This work attempted to understand the behavior of the Upper Cretaceous Nezzazat and Lower Cretaceous–Carboniferous Nubia sandstone reservoirs in response to production-induced depletion and fluid injection for enhanced hydrocarbon recoveries from the October oil field, Gulf of Suez, Egypt. Pore pressure (PP), vertical stress (Sv) and minimum horizontal stress (Shmin) magnitudes were modeled based on well logs, drilling data and subsurface measurements. The latest measurements indicated 11.7–12.7 MPa pressure drop (ΔPP) in the Nezzazat reservoirs, while the Nubia sandstone reservoir was depleted by 19–21 MPa. Revised PP and Shmin gradients offer a narrow mud weight window of 9–10.7 PPG (pore pressure gradient) if the entire Lower Miocene–Carboniferous section was planned to be drilled with a single casing in the infill/injector wells. A more conservative approach will be to drill the depleted reservoirs with 5.5–9.3 PPG mud window and case separately, although that may incur an additional cost. Based on the PP–Shmin poro-elastic coupling, stable stress path values of 0.61 and 0.65 are interpreted in the Upper and Lower reservoirs, indicating depletion-induced normal faulting is unlikely to occur at the present rate of depletion. The reservoir stability threshold during pressurization was assessed for fluid injection optimization to sustain production and curtail the bypassed oil. The maximum allowable pressure build-up during injection was estimated using various possible pore pressure–stress coupling scenarios at their maximum depletion state. Based on the PP–Shmin coupling approach, maximum pressure increments of 23 and 27 MPa can be permitted in the depleted Nezzazat and Nubia sandstone reservoirs during injection, without exceeding the lower limit of caprock Shmin, as applicable for both the reservoirs. This will ensure the geomechanical stability of the reservoirs as well as the caprock integrity. This geomechanical study provides crucial comprehensions regarding the optimization of drilling, production, and fluid injection by reducing the risk of reservoir instabilities and formation integrity.