The assessment of present-day stresses and pore pressures in a prolific onshore hydrocarbon bearing field located in the southern Cambay Basin, western India, is conducted through the development of a comprehensive geomechanical model. A-C quality wellbore breakouts, inferred from the available four-arm caliper logs and anisotropy analyses of dipole shear sonic logs, indicate a NE (N40°E to N50°E) azimuth for maximum horizontal stress (SHMax). Pore pressure characterisation reveals mild overpressure in the Lower Eocene Shale caused by disequilibrium compaction resulting from high sedimentation rates. Vertical stress (Sv) was derived from density logs, and a poroelastic strain model was employed to quantify the minimum (Shmin) and maximum horizontal stress components (SHMax), being later validated with leak-off tests. Based on the relative magnitudes of three principal in-situ stress components, post-rift strata (Upper Eocene and younger) reveal a normal faulting regime (Sv > SHMax > Shmin), whereas a normal fault to strike-slip faulting (SHMax ≥ Sv > Shmin) transition is observed in the syn-rift unit (Lower Eocene and older). The Mohr-Coulomb rock failure criterion was utilised to depict the shear failure gradient to prevent wellbore instability, and results were validated with caliper logs. We have also analysed the fault reactivation potential at reservoir level using frictional fault theory and stress polygons. The results indicate that a minimum of 31% increase in pore pressure by fluid injection and hydraulic fracturing treatment can cause shear slippage of critically oriented faults, resulting in induced seismicity. Our study has helped to understand the interplay between stress states and pore fluid pressure and their impact on reservoir development, drilling and completion design, and fault stability analysis in any given oil and gas field.
Shib Sankar Gangulia,∗, Souvik Sen; Marine and Petroleum Geology 118 (2020) 104422; https://doi.org/10.1016/j.marpetgeo.2020.104422