The goal of reservoir characterization is to describe the spatial distribution of petrophysical parameters such as porosity, permeability, and saturation. Petrophysical properties in themselves have no spatial information and must be linked with geologic models before they can be displayed in 3D. This is best done by developing relationships between rock fabrics and petrophysical properties because permeability and saturation are controlled by pore-size distribution, which a product of depositional and diagenetic history (Fig. 1). Numerical engineering data and interpretive geologic data are linked at the rock fabric level because pore structure is fundamental to petrophysical properties and pore structure is the result of spatially distributed depositional and diagenetic processes.

Porosity, permeability, and capillary pressure data (used to estimate saturation) are obtained from core analysis. Even in the most heavily cored reservoirs, however, cores constitute a fraction of their available wellbore data. The most common source of wellbore data are wireline logs. Porosity values are readily obtained from wireline logs and saturation can be obtained from a combination of porosity and resistivity logs using the Archie equation and other methods. Permeability values, however, cannot be obtained directly from wireline logs in carbonate reservoirs because of the complexity and large variability of carbonate fabrics.

The purpose of this module is to illustrate the large variety of carbonate fabrics and present the rock fabric method of relating these fabrics to permeability. Capillary properties and saturation can also be related to the rock fabrics but those relationships will be presented in a future module. Methods for integrating this information into wireline-log analysis will also be presented in a future module.