Modelling plume behavior through a heterogeneous sand pack using a commercial invasion percolation model
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Once the injection phase of a geological carbon sequestration operation ends, capillary forces are critical for hampering the upward migration of buoyant CO2 to shallower environments. Reservoir heterogeneity is also a key factor controlling plume spreading and trapping efficiency as well as a source of uncertainty about the deep subsurface. However, these two features are typically overlooked or overly simplified by numerical models that emphasize on viscous flow driven by pressure gradients. In particular, when considering far-field regions of storage reservoirs with vanishing pressure gradients, the physics governing the CO2 flow into brine-saturated rocks become dominated by capillary and buoyancy forces. Hence, there is currently a debate on whether numerical models founded on Darcy’s law can capture some of the migration phenomena that characterize long-term CO2 migration in saline formations. In this study, we consider experimental observations from a previous physical model that illustrates flow patterns of a CO2-surrogate plume migrating through a well-characterized sand aquifer saturated with a brine-analog. Then, we compare Monte Carlo sets of invasion percolation simulations with direct observations of plume distribution to evaluate the effects of a heterogeneous capillary pressure field. The observed plume distribution appears to be controlled by a combination of buoyant migration and trapping at capillary barriers under near-hydrostatic pressure conditions. Although these observations are gathered in a simplified and relatively small laboratory system, an analogous behavior has been documented at reservoir scale for the Sleipner storage site, where a series of shale layers inhibited the buoyant migration of the plume.
KeywordsInvasion percolation Sandbox experiments Surrogate fluids Capillary pressure heterogeneity
Funding for performing invasion percolation simulations was provided by the Center for Frontiers of Subsurface Energy Security, an Energy Frontier Research Center funded by the US Department of Energy, Office of Science, Basic Energy Sciences under Award # DE-SC0001114. The experimental work was supported by the US Department of Energy through the National Energy Technology Laboratory’s CO2 sequestration R&D Program under Grant DE-FE0004630 and National Science Foundation Award #: EAR-1045282 through the Hydrologic Sciences Program. The authors thank Steven Bryant and three anonymous reviewers for insightful observations and LT acknowledges additional funding from the Bureau of Economic Geology.
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