3D simulation of hydraulic fracturing by foam based fluids using a fracture propagation model coupled with geomechanics in an unconventional reservoir the Cooper Basin, South Australia

Abstract

Energized fluids have been previously used in hydraulic fracture treatment in depleted and low permeable gas reservoirs and have proven to be highly efficient to aid well cleanup as well as to minimize liquid retention effect and clay swelling. On the other hand, the Australian Cooper Basin has a very complex stress regime where high fracture gradients, high tortuosity induced fractures and high pressure dependent leakoff are commonly observed. Therefore, the application and optimisation of this technology in unconventional reservoirs of the Cooper Basin which needs to be adapted to counter these and reservoir effects. The Murteree and Roseneath shale formations in the Cooper Basin are 8,500 ft in depth and have been targets for shale gas production by different oil and gas operators. In this paper, petrophysical evaluation of shale gas potential (Total Organic Carbon) from the Permian Murteree formation has been studied. Next, a geomechanical evaluation was carried out by generating a 1D vertical mechanical earth modelling (MEM) to define the stress regime and the principle stresses variation which requires full-wave sonic logs and a diagnostic fracture injection test (DFIT) to construct and calibrate the model. A 3D hydraulic fracture simulation in a vertical well was developed and validated with postfrac production data. Then, a sensitivity analysis was performed using a selection of different fracturing fluid treatments. In the fracture propagation model, a large number of cases were simulated based on different types of fracturing fluids. It was found that the foam quality could contribute to a higher fracture pressure. This is because higher viscosity of foam contributes to higher net pressure in the fracture by improved leakoff control, with greater proppant carrying capacity comparing with slickwater to increase fracture conductivity. Based on our reservoir inputs, the simulation results indicated that the optimum scenario is a foam quality of 70% for both N2 and CO2 as it generates the maximum gas productivity. Modelling predictions support the expectation of long term productivity gains through the use of foams fracturing fluid. It is concluded that the use of foam results in a more rapid clean-up of the fracture itself and inside the wellbore, which is expected to provide higher productivity.