Recent Advances in the Understanding and Incorporation of the Multiphase Fluid Flow Properties of Fault Rocks Into Production Simulation Models

Abstract

Abstract For many years it has been common practice to adjust fault transmissibility multipliers within production simulation models to achieve a history match without any scientific justification. In effect, this often means that faults are made ‘scapegoats’ to compensate for inadequacies in reservoir characterisation. In recent years it has become increasingly popular to calculate geologically-realistic transmissibility multipliers based upon measurements of absolute fault permeability and fault rock thickness. A key problem with this method is that it does not take into account the multiphase flow properties (relative permeability and capillary pressure) of fault rocks. This is hardly surprising as the multiphase flow properties of fault rocks are still largely unknown. Here we present measurements that show that under reservoir conditions cataclastic fault rocks may often have maximum gas relative permeabilities that are over two orders of magnitude lower than the undeformed reservoir sandstone adjacent to the fault. Incorporating the multiphase flow properties of faults into production simulation models is still challenging as their static and dynamic properties vary significantly compared with the undeformed reservoir. We review different existing methods for incorporating the multiphase flow properties into simulation models, and we recommend some possible approaches for treating faults that improve on the existing knowledge and software.