The Australian Cooper Basin is a structurally complex intra-cratonic basin with large unconventional hydrocarbon potential. Fracture stimulation treatments are used extensively in this basin to improve the economic feasibility; however, such treatments may induce fault activity and risk the integrity of hydrocarbon accumulations. Fault reactivation may not only encourage tertiary fluid migration but also decrease porosity through cataclasis and potentially compartmentalise the reservoir. Relatively new depth-converted three-dimensional seismic surveys covering the Dullingari and Swan Lake 3D seismic surveys were structurally interpreted and geomechanically modelled to constrain the slip tendency, dilation tendency and fracture stability of faults under the present-day stress. A field-scale pore pressure study found a maximum pressure gradient of 11.31 kPa/m within the Dullingari 3D seismic survey, and 11.14 kPa/m within the Swan Lake 3D seismic survey. The present-day stress tensor was taken from previously published work, and combined with local pore pressure gradients and depth-converted field-scale fault geometries, to conclude that SE–NW-striking strike-slip faults are optimally oriented to reactivate and dilate. High-angle faults striking approximately E–W appear most likely to dilate, and act as fluid conduits irrespective of being modelled under a strike-slip or compressional stress regime. Near-vertical SE–NW and NE–SW-striking faults were modelled to be preferentially oriented to slip and reactivate under a strike-slip stress regime. Considering that SE–NW-striking strike-slip faults have only recently been interpreted in the literature, it is possible that many reservoir simulations and development plans have overlooked or underestimated the effect that fault reactivation may have on reservoir properties. Future work investigating the likelihood that fracture stimulation treatments may be interacting, and reactivating, pre-existing faults and fractures would benefit field development programs utilising high-pressure hydraulic fracture stimulation treatments.

Hydraulic fracturing in tight gas reservoirs has been performed in the Cooper Basin for decades in reservoirs containing high stress and pre-existing natural fractures, especially near faults. The hydraulic fracture is affected by factors such as tortuosity, high entry pressures, and the rock fabric including natural fractures. These factors cause fracture plane rotation and complexities, leading to fracture disconnection or reduced proppant placement during the treatment. In this paper, rock properties are estimated for a targeted formation using well logs to create a geomechanical model. Natural fracture and stress azimuths within the interval were interpreted from borehole image logs. The image log interpretations inferred that fissures are oriented 30–60° relative to the maximum horizontal stress. Next, diagnostic fracture injection test (DFIT) data was used with the poro-elastic stress equations to predict tectonic strains. Finally, the geomechanical model was history-matched with a planar 3D hydraulic fracturing simulator, and gave more insight into fracture propagation in an environment of pre-existing natural fractures. The natural fracture azimuths and calibrated geomechanical model are input into a framework to evaluate varying scenarios that might result based on a vertical or inclined well design. A well design is proposed based on the natural fracture orientation relative to the hydraulic fracture that minimises complexity to optimise proppant placement. In addition, further models and diagnostics are proposed to aid predicting the hydraulically induced fracture geometry, its impact on gas production, and optimising wellbore trajectory to positively interact with pre-existing natural fractures.