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Reliable relative permeability data is an essential input parameter in reservoir engineering, most significantly in the area of reservoir simulation of dual porosity systems. However, measurements of relative permeability do not work well, because of laboratory limitations. Also, reservoir core samples are generally extracted from zones where induced or natural fractures are absent. Obviously, data obtained from these cores may not reflect the real behaviour of naturally fractured reservoirs. Because of this laboratory limitation, many commercial reservoir simulators neglect the effect of dual porosity on relative permeability, and implicitly assume that relative permeability is a straight line. This assumption in naturally fractured systems may lead to erroneous results. The purpose of this study is to rectify these shortcomings by laboratory experimental contributions. Thus, the main objectives are: (a) to perform special core analyses on Berea outcrop core samples as a model of rock; (b) to simulate fracture opening by cutting these samples in such a way as to get different fracture apertures; (c) to investigate the effect of dual porosity on the shape of capillary pressure curves; and (d) to evaluate the effect of fracture opening on both absolute and relative permeability. A good correlation between absolute permeability and fracture aperture is obtained. The effect of dual porosity is observed clearly on capillary pressure curves. Unsteady-state tests could not be used to measure relative permeability on these specially prepared core samples. This is due to the fact that fractures become the easiest pathway for water flow, which results in high residual oil saturation in the matrix. However, the centrifuge technique test is run with success because both matrix and fracture are subjected to the centrifuge field. These findings are extended to an actual naturally fractured reservoir (NFR) in Algeria. The Tin Fouye Tabankort (TFT) reservoir is selected as a prototype of an Algerian NFR. Availability of naturally fractured cores and published data are the principal reasons for this selection. A discussion of TFT natural fracture indicators is presented, including core observations, well test analysis, and borehole imager tools. Displacement tests are conducted on a full diameter core in order to solve the laboratory limitations, and to obtain representative data of relative permeability. These laboratory tests indicate the existence of a good correlation between permeability and fracture opening. The correlation is used to estimate the aperture of natural fractures in the TFT reservoir. This study may also lead to the development of a laboratory technique for determining systematically the fracture intensity index. Background Multiphase flow of fluids through porous media can be related to the relative permeability of each phase. These flow properties are the composite effect of several petrophysical parameters, including: pore geometry, wettability, fluid distribution, and saturation history. This concept of relative permeability is utilized extensively in reservoir engineering for understanding and predicting many physical phenomena that occur during reservoir exploitation. According to Rossen and Kaumar(1), most reservoir simulators neglect the effect of the dual porosity on relative permeability. However conventional fractured-reservoir simulators assume that straight-line relative permeability curves apply within the fracture pore space.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn highly heterogeneous reservoirs classical characterization methods often fail to detect the location and orientation of the fractures. Recent applications of Artificial Intelligence to the area of reservoir characterization have made this challenge a possible practice. Such practices consist of seeking the complex relationship between the fracture index and some geological and geomechanical drivers (Facies, porosity, permeability, bed thickness, proximity to faults, slopes and curvatures of the structure) in order to obtain a fracture intensity map using Fuzzy Logic and Neural Network.This paper shows the successful application of Artificial Intelligence tools such as Artificial Neural Network and Fuzzy Logic to characterize naturally fractured reservoirs. A 2D fracture intensity map and fracture network map in a large block from Hassi Messaoud field have been developed using Artificial Neural Network and Fuzzy Logic.This was achieved by first building the geological model of the permeability, porosity and shale volume using stochastic conditional simulation. Then by applying some geomechanical concepts first and second structure directional derivatives, distance to the nearest fault, and bed thickness were calculated throughout the entire area of interest. Two methods were then used to select the appropriate fracture intensity index. In first method well performance was used as a fracture index. In the second method, which consists of a new proposed approach, a Fuzzy Inference System (FIS) was built. With such system static to dynamic data was coupled to reduce the uncertainty and resulted in a more reliable Fracture Index. The different geological and geomechanical drivers were ranked with the corresponding fracture index for both methods using a Fuzzy Ranking algorithm. Only much important data were selected to be mapped with the appropriate fracture index using a feed forward Back Propagation Neural Network (BPNN). The neural network was then used to obtain a fracture intensity maps throughout the entire area of interest. A mathematical model based on "the weighting method" was then applied to obtain fracture network maps, which resulted in a deep insight about the major fracture trends.The obtained maps were compared in the end and the results show that the proposed approach is a feasible methodology to map the fracture network.

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