Assessment of pore pressure, wellbore failure and reservoir stability in the Gabo field, Niger Delta, Nigeria - Implications for drilling and reservoir management

This work investigates a 3400m thick Tertiary succession from the prolific Gabo hydrocarbon field in the Niger Delta and presents a well-scale geomechanical model to address the pore pressure, borehole stability and fault slip potential attributes. The Tertiray stratigraphy is dominated by cyclic elastic sedimentation and it produces hydrocarbon from the Eocene Agbada Formation. An average vertical stress gradient of 0.85-0.90 PSI/feet is interpreted from the density logs. Extensive direct downhole measurements indicate a sub-hydrostatic pressure gradient of 0.325 PSI/feet in the Upper Agbada reservoir sands, while the lower producers are presently in hydrostatic regime (0.435 PSI/feet). Pore pressure against the shales are estimated by Eaton's disequilibrium compaction method, which are found to be mildly overpressured (0.49 PSI/feet). The minimum horizontal stress (S-hm(in)) gradient ranges between 0.59 and 0.70 PSI/feet. Wellbore stability is addressed by the Mohr-Coulomb failure model and the assessed failures are corroborated with the caliper log observations. Drilling mud weight used in the studied wells were found to be less than the shale collapse pressure gradient, resulting in selective wellbore over-gauging in the Eocene shales, intercalated with the sandstone reservoir intervals. Safe and effective downhole pressure window is inferred from the interpreted pore pressure, collapse pressure and Sh m h, to avoid any kick, loss or compressive wellbore failures by optimum mud weight designing. Inferences on drilling optimization are discussed which will be helpful for better planning of the infill injector wells. A fault slip analysis indicates that pore pressure could be increased by 1100-1200 PSI during the repressurization in the Upper and Lower Agbada reservoirs without inducing reservoir instabilities as well as caprock failure.