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A new method for construction of hysteresis capillary pressure relationships for use in reservoir simulation models is presented. The method is based on the experimental drainage-imbibition bounding curves and the history of the saturation changes. By scaling of the measured drainage and imbibition bounding curves into the saturation ranges in question for hysteresis scanning loops, any family of hysteresis curves may be constructed. The method is well suited for use in reservoir simulation models. Results of highly accurate laboratory measurements of capillary pressures on a gas-oil system including re-imbibition and re-drainage are presented. Predictions of hysteresis behavior of the laboratory system by the new method show satisfactory agreement with the experiments, while prediction by the much used Killough's method fail to match the experiment, primarily because it does not scale saturations. It is also observed that the commonly used Land equation for prediction of residual saturations is not representative for the system under investigation. Since the Land equation do not distinguish between rock types, it is not recommended used unless experimental support of its applicability exists. Our results show that the relationship between the residual saturation and the initial saturation for a hysteresis imbibition process is approximately linear. Introduction In a paper published in 1965, Morrow and Harris presented experimental results and a comprehensive discussion of capillary behavior of porous materials. They show that a hysteresis curve departing from one of the bounding drainage or imbibition curves is uniquely defined by the departing point on the curve. By the same token, virtually an infinite number of families of hysteresis curves may result from saturation reversals, and each branch is defined by the departing point and the history of saturation reversals. In order to define an imbibition hysteresis curve, the residual saturation in addition to the departing point must be known. Commonly used for prediction of residual saturation is the semi-empirical relation presented by Land based on matching of experimental data. He found that for a given sand the difference in reciprocals of residual and initial saturations remains constant. Several authors have discussed hysteresis behavior of porous media. Of particular interest is representation of hysteresis in reservoir simulation. Model input data normally includes complete drainage and imbibition curves. The simulation model then applies some method to predict hysteresis residual saturations and hysteresis capillary pressures and relative permeabilities. Both Killough and Carlson presented methods for predicting hysteresis in relative permeability. For prediction of hysteresis in capillary pressures, the method presented by Killough is frequently employed. His method computes hysteresis capillary pressures by weighting of the complete drainage and imbibition curves. However, as pointed out by Tan, Killough's method was specially formulated for the case where the drainage and imbibition curves meet at the residual saturation. Because of that, the method is often inadequate. Recently, very accurate laboratory measurements of gas-oil capillary hysteresis have been made in the laboratories of IFP in a cooperation with Total and Elf Aquitaine. Measurements of capillary pressures including complete drainage and imbibition curves and intermediate drainage-imbibition and drainage-imbibition-drainage loops were made. The results are presented in this paper and used for evaluation of hysteresis prediction methods. Experiment Gas-oil drainage and imbibition capillary pressure cycles were measured using the Porous Plate Method. A schematic of the laboratory setup is shown in Fig. 1. The laboratory setup includes: P. 597^

TX 750e3-3836, U. S. A., fax 01 -972 -952-e435. AbstractA new approach is described to characterise fractured reservoirs using a software code which can simulate transient well tests in a realistic 3D fracture/matrix model. By a process of iteration the geological and flow data can be reconciled to produce plausible models which could help to constrain reservoir simulation. The numerical results indicate that the simulated pressure derivatives generally show different characteristics with different fracture pattern configurations. The results also indicate that theoretical dual porosity behaviour is absent when a more realistic transient matrix to fracture flow solution is used. This approach has important implications in the use of well tests to determine parameters for input to a multiphase flow simulator, where the well positioning in relation to highly conductive fractures is critical. The advantage of the described approach, compared to conventional analytical analysis, is that the geological data are calibrated and preserved. Parameters can then be more accurately represented in a dynamic reservoir model.

Methane diffusion in micro-and mesopores of carbonaceous materials is dominated by molecular interactions with the pore walls. As a consequence, the fluid molecules are mainly in a diffusive regime and the laws of fluid mechanics are not directly applicable. A method called the "free volume theory" has been successfully used by different authors to study the diffusion of n-alkanes into microporous carbons. However, we show in this paper that such a method fails to describe the dynamical properties of methane in porous hosts presenting both micro-and mesopores. We further evidence that this theory is limited to structures whose pore diameters are lower than ∼3nm. We then 1 propose a simple scaling method based on the micro-and mesoporous volume fraction in order to predict diffusion coefficients. This method only requires the knowledge of i) the host microporous volume fraction and ii) the self-diffusion coefficient in micropores smaller than 3nm, which can be obtained using the "free volume theory", Quasi-Elastic Neutron Scattering experiments, or atomistic simulations.