Simulation of a shale gas field development: An example from Western Australia

Abstract

Shale gas exploration activities have been growing rapidly in Australia. A flow rate of up to 2 MMSCFD has been reported recently from the first exploratory vertical well in the Cooper Basin in South Australia. Perth and Canning Basins in Western Australia are also reported to be highly prospective. However, shale gas production differs from conventional reservoirs primarily because of extremely low permeability and other petrophysical characteristics. Commercial production requires massive hydraulic fracturing often in long horizontal completions. The potential development of a shale gas field in Western Australia has been simulated to optimize production and minimize development cost through sensitivity analyses. Conditions in Australia are particularly challenging often because of significantly higher costs in drilling, completion and fracturing than those of the US. The minimum number of wells and the maximum Net Present Value (NPV) was iterated by simulation. The factors influencing their overall success of the field development project were investigated in order to generate a workflow model suitable for a variety of cases. The influence of well fracture and other parameters such as completion length, fracture geometry, permeability and gas price was tested against NPV to optimize the development. Optimization of any development should be possible by iterating on any parameter and the related variables. Whilst in conventional gas there is a clear understanding of what is economically viable, this is not the case in shale gas particularly in Australia. Before embarking on any drilling, testing or development activities simulation sensitivity studies of this nature are essential.