Integrating borehole image log, core data, and computed tomography for characterizing natural open fractures in the Pre-salt Barra Velha Formation, Santos Basin, Brazil

Understanding fracture networks in carbonate reservoirs is essential for improving predictions of fluid flow and reservoir behaviour, but their complexity continues to pose major challenges for accurate characterization and modelling. In the Brazilian pre-salt carbonates in the Santos Basin, research has predominantly focused on mound-like buildups, leaving the fracture architecture of slope carbonates underexplored. This study addresses this gap by conducting an integrated, multi-scale analysis of fracture systems within a pre-salt interval from a well located in the slope domain. The approach combines conventional core descriptions, computed tomography, and borehole image logs to assess fracture morphology, distribution, and genesis across three distinct seismic sequences representing Lower, Middle, and Upper Barra Velha Formation (BVE). Six fracture types were identified: open-fracture, partial-open fracture, vuggy-fracture type 1 and type 2, shear-fracture, and vug-lineation that vary by genesis (tectonic vs. depositional) and timing (early or late burial). In the Lower and Middle BVE sequences, early cemented fractures (F0) are primarily linked to syn-depositional tectonic, whereas the Upper BVE sequence reflects tectonic quiescence and a predominance of burial-related fractures such as strata-bound and fracture-like features (F1 to F3, respectively). A late fault reactivation generated tectonic fractures (F4) that are distributed throughout the BVE interval, with higher intensities in the Lower and Middle BVE. Fracture orientation analysis reveals two dominant sets: (1) N–S and NE–SW strata-bound fractures, controlled by layering, and (2) E–W and NW–SE oblique fractures, likely depositional and tectonic in origin, respectively. The prevalence of NW–SE-oriented fractures suggest the influence of relay ramps in the vicinity of the well and demonstrates the structural complexity of the area. Vuggy and low-amplitude fractures exhibit the highest intensities (P 21 ) and significantly enhance reservoir permeability. This study highlights the value of integrating tools with varying resolutions and underscores the need for a robust multi-scale workflow. Incorporating conceptual models for matrix, fracture, and non-matrix porosity are fundamental to improving the predictive capacity of geological models, supporting more reliable reservoir simulations.