Flow around faults of the West Netherlands Basin in the context of geothermal energy

Abstract

Over the past fifteen years, geothermal energy development has increased in the West Netherlands Basin (WNB), both onshore and offshore in the southwest of The Netherlands. Main target reservoirs here for geothermal energy are the Delft and Alblasserdam Members of the siliciclastic Nieuwerkerk Formation. The structural geology of the WNB is complex as it is characterized by extensive, generally NW-SE oriented fault systems, which formed during various deformation phases in the Mesozoic and Cenozoic eras, resulting in intra-basin fault networks like grabens, half-grabens, and pop-up structures. Understanding these fault systems is crucial for the safe and profitable extraction of geothermal energy, as these faults have an affect both on fluid flow and potential seismic activity. Hence, a proper understanding of a fault’s geometry, displacement, kinematic history and rock properties is of key importance. This study aims to assess how faults with varying properties and offsetting the Nieuwerkerk Fm., affect fluid flow and stress distribution in the WNB. This was done by firstly performing a 3D kinematic analysis of faults for an area of interest within the WNB using 3D seismic interpretation. Subsequently, the shale gauge ratio (SGR%) (Yielding, 2002) and damage zone width was calculated for a specific fault of interest by using 3D seismic, and well log data from nearby wells. Lastly, numerical models were created by using FLAC3D-ToughREACT software (Taron et al., 2009), to simulate cold fluid injection under different fault’s properties conditions, for a two-year period. By exploring various scenarios of shale content and damage zone width, the impact of different fault properties on fluid flow and temperature and stress distributions is assessed. Amongst others, it is found that a high but realistic shale gouge ratio results significant pressure compartmentalization. A permeability-decreasing damage zone has similar effects to a high shale gouge ratio and burdens the impact of SGR%, when high SGR% and decreased permeability damage zone coexist. However, a permeability-increasing damage zone alleviates the effect of a high shale gouge ratio. This underlines the relevance of understanding permeability evolution in fault damage zones. Time evolution analysis reveals the temperature changes have higher influence on the stress ratio changes, however, while pore pressure changes depend on temperature changes, the increase of the pore pressure by the convection circulation inside the reservoir is the key to the stress distribution along the fault. In conclusion, this study highlights the importance of blending geological insights with advanced modelling to manage risks like induced seismicity and improve reservoir performance in geothermal projects.