Unveiling the Diagenetic and Mineralogical Impact on the Carbonate Formation of the Indus Basin, Pakistan: Implications for Reservoir Characterization and Quality Assessment

Abstract

The Chiltan formation is a potential hydrocarbon-producing reservoir in the Indus Basin, Pakistan. However, its diagenetic alterations and heterogeneous behavior lead to significant challenges in accurately characterizing the reservoir and production performance. This manuscript aims to utilize six carbonate core samples of the Chiltan limestone to conduct an in-depth analysis of the diagenetic impacts on reservoir quality. The comprehensive formation evaluation was carried out through thin-section analysis, SEM-EDS, and FTIR investigation, as well as plug porosity and permeability measurements under varying stress conditions. In result, petrography revealed three microfacies of intraclastic packestone (MF1), bioclastic pelliodal packestone (MF2), and bioclastic ooidal grainstone (MF3), with distinct diagenetic features and micro-nano fossil assemblages. The MF1 microfacies consist of bioclasts, ooids, pellets, and induced calcite, while the MF2 microfacies contain micrite cemented peloids, algae, and gastropods. Although, the MF3 grainstone microfacies contains key features of bioclasts, milliods, bivalves, echinoderms, and branchiopods with intense micritization. Diagenesis has a significant impact on petrophysical properties, leading to increased reservoir heterogeneity. The specified depositional environment exposed the alteration of the Chiltan formation during distinct diagenetic phases in marine, meteoric, and burial settings. Marine diagenesis involves biogenic carbonates and micro-nano fossils, while meteoric diagenesis involves mineral dissolution, reprecipitation, secondary porosity, compaction, cementation, and stylolite formation. Pore morphology and mineralogy reveal a complex pore network within the formation, including a micro-nano pore structure, inter–intra particle, moldic, vuggy, and fenestral pores with variations in shape, connectivity, and distribution. Various carbonate mineral phases in the formation samples were analyzed, including the calcite matrix and dolomite crystals, while silica, calcite, and clay minerals were commonly observed cement types in the analysis. The core samples analyzed showed poor reservoir quality, with porosity values ranging from 2.02% to 5.31% and permeability values from 0.264 mD to 0.732 mD, with a standard deviation of 1.21. Stress sensitivity was determined using Klinkenberg-corrected permeability at increasing pore pressure conditions, which indicated around 22%–25% reduction in the measured gas permeability and 7% in Klinkenberg permeability due to increasing the net confining stress. In conclusion, the Chiltan formation possesses intricate reservoir heterogeneity and varied micropore structures caused by diagenesis and depositional settings. The formation exhibits nonuniform pore geometry and low petrophysical properties caused by the diverse depositional environment and various minerals and cement types that result in a low-quality reservoir. Stress sensitivity further decreases the permeability with varying stress levels, emphasizing the need of stress effects in reservoir management. The results of this study provide a solid foundation in reservoir characterization and quality assessment that has implications for predicting fluid flow behavior, providing insight into geological evolution and its impact on reservoir quality and leading to improving resource exploration and production strategies.