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.
| Date of Award | May 2020 |
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| Original language | English (US) |
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| Awarding Institution | - Physical Sciences and Engineering
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| Supervisor | J. Carlos Santamarina (Supervisor) |
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