Speaker
Description
The CarbonSAFE Project aims to demonstrate large-scale CO2 storage in the United States, using deep characterization wells to support commercial hub for tens of millions of tonnes of anthropogenic CO2. Large-scale injection of CO2 into the Earth’s crust requires an understanding of the multiphase flow properties of high-pressure CO2 displacing brine. In this perspective, the main source of uncertainty is the lack of reliable CO2–brine relative permeability data at the high pressures and temperatures expected in deep sedimentary formations. Due to the geothermal gradient, formations at the reservoir depth can exceed the CO2 critical temperature of 31.1°C, placing the injected CO2 in a supercritical state. Under these conditions, relative permeability is influenced by changes in density, viscosity, interfacial tension, and rock wettability. Existing laboratory studies rarely extend into this pressure–temperature range, limiting confidence in injectivity forecasts and storage capacity estimates for ultra-deep sites. We use advanced core-flooding system designed to replicate in-situ conditions up to 120°C and 38 MPa. The system employs a two-stage pressure scheme that combines a gas booster with a high-precision dual-cylinder pump controller, enabling CO2 to be raised from cylinder pressures (~800 psi) to reservoir conditions while maintaining continuous, stable flow. Experiments are conducted in Berea sandstone as a well-characterized proxy for quartz-rich storage formations. Five drainage CO2-brine relative permeability curves were measured on a single Berea sandstone at pressures (20-35 MPa), temperatures (80-105 °C). Preliminary results suggest that endpoint relative permeabilities and residual saturations are only weakly sensitive to pressure and temperature within the tested range, consistent with primary control by wettability and interfacial tension. In contrast, the curvature and effective mobility of CO2 display measurable trends with increasing pressure and temperature, reflecting changes in CO2 density and viscosity and associated capillary numbers. The resulting high-pressure, high-temperature relative permeability dataset will aid the evaluation of injectivity and storage-capacity predictions and provide transferable guidance for the design and risk assessment of future ultra-deep CO2 storage projects.
| Country | United States |
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