(559i) Impact of Relative Permeability and Capillary Pressure Parameters on Chemical Trapping Predictions in Ccus

Injecting anthropogenic carbon dioxide into the subsurface is considered as a viable option for climate change mitigation. CO₂ injection is also used as a tool in commercial geological operations (e.g. CO₂-enhanced oil recovery, CO₂-enhanced geothermal systems, etc.) for process efficiency enhancement. In any of these applications, it is critical to understand and predict the behavior, migration and long-term fate of the injected CO₂. We investigated the impact of relative permeability and capillary pressure (RP-CP) parameters on the predictions of CO₂ trapping in solution and as minerals. It is difficult to acquire lab-tested RP-CP data specific to the formations being modeled. Moreover, even applying lab-derived RP-CP data in the models can lead to significant uncertainty due to unforeseen heterogeneity in the reservoir. In most cases, generic RP-CP parameters from literature are employed in reactive transport models. Our hypothesis is that this choice of RP-CP parameters can lead to significant differences in the predictions of solubility and mineral trapping made by the models. We investigated four lab-measured RP-CP curves calibrated to the van Genuchten model as applied in most multiphase flow models. Results were compared to those obtained from “standard” parameters used frequently in literature. Significant differences in CO₂ plume migration and dissolution were found in the post-injection phase (>200 years). The reservoir geochemistry was set to that of the Morrow Sandstone of the Farnsworth Unit, Texas. This project was conducted under the auspices of the National Energy Technology Laboratory and its Southwest Regional Partnership on Carbon Sequestration.