Characterization of Carbonate Porosity Using Petrophysical Properties and Image Analysis

Abstract

Three techniques for describing pore size distributions were investigated to explain large differences in Klinkenberg b factors for heterogeneous, high permeability, carbonate core samples. Gas expansion permeametry was used to determine gas permeametry was used to determine gas permeability and Klinkenberg-corrected permeability and Klinkenberg-corrected permeability on a select group of Middle permeability on a select group of Middle East carbonate cores. Samples with similar high permeabilities (600 - 900 md) showed a factor of 20 variation (0.6–12.8) in Klinkenberg b factors. Mercury injection derived pore size distributions were compared with petrographic image analysis (PIA) and scanning electron microscopy (SEM) analysis results to identify a basis for the range in b factor values. No method provided a direct correlation with Klinkenberg b values. All methods indicated that samples with high permeability and high b values also had an permeability and high b values also had an increase in the distribution of larger pores. PIA results indicated pores. PIA results indicated statistically a linear relationship between the number of throats and b factor. Introduction The complex nature of carbonate porosity often raises significant questions in the interpretation of various field and laboratory tests. Among these are single well tracer tests and unsteady state displacement tests. A better understanding of the relationship between the rock structures and transport properties is the first step in improving these interpretations. Petrophysical properties were measured on Petrophysical properties were measured on a group of Middle East carbonate samples. Items determined included Klinkenberg gas slip factor, krypton surface areas, and pore size distribution determined from pore size distribution determined from mercury injection. These measurements were combined with SEM and petrographic image analyses to describe and compare the samples. Klinkenberg Gas Slip Factor Adzumi in 1937 and Klinkenberg in 1941 introduced the concept of gas slip to explain deviations from Darcy's Law. The gas slip phenomena is considered to occur when the diameter of the porous media approaches the mean free path of the f lowing gas. The result is a non-zero velocity for the gas at the pore wall and a higher measured permeability. The mean free path of the gas is reduced with increasing mean pressure. At infinite mean pressure, the mean free path of the gas is equal to the mean free path of a liquid and the measured permeability is equal to the liquid permeability. The Klinkenberg b factor defines the slope of the line for measured gas permeability versus the reciprocal mean pressure. This relationship is shown in Figure 1. P. 143

Clustering Cum Polar Coordinate Feature Transformation (C-PCFT) Approach to Identify Pores in Carbonate Rocks

“…We suspect that this method may be relevant for low-quality grayscale images. Similar remarks can be made for the work of Funk et al [6], who described the pore size distributions of rock samples by analysing the petrophysical properties of rocks extracted from their RGB image samples. Van den Berg et al [7] presented a sophisticated image analysis method for porosity classification that required highquality images (resolution and chrominance) as inputs.…”

Pore Structure Characteristics and Permeability Prediction Model in a Cretaceous Carbonate Reservoir, North Persian Gulf Basin

“…Many research results have been published about pore structure of Cretaceous carbonate in the Middle East reservoirs [21][22][23]. Marzouk et al identified the pore structure and the rock texture of a carbonate reservoir in the Middle East by using a diagram derived from thin section analysis and mercury injection capillary pressure (MICP) [24].…”