The In Situ stress field of the West Tuna area, Gippsland Basin: Implications for natural fracture-enhanced permeability and wellbore stability

Abstract

The in situ stress field and natural fracture occurrence in the West Tuna area of the Gippsland Basin were evaluated in order to assess the potential for natural fracture-enhanced permeability in the deep intra-Latrobe group and Golden Beach Subgroup reservoirs, and to investigate wellbore stability issues in the area. Borehole breakout and drilling-induced tensile fractures (DITFs) interpreted on six image logs from the West Tuna area constrain the maximum horizontal stress orientation to ~138°N. Leak-off test data suggest the upper bound to the minimum horizontal stress is ~20 MPa/km. The vertical stress was derived from density and sonic log data and ranges from 20 MPa/km at 1km to 22 MPa/km at 3km depth. The maximum horizontal stress magnitude was constrained to ~40 MPa/km using occurrence of DITFs. The in situ stress regime in the West Tuna area is therefore interpreted to lie on the boundary of strike-slip and reverse (sHmax>sv ? shmin). Natural fractures and wellbore failure (breakout and DITFs) were observed to form preferentially in the cemented sandstone units. Finite element methods were utilised to investigate the far-field and near-wellbore stress distribution between horizontal, interbedded sands and shales. Preliminary modelling indicates that a higher Poisson?s ratio for the shale drives it towards a more isotropic far-field stress state. This decreases the propensity for wellbore failure in the shale layers. Fracture susceptibility analysis of interpreted fracture sets in the sandstone units suggests that electrically conductive fractures are also optimally oriented to be hydraulically conductive in the far-field. Fractures in the shales are slightly less likely to be open and hydraulically conductive in the far-field due to the transition to a more isotropic in situ stress regime.