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Offshore crystalline basement volumes forming fractured reservoirs contain hydrocarbons within hydraulically conductive fracture networks. These networks, in places occurring at sub-seismic scales, may develop from geologically long and complex polyphase deformation histories. If, on the one hand, characterising fracture-related permeability and connectivity is vital in assessing hydrocarbon play prospectivity, on the other it is challenging due to the inaccessibility of the off-shore volumes and the small average size and intricacy of transmissive fractures. Indeed, approaches relying on deep wells and regional seismic data usually lack the spatial, temporal, and genetic resolution to properly resolve the sub-seismic fracture networks that guarantee the secondary permeability of those rock volumes. Correlative studies on onshore analogues, may therefore be of great assistance. Leveraging the improved resolution advantages of a series of geologically well-constrained onshore analogues, this study incorporates multi-scalar lineament trace maps, outcrop, and drill hole orientation data from Smla Island in Central Norway to identify a number of systematic fracture sets, associated fracture size distributions, and fracture frequency and trace intensities. Crucially, this study also incorporates both deterministic cross-cutting/termination information, and absolute K-Ar age constraints from fault gouges on Smla on the age of formation of the main faults and fracture sets. These fracture and temporal input variables were used to generate several grown discrete fracture network (DFN) models. By generating fractures in a series of timesteps, these models produce a more realistic simulation of natural fracture patterns, including important fracture intersections and terminations. The models represent stochastic fracture network realisations which 'back-strip from the present to the Mid-Cretaceous, Late Triassic-Early Jurassic, and the Late Carboniferous/Early Permian. Based on each of these time-stage models, probabilistic outputs of 3D fracture network connectivity, and permeability tensor orientations using assumed reservoir values were produced. Our findings suggest a temporal shift in the principal permeability (K) tensor orientations during the extension of the Mid-Norwegian margin, opening of the North Atlantic, and Norwegian Sea basin development. A comparative analysis with known Norwegian Sea reservoir charging and fluid migration events suggests possible key basement-hosted tectonic structural geometries that have had permeability values through time that are of interest for hydrocarbon accumulation and potential geofluid storage.
Hodge et al. (Fri,) studied this question.