Investigation of CO₂ migration in saline aquifers using real-rock microfluidic experiments
| dc.contributor.advisor | Hosseini, Seyyed Abolfazl | |
| dc.creator | Taleb Restrepo, Shadya | |
| dc.date.accessioned | 2024-04-30T01:43:59Z | |
| dc.date.available | 2024-04-30T01:43:59Z | |
| dc.date.issued | 2023-12 | |
| dc.date.submitted | December 2023 | |
| dc.date.updated | 2024-04-30T01:44:00Z | |
| dc.description.abstract | Over the past decade, reducing carbon dioxide (CO₂) emissions has become critical to tackle climate change and its impacts on human life. While several efforts are being made worldwide to reduce emission levels, geological carbon storage represents a viable technology to sequester CO₂ from large-scale emission sources that are hard to abate. However, the injection of CO₂ into subsurface porous rocks is a complex process and understanding multiphase flow processes is critical for the long-term and short-term assessment of the stored CO₂. This thesis focuses on understanding of CO₂ migration at the pore scale. Synthetic microfluidic models allow precise control of the pore topology; however, they fail to reproduce rock-fluid interactions and cannot capture the effects of heterogeneous mineral distribution. I use real-rock microfluidic devices made of sandstone to estimate the saturation of trapped CO₂ in a brine-saturated porous medium. I first present the micromodel fabrication methodology that combines rock thin sections with nanofabrication techniques (e.g., soft lithography). Images obtained during the experiments are used to detect the phase saturation of each fluid in the micromodel. Then, I obtain capillary pressure curves using the wetting-phase saturations and peripheral pressure measurements. I conducted fluid flow experiments under dynamic conditions using sandstone samples from Cranfield, Mississippi (Lower Tuscaloosa Formation) and commercial lab samples of Berea sandstone from Ohio and used analog fluids to match the supercritical CO₂ and brine properties. Our experimental results heavily depend on the injection flow rate of the supercritical CO₂ analog; however, for Tuscaloosa samples, when normalized with flow rate, the capillary pressure curves collapse into a single trend. Our experimental results were compared with core-scale measurements. While the two techniques successfully compare for the tests conducted here, it is important to consider the scale of heterogeneities present in the rock. Micromodel-based capillary pressure determination is a useful approach when the size of the heterogeneities is smaller than the micromodel size. | |
| dc.description.department | Energy and Earth Resources | |
| dc.format.mimetype | application/pdf | |
| dc.identifier.uri | ||
| dc.identifier.uri | https://hdl.handle.net/2152/124959 | |
| dc.identifier.uri | https://doi.org/10.26153/tsw/51560 | |
| dc.language.iso | en | |
| dc.subject | Geologic carbon storage | |
| dc.subject | Microfluidics | |
| dc.title | Investigation of CO₂ migration in saline aquifers using real-rock microfluidic experiments | |
| dc.type | Thesis | |
| dc.type.material | text | |
| thesis.degree.department | Energy and Earth Resources | |
| thesis.degree.grantor | The University of Texas at Austin | |
| thesis.degree.name | Master of Science in Energy and Earth Resources | |
| thesis.degree.program | Energy and Earth Resources |
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