The paper describes the upscaling and reservoir simulation of a giant Middle East oil field, the geological modeling of which is described in a companion paper. 1 The main objective of the study was the simulation of the irregular water advance observed in some parts of the field as a consequence of peripheral water injection.Three scales of heterogeneity were identified in the characterization phase: the matrix, the stratiform Super-K intervals, and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used.The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled with algebraic methods, while the stratiform Super-K layers and fracture properties were reproduced explicitly at the simulation gridblock scale through an original upscaling procedure.The history match was achieved in a short time by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification.Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order.In a later stage, the model was used to run production forecasts under different exploitation scenarios.The conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, is necessary for accurate reservoir simulation and effective reservoir management.

This paper describes a technique to incorporate conductive faults and -fractures in a reservoir simulation model. The technique is appropriate for reservoirs with significant primary matrix productivity, and a large spacing between fractures (in the order of tens of meters). The single porosity (one grid) formulation is applied. Any fracture geometry can be represented accurately without grid modifications. The key elements of the approach are pseudo relative permeability curves for grid bocks containing fractures. These curves are determined through an analytical procedure, based on the local fracture and matrix properties. The method is applied successfully to a Middle East carbonate reservoir. Introduction Conductive faults and -fractures are common features in reservoirs worldwide. Several methods have been proposed to model fluid flow in fractured reservoirs. Well known is the Warren and Root [1] approach, which applies homogenization of the fracture properties and a dual porosity formulation (separate matrix and fracture grids). The homogenization of the fracture properties is possible when the Representative Elementary Volume (REV) [2] of the fracture network is smaller than the reservoir simulation grid. This paper focuses on fracture patterns that can not be homogenized, because the fracture REV is several times larger that the grid block size. Figure 1 provides an illustration. This figure represents a 10 by 22 kilometer sector of a much larger carbonate reservoir. The displayed fracture pattern is obtained from fracture analysis [3]. It is superimposed on a 250 by 250 meter simulation grid. In this example the conductive fractures are identified as the key contributor to unstable movement of the water injection front. Consequently, the fracture pattern must be incorporated when a simulation model is to be built. Several methods are available in the literature to integrate conductive fractures in a reservoir simulation model. Some of these methods are described below, with their strengths and weaknesses summarized in Table 1. Phelps et al [4] apply local grid refinement (LGR) to model conductive fractures explicitly. This approach is thorough in the handling of the physical elements of the displacement process. However, numerical difficulties may be experienced due to a large flow rate in grid blocks with a small pore volume. This is especially the case when a rapidly advancing water tongues develop due to gravity segregation in the fractures. Henn et al [5] extend the LGR technique by applying vertical lumping of the fractured grid blocks, in combination with an analytical treatment of capillary/gravity equilibrium in the fracture. Their method strongly improves numerical performance of the simulation model. The general disadvantage of these LGR approaches is that they are impractical for complex fracture patterns like the one shown in Figure 1. Cosentino et al [6] apply a dual media (dual permeability dual porosity) formulation to model conductive fractures explicitly. Their approach facilitates the capture of any complex fracture geometry without the need for modifications to the grid geometry. The method is thorough in its treatment of the processes that may take place during water flooding. The numerical challenges, with respect to high flow rates in grid cells with a small pore volume, are comparable to those experienced in the conventional LGR approach. Subsequently, relatively small time steps are required to adhere to stability criteria.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe paper describes the upscaling and reservoir simulation of a giant Middle East oilfield, whose geological modeling is described in a companion paper (1). The main objective of the study was the simulation of the irregular water advance observed in some parts of the field, as a consequence of peripheral water injection.Three scales of heterogeneity were identified in the characterization phase, namely the matrix, the stratiform Super-K intervals and the fractures. To accommodate the different hydraulic properties of each heterogeneity system, a dual-media approach (dual porosity and dual permeability) was used.The assignment of the effective properties to the simulation grids (matrix and fracture grids) was performed independently for the three heterogeneity systems. In particular, the geostatistical facies model was upscaled using algebraic methods, while the stratiform Super-K layers and fractures properties were explicitly reproduced at the simulation gridblock scale, through an original upscaling procedure.The history match was achieved in a short time, by a small variation of the fractal dimension of the fracture distribution and without resorting to any local modification.Simulation results showed that the fracture system was the controlling factor in terms of water advance and breakthrough, while the impact of the stratiform Super-K layers proved to be of second order.In a later stage, the model was utilized to run production forecasts under different exploitation scenarios.Conclusions of this study indicate that for such porous and fractured reservoirs with stratiform Super-K occurrences, a detailed characterization of all the heterogeneity systems, coupled with a dual-media formulation, are necessary requisites for accurate reservoir simulation and effective reservoir management.

