil recovery can be enhanced significantly thanks to the thermal effects associated with oil oxidation. In addition, from an operating point of view, economical and feasibility studies concluded on favourable future perspectives. However, its use is limited by safety reasons due to the explosive mixture resulting from oxygen and hydrocarbons. In the reservoir rock, the microscopic size of the pores prevents any explosion. On the other hand, a commingled arrival of oxygen and hydrocarbons in production wells may result in dramatic damages. Therefore, air-injection methods require a careful assessment of the involved reservoir displacement mechanisms, in particular the magnitude and kinetics of matrix-fracture transfers. Actually, the latter will largely control the displacement efficiency as well as the composition of well effluents from which residual oxygen has to be absent. The aim of this paper is to identify and model the physical mechanisms controlling matrix-fracture transfers during air injection in light-oil fractured reservoirs, first at the matrix block scale then at the field scale. The study actually relies on a careful analysis and compositional thermal simulations on a fine-grid single-porosity model of a matrix block surrounded by air-invaded fractures that allows us to study the influence of block size on the kinetics of oil recovery as well. These fine-grid simulations mainly show that gas diffusion and thermodynamic transfers are the major physical mechanisms controlling the global kinetics of matrix-fracture transfers and the resulting oxidation of oil. The chronology of extraction of oil components from the matrix blocks can then clearly be interpreted in relation with phase transfers. Once all the mechanisms have been identified, we focus on the equivalent (up-scaled) dual-porosity modelling. This model, rooted in a specific numerical formulation which ensures a proper up-scaling of diffusion and inter-phase transfers at the overall scale of matrix blocks, eventually appears to be a reliable simulation tool usable for field-scale predictions, in agreement with the previously defined reference model. Thus, results could be simulated and interpreted at different scales closer to the field scale than the matrix block scale. In addition, some conclusions were drawn regarding the sensitivity of the process to the kinetics of oxidation and the water saturation conditions. Petrophysical Data The petrophysical and thermodynamic properties used in our simulations are largely inspired from the Ekofisk field (Thomas et al., 1983, 1991, Agarwal et al., 1999, Jensen et al. 2000). The matrix medium has a permeability K of 1mD, a porosity F equal to 30%. The calorific capacity of the unsaturated rock is equal to 2.35 Jg−11°C−1 and the overall thermal conductivity of the fluid-saturated rock equals 1.8 Wm−1°C−1. The working pressure is 5600 Psi, very close to the bubble point pressure and temperature is 266°F. The irreducible water saturation, Swi, is 0.15 and the residual oil saturations, Sorw and Sorg, are both equal to 0.25. Capillary pressures and relative permeability curves are shown figure 1. Petrophysical Data The petrophysical and thermodynamic properties used in our simulations are largely inspired from the Ekofisk field (Thomas et al., 1983, 1991, Agarwal et al., 1999, Jensen et al. 2000). The matrix medium has a permeability K of 1mD, a porosity F equal to 30%. The calorific capacity of the unsaturated rock is equal to 2.35 Jg−11°C−1 and the overall thermal conductivity of the fluid-saturated rock equals 1.8 Wm−1°C−1. The working pressure is 5600 Psi, very close to the bubble point pressure and temperature is 266°F. The irreducible water saturation, Swi, is 0.15 and the residual oil saturations, Sorw and Sorg, are both equal to 0.25. Capillary pressures and relative permeability curves are shown figure 1.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAl Khalij could be viewed as the archetypal complex carbonate field. Laterally sealed by a stratigraphic closure, the reservoir monocline consists in a layercake of alternating good and poor quality rock whose fabric has been intensively reworked during multiple phases of diagenesis. Additionally, the oil column is relatively thin and average water saturation above free water level exceeds 85%.Al Khalij development challenge can thus be formulated as: "How to efficiently recover a large oil accumulation trapped with much larger amounts of water in the capillary transition zone of a highly heterogeneous reservoir of uncertain boundaries overlying an active aquifer?" To meet a challenge of such magnitude, a phased development was undertaken and completed recently, nine years after kick-off. Even so, the expected recovery factor remained low and the reservoir model unmatched. This paper describes the extensive work program implemented to better understand early-time reservoir behavior and find ways to increase recovery.Starting with a "back to the rocks" approach, a wide range of studies and additional measurements were undertaken, culminating in full field reservoir simulations. Innovative modeling and interpretation techniques were implemented to extract maximum information from formation pressure and pressure build-up measurements. Where key uncertainties remained, specific solutions were sought in terms of enhanced data acquisition and monitoring programs, from petrophysical measurements on full size cores to injection PLTs in oil producers. Integrated static and dynamic syntheses reviewed all resulting information to better assess critical reservoir heterogeneity levels. A specifically designed dual-porosity simulation model was built to properly represent the smallscale heterogeneity impact, and successfully history matched.In less than two years, a full field redevelopment plan was defined that is expected to double the recovery factor. The innovative acquisition, interpretation and modeling techniques developed in the process could fruitfully be applied to other complex fields.

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