Quantitative characterization of fractured carbonate rocks is of interest for several reasons: first, because naturally fractured carbonate oil reservoirs are among the most important in the world; second, because fluid flow through the pore system depends on the internal geometry of the rock; and, third, because numerical simulation of such reservoirs require reliable values of matrix porosity, fracture porosity, and block size.

Naturally fractured reservoirs are complex systems whose flow properties are not well understood. From the fluid transport viewpoint, fractured carbonate reservoirs can be considered to consist of two basic components: matrix blocks and fracture network. Matrix blocks are characterized by their low fluid conductivity, and their main function is to storage fluids, whereas the fracture network is composed of highly conducting channels.

This paper describes a simplified method for determining matrix and fracture porosities of carbonate media, as well as block size. The method makes use of total interconnected porosity and formation resistivity factor data. Of fundamental importance to the method is the fact that, in the case of fractured carbonate media saturated with a conducting fluid, the conductivity of the fracture network is much greater than that of the matrix blocks, so that, for practical purposes, the latter can be considered as negligible.

For illustration purposes, an application to a real case is presented. To this end, use is made of two procedures, one for fracture porosity and the other for block size. A step by step description is given for each procedure. It is considered that the simplicity of the procedures make the methodology an attractive tool for the characterization of carbonate fractured reservoirs.

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