Reservoir management engineers at Aramco are fortunate to have a wealth of information about their reservoirs in the corporate database. However, this wealth of information comes with a challenge of analyzing this immense collection of data and utilizing this information for decision-making. In this study we used data mining process to explore our database and evaluate the performance of wells in a study area of Ghawar field. The performance of more than 450 wells was then related to the super-k existence from flowmeter data. The existence of super-k layer was believed to cause premature water breakthrough and hence poor vertical sweep. The objective of the study was to answer the following question: Will producing a super-k well without isolating the super-k layer result in less cumulative oil production after water breakthrough? In this paper we developed a methodology to identify and quantify super-k while avoiding the pitfall of black or white (i.e. super-k or non super-k well). Super-k quantification was accomplished by deriving Fluid Flow Index from flowmeter surveys. The next challenge was to come up with a consistence measure of well performance so that all the wells can be compared on the same basis. This challenge was overcome by introducing the new definition of cumulative oil production and average oil rate after water breakthrough. In this paper we developed correlations to predict the performance of future wells to be drilled in the area. The study indicated that there was a positive correlation between super-k and high average rate after water breakthrough. Also, it was found that anomalous flood front encroachment in the east flank of the field is unrelated to the super-k. The study showed that reservoir performance is controlled by the interaction between Faults/ Fractures and Super-k layers. The results of this study created a paradigm shift in perceiving super-k layers in Ghawar. Field data showed an improved well performance by perforating isolated super-k layers. Moreover, the derived Fluid Flow index was used in building an enhanced and more realistic model for the field. Introduction Super-K or extremely permeable intervals are quite common in the study area of Ghawar field. In this carbonate reservoir, super-k zones can be horizontal layers, created during deposition or after digenesis, or they are just as likely to be sub-vertical fractures and faults1. However, since most of the wells in the study area are vertical, the probability of intersecting sub-vertical fractures and faults is very low. The first approach to treating super-k zones in carbonate reservoirs is to identify the nature of these zones in the wellbore. To this end, flowmeter logs is required to first identify potential zones and second characterize their properties. Continuous flow meters are routinely obtained in wells with openhole completions in Ghawar field to improve sweep from all the zones. It became apparent that in some wells, extremely high fluid-flow was confined to thin, apparently strati-bound ‘super-permeable’ intervals. This is in marked contrast with other wells, where continuous flow meters indicated that the fluid flow was distributed more uniformly across the openhole reservoir section.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper describes a method to condition facies (rock-type) permeabilities in geostatistical models to dynamic reservoir data: the flow meter log and the well test KH value. The proposed approach consists of two steps. In the first step, the flow meter logs are transformed into (reference) permeability profiles by use of the well test permeability-thickness (KH). This transformation is analytical, meaning that a geostatistical reservoir realization and numerical flow simulation are not required. In the second step, synthetic permeability profiles are computed for the known rock-type classification at the well locations. An optimization procedure is applied to improve the match of these synthetic permeability profiles with the reference (flow meter) profiles. In this process the initial (core based) rock-type permeability model is modified. The optimization procedure simultaneously takes into account all the wells, and is subject to geological constraints imposed by the user (ranking, permeability bounds). Although a number of assumptions must be verified, this fully analytical approach leads to a fast, flexible, and practical optimization routine that is relatively easy to implement. The up-front integration of dynamic data into the modeling process leads to a more representative permeability description than is obtained using only plug values. Because of the global nature of the optimization method, a satisfactory match can be extrapolated throughout the reservoir with a reasonable degree of confidence. The paper presents a successful application of the procedure to a Middle East reservoir.