TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFormation Testing (FT) can collect high-resolution data sufficient to capture small variations in fluid and formation properties.Unfortunately, conventional interpretation techniques are rarely capable of processing the data from complex tool configurations and formation properties. Studies have shown that numerical simulation can replicate the complex physics of multiphase fluid flow but often not at the level of detail needed for high-resolution data interpretation.In this paper, we propose a general three-dimensional and multiphase numerical model to incorporate various wellbore and/or tool factors. Unlike the analytical source representation of a well commonly used in reservoir simulation, the proposed model establishes the internal boundary of a well, generally involving the pressure and flow rate at the sandface, where the size of the wellbore or tool configuration is equivalent to or smaller than that of the grid cells. This fully coupled and fully implicit model at a fine spatial and temporal scale is advantageous in revealing further potentially useful information and realizing the synergy across a spectrum of FT applications. As a result, wellbore and/or tool factors, particularly the tool storage effect, can be integrated at a level of detail not previously possible in the absence of a comprehensive wellbore model.The mathematical formulations and numerical schemes are presented. Simulation studies include the primary FT applications in the field, i.e., pressure transient testing and fluid sampling for both oil-based and water-based mud filtrate. These examples show that the proposed near-wellbore highresolution modeling approach with non-negligible wellbore and/or tool factors permits new insights into fluid flow in FT applications.

The meniscus profiles determined numerically by White & Tallmadge (1965) have been found to be in error. Accordingly, the reported values of meniscus height and curvature at the top of the meniscus are also in error. These errors were initially suspected by observing that top curvatures calculated from the reported values of height fell below the minimum possible (flat plate) value at large radii.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe number of components used in the compositional simulation of petroleum reservoirs affects both the accuracy and the speed of simulation results. A proprietary, fully automatic fluid characterization technology provides an efficient way to reduce the number of components of reservoir fluid samples used to simulate relevant laboratory tests within a predefined accuracy. This paper focuses on investigating how the number of components impacts the speed and accuracy of real world compositional reservoir simulations.The procedure starts with using PVT laboratory test data to characterize the reservoir fluid behavior under anticipated reservoir production mechanisms. The PVT laboratory test data are matched within a given accuracy by running the proprietary Fully Automatic Reservoir Fluid Characterization package, where the minimum number of components can be set by the user. The characterized EOS parameters are directly exported to a compositional simulator to perform the actual reservoir simulation using different numbers of components and two different simulation schemes, i.e., IMPES and Fully Implicit. Simulations are performed for a range of fluid types, from volatile oils to gas condensates. This paper presents a systematic investigation of how the number of components influences the accuracy of simulation results and the speed of the simulation. Three examples show that this method of reducing the number of components results in a significant increase in the compositional simulation speed while, at the same time, retaining the prediction accuracy.