Doctor of Philosophy (PhD)


Craft & Hawkins Department of Petroleum Engineering

Document Type



Shale oil reservoirs are prolific on the short term due to hydraulic fracturing and horizontal drilling but experience significant production decline, leading to poor ultimate recovery and leaving billions of barrels of oil buried in the ground. In this study, a systematic multi-scale investigation of an enhanced oil recovery (EOR) process using relatively inexpensive silicon dioxide nanoparticles and carbon dioxide for shale oil reservoirs was conducted. Using the Tuscaloosa Marine Shale (TMS) as a case study, aqueous dispersions of nanosilica in conjunction with CO2 were investigated at nano-to-core scales. At the nanoscale, atomic force microscope was used to investigate the wettability modification performance of silica nanoparticles by measuring adhesion force between specific functional groups and pure minerals in nanofluid media. At the micron-scale, the roles of silica-based nanofluids in fluid/fluid interactions and rock/fluid interactions were distinguished by characterizing interfacial tension and advancing contact angle using optical tensiometer and the dual-drop-dual-crystal technique, respectively. Core-scale investigations consisted of: high-pressure CO2 EOR coreflood experiment, reservoir rock/fluid characterization, physics-based modelling of capillary pressure and relative permeability using nano-to-core scale experimental data, and compositional simulation. Results showed that hydrophilic silica nanoparticle (HNP) dispersions can effectively improve nanoscale wettability alteration (towards less oil-wet state) by decreasing adhesion force and work required to spontaneously desorb dominant functional groups in TMS crude oil from pure mineral surfaces. However, the grafting of aminosilanes on the surfaces of nanosilica generally increased adhesion force. At the micron-scale, HNP solutions showed great potential for enhancing oil recovery in TMS through wettability modification but not interfacial tension xviii reduction, whereas APTES-modified nanoparticle dispersions showed promising EOR potential through both mechanisms. At the core scale, coreflood experiment and compositional simulation showed that up to 30% of oil-in-place can be recovered with CO2 EOR in TMS. The nano-to-micron scale mechanisms of silica-based nanofluids translated into a notable decrease in capillary pressure, an increase in oil relative permeability and a decrease in water relative permeability. However, the strongly-water state in TMS masked the synergistic effects of nanoparticle-assisted CO2 EOR and thus helped revealed the initial wetting state as an important EOR screening criterion for shale oil reservoirs.

Committee Chair

Rao, Dandina N.