Deep saline aquifers, characterized by wide distribution, large storage capacity, and low competition with oil and gas resources, are widely regarded as ideal media for geological CO₂ storage. This study elucidates the dissolution and diffusion behavior of CO₂ in real formation water under complex temperature–pressure conditions is of great significance for improving storage efficiency and ensuring long-term safety. Taking the Jurassic Sangonghe Formation in the Junggar Basin as the research object, a NaHCO₃-type formation water model containing Na⁺, K⁺, Ca²⁺, Mg²⁺ and ions was constructed based on regional geological and hydrochemical data. Molecular dynamics simulations were then performed to systematically investigate the dissolution behavior, density distribution, intermolecular interactions, and diffusion mechanisms of CO₂ in formation water under varying temperature and pressure conditions. The simulation results indicate that under isothermal conditions, pressure is the dominant factor controlling CO₂ occurrence and dissolution. Low pressure favors rapid dissolution of CO₂, moderate pressure enables efficient utilization of storage capacity, and high pressure helps maintain long-term system stability. Under isobaric conditions, elevated temperature markedly enhances CO₂ solubility by weakening hydrogen bonding and intensifying molecular thermal motion, thereby promoting uniform dispersion of CO₂ molecules and the formation of stable solvation structures. Under coupled temperature–pressure conditions, the CO₂ adsorption amount increases significantly with burial depth in the low-pressure interval (approximately 1000~4000 m), indicating a strong promotion of dissolution by pressure increase; in the high-pressure interval (>4000 m), the adsorption continues to increase but with a decreasing rate, reflecting that temperature-induced desorption gradually offsets the promoting effect of pressure. In addition, the diffusion coefficient shows a stratified trend: elevated temperature in shallow zones promotes CO₂ molecular migration, whereas high pressure in deep zones significantly suppresses diffusion, with a relatively small overall variation. Comprehensive analysis suggests that the depth interval of 1000~4000 m is the most suitable range for CO₂ geological storage, as it ensures both high dissolution efficiency and long-term stability. This study elucidates the microscopic mechanisms of CO₂ dissolution and diffusion in formation water under complex temperature–pressure conditions, deepens the understanding of CO₂ fluid occurrence and migration in deep geological environments, and provides scientific guidance for evaluating storage potential, selecting suitable storage sites, and designing injection strategies, offering valuable references for CCUS engineering practice.

Shale gas in southern China is found to contain economically valuable helium (He), which is inconsistent with conventional perspective that hydrocarbon gases in shale would dilute He to sub-economic levels. The adsorption of gases in the nanopores of organic matter is considered a crucial factor influencing the shale gas composition. The adsorption behaviors of He, methane (CH₄) and their mixtures in kerogen nanopores were performed by the Grand Canonical Monte Carlo simulation. The molecular simulations of pure He reveal that He can be adsorbed in shale and the adsorption capacity of He increases with the burial depth of shale. Before the hydrocarbon generation from kerogen, He has been continually generated in shale, the simulations further demonstrate that pure He can be partially preserved in shale as adsorbed gas phase. The simulations of competitive adsorption between CH₄ and He show that the adsorption selectivity of CH₄/He is consistently higher than 1.0 under the simulated conditions. This indicates that the previously adsorbed He will be displaced by CH₄ and subsequently concentrated in hydrocarbon gas as free gas phase during the process of hydrocarbon gas generation from kerogen. After the termination of hydrocarbon gas generation, He continues to be generated in shale and preferentially concentrated in free shale gas. Therefore, the concentration of He in shale gas will gradually increase with the generation time of He. In addition, our simulations indicate that high pressure and deep burial depth can enhance the adsorption of He in kerogen, suggesting that deeply buried organic-rich shale probably retains more adsorbed helium. Molecular simulations of He adsorption provide new insights into the accumulation process of He in shale gas and are of great significance for assessing helium resource potential in shale gas.