Estimating Permeability of Vuggy-and-Fractured Carbonates by Modeling Mud-Filtrate-Invasion Effects on Resistivity Logs
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 121136, "Modeling Mud-Filtrate-Invasion Effects on Resistivity Logs To Estimate Permeability of Vuggy-and-Fractured Carbonate Forma tions," by Luis Javier Miranda, SPE, Carlos Torres-Verdin, SPE, and Jerry Lucia, SPE, University of Texas at Austin, prepared for the 2009 SPE EUROPEC/EAGE Annual Conference and Exhibition, Amsterdam, 8-11 June. The paper has not been peer reviewed.
A method was developed to diagnose and estimate secondary porosity and absolute permeability of vuggy-and-fractured carbonate formations by use of numerical simulation of mud-filtrate-invasion process. The method was used to interpret data acquired in a carbonate reservoir in the Barinas-Apure basin in southwestern Venezuela.

Introduction
Permeability estimation is an important step of reservoir characterization. In heterogeneous reservoirs, in which rock composition and petrophysical properties vary, integration of core measurements with well-log data is necessary to predict petrophysical properties in zones with no or scarce core samples. Permeability was estimated by numerical simulation of the mud-filtrate-invasion process that takes place in complex reservoirs having a triple-porosity system. Dual-laterolog and array-induction-resistivity logs were simulated to validate the estimation of petrophysical properties. This method includes the geological characterization of core measurements and the integration of well-log and production data.

Field Description
The O-BOR-2E reservoir is in the Borburata field, in the Barinas-Apure petroleum basin of southwestern Venezuela. The field, covering a total area of 14 km2, includes a group of smaller zones delimited by faults. The carbonate reservoir accounts for most of the hydrocarbon production of the field, which was discovered in 1994. It has wide variations of rock composition and petrophysical properties and, as Fig. 1 shows, comprises a triple-porosity system (i.e., matrix, vugs, and fractures), according to observations and analysis of core measurements and nonconventional well logs.

Sedimentary Model
Facies in the O-BOR-2E reservoir are sandstone, mixed sandstone/dolostone, dolostone, pelecypod limestone, foraminiferal limestone/siltstone, and shale. The volumetric concentration of each facies varies across the field. An important observation is that the best oil-producing wells are in zones with large amounts of dolomite that also are associated with an increase of secondary porosity (interconnected vugs and fractures).

Method of Core/Log Integration
Most interpretation methods to estimate permeability are based on empirical correlations between permeability and porosity, irreducible water saturation, pore-throat radius, and other factors. Integration of core and log data is necessary to estimate permeability. The large variability observed in rock composition and petrophysical properties, coupled with a high degree of spatial diversity, makes it necessary to use nonconventional interpretation methods to estimate permeability.