Wettability alterations of amorphous shales in geological carbon storage: Impact of acidic conditions in deep saline aquifers

Abstract

Listen

Translate article

The feasibility of Geological carbon storage (GCS) in deep saline aquifers is mainly determined by its ability to prevent CO2 leakage through caprock, which is most commonly shale. The wettability of the shale–CO2–brine system is one of the most essential petro-physical parameters in the assessment of the integrity of shale caprock. Current literature suggests that wettability measurements of the shale–CO2–brine system have many contradictory outcomes. Furthermore, previous applications of molecular dynamic simulation (MDS) to estimate wettability of the shale–CO2–brine system disregarded variations in shale composition and concentrated on just a single component. Moreover, there has been limited investigation into the effect of CO2 dissolution in brine and the resultant acidic conditions on the wettability of the shale–CO2–brine combination. In this study, MDS is implemented for evaluating the wettability of a system made up of amorphous shale, CO2, and brine under conditions representative of typical geological storage site. An amorphous shale molecular model has been developed through the integration of illite, quartz, and kerogen. The microscopic wetting and half-angle fitting approaches have been applied to establish the wettability. A qualitative investigation was also conducted to further examine the wettability of the studied systems. Additionally, a contrasting analysis was conducted to assess the conclusions of this study in relation to relevant literature data. The findings of this study demonstrate the wettability of an amorphous shale–CO2–brine system is significantly influenced by the composition of the shale and the presence of acidic conditions. The water contact angles for shales with TOC values of 5% and 10% were measured to be 42.1° and 52.5°, respectively, at a pressure of 10 MPa and a temperature of 333 K, without taking into account any acidic conditions. The addition of induced acidic conditions resulted in a 15% and 24% increase in the water contact angle, respectively, for high and low TOC shale systems, respectively. The findings of this study have significant implications on the containment of stored CO2, thereby contributing to the worldwide efforts of minimizing greenhouse gas emissions through enhancements in the performance of GCS processes.