Fluid Transport in Fractured Carbonate Rocks

Carbonate rocks store half of the world’s proven oil reserves. Whereas the rock matrix controls storativity, natural and induced fractures control the overall flow in fractured carbonate reservoirs and lead to complex hydromechanical processes. This thesis combines novel experimental devices, test protocols, and numerical methods to advance the understanding of flow-related phenomena in a variety of geological materials. Genesis and postdepositional diagenetic processes define the porous network topology and the matrix permeability. The underlying predictor for permeability is pore size; however, all prediction models have one order of magnitude uncertainty. The use of permeability measurements with simple data acquisition and interpretation provides the “true value” of permeability and avoids inherent uncertainty in correlation-based estimates. Fractures in the subsurface localize flow and deformations and also pose inherent numerical challenges when modeling fractured rock behavior. Roughness, matedness, and strength all control hydromechanical responses at the fracture level. Physics-inspired, data driven transmissivity models and predictive numerical methods help to identify and predict salient coupled processes. Although the fundamental laws of capillarity are well understood, complexities arise in fractured systems as they add multi-scale geometric effects. Fractures and matrices display inherent characteristic velocities and capillary behavior. The invasion morphologies depend on the velocity during immiscible displacement and are a visible manifestation of the balance between the fracture viscous drag and the matrix capillary suction forces.