Organic-rich shales present significant potential for underground hydrogen storage, yet our understanding of the interactions of H₂ with CH₄ and CO₂ in kerogen-hosted nanopores remain insufficient. This study constructs and validates macromolecular models of high-maturity and overmature kerogens via combining solid-state carbon-13 nuclear magnetic resonance spectroscopy, Fourier-transform infrared spectroscopy, and X-ray photoelectron spectroscopy. Grand canonical Monte Carlo and molecular dynamics simulations are performed, which reveal that kerogen maturity controls the competitive adsorption and diffusion of methane/hydrogen and carbon dioxide/hydrogen mixtures by regulating nanopore structure and surface chemical heterogeneity. Compared with high-maturity kerogen, overmature kerogen shows stronger confinement and a more pronounced near-surface enrichment of CH₄ and especially CO₂, which reduces the effective storage space available for H₂. Mechanistically, CH₄/H₂ competition is driven by van der Waals interactions, whereas CO₂/H₂ competition is dominated by stronger electrostatic and inductive interactions, establishing a thermodynamic affinity order. The radial distribution functions and interaction energies are measured, which confirm that CH₄ and CO₂ monopolize high-energy surface sites, relegating H₂ to a weakly adsorbed, bulk-like state. Although H₂ exhibits the weakest adsorption affinity, its high mobility suggests a stronger migration tendency and potential leakage risk, which should be considered when evaluating long-term containment security during underground hydrogen storage. Overall, this study reveals that maturity-controlled coupling exists between kerogen structure, competitive adsorption and gas transport, providing molecular-scale insights into hydrogen storage security, injectivity, leakage risk, and recovery in organic-rich shale reservoirs.

Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs. In this study, the injected hydraulic fracturing fluid (HFF) and flowback and produced water (FPW) in tight oil reservoirs of the Lucaogou Formation in the Junggar Basin are temporally sampled from day 1 to day 64. Freshwater is used for fracturing, and HFF is obtained. The chemical and isotopic parameters (including the water type, total salinity, total dissolved solids (TDS), pH, concentrations of Na⁺, Cl⁻, Ba⁺, K⁺, Fe²⁺ + Fe³⁺, and CO₃²⁻, δD, and δ¹⁸O) are experimentally obtained, and their variations with time are systematically analyzed based on the flowback water. The results show that the water type, Na/Cl ratio, total salinity, and TDS of the FPW change periodically primarily due to the HFF mixing with formation water, thus causing δD and δ¹⁸O to deviate from the meteoric water line of Xinjiang. Because of water–rock interaction (WRI), the concentrations of Fe²⁺ + Fe³⁺ and CO₃²⁻ of the FPW increase over time, with the solution pH becoming more alkaline. Furthermore, based on the significant changes observed in the geochemistry of the FPW, three separate time intervals of flowback time are identified: Stage Ⅰ (< 10 days), where the FPW is dominated by the HFF and the changes in ions and isotopes are mainly caused by the WRI; Stage Ⅱ (10–37 days), where the FPW is dominated by the addition of formation water to the HFF and the WRI is weakened; and finally, Stage Ⅲ (> 37 days), where the FPW is dominated by the chemistry of the formation water. The methodology implemented in this study can provide critical support for the source identification of formation water.