Tracing back the source of contamination

From the time a contaminant is detected in an observation well, the question of where and when the contaminant was introduced in the aquifer needs an answer. Many techniques have been proposed to answer this question, but virtually all of them assume that the aquifer and its dynamics are perfectly known. This work discusses a new approach for the simultaneous identification of the contaminant source location and the spatial variability of hydraulic conductivity in an aquifer which has been validated on synthetic and laboratory experiments and which is in the process of being validated on a real aquifer

The transport of nanoparticles in subsurface with fractured, anisotropic porous media: Numerical simulations and parallelization

The flow of fluids through fractured porous media has been an important topic in the research of subsurface flow. The several orders of magnitude in size between the fractures and the rock matrix causes difficulties for simulating such flow scenario. The fluid velocities in fractures are also several orders of magnitude higher than that in the rock matrix due to high permeability and porosity. If there exists pollutant such as nanoparticles in the fluids, the pollutant may be transported rapidly and the rock matrix’s properties near the fractures are hence changed. In this research, we simulate the transport phenomena of nanoparticles in the fluid flow through fractured porous media. The permeability fields which contain different anisotropy angles are considered in the simulation. Fractures are represented explicitly by volumetric grid cells and the numerical algorithm is parallelized in order to reduce the simulation time. We investigate the effect of the appearance of fractures and rotated anisotropy on the transport of nanoparticles, particles deposition, entrapment and detachment. The results show that flow directions are affected by the direction of anisotropy and the transport of nanoparticles in the fractures is significantly faster than that in rock matrix due to high fluid velocities. The direction of anisotropy distorted the pressure field and changed the fluid flow directions, which determined the time needed for the pollutant front to reach the fractures. The parallel efficiency of the overall algorithm is also discussed and the experimental results show that it is deeply affected by the performance of the multigrid solver

A Systematic Multiscale Investigation of Nanoparticle-Assisted CO2 Enhanced Oil Recovery (EOR) Process for Shale Oil Reservoirs

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