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The penneability, capillary properties, and m values of carbonate rocks are related to the particle size, amount of interparticle porosity, amount of separate vug porosity, and the presence or absence of touching vugs. Particle size, percent separate vug porosity, and the presence or absence of touching vugs usually can be detennined visually. The amount of interparticle porosity is more difficult to detennine visually and is done best by subtracting the visual estimate of separate vug porosity from the measure of total porosity obtained from wireline porosity logs or laboratory measurements. In the absence of touching vugs, the penneability, m values, and capillary properties can be estimated if the particle size, percent separate vug porosity, and total porosity are known. No acceptable method has been developed to estimate visually the penneability of touching vugs.A classification of carbonate porosity is proposed based on the data presented. This classification is intended to be used in the field or for routine laboratory description. Interparticle porosity is classified according to particle size and the dense or porous appearance of the interparticle area. Vuggy porosity is classified according to type of interconnection. Separate vugs are connected through the interparticle pore space and classified by percent porosity. Touching vugs are connected to each other and classified by presence or absence.

During the past 15 years, methods and technology for predicting the performance of carbonate reservoirs have improved dramatically. This advance occurred in response to the realization that more than half of the oil that could be swept by waterflooding is not contacted and remains in the reservoir. Attempts to simulate this performance and locate the remaining oil by use of simple reservoir models and newly developed flow-simulation computer programs have failed mainly because of the extreme heterogeneity that characterizes carbonate reservoirs. It is, in fact, the extreme geologic and petrophysical heterogeneity typical of carbonate reservoirs that distinguishes carbonate from siliciclastic reservoirs. Research programs focused on understanding the nature of the heterogeneity and developing methods to characterize carbonate reservoirs, together with improvements in computer capability and simulation programs, have led to more reliable predictions of reservoir performance and to methods for locating volumes of unswept oil in reservoirs under waterflood.Reservoir characterization encompasses the understanding and methods used to characterize reservoir heterogeneity. It can be defined as the construction of realistic 3D images of petrophysical properties used to predict reservoir performance, and it is a multidisciplinary, integrated task involving expertise in reservoir geology, geophysics, petrophysics, well logging, geostatistics, and reservoir engineering. Three-dimensional images are obtained from geological models constructed with core, wireline-log, and geophysical data. Petrophysical properties, obtained from core, wireline-log, and production data, are distributed within the geological model by linking petrophysical properties to geologic fabrics and by use of advanced geostatistical and geophysical methods. Finally, the model is put into a numerical simulator for testing and predicting future performance.The extreme petrophysical heterogeneity found in carbonate reservoirs is clearly demonstrated by the wide variability observed in porosity-permeability crossplots of core-analysis data. Research has shown that basic rock fabrics dominate control of petrophysical heterogeneity; within a rock-fabric facies, porosity and permeability have little spatial correlation and are widely variable at the scale of inches and feet. Permeability, in particular, can vary by a factor of 10 or more at the small scale and is nearly randomly distributed (Fig. 1). 1,2 This result suggests that much of the variability observed in core-analysis data is spatial noise and can be averaged within rock-fabric facies for the purposes of constructing a reservoir model. Only rock fabrics, not pore-throat size, permeability/porosity ratio, or flow-zone indicators, have vertical and lateral continuity. Therefore, rock-fabric facies are the basic elements for characterizing a carbonate reservoir. 3 Rock fabrics are geologic descriptors that characterize pore size according to particle size and sorting, interparticle porosity, and various ...

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