Abstract
Wettability is one of the main parameters controlling CO2 injectivity and the movement of CO2 plume during geological CO2 sequestration. Despite significant research efforts, there is still a high uncertainty associated with the wettability of CO2/brine/rock systems and how they evolve with CO2 exposure. This study, therefore, aims to measure the contact angle of sandstone samples with varying clay content before and after laboratory core flooding at different reservoir pressures, of 10 MPa and 15 MPa, and a temperature of 323 K. The samples’ microstructural changes are also assessed to investigate any potential alteration in the samples’ structure due to carbonated water exposure. The results show that the advancing and receding contact angles increased with the increasing pressure for both the Berea and Bandera Gray samples. Moreover, the results indicate that Bandera Gray sandstone has a higher contact angle. The sandstones also turn slightly more hydrophobic after core flooding, indicating that the sandstones become more CO2-wet after CO2 injection. These results suggest that CO2 flooding leads to an increase in the CO2-wettability of sandstone, and thus an increase in vertical CO2 plume migration and solubility trapping, and a reduction in the residual trapping capacity, especially when extrapolated to more prolonged field-scale injection and exposure times.
Highlights
Carbon geological sequestration (CGS) has been proposed as an efficient method to reduce anthropogenic CO2 emissions into the atmosphere and mitigate global climate change [1]
The results clearly indicate that the contact angles after flooding were higher than before the flooding for both samples
This shows that Berea and Bandera Gray sandstones became more CO2 -wet after CO2 injection
Summary
Carbon geological sequestration (CGS) has been proposed as an efficient method to reduce anthropogenic CO2 emissions into the atmosphere and mitigate global climate change [1]. The technique involves capturing CO2 from large stationary emission sources and locking it into some natural geological formations [1,2,3]. There are three geological formations that have attained a wide consideration. They include (1) depleted oil and gas reservoir, (2) deep saline aquifers, and (3) coal seams [1]. In saline aquifers and oil and gas reservoirs, CO2 storage is typically placed at depths below 800 m, where CO2 becomes liquid or supercritical because of the ambient pressure and temperature conditions [1]. The vertical migration of CO2 is the main problem involved in CO2 injection due to the density differences between the brine and CO2 [4,5]. It is essential to assess the different functional trapping mechanisms, which prevent the buoyant
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