Calibration of Permeability Models from Sandstones to Carbonates Using Capillary Pressure: Applicable to U.S. Shallow Marine Reservoirs

Permeability estimation plays a crucial role in reservoir characterization and is commonly determined through core analysis. Additionally, permeability can be inferred from mercury injection test data. Several models have been developed for this purpose, with their parameters influenced by factors such as pore structure, rock heterogeneity, and pore throat distribution. The widely recognized permeability prediction models of Winland, Pittman, and Dastidar, have been primarily developed based on sandstone formations, with Winland’s model also applied to both sandstone and carbonate rocks. However, due to the inherent heterogeneity of ca...  more

Permeability estimation plays a crucial role in reservoir characterization and is commonly determined through core analysis. Additionally, permeability can be inferred from mercury injection test data. Several models have been developed for this purpose, with their parameters influenced by factors such as pore structure, rock heterogeneity, and pore throat distribution. The widely recognized permeability prediction models of Winland, Pittman, and Dastidar, have been primarily developed based on sandstone formations, with Winland’s model also applied to both sandstone and carbonate rocks. However, due to the inherent heterogeneity of carbonate reservoirs particularly in terms of petrophysical properties and diagenetic alterations the accuracy of these models becomes debatable, especially in complex carbonate reservoirs such as those in Texas and Oklahoma, United States. To improve permeability predictions in carbonate reservoirs, these models require further adjustments to account for their unique pore structures. Since these permeability models were originally calibrated based on sandstone formations, they need to be recalibrated for carbonate rocks due to the significant differences in heterogeneity, as well as variations in petrophysical properties and diagenetic processes between carbonate and sandstone reservoirs. This study calibrates sandstone-based permeability models for carbonate rock formations through a comprehensive investigation of carbonate rock properties and formations. In this study, a total of 1,367 thin section reports and 70 porosity-permeability tests were conducted. The average sampling interval was 25 cm. Porosity in the plug samples was measured using Boyle’s Law, while permeability was determined based on Darcy’s Law. A thin section was prepared from each plug sample and examined under a polarizing microscope. In this study, permeability ranges from 0.01 to 450 mD, and porosity ranges from 1% to 30%. This model calibrates the widely recognized permeability prediction models of Winland, Pittman, and Dastidar for carbonate reservoirs. This model resolves the limitations of permeability models originally adjusted for sandstone reservoirs by recalibrating them for carbonate reservoirs. It incorporates a comprehensive study of the geological and petrophysical characteristics of carbonate formations to enhance accuracy in permeability prediction.