Integrated Characterization and Reservoir Potential of the Heavy Mineral Deposits Hosted by Carbonate Sediments in Saudi Arabia

The carbonate sediments of the study area represent a major sediment fill that covers an area of around 3.7 million square kilometers across the Arabian Gulf region, hosting one of the most prolific non- associated gas plays in the world (Alsharhan, 2006; Pöppelreiter and Marshall, 2014). The shallow marine carbonate sediments of the study area were deposited near the equator due to a major transgression on top of thick siliciclastic deposits coinciding with the icehouse-greenhouse transition (Fig. 1). The hydrocarbon play is part of the Paleozoic petroleum system sourced primarily from the organic-rich Silurian Qusaiba shales, which are considered the source rocks for 80-90% of all Paleozoic hydrocarbons in many prominent oil and gas fields in North Africa and Arabia (Mahmoud et al., 1992; Nairn and Alsharhan, 1997). The seals of the study area include different types: impermeable bedded anhydrite layers, tight carbonate layers, and the thick shale layers of the overlying formation, which is considered a regional seal that separates this Paleozoic petroleum system from the Mesozoic petroleum system (Konert et al., 2001, Alqahtani, 2019). The formation sediments comprise carbonates and evaporites (from highest to lowest), dolomite, limestone, and anhydrite. Traces of auxiliary minerals: celestite, pyrite, barite, chert, fluorite, quartz, and clay minerals are present in the formation with no effect on reservoir quality. The study area includes three separate units two from the Late Permian and one from the Early Triassic, confined within a salt-cored structure resulting from the Precambrian Hormuz salt. This near-circular structure is associated with prominent deeply rooted faults that are detectable from seismic data, acting as pathways to hydrocarbons and other metal-rich hydrothermal fluids (Fig. 2) (Stewart, 2018; Alqahtani, 2019). The lithology mainly consists of clean carbonates and evaporites, consisting of dolomite, limestone, and anhydrite. Reservoir quality is controlled by the interplay between original depositional factors and post-depositional (diagenetic) factors. Dolomitization, dissolution, and anhydrite cementation are the most critical diagenetic processes, impacting reservoir quality positively and negatively. The study area has eight depositional lithofacies, and they are named after their depositional environments. The lithofacies (from updip to downdip) are subaerial exposure, sabkha/saline anhydrite, tidal flat, lagoon, shallow subtidal, shoal flank, shoal crest, and open marine. The lithofacies succession represents deposits of shallow marine homoclinal ramp within a tectonically stable epeiric sea. Based on the level of restriction, lithofacies can be grouped into three depositional zones: marginal marine, barrier, and normal marine (Fig. 3). The marginal marine includes five back-barrier lithofacies. This zone shows significant restriction in the form of muddy texture, rare restricted biota, and extensive dolomite and anhydrite lithologies. The barrier zone includes the grain-dominated shoal crest and shoal flank, which consist primarily of ooids, peloids, bioclasts, and intraclasts. Grain-dominated shoal complex lithofacies are reservoir rocks and the most diagenetically prone facies where dolomitization, dissolution, calcite, and anhydrite cementations occur. Molds are the most common pore type when dissolution dissolves metastable aragonitic ooids and fossils. Dolomitization connects molds by the porous crystalline matrix that is also prone to fracturing. Anhydrite cementation postdates dolomitization and kills all pore types. The normal marine zone includes deeper water open marine lime mudstone lithofacies, the least diagenetically altered lithofacies with open marine fossils (Alqahtani, 2019). This core-based study aims to identify types of heavy mineralization and examine their effect on well logs and the pore system within the mineralized intervals.