The Late Carboniferous and Early Permian Al Khlata Formation represents the lower unit of the Haushi Group, related to the third glacial event in the Arabian Plate. Al Khlata Formation, which is a proglacial fluvial and deltaic depositional system, is an important hydrocarbon target in Oman. The accurate estimation of the amount of hydrocarbon that can be produced from Al Khlata reservoirs is very challenging because the rock properties in Block 56 vary significantly which are poorly understood. This study aims to construct the diagenetic model and predict reservoir quality evolution of the studied Al-Khlata Formation sandstones in Block 56 with help of depositional environment and stratigraphic frameworks to have a better understanding of the petrophysical properties and thus volumetric calculations. This study is based on an integrated analytical technique including petrophysical analysis using wireline logs and drilling cuttings, and thin-section petrography for textural, mineral, and grain fabric determinations. However, the study revealed that the Al Khlata Formation consists of two correlative and laterally continuous sandstone bodies: sand 2 and sand 1, in ascending order characterized by significant heterogeneity in lithology, petrophysical properties, and diagenetic alterations. The thickness of the correlatable sandstone bodies within the Al Khlata Formation varies from one well to another because their deposition was highly controlled by the salt movement during the Late Devonian to the Late Carboniferous hiatus. Moreover, this study has revealed that the correlation between wells allowed the prediction of the influence of the glacial environments on the petrophysical properties of sandstone bodies. There is no consistent trend for the lateral and vertical distribution of porosity and permeability of the lacustrine and deltaic proglacial sandstone bodies, due to the complexity of the glacial environment. The degree of comparison between the two oil-bearing sandstones in terms of petrophysical properties is obvious. For example, sand 2 has good to excellent reservoir quality because of low average shale volume, and good average porosity. Sand 1 is a tight reservoir because it is enriched with shale, has poor porosity, and is very hard to drill because of diamictite. Based on petrographic analysis of ALJUMD-1 well and ALJUMD-2 well thin sections, the main component of both sandstones was fine to medium quartz grains, lithic fragments such as mud intraclasts and feldspar grains, respectively from the dominant to less diverse. Sand 2 is controlled by the dissolution of unstable grains and equant calcite cement. However, the primary porosity such as intergranular porosity that formed during deposition time and secondary porosity created by dissolution have overcome the cementation. While sand 1 was mostly controlled by the complete and partial dissolution of unstable grains such as mud lithic fragments by meteoric water that occurred during deglaciation and was facilitated by a warm climate. By integrating petrophysical and petrographic analyses, sand 2 has better reservoir characteristics compared with sand 1. Subsequently, all of that has a significant impact on the hydrocarbon potentiality of each sand. For example, modeling will help in drawing more efficient drilling, production, and recovery strategies.