Water Saturation, Not Porosity, Decides Pay in Gulf of Suez Asl Sandstone

A quartet of wells piercing the Lower Miocene Asl Sandstone in the north-central Gulf of Suez has yielded one of the clearest demonstrations yet that porous rock and productive rock are not the same thing. In a new integrated petrographic and petrophysical evaluation, researchers from Tanta University, Gulf of Suez Petroleum Company, the University of Sharjah, Suez Canal University, the Egyptian Petroleum Research Institute and King Saud University show that fluid saturation, rather than porosity alone, is the decisive control on effective hydrocarbon pay within this heterogeneous syn-rift reservoir.

The study, published in Frontiers in Earth Science, examined the Asl Member of the Upper Rudeis Formation in four wells: ET-A3, ET-A4, NO159-6ST1 and GS160-5A. The team combined conventional open-hole wireline-log analysis with thin-section petrography from the reference well ET-A3 and structural and depositional interpretation. Their central finding is stark: all four wells contain intervals that qualify as reservoir-quality sandstone, but the amount of that rock that actually qualifies as hydrocarbon-bearing pay varies by more than an order of magnitude, driven almost entirely by water saturation.

The Asl Sandstone sits within the Rudeis Formation, an Early to Middle Miocene marine syn-rift unit deposited during the rift climax of the Gulf of Suez, a mature Oligocene–Miocene continental rift basin characterised by tilted fault blocks, asymmetric half-grabens and transfer zones. Reactivation of inherited Pan-African basement fabrics produced dominant NW–SE-trending Clysmic normal faults and subordinate NE–SW cross faults, which controlled accommodation, sediment routing and hydrocarbon entrapment. The Asl Member is interpreted as a tectonically influenced deep-marine gravity-flow system, comprising turbidite sandstone, debris-flow deposits, shale beds and redeposited carbonate material, supplied through fault-related sediment-entry points.

Thin sections from the upper Asl core interval in ET-A3 classify the rock as lithic arenite to sublithic arenite: a quartz-dominated framework with minor lithic fragments and no observed feldspar. Monocrystalline quartz grains make up 89 percent of the quartz population. Grain sizes range from fine to very coarse, with 58 percent of the material in the medium to coarse fraction, and predominantly poor sorting points to variable flow energy and relatively rapid deposition. Grain contacts are dominated by concavo-convex types at 40 percent, with planar, sutured and point contacts recording variable compaction from high to minimal intensity.

Diagenesis emerges as a major modifier of pore space. Calcareous cement dominates at 74 percent of observed cement types, followed by siliceous cement at 17 percent and dolomitic cement at 5 percent. Compactional grain contacts, silica overgrowths and pore-filling clays reduce pore volume and connectivity, while local dissolution creates secondary porosity. Notably, microfracture-related pores account for 58 percent of recorded pore occurrences but provide limited visible pore volume, whereas preserved intergranular pores account for 32 percent and locally reach approximately 20 percent, forming the principal storage component. Glauconite and pyrite in the sections support marine deposition and reducing diagenetic conditions respectively.

These textural characteristics underpin the depositional interpretation. Grain size, sorting, roundness and packing relationships support deposition within a submarine-fan system spanning proximal, middle and distal settings: coarse, poorly sorted, angular proximal deposits laid down by high-density turbidity currents and debris flows; fine to medium-grained, moderately sorted mid-fan deposits forming the main reservoir fairway; and fine-grained, well-sorted, clay-rich distal turbidites of lower reservoir quality. Siliciclastic material was sourced from adjacent exposures including Wadi Baba, Wadi Feiran and Wadi Araba and transported along cross-faults and rift-related depressions, with carbonate deposition alternating as sources switched.

The petrophysical workflow applied consistent cut-offs to separate rock classes. Net reservoir was defined using shale volume below 0.35 v/v and effective porosity above 0.10 v/v; net pay additionally required water saturation below 0.60 v/v. Water saturation was computed with the Indonesian model, which incorporates clay-volume effects, using a formation-water resistivity of 0.026 ohm-metres calibrated to reservoir temperature. Across the four wells, average effective porosity within net-reservoir intervals spans a narrow 0.125 to 0.157 v/v, while average water saturation ranges far more widely, from 0.107 to 0.597 v/v.

Well NO159-6ST1 stands out as the most favourable interval. Within a gross Asl thickness of 73.4 feet, it contains 61 feet of net reservoir and 60 feet of net pay, a pay-to-gross ratio of 0.817, very low shale volume of 0.023 v/v, effective porosity of 0.158 v/v and water saturation of just 0.101 v/v within pay. ET-A3 contains 69 feet of both net reservoir and pay within a 163.1-foot gross interval, with effective porosity of 0.139 v/v and water saturation of 0.126 v/v, though its higher shale volume of 0.160 v/v reflects a more heterogeneous architecture. GS160-5A holds 22.5 feet of net reservoir, all meeting pay criteria, with porosity of 0.143 v/v and water saturation of 0.131 v/v.

ET-A4 tells the opposite story and delivers the study’s key lesson. It contains 34 feet of net reservoir with low shale volume of 0.046 v/v and moderate effective porosity of 0.125 v/v, yet only 3 feet qualifies as net pay because average water saturation reaches 0.597 v/v, indicating predominantly water-bearing conditions. The authors attribute this to a deeper paleo-fluid contact, a different pressure regime or fault-related compartmentalisation isolating the block from hydrocarbon charge, though they stress this interpretation remains tentative without pressure or production data. Because effective porosity varies so little across the wells while saturation varies so much, fluid saturation is identified as the principal control on pay development in this dataset.

The study is candid about its limits. Core permeability measurements were unavailable, restricting direct assessment of fluid-flow capacity, and interval-specific production or well-test data were lacking, so the petrophysical interpretation could not be validated against production performance. Saturation exponents were assigned standard values in the absence of core-derived electrical measurements, and the 3-foot pay interval in ET-A4 approaches wireline-log vertical-resolution limits. Property maps built from only four wells illustrate first-order spatial trends rather than detailed predictions. Even so, the framework offers transferable screening criteria: exploration for the Asl Sandstone, and for comparable compartmentalised Miocene syn-rift plays, should prioritise thick, relatively clean sandstone with preserved pore space and favourable saturation confirmed jointly by seismic and well data, rather than relying on porosity or sandstone thickness alone.

Subject of Research: Petrographic and petrophysical characterization of the Lower Miocene Asl Sandstone reservoir in the north-central Gulf of Suez, Egypt

Article Title: Quantitative reservoir characterization and exploration significance of the lower Miocene Asl Sandstone, north-central Gulf of Suez, Egypt

Article References: Barakat, M. K., El-Gendy, N. H., Emara, A. A., Abdel-Fattah, M. I., Farouk, S., & Al-Kahtany, K. (2026). Quantitative reservoir characterization and exploration significance of the lower Miocene Asl Sandstone, north-central Gulf of Suez, Egypt. Frontiers in Earth Science, 14, 1982680. https://doi.org/10.3389/feart.2026.1982680

Image Credits: AI Generated

DOI: 10.3389/feart.2026.1982680

Keywords: Asl Sandstone, Gulf of Suez, Rudeis Formation, petrophysics, net pay, water saturation, submarine fan, syn-rift reservoir, diagenesis, porosity, hydrocarbon exploration, Egypt