No abstract

No abstract

No abstract

No abstract

Every year, millions of tons of CO2 are stored in CO2-storage formations (deep saline aquifers) containing traces of organic acids including hexanoic acid C6 (HA), lauric acid C12 (LuA), stearic acid C18 (SA), and lignoceric acid C24 (LiA). The presence of these molecules in deep saline aquifers is well documented in the literature; however, their impact on the structural trapping capacity and thus on containment security is not yet understood. In this study, we therefore investigate as to how an increase in organic acid concentration can alter mica water wettability through an extensive set of experiments. X-ray diffraction (Figure S2), field emission scanning electron microscopy, total organic carbon analysis, Fourier-transform infrared spectroscopy, atomic force microscopy, and energy-dispersive X-ray spectroscopy were utilized to perceive the variations in organic acid surface coverage with stepwise organic acid concentration increase and changes in surface roughness. Furthermore, thresholds of wettability that may indicate limits for structural trapping potential (θr < 90°) have been discussed. The experimental results show that even a minute concentration (∼10–5 mol/L for structural trapping) of lignoceric acid is enough to affect the CO2 trapping capacity at 323 K and 25 MPa. As higher concentrations exist in deep saline aquifers, it is necessary to account for these thresholds to derisk CO2-geological storage projects.

No abstract

Geological H 2 storage plays a central role to enable the successful transition to the renewable H 2 economy and achieve net-zero emission in the atmosphere. Depleted oil and gas reservoirs are already explored with extensive reservoir and operational data. However, residual hydrocarbons can mix with injected H 2 in the reservoirs. Furthermore, low density and high diffusivity of H 2 may establish H 2 leakage from the reservoirs via fault pathways. Interestingly, H 2 can be consumed by microorganisms, which results in pore-network precipitation, plugging, and partial permeability impairment. Therefore, stored H 2 may be lost in the formations if the storage scenario is not planned cautiously. While salt caverns are safe and commercially proven geo-rock for H 2 storage, they have low-storage capacity compared to depleted gas reservoirs. Moreover, salt structures (e.g., domel, bedded) and microorganisms activities in the salt cavern are limiting factors, which can influence the storage process. Accordingly, we discuss challenges and future perspectives of hydrogen storage in different geological settings. We also highlight geographical limitations with diverse microbial communities and theoretical understanding of abiotic transformation (in terms of rock's minerals, i.e., mica and calcite) for geological H 2 storage. Regarding the fundamental behavior of H 2 in the geological settings, it is less soluble in formation water; therefore, it may achieve less solubility trapping compared to CO 2 and CH 4 . Furthermore, H 2 gas could attain higher capillary entrance pressures in porous media over CH 4 and CO 2 due to higher interfacial tension. Additionally, the low viscosity of H 2 may facilitate its injection and production but H 2 may establish the secondary trapping and viscous fingering. Thus, this review documents a blend of key information for the amendment of subsurface H 2 storage at the industrial scale.

No abstract