Reservoir characteristics and source rock geochemistry are essential for petroleum system investigation as they reveal reservoir quality and hydrocarbon generation capability, respectively. The primary Karama oil field reservoir of Abu El Gharadig Basin is the limestone-sand-shale Abu Roash G (AR/G) Member. This study examines AR/G, analyzes source rocks for maturity and organic elements, and defines the main reservoir lithotypes and evaluates reservoir properties. Five well log datasets and an AR/F pyrolysis analysis on another well were used in this study to characterize the AR/G’s 168-foot effective thickness and assess the AR/F source-rock maturation. The effective porosity is up to 30%. The highest shale concentration was 24% in central and western parts of the field. Therefore, drilling development wells in this area, especially east and north, demands caution. The composition and vertical and lateral lithofacies variations of the defined reservoir in the Karama field region are a significant control of its petrophysical properties. The pyrolysis of AR/F revealed 1.32–5.84% content of organic matter. That content qualifies AR/F as a hydrocarbon source if thermal maturity is reached. Type I and type II kerogen in the Abu Roash F Member suggests oil production. The Abu Roash G Member and Upper Bahariya (UB) formation produce oil and gas due to their own type II and III kerogen. GC biomarker data suggests that the research area is predominantly maritime, with most samples showing environmental degradation. The area under consideration has one reservoir, AR/G, and three members of source rocks in AR/F&G and UB. AR/G electrofacies revealed various lithotypes and flow units.

The Sequoia Pliocene channel reservoirs within the West Delta Deep Marine (WDDM) concession, located offshore of the Nile Delta, pose significant challenges due to their complex stratigraphy and variable reservoir properties. This study employs an integrated approach, combining seismic data interpretation with comprehensive petrophysical analysis, to characterize these reservoirs and assess their hydrocarbon potential. Seismic data interpretation revealed a complex depositional environment, characterized by an upward-fining sequence of sandstones and mudstones. High seismic amplitudes were associated with gas sands, while lower amplitudes indicated background shale. The seismic stratigraphy indicates that the Sequoia channel system evolved from an initial high-energy erosional phase to a more subdued depositional environment, leading to significant heterogeneity in the reservoir quality. Petrophysical analysis demonstrated that effective porosity values within the reservoir range from 18 to 30%, with water-saturation levels of between 38 and 68%, reflecting the variability in reservoir properties across different zones. The calculated gas initially in place (GIIP) for the Sequoia channel ranges from 724.1 to 4158.71 Bcf, highlighting the substantial hydrocarbon potential within this complex system. This study underscores the importance of integrating seismic and petrophysical data to develop a comprehensive understanding of the Sequoia channel reservoirs. The results provide a robust framework for optimizing field development strategies, which is crucial for maximizing hydrocarbon recovery. The findings also offer valuable insights into the geological complexities of the WDDM concession, serving as a reference for future exploration and production efforts in similar deep-water environments.

The Gulf of Suez is a sedimentary rift-basin with thick evaporites and complex structural settings that presents challenges to achieving quality imaging based on seismic reflection data. Such subsurface settings and the lack of 3D seismic data poses challenges in building reservoir models to guide hydrocarbon exploration and development, especially in southern parts the Gulf of Suez. This study attempts to overcome the challenges of both 2D seismic interpretation and building a static reservoir model of two Miocene reservoir formations, Ras Ghara Field, Southern Gulf of Suez. Integration of well log data analysis of nine wells and regional-tectonics cognizant 2D seismic interpretation of nineteen 2D seismic lines enabled a reliable 3D static reservoir model. The Miocene reservoir characterization reveals heterogeneity in lithofacies distribution, with thick evaporite sequences causing seismic reflection distortions. Significant hydrocarbon accumulations are associated with horst fault blocks. The Miocene reservoirs demonstrate effective porosity of 14-33%, water saturation of 16-65%, and hydrocarbon saturation of 35-84%. Two new prospects are identified based on structure, facies distribution, and petrophysical results, with estimated original oil in place (OOIP) of 2,002,404 stock tank barrels (STB) and 1,175,580 STB for the Kareem Formation, and 6,302,916 STB and 2,841,894 STB for the Rudeis Formation.