Assessment of pore pressure, wellbore failure and reservoir stability in the Gabo field, Niger Delta, Nigeria - Implications for drilling and reservoir management. (January 2021)

• Record Type: Journal Article
• Authors: Agbasi, Okechukwu Ebuka; Sen, Souvik; Inyang, Namdie Joseph; Etuk, Sunday Edet
• Is Part Of: Journal of African earth sciences. Volume 173(2021)
• Publication Date: 2021-01
• Subjects: Pore pressure -- Wellbore stability -- Fault slip -- Reservoir stability -- Niger Delta; Earth sciences -- Africa -- Periodicals; Earth sciences -- Middle East -- Periodicals; Geology -- Africa -- Periodicals; Geology -- Middle East -- Periodicals; Sciences de la terre -- Afrique -- Périodiques; Sciences de la terre -- Moyen-Orient -- Périodiques; Géologie -- Afrique -- Périodiques; Géologie -- Moyen-Orient -- Périodiques; Earth sciences; Geology; Africa; Middle East; Periodicals; Electronic journals; 556.05
• DOI: 10.1016/j.jafrearsci.2020.104038
• Languages: English
• ISSNs: 1464-343X

Abstract

Abstract: 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 clastic 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 (Shmin ) 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 Shmin 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. Highlights: Vertical stress gradient ranges between 0.85 and 0.90 PSI/feet. Upper and Lower Agbada reservoirs show sub-hydrostatic and hydrostatic pressure regimes, respectively. The Eocene Agbada shales have pore pressure gradient of around 0.49 PSI/feet. Collapse pressure gradient of the Eocene shales are assessed and validated with caliper log-based observations. Critical formation pore pressure limit to induce fault slippage is estimated.