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In order to evaluate the hydrocarbon potential of the Matruh Basin, North Western Desert of Egypt, the tectonic history, basin analysis, and maturity modeling of the Albian-Cenomanian Formations of the Matruh Basin were investigated using well logs and 3D seismic data. Structural analysis of the tops of the Bahariya, Kharita, and Alamein Dolomite Formations reveals them to dip to the southeast. Burial history and subsidence curves show that the basin experienced a tectonic subsidence through the Middle-Late Jurassic and Early Cretaceous times. Thermal maturity models indicated that Cenomanian clastics of the Bahariya Formation are in the early mature stage in the east portions of the area, increasing to the mid maturity level in the southwestern parts. On the other hand, the Albian Kharita Formation exhibits a mid maturation level in the most parts of the area. The petroleum system of the Matruh Basin includes a generative (charge) subsystem with Middle Jurassic and Cenomanian sources (for oil/gas) and Turonian sources (for oil), with peak generation from Turonian to Eocene, and a migration-entrapment subsystem including expulsion and migration during Early Tertiary to Miocene into structures formed from Late Cretaceous to Eocene.

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The Qasr oil and gas Field is located in the north western desert of Egypt. It belongs to the southeastern part of the Lower Jurassic-Cretaceous Shushan Basin. The Lower Cretaceous Alam-El Bueib formation composed of clastic rocks with noticeable carbonate proportions, and forms multiple oil-bearing sandstone reservoirs in Qasr field. The study aims to define and analyze the Surface and subsurface structural features which are a key issue in assessing reservoir quality. Through this integrated approach, one may be able to identify lithologies and fluids in this region and provide possibly new hydrocarbon fairways for exploration. For this purpose, seismic and well data were interpreted and mapped in order to visualize the subsurface structure of the Cretaceous section. Results show the effect of NE-SW, NW-SE, and E-W trending normal faulting on the Lower Cretaceous Alam-El Bueib formation and is extended to the Upper Cretaceous Abu Roash Formation. The effect of folding is minimal but can be detected. These normal faults are related to the extensional tectonics which affected the north western desert of Egypt during the Mesozoic. One reverse fault is detected in the eastern part and is related mostly to the inversion tectonics in the Late Mesozoic. The depth structure contour maps of the Alam-El Bueib horizons (AEB-1, AEB-3A, and AEB-3D) show several major normal faults trending NE-SW and minor normal faults trending NW-SE. One larger branching normal fault trending E-W and lies to the south of the study area. These step-normal faults divide the area into a number of tilted structural blocks which are shallower in the south and deepen to the north. The area of study was most probably affected by E-W trending normal faults during the opening of the Atlantic Ocean in the Jurassic. Later right-lateral compression resulted from the movement of Laurasia against North Africa, changed their trend into NE-SW faults with minor NW-SE trending folds. These compressive stresses are also responsible for the reverse faulting resulted by inversion in the Late Mesozoic.

The detection of thin sandstone reservoirs on seismic sections is a matter of seismic resolution and bed thickness. Usually, layers thinner than 50 ft. thick are difficult to visualize on vertical seismic sections. The problem is observed in the northwestern desert of Egypt, where several thin oil-bearing sandstone reservoirs are located, among them Qasr Field which produces oil from the Lower Cretaceous Alam El Bueib Formation, specially unit AEB-3D (D2). The aim is to follow unit (D2) sandstone channels using available horizontal and vertical seismic sections coupled with other well logs and well data. The analytical method includes interpreting lithostratigraphic units from wells logs, mapping sandstone channels, generating synthetic seismograms and correlation with stratigraphy from wells, and finally to detect channels on seismic sections using positive and negative amplitudes with proper time slice. Finally, results show that, although unit AEB-3D (D2) sandstone is ± 50 ft. thick, it can be detected using seismic modeling and well data with some efficiency.