Three-Dimensional Hydrocarbon Potentiality Modeling of the Source/Reservoir Rocks of the Alam El Bueib and Khatatba Formations, Shoushan Basin, North Western Desert, Egypt

Abstract

The present research aims at modeling in three-dimensional (3D) the highly productive hydrocarbon zones of the Cretaceous Alam El Bueib (AEB) and Jurassic Khatatba formations located in the TUT oil field, Shoushan Basin, North Western Desert. This is based on the assessment of the geochemical and petrophysical characteristics of the two formations to help effective setting of future exploration plans. Geochemical and petrophysical analyses were carried out using PetroMod 11 and Interactive Petrophysics (IP) 3.6, respectively. 3D Modeling has been carried out integrating Voxler 3 software in a GIS environment to enable building a permanent geodatabase of the subsurface geological conditions, and trace lateral and vertical lithofacial variations and changes in thickness of different source and reservoir rocks. Source rock evaluation using Total Organic Content (TOC), free hydrocarbon (S1), residual hydrocarbon potential (S2), hydrogen Index (HI), Genetic Potential (GP) and maximum Temperature (Tmax) geochemical parameters and vitrinite reflectance (Ro %) from one well was used to predict hydrocarbon maturation and time of its generation. Petrophysical data analysis comprising total thickness, shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation, residual and movable hydrocarbons helped in determining production zones, reservoir and pay thicknesses, and distinguishing of gas, oil, and water contacts. The results of organic geochemical analysis clarify an early stage of hydrocarbon generation during Late Cretaceous at about 68 my and 92 my for the AEB and Khatatba formations, respectively. The temperature of maximum pyrolytic hydrocarbon generation ranges from 430 °C to 460 °C, reflecting thermally mature organic matter. The average value of TOC (wt %) are 0.88 and 6.69 for the AEB and Khatatba formations, respectively. Majority of samples from the AEB Formation show poor to good organic matter quality of kerogen type III (gas prone) while those from the Khatatba Formation yielded poor to very good quality of kerogen type II (oil with some gas) and type III (gas-prone). Petrophysically, the percentages of effective porosity, volume of shale, and hydrocarbon saturation averaged 12.29, 11.57, and 51.8 for AEB Formation, and 9.63, 7.17, and 80.15 for the Khatatba Formation, respectively. The constructed 3D lithofacial, geochemical, and petrophysical models when integrated with the petroleum characterization model enabled the effective evaluation of the petroleum system, hydrocarbon potentiality and possible highly productive hydrocarbon zones.