Beyond the Matrix: Integrating Tectonic Features for Realistic Carbonate Reservoir Modeling

Over the past decade, our research has revealed that permeability in carbonate reservoirs is fundamentally controlled by tectonic-related secondary features—such as fractures, sheared bedding, and karstification—rather than by matrix properties as in clastic systems. Despite this, most subsurface modeling technologies still rely on matrix porosity-permeability trends, which are inadequate for predicting flow in carbonates. Our studies in Abu Dhabi and the wider region demonstrate that these secondary features, formed and modified by tectonic processes, create the primary pathways for fluid movement and reservoir connectivity.

To accurately represent these features in dynamic models, an integrated workflow is essential. This includes advanced borehole imaging, multi-attribute seismic analysis, and machine learning to extract and model fractures, bedding corridors, and karst systems in three dimensions. Geomechanical modeling is also critical to assess the kinematic activity and connectivity of these features, determining their contribution to effective permeability. By incorporating tectonic-driven heterogeneities into geocellular models, we achieve more realistic simulations of reservoir behavior, improved well placement, and optimized production strategies. This approach marks a paradigm shift in carbonate reservoir characterization, emphasizing the need to routinely include tectonic features as primary permeability drivers in offshore field development.