The vertical and lateral distribution of pore pressure , as well as fracture pressure, is of great interest in the petroleum industry . An appropriate model of these pressure values can lead to successful drilling and production operations in all stages of the hydrocarbon Field lifecycle. This work aims to model the vertical distribution of pore and fracture pressures of the giant El Morgan oil Field in the Gulf of Suez region. Two development wells were analyzed to interpret the pore and fracture gradients along accumulative 4200 m of a sedimentary section ranging from Early Miocene to Recent age. Wireline logs, downhole measurements, and drilling events were incorporated together in the modeling process, and the standard industry Eaton's methods were used for the calculation process. An average of 17 ppg (EMW) lithostatic gradient has been modeled for El Morgan Field. The fracture pressure of the Middle Miocene sandstone reservoirs was observed to range from 11.92 to 13.12 ppg. The pore pressure modeling indicates strong overpressure against Late Miocene shale deposits with a magnitude of 10.6 ppg. Mild overpressure of 9.6 ppg equivalent gradient has been defined in Middle Miocene shales. The primary hydrocarbon reservoirs reveal sub-hydrostatic or (sub-normal) conditions resulting from production-related depletion. An appropriate casing seat design was developed according to the developed model.