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<p>The Rio Del Rey Basin is characterized by complex faulting and structural deformation, introducing significant uncertainties in reservoir characterization. Geomechanical analysis is critical for optimizing production from fractured reservoirs, ensuring wellbore stability during drilling, and accurately predicting pore pressure. This study investigates the geomechanical properties and wellbore stability of selected wells (A1 and A3) drilled through the Agbada Formation in the Rio Del Rey Basin, Cameroon. Integration of petrophysical and geomechanical analyses using Techlog software provided a comprehensive understanding of subsurface conditions. Pore pressure was estimated from sonic and resistivity logs based on the Normal Compaction Trend and Eaton’s method, while fracture pressure was determined using the Eaton fracture pressure model. Unconfined compressive strength (UCS) was derived from shale volume, dynamic Young’s modulus, and dynamic Poisson’s ratio, and horizontal stress bounds were evaluated using the Mohr–Coulomb failure criterion. Results indicate that both wells traverse structurally distributed, overpressured shale formations, with average pore pressure gradients of 0.60 psi/ft (11.54 ppg) and 0.51 psi/ft (9.81 ppg) in Well A1, and 0.47 psi/ft (9.04 ppg) and 0.62 psi/ft (11.92 ppg) in Well A3 from sonic and resistivity methods, respectively. The UCS values averaged 787.20 psi (Well A1) and 397.46 psi (Well A3), with corresponding friction angles of 32.09° and 26.02°, indicating mechanically weak and ductile formations. These quantitative results indicate a basin-scale stress regime dominated by disequilibrium compaction and gravity-driven tectonism, characterized by elevated pore pressure, reduced effective stress, and limited stress anisotropy. Such geomechanical conditions have direct implications for reservoir performance, including narrow drilling mud weight windows, increased susceptibility to wellbore instability, reduced fracture efficiency during stimulation, and heightened risks of sand production and formation deformation across the Agbada Formation. The findings highlight the importance of integrating quantitative geomechanical parameters into drilling design, casing strategy, and production planning for safe and efficient field development in the Agbada Formation.</p>

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Integrated Well Log–Based Geomechanical Analysis for Pore Pressure, Rock Strength, and Wellbore Stability in the Agbada Formation, Rio Del Rey Basin, Cameroon

  • 期刊论文

  • 发表日期：

    2026年4月8日

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  • Lionel Takem Nkwanyang,
  • Jennifer Bi-emfor Che,
  • Florence Njinto Kwankam,
  • Bernard Che Ngu,
  • Zerubbabel Akongneh,
  • Kennedy Folepai Fozao

摘要

The Rio Del Rey Basin is characterized by complex faulting and structural deformation, introducing significant uncertainties in reservoir characterization. Geomechanical analysis is critical for optimizing production from fractured reservoirs, ensuring wellbore stability during drilling, and accurately predicting pore pressure. This study investigates the geomechanical properties and wellbore stability of selected wells (A1 and A3) drilled through the Agbada Formation in the Rio Del Rey Basin, Cameroon. Integration of petrophysical and geomechanical analyses using Techlog software provided a comprehensive understanding of subsurface conditions. Pore pressure was estimated from sonic and resistivity logs based on the Normal Compaction Trend and Eaton’s method, while fracture pressure was determined using the Eaton fracture pressure model. Unconfined compressive strength (UCS) was derived from shale volume, dynamic Young’s modulus, and dynamic Poisson’s ratio, and horizontal stress bounds were evaluated using the Mohr–Coulomb failure criterion. Results indicate that both wells traverse structurally distributed, overpressured shale formations, with average pore pressure gradients of 0.60 psi/ft (11.54 ppg) and 0.51 psi/ft (9.81 ppg) in Well A1, and 0.47 psi/ft (9.04 ppg) and 0.62 psi/ft (11.92 ppg) in Well A3 from sonic and resistivity methods, respectively. The UCS values averaged 787.20 psi (Well A1) and 397.46 psi (Well A3), with corresponding friction angles of 32.09° and 26.02°, indicating mechanically weak and ductile formations. These quantitative results indicate a basin-scale stress regime dominated by disequilibrium compaction and gravity-driven tectonism, characterized by elevated pore pressure, reduced effective stress, and limited stress anisotropy. Such geomechanical conditions have direct implications for reservoir performance, including narrow drilling mud weight windows, increased susceptibility to wellbore instability, reduced fracture efficiency during stimulation, and heightened risks of sand production and formation deformation across the Agbada Formation. The findings highlight the importance of integrating quantitative geomechanical parameters into drilling design, casing strategy, and production planning for safe and efficient field development in the Agbada Formation.