Introduction:
Injection of large volumes of dry or undersaturated (with respect to water) supercritical CO2 into the geological formation causes evaporation of the formation water. As evaporation proceeds, the concentration of the dissolved salts in brine pore fluid increases. Under the thermodynamic conditions of a given storage reservoir, when the salt concentration reaches the solubility limit, crystals start to precipitate out of the aqueous phase, and salt bodies grow in the porous medium.
Salt precipitation during subsurface injection of CO2 into the saline aquifers can alter reservoir and top seal rocks' properties. While precipitation of salt crystals in the near-wellbore regions and the reservoir units is unfavourable, it may positively impact the permeability of leaking pathways in the fractured caprocks. The permeability of reservoir rock in the near-wellbore regions can be severely reduced because of brine evaporation into the CO2 stream and the consequent salt precipitation. The near-wellbore salt formation triggers excess pressure build-up and induces a decline in injection efficiency.
Research Objectives:
Identify precipitation pattern, location, and timing of salt crystal accumulations in the porous medium over broad salinity and temperature-pressure conditions relevant to CCS Operations.
Research Scope:
For the experimental part of the project, A) lab-on-chip investigations on glass-microchips (synthetic porous medium) and geomaterial microfluidics (natural reservoir and caprocks), B) sandbox tests (glass beads and/or sand-size quartz-rich aggregates) will be conducted to provide insights into the physics and dynamics of salt precipitation at the pore-scale and also to find the possible explanations for the large-scale salt precipitation observed in the field.
For the numerical simulation part of the project, based on the competencies and interests of the candidate, investigations in two different length scales can be performed: (a) pore- and mesoscale using either Lattice Boltzmann Method (LBM) or Pore Network Modeling (PNM) or (b) continuum-scale (core-scale) and large-scale simulations of subsurface CO2 injections using simulators such as open-source MATLAB Reservoir Simulation Toolbox (MRST), and Open Porous Media (OPM).
For each part, candidates will have training and responsibilities to develop the necessary tools for carrying out the research (laboratory setup or numerical code), conducting the research to answer open questions, following the overall objectives, and compiling a report/manuscript to present the results and discuss findings.
As Figure 2 shows, the interplay between petrophysical, geochemical, and geomechanical parameters influences the injectivity considering the composition of a given rock and fluid system (in situ and injected). In these two projects, we limit the study's scope to geochemistry (fluid-rock interactions) and petrophysics (fluid flow in porous medium and transport properties).
With active participation and supervisors' directions, the candidates will have an opportunity to be involved in state-of-the-art research, receive training in experimental and modelling techniques, familiarize themselves with reactive transport studies, and be part of a lively curiosity-driven research group. In collaboration with supervisors, the candidates will disseminate the project outcome in conference proceedings, if possible, peer-reviewed articles.
The project will be an opportunity to start learning and working with techniques for studying the fluid flow and reactive transport processes relevant not only for CO2 storage but also for hydrogen storage, geothermal energy, waste disposal, and environmental studies.