Fluid pH and carbonate speciation gradients in near-wellbore region reflect CO2 plume shape deep into aquifer.
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Trend in pH change provides diagnostic capabilities of plume during injection and post-injection periods.
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Solubility trapping takes precedence when aquifers have significantly large pH and lower salinity.
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Salinity and brine density promote plume height as they hinder CO2 solubility into the aqueous phase.
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Plume growth strongly relates to activities of aqueous CO2 and HCO3-1.
Abstract
Geological carbon sequestration in saline aquifers is one of the most promising strategies to help mitigate emissions of CO2 to the atmosphere. Significant challenges in ensuring the security of the sequestration process rest in the evolution and expansion of the CO2 plume in the subsurface. The ability to track the movement of the injected CO2 poses another challenge. Critical questions related to the integrity of the sequestration operations in saline aquifers relate to plume characteristics that can we monitor using well-based variables. We addressed this and related questions using an integrated modeling framework through a numerical investigation of carbon sequestration in saline aquifers during long-term and post-injection periods. This modeling paradigm incorporates the effect of structural, geological, and petrophysical characteristics. That way, we can account for critical physicochemical processes, rock-fluid interactions, and lithology dependencies. The well fluid variables investigated include fluid composition, pH, fluid density, and ion activity. We learned that fluid property analytics and diagnostics can be powerful tools to estimate the movement of CO2 and its storage in different trapping mechanisms. These analytics can help optimize operational aspects and simplify reservoir-scale models while still reflecting the complex nature of the CO2 interactions underground and offering insights into plume evolution.
