Geology-Based Permeability Modeling in Carbonate

Abstract

Carbonate rocks exhibit heterogeneity at all scales, which implies difficulties in characterizing these rocks and predicting their permeability. Rock characterisation can become easier and resolvable when the effect of geology on fluid flow is studied and understood. The aim of this presentation is to briefly discuss our previously presented workflow that resolves the porosity-permeability relation in the domain of geology, and move one step ahead to evaluate three existing permeability prediction models. Extensive work was done in this study where more than 1000 core plugs were tested from 7 different Cretaceous and Jurassic carbonate reservoirs in the Middle East. The plugs were properly selected to cover all property variations along the cored intervals. The data set included porosity-permeability, thin section photomicrographs and high pressure mercury injection data. Plug scale CT images were also used to disqualify any unrepresentative sample. Rock textures were extracted from thin sections and classified to be grainy, mixed & muddy. Each texture gave unique poroperm trend, and it was observed that the extent of the trend was controlled by the diagenesis process. Rock types were then identified on each trend by linking the texture information to the mercury injection capillary pressure data and pore throat size distribution.This data integration was used to test and validate three different permeability models (Kozney, Winland & Lucia) and evaluate their effectiveness in carbonate reservoirs. The value added out of this work is first “enhanced understanding of permeability controls in carbonates” and second “gave the possibility to evaluate three existing permeability equations that are widely used in the literature”.

AAPG Datapages/Search and Discovery Article #90370 ©2020 AAPG Middle East Region Geoscience Technology Workshop, 3rd Edition Carbonate Reservoirs of the Middle East, Abu Dhabi, UAE, January 28-29, 2020