The rising demand for clean energy has drawn the attention for more geological research to low enthalpy geothermal applications in the Netherlands. A multi-scale reservoir characterization is carried out with the aim to understand the geothermal reservoir potential of the Triassic Main Buntsandstein (RBM) in the Tilburg area. Seismic data, well logs and petrophysical data are used to evaluate the reservoir architecture, stratigraphy, and quality of the potential Main Buntsandstein geothermal aquifer. It was found that the study area is located within a horst- and graben system bounded by normal faults where the top boundary of the RBM is located at depths of 1900 – 2100 m for the horsts and 3300 – 3500 m for the grabens. The horsts and grabens range from circa 3000 to 4000 meters in width. Well log correlations and thickness maps at RBM scale suggest thicknesses of the Subgroup from ca. 160 to 220 meter. The thickness of the Main Buntsandstein generally decreases on the horsts and increases towards the grabens, suggesting higher temperatures of up to 100° C and thicker sand units in the grabens. Thickness generally decreases on the horsts and increases towards the graben suggesting faults were active at time of deposition and better geothermal potential in the grabens due to greater depths and thicker RBM unit. The core analysis of the study showed that the potential Main Buntsandstein reservoir is composed of a variation of sand- and mudstones interlayers, which were deposited on a large fluvial-fan system terminating in a playa-lake environment towards the basin center. Four different facies associations were distinguished within the cores of wells AND-06, KWK-01, SPC-01 and WWN-01-S2. Optimal reservoir connectivity is, according to the facies architecture model, expected in the Lower Volpriehausen and Detfurth Sandstone Members due to the presence of stacked amalgamated fluvial fan sandstone facies. It appeared that aquifer quality does not correlate with increasing depth or stratigraphic position, although the Volpriehausen- and Detfurth Claystone Members display significant poorer reservoir properties. These members, which can be correlated at well distance due to its widespread deposition as playa-lake sediments, are likely to act as a baffle to flow in the subsurface. Best reservoir potential, considering petrophysical measurements on porosity and permeability, is within the fluvial fan sandstones of all facies associations whereas the fine grained cross bedded sandstones show best reservoir quality of all encountered lithofacies. The data showed highly variable measurements where highest mean values for the porosity (11 %) and permeability (105 mD) are encountered in the Lower Detfurth Sandstone Member of well HVB-01. It turned out that northern located wells of Tilburg (AND-06, KWK-01, WWN-01-S2 and SPC-01) showed considerable poor reservoir potential with mean values of below 10% and 10 mD for the porosity and permeability. The southern wells, however, appear to have generally higher reservoir properties compared to the northern wells suggesting better geothermal potential in the area south of Tilburg.

In the geothermal exploration well, NLW-GT-01, in the West Netherlands Basin, a very tight reservoir with low porosity (≤5.0%) and matrix permeability (≤ 0.1mD) has been encountered in the Main Buntsandstein Subgroup. The impact of natural fractures, which can significantly impact fluid flow in tight reservoirs, has been studied. However, there is a lack of consensus in different studies on the fracture classification. In this study, a re-evaluation is performed of the well data of the NLW-GT-01 and VAL-01 wells. An analysis comparing core, geophysical, and image logs is performed to document the drivers and characteristics of natural fracture distribution in the WNB and investigate the geological and geomechanical parameters influencing the development of fractures in the Main Buntsandstein Subgroup. On the core of NLW-GT-01 and VAL-01, five types of fractures are classified veins, joints, Mode II fractures, stylolites and drilling-induced fractures. The natural fractures have a dominant NW-SE strike orientation. The drilling-induced fractures and the borehole breakouts indicate a NE-SW oriented in-situ minimum stress and an NW-SE oriented maximum stress. The natural fractures are favourably oriented to be open based on their orientation compared to the in-situ stress orientation. The fractures are associated with large-scale tectonic events. During the burial of the formation related to the extensional phase of the WNB during the Mesozoic, veins, joints, conjugate fractures, and stylolites could be formed. During the inversion of the basin in the Late Mesozoic-Cenozoic, tectonic stylolites could have been formed, and the previously formed conjugate fractures could have been reactivated. Natural fractures are concentrated in more heterolithic intervals of the VAL-01 and NLW-GT-01 wells in both image logs and cores. These heterolithic sections display alternations of medium sandstones with silt- and claystones. The identification of more fractures in VAL-01 compared to NLW-GT-01 can be explained by the difference in basin location. VAL-01 is located in the centre of the basin where distal playa environments produced more fine-grained material alternating with coarser sands. The more proximal NLW-GT-01 is dominated by fluvial sands. The lithological variability produces Young’s and Shear modulus variability that seems to be driving increased fracture density rather than the absolute value of the Young’s modulus causes this.