Relationship between pore geometry, measured by petrographic image analysis, and pore-throat geometry, calculated from capillary pressure, as a means to predict reservoir performance in secondary recovery programs for carbonate reservoirs.



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The purpose of this study was first to develop a method by which a detailed porosity classification system could be utilized to understand the relationship between pore/pore-throat geometry, genetic porosity type, and facies. Additionally, this study investigated the relationships between pore/pore-throat geometry, petrophysical parameters, and reservoir performance characteristics. This study focused on the Jurassic Smackover reservoir rocks of Grayson field, Columbia County, Arkansas. This three part study developed an adapted genetic carbonate pore type classification system, through which the Grayson reservoir rocks were uniquely categorized by a percent-factor, describing the effect of diagenetic events on the preservation of original depositional texture, and a second factor describing if the most significant diagenetic event resulted in porosity enhancement or reduction. The second part used petrographic image analysis and mercury-injection capillary pressure tests to calculate pore/pore-throat sizes. From these data sets pore/pore-throat sizes were compared to facies, pore type, and each other showing that pore-throat size is controlled by pore type and that pore size is controlled primarily by facies. When compared with each other, a pore size range can be estimated if the pore type and the median pore-throat aperture are known. Capillary pressure data was also used to understand the behavior of the dependent rock properties (porosity, permeability, and wettability), and it was determined that size-reduced samples, regardless of facies, tend to show similar dependent rock property behavior, but size-enhanced samples show dispersion. Finally, capillary pressure data was used to understand fluid flow behavior of pore types and facies. Oncolitic grainstone samples show unpredictable fluid flow behavior compared to oolitic grainstone samples, yet oncolitic grainstone samples will move a higher percentage of fluid. Size-enhanced samples showed heterogeneous fluid flow behavior while the size-reduced samples could be grouped by the number of modes of pore-throat sizes. Finally, this study utilized petrographic image analysis to determine if 2- dimensional porosity values could be calculated and compared to porosity values from 3-dimensional porosity techniques. The complex, heterogeneous pore network found in the Grayson reservoir rocks prevents the use of petrographic image analysis as a porosity calculation technique.