Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences of these networks. Our study focuses on the Southern Chotts–Jeffara Basin, which hosts reservoirs within Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proved that a regional shortening phase occurred between the Permian and Jurassic, forming open folds and a distributed fracture network. Analysis of late Paleozoic and Mesozoic outcrops within the basin has identified several sets of fractures (with dip directions and dip angles of 150/80 and 212/86) and compressional structural features that support this shortening hypothesis. We have integrated fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we found that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid-flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provide an insight into network characterization within naturally fractured reservoirs of Tunisia, and how certain structures form fluid pathways that influence flow and production.

Faulted and fractured systems form a critical component of fluid flow, especially within low-permeable reservoirs. Therefore, developing suitable methodologies for acquiring structural data and simulating flow through fractured media is vital to improve efficiency and reduce uncertainties in modelling the subsurface. Outcrop analogues provide excellent areas for the analysis and characterization of fractures within the reservoir rocks where subsurface data are limited. Variation in fracture arrangement, distribution and connectivity can be obtained from 2D fractured cliff sections and pavements. These sections can then be used for efficient discretization and homogenization techniques to obtain reliable predictions on permeability distributions in the geothermal reservoirs. Fracture network anisotropy in the Malm reservoir unit is assessed using detailed structural analysis and numerical homogenization of outcrop analogues from an open pit quarry within the Franconian Basin, Germany. Several events are recorded in the fracture networks from the Late Jurassic the Alpine Orogeny and are observed to be influenced by the Kulmbach Fault nearby with a reverse throw of 800Â m. The fractured outcrops are digitized for fluid flow simulations and homogenization to determine the permeability tensors of the networks. The tensors show differences in fluid transport direction where fracture permeability is controlled by orientation compared to a constant value. As a result, it is observed that the orientation of the tensor is influenced by the Kulmbach Fault, and therefore faults within the reservoirs at depth should be considered as important controls on the fracture flow of the geothermal system.