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. Introduction Fault rocks often have a significant impact on fluid flow within petroleum reservoirs. Until recently, only the absolute permeability values of fault rocks had been measured. Recently, it has been suggested that in some reservoirs it may be beneficial to take into account the multiphase fluid flow properties of fault rocks (i.e. capillary pressure and relative permeability) in simulation models (Fisher and Knipe, 2001; Manzocchi et al., 2002; Al-Busafi et al., 2005; Fisher, 2005; Al-Hinai et al., 2006). The extent to which this can be undertaken is, however, limited by the fact that there have not been any robust studies of the relative permeability of fault rocks. Here we attempt to fill this knowledge gap by presenting new relative permeability and capillary pressure measurements for fault rocks. We also discuss how these results can be incorporated into a production simulation model to dramatically improve the history match of the production data. We begin by describing the fault specimens used in the analysis as well as the experimental techniques employed. The experimental results obtained for these cataclasitc fault rock samples are then presented. A generic study of how to incorporate these results into production simulation is then presented to demonstrate the importance of accounting for the multiphase flow properties in production simulation models. The existing methods for treating faults in production simulation models are then reviewed and two alternative approaches are described and evaluated. Fault Location and Geology The extensional Lossiemouth fault zone, which lies on the southern margin of the Moray Firth, cuts through the Late Permian/Early Triassic Hopeman Sandstone exposed in the Clashach Quarry near Burghead in north-east Scotland, Figure 1. The main Lossiemouth fault slip plane trends E/W to WSW/ENE and dips to the south. The main phase of faulting probably occurred during the Late Jurassic development of the Inner Moray Firth rift. The Hopeman Sandstone is a clean, high-porosity, yellow-brown sandstone of predominantly aeolian origin, which lies unconformably on Devonian sediments of the Orcadian Basin. It is approximately 70 m thick in this area, and in general dips at a shallow angle to the north.