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Modem methods of characterizing carbonate reservoirs include geologic and engineering studies of various types and at a range of scales, all focused on describing the volume and distribution of oil and gas saturation and the flow characteristics of the reservoir. Such activities include (1) constructing the geologic reservoir framework at the sequence scale, (2) making detailed facies maps at the parasequence scale, (3) analyzing petrophysical data through integration of rock-fabric, facies, porosity, permeability, and water saturation, (4) mapping petrophysical parameters, (5) interpolating deterministic data between wells using geostatistical methods, (6) analyzing production data, and (7) inputting data into computer flow simulators for performance evaluation.

In 1952, G. E. Archie published a landmark paper showing that petrophysical properties can be related to rock textures. Although this relationship forms a fundamental basis for all reservoir characterization studies, it is often overlooked, resulting in beautiful geologic reservoir descriptions that cannot be converted into engineering parameters or in exquisite engineering studies that defy geologic understanding. This is particularly true in carbonate reservoirs, where correlations are uncertain, pore geometries complex, and log analysis perplexing.

Research on several carbonate fields in the Permian Basin and published datafrom fields in other basins and from other geologic ages, have shown the significant rock-fabric parameters for carbonate reservoir characterization to be (1) size and sorting of depositional and diagenetic particles, (2) volume of interparticle pore space, (3) volume of separate-vug pore space, and (4) presence or absence of touching-vug porosity. The three-dimensional spatial distribution of these four parameters together

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