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Carbon-Based Energy Systems > CO2 StorageMultiphase Flow of CO2 and Water in Reservoir Rocks
Start Date: September 2011
Sally Benson, Department of Energy Resources Engineering, Stanford University
This research program combines laboratory experiments, numerical methods and analytical solutions to evaluate the fundamental science underpinning sequestration of atmospheric carbon dioxide in saline aquifers and the multiphase flow of CO2, brine and to a lesser degree, oil. As the research progresses, researchers will assess which, if any, modifications to currently accepted multiphase flow theories are needed and will develop approaches for reliably predicting field-scale performance.Background
Carbon dioxide capture and sequestration (CCS) in deep geological formations is an important component of the portfolio of options for reducing greenhouse emissions. Saline aquifers have the largest sequestration capacity, as compared to oil and gas reservoirs or deep unminable coal beds. Saline aquifers are also more broadly distributed and thus, closer to more emission sources. However, unlike oil and gas reservoirs with proven seals that have withstood the test of time, saline aquifers must be carefully characterized to assure that CO2 will achieve high retention rates and remain permanently trapped in the subsurface. Improved fundamental understanding of multiphase flow (i.e., the simultaneous flow of more than one fluid phase through a porous medium) and trapping in CO2-brine systems is needed to take advantage of the large storage capacity of saline aquifers.Approach
Optimizing the design and operation of injection projects will depend on knowledge of injectivity (i.e., the rate and pressure at which fluids can be pumped underground without fracturing the formation), trapping capacity, distribution of CO2 in the subsurface and the extent of the subsurface plume. A combination of multiphase flow experiments, numerical simulations, flow theory and reservoir characterization is used to address fundamental issues as shown in Figure 1. Interaction and iteration among these four approaches improves the ability to identify and test new phenomena and techniques that can be applied to quantitative models.
Capillary pressure is one of the dominant forces in long-term sequestration, and a better understanding of the capillary heterogeneity and relative permeability of CO2-water systems is essential for accurate simulations ranging from the sub-core to the basin scale.
Recent work on core-scale multiphase flow properties of CO2 and water in sandstone rocks at reservoir conditions focuses on four components related to capillary forces:
(1) In situ measurements of capillary pressure and capillary heterogeneity
(2) Enhanced trapping due to capillary barriers
(3) Influence of capillary pressure treatment on solubility trapping
(4) Semi-analytical solutions for predicting CO2 saturations as a function of flowrate, interfacial tension and core geometry
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