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Geofluid reservoirs located in heterolithic successions (e.g., turbidites) can be affected by vertical and lateral compartmentalization due to interbedded fine-grained facies (i.e., shale, siltstones) and the presence of faults, respectively. A fault can behave as a conduit or barrier to fluid flow depending on its architecture and the individual hydraulic behavior of its components (i.e., fault core, damage zone). The fault core, normally composed by fault rock or smeared clay material, commonly acts as a flow inhibitor across the fault. Fault-related fractures (macro- and microscopic) in the damage zone generally increase the permeability parallel to the fault, except when they are cemented or filled with gouge material. Although macrofractures (which define the fracture porosity) dominate fluid flow, the matrix porosity (including microfractures) begins to have a more important role in fluid flow as the aperture of macrofractures is occluded, particularly at greater depth. This study investigates the variation in matrix permeability in fault zones hosted in heterolithic successions due to fault architecture and stratigraphy of host rock (i.e., sand-rich turbidites). Two key areas of well-exposed, faulted Miocene turbidites located in central and southern Italy were selected. For this study, six separate fault zones of varying offset were chosen. Each impacts heterolithic successions that formed under similar tectonic conditions and burial depths. Across the selected fault zones, an extensive petrophysical analysis was done in the field and laboratory, through air permeameter measurements, thin section, and synchrotron analysis in both host rock, damage zone, and fault core. Results suggest that the amount and distribution of clay layers in a heterolithic sequence affects fluid flow across the fault, regardless of fault offset.

Fluid flow through a single fracture is traditionally described by the cubic law, which is derived from the Navier-Stokes equation for the flow of an incompressible fluid between two smooth-parallel plates. Thus, the permeability of a single fracture depends only on the so-called hydraulic aperture which differs from the mechanical aperture (separation between the two fracture wall surfaces). This difference is mainly related to the roughness of the fracture walls, which has been evaluated in previous works by including a friction factor in the permeability equation or directly deriving the hydraulic aperture. However, these methodologies may lack adequate precision to provide valid results. This work presents a complete protocol for fracture surface mapping, roughness evaluation, fracture modeling, fluid flow simulation, and permeability estimation of individual fracture (open or sheared joint/pressure solution seam). The methodology includes laboratory-based high-resolution structure from motion (SfM) photogrammetry of fracture surfaces, power spectral density (PSD) surface evaluation, synthetic fracture modeling, and fluid flow simulation using the Lattice-Boltzmann method. This work evaluates the respective controls on permeability exerted by the fracture displacement (perpendicular and parallel to the fracture walls), surface roughness, and surface pair mismatch. The results may contribute to defining a more accurate equation of hydraulic aperture and permeability of single fractures, which represents a pillar for the modeling and upscaling of the hydraulic properties of a geofluid reservoir.