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In carbonate rocks, channelized fluid flow through fracture conduits can result in the development of large and connected karst networks. These cavity systems have been found in multiple hydrocarbon and geothermal reservoirs, and are often associated with high-permeability zones, but also pose significant challenges in drilling and reservoir management. Here, we expand on the observed interplay between fractures, fluid flow and large cave systems, using outcrop analysis, drone imagery and fluid-flow modelling. The studied carbonate rocks are heavily fractured and are part of the Salitre Formation (750–650 Ma), located in central Bahia (NE Brazil). Firstly, the fracture and cave network data show a similar geometry, and both systems depict three main orientations, namely; NNE–SSW, NW–SE and ESE–WNW. Moreover, the two datasets are dominated by the longer NNE–SSW features. These observed similarities suggest that the fractures and caves are related. The presented numerical results further acknowledge this observed correlation. These results show that open fractures act as the main fluid-flow conduits, with the aperture model defining the fracture-controlled flow contribution. Furthermore, the performed modelling highlights that geometrical features such as length, orientation and connectivity play an important role in the preferred flow orientations. Thematic collection: This article is part of the Naturally Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/naturally-fractured-reservoirs

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The positive impact that natural fractures can have on geothermal heat production from low-permeability reservoirs has become increasingly recognised and proven by subsurface case studies. In this study, we assess the potential impact of natural fractures on heat extraction from the tight Lower Buntsandstein Subgroup targeted by the recently drilled NLW-GT-01 well (West Netherlands Basin (WNB)). We integrate: (1) reservoir property characterisation using petrophysical analysis and geostatistical inversion, (2) image-log and core interpretation, (3) large-scale seismic fault extraction and characterisation, (4) Discrete Fracture Network (DFN) modelling and permeability upscaling, and (5) fluid-flow and temperature modelling. First, the results of the petrophysical analysis and geostatistical inversion indicate that the Volpriehausen has almost no intrinsic porosity or permeability in the rock volume surrounding the NLW-GT-01 well. The Detfurth and Hardegsen sandstones show better reservoir properties. Second, the image-log interpretation shows predominately NW–SE-orientated fractures, which are hydraulically conductive and show log-normal and negative-power-law behaviour for their length and aperture, respectively. Third, the faults extracted from the seismic data have four different orientations: NW–SE, N–S, NE–SW and E–W, with faults in proximity to the NLW-GT-01 having a similar strike to the observed fractures. Fourth, inspection of the reservoir-scale 2D DFNs, upscaled permeability models and fluid-flow/temperature simulations indicates that these potentially open natural fractures significantly enhance the effective permeability and heat production of the normally tight reservoir volume. However, our modelling results also show that when the natural fractures are closed, production values are negligible. Furthermore, because active well tests were not performed prior to the abandonment of the Triassic formations targeted by the NLW-GT-01, no conclusive data exist on whether the observed natural fractures are connected and hydraulically conductive under subsurface conditions. Therefore, based on the presented findings and remaining uncertainties, we propose that measures which can test the potential of fracture-enhanced permeability under subsurface conditions should become standard procedure in projects targeting deep and potentially fractured geothermal reservoirs.