Figure 1. (a and b) Direct pore-scale numerical simulations of two-phase flow in three-dimensional real-rock models using digital rock technology. (c and d, respectively) Invasion pattern of CO₂ injected into a water-wet and non-water-wet rock sample. CO₂ ganglia trapped in the pore space of (e) a water-wet sample and (f) a heterogeneous-wet sample.
When two fluids migrate together though pores in rocks, complex interactions occur between the fluids and with the rock matrix. These complexities influence the amount of each fluid that can be injected into or extracted from the pores, and how far fluids will migrate. Our team at the Gulf Coast Carbon Center studies the geosystem response to carbon dioxide (CO₂) injected into the subsurface to avoid emissions into the atmosphere—carbon storage. A major theme of our research is how to best design and monitor injection to maximize confidence in the ability of storage sites to retain CO₂ over periods of hundreds to thousands of years.
Buoyancy and viscous forces cause CO₂ to migrate away from the injection location, which increases the risk of its escape from the injection zone. We study the pore-scale processes that limit CO₂ plume migration and enhance storage capacity in saline aquifers. Two main processes effectively limit the plume extent: (1) capillary trapping, which happens when CO₂ pinches off and becomes immobilized in the pore space by capillary forces, and (2) dissolution trapping, where CO₂ gets dissolved and hence trapped in the resident brine.
Traditionally, observations of pore-scale processes have been made using core samples in the laboratory. However, many factors limit this traditional approach, such as the cost and long time necessary for each analysis and the relative unavailability of high-quality cores. The core samples themselves have heterogeneous textures, which lead to various pore-scale responses of the fluids. Given these limitations, correct scaling of small-scale forces is difficult in the laboratory. In addition, the use of real fluid requires high pressure conditions and the use of proxy fluids is imprecise.
To resolve these issues, Sahar Bakhshian of the Gulf Coast Carbon Center spearheaded an innovation that creates pore-scale simulations of two-phase flow in real-rock models. By leveraging digital rock-scanning technology such as microtomographic imaging, our team can create a high-quality pore-scale model of any rock matrix. These high-resolution rock models allow many different numerical experiments to be run under controlled conditions. Exploiting parallel computing algorithms and high-performance computing platforms enables efficient computationally intensive simulations on high-resolution scanned rock images.
Using machine learning, our scientists aim to upscale these various pore-scale processes to determine how two-phase flow interacts at a large scale with bedforms, reservoir architecture, and basin-scale depositional systems to ensure responsible CO₂ injection and storage. Furthermore, we are advancing toward validating our numerical models using fabricated micromodels. With these innovations, we can better assess how much of the injected CO₂ will be retained near the injection well and how quickly and widely CO₂ will move underground using targeted study sites like the Miocene-aged sandstone strata of the subsea Gulf of Mexico. This information is needed to design commercial injection projects to reduce atmospheric CO₂ emissions.
Publications
Bakhshian, S., and Hosseini, S. A., 2019, Pore-scale analysis of supercritical CO₂-brine immiscible displacement under fractional-wettability conditions: Advances in Water Resources, v. 126, p. 96–107, doi:10.1016/j.advwatres.2019.02.008.
Bakhshian, S., Hosseini, S. A., and Lake, L. W., 2020, CO₂-brine relative permeability and capillary pressure of Tuscaloosa sandstone: effect of anisotropy: Advances in Water Resources, v. 135, no. 103464, 13 p., doi:10.1016/j.advwatres.2019.103464.
Bakhshian, S., Hosseini, S. A., and Shokri, N., 2019, Pore-scale characteristics of multiphase flow in heterogeneous porous media using the lattice Boltzmann method: Scientific Reports, v. 9, no. 3377, 13 p., doi:10.1038/s41598-019-39741-x.
Treviño, R. H., and Meckel, T. A., eds., 2017, Geological CO₂ Sequestration Atlas of Miocene Strata, Offshore Texas State Waters: The University of Texas at Austin, Bureau of Economic Geology Report of Investigations No. 283, 74 p.
Name of Project: Permanent Storage of CO₂—Contribution of Pore-Scale Modeling
Name of Research Program: Gulf Coast Carbon Center
Project PI: Sahar Bakhshian
Other key personnel: Tip Meckel, Susan Hovorka, Seyyed Hosseini, Ramón Treviño, Vanessa Nuñez-López, Alex Bump, Mike DeAngelo, Katherine Romanak, Dallas Dunlap, Iulia Olariu, Tucker Hentz, and students Melianna Ulfah, John Franey, Arnold Aluge, and Harry Hull
Principal information contact:
Sahar Bakhshian
Email: sahar.bakhshian@beg.utexas.edu
Telephone: 512-471-2243
Website: http://www.jsg.utexas.edu/sb/
Susan Hovorka
Email: susan.hovorka@beg.utexas.edu
Telephone: 512-471-4863
Funding sources: Gulf Coast Carbon Center industrial affiliates (gulfcoastcarbon.org), U.S. Department of Energy’s National Energy Technology Laboratory, and The University of Texas at Austin’s Energy Institute “Fueling a Sustainable Energy Transition” program
Other key (institutional or business) partners/collaborators: State of Texas General Land Office
Geographic areas of study: Global, but with a focus on onshore and offshore subsurface Texas and Louisiana
General discipline of study: Geologic modeling of fluid flow with a focus on carbon capture and storage
Keywords (for search returns): CCS, carbon capture and storage, Gulf of Mexico, Texas, Louisiana, CO₂, carbon dioxide, climate mitigation, negative emissions, greenhouse gas, emissions reduction
