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.

Calcites, brittle minerals that are extensively distributed in shales, hold great significance for indicating shale oil and gas occurrence, reservoir stimulation, and sedimentary environments. In recent years, increasing studies have been conducted on the types, genetic mechanisms, and geological significance of calcites in shales. However, systematic reviews on these topics remain limited. In this study, calcites in shales are categorized into two types initially: micritic calcites (including dispersed granular, nodular, and lamellar calcites, calcite cements, and biogenic calcites) and sparry calcites (including fibrous, bladed, and equiaxed calcites). The subsequent results indicate that the formation of calcite veins is jointly driven by fluid overpressure, tectonic stress, and crystallization forces. The formation process is affected by microbial reduction in the early stage, relates to the decarboxylation of organic matter in the middle stage, and is associated with the methane thermochemical oxidation-related fluid activity in the late stage. During the thermal evolution of calcite veins, dissolution windows and retrograde dissolution also occur. Calcites in lacustrine and marine shales generally share similar formation mechanisms, with differences attributed primarily to sedimentary environments. The high degree of enrichment of micritic calcites, the combination of shales and bioclastic layers, and calcite inclusions all provide valuable indications for the reconstruction of paleosedimentary and diagenetic environments. Regarding shale brittleness, calcites both enhance the shales' brittleness index and promote the propagation of hydraulically stimulated fracture networks as brittle minerals. However, their cementation reduces reservoir porosity, creating dual effects on reservoir stimulation. Additionally, calcite veins preserve records of the hydrocarbon migration process, while their dissolution pores and bedding-parallel fractures offer important reservoir spaces for shale oil and gas. Nevertheless, the genetic mechanisms of calcites in ancient, highly evolved shales and their coupling relationship with the hydrocarbon generation process of organic matter remain poorly understood. Furthermore, the accuracy of U-Pb dating techniques for calcites in shales is yet to be substantially improved, and further improvements in the precision of relevant detection techniques are required to further reveal the complex formation process of the calcites. Advancements in these areas will provide more improved theories for the sweet spot prediction and efficient exploitation of oil and gas from calcite-rich shales.

The successful drilling of well Shendi Take-1 has opened a new era in the petroleum industry, marking the beginning of 10000-meter deep hydrocarbon exploration. Consequently, investigating the hydrocarbon exploration depth to its limits and the boundaries for hydrocarbon occurrence has become a hot topic in the geological community. In this study, we present a systematic summary of the discoveries and geological theory of hydrocarbon exploration at a depth of 10000 m. The hydrocarbon generation potential of the Nanhua, Ediacaran, and Cambrian source rocks is quantitatively assessed. It is demonstrated that the depth threshold for preserving liquid oil extends up to 9000 m in basins with low geothermal gradients, thereby enhancing the potential for ultra-deep oil exploration. Mechanisms responsible for the preservation of large-scale oil reservoirs formed 250 million years ago are identified, supporting the exploration of ultra-deep ancient hydrocarbon reservoirs. Furthermore, it is proposed that carbonate reservoirs exhibit no definitive lower depth limit. Additionally, a new type of fractured-vuggy oil reservoirs, formed by complex seepage processes and characterized by multiple oil-water interfaces, is identified. This discovery reveals the mechanisms by which secondary geochemical processes modify the properties and phases of hydrocarbons. Ultra-high oil and gas columns are discovered in ultra-deep reservoirs, revealing the enrichment and distribution patterns of hydrocarbons in high-yield and high-efficiency wells. These findings provide theoretical support for achieving major hydrocarbon discoveries in ultra-deep reservoirs and for reshaping hydrocarbon exploration strategies. Furthermore, they also open the new frontier of hydrocarbon exploration at a depth of 10000 m, marking a new era for the petroleum industry. Additionally, we analyze major challenges in the geological theory of hydrocarbon exploration at such a depth, propose the concept of limit hydrocarbon exploration depth, and examine the boundaries for hydrocarbon occurrence. It is therefore essential to accelerate efforts to bridge the knowledge gap created by the high temperature and high pressure conditions in the Earth's interior, thereby enabling free hydrocarbon exploration within the limit depth range. Such progress will help position hydrocarbon resources in 10000-m-deep plays as a vital component in safeguarding China's energy security.

Multiple sets of marine shale sequences occur in western Hubei Province and its adjacent areas within the Middle-Upper Yangtze region, offering substantial resource potential. However, their shale gas preservation conditions differ significantly due to the heterogeneous porosity and fracture system resulting from multistage tectonic reworking. This necessitates developing region-specific evaluation systems and exploitation techniques. Drawing on previous application cases and guided by the research paradigm of geology-engineering integration, this study presents key technologies potentially applicable to shales in western Hubei Province, spanning from reservoir and sweet spot evaluation to fracturing scheme design and fracturing performance monitoring. Several insights are gained accordingly. In terms of pore evaluation, the pore heterogeneity caused by compaction and rebound can be quantified using ideal shape coefficients and fractal dimensions, both of which are influenced by structural deformations, thereby guiding reservoir classification. For seismic data interpretation, pre-stack elastic inversion and azimuthal anisotropy inversion can be employed as core techniques, overcoming the limitation of individual post-stack attributes in typically detecting only major faults. Furthermore, the inversion boundaries are constrained using log-seismic joint quality control and geomechanical simulation, contributing to enhanced reliability of sweet spot evaluation and efficient exploration in areas with complex structures. For fracturing scheme design, scientifically formulated well shut-in strategies, tailored to regional geological characteristics, are essential to activate the fracture-matrix imbibition effect. Parameters with vastly different scales used in the design, such as meter-scale fracture half-length and millidarcy-scale fracture conductivity, can be co-optimized using artificial intelligence (AI) algorithms such as the genetic algorithm (GA) and the simultaneous perturbation stochastic approximation (SPSA) algorithm. Dynamic monitoring of fracturing performance can be achieved using trace chemical tracer technology, thereby reducing target ambiguity caused by structural complexity. Research on shale gas in the structurally complex areas of western Hubei faces multiple challenges, spanning from basic geological understanding to development engineering. These challenges create an urgent need for deep interdisciplinary collaboration. Therefore, this study highlights research into geology-engineering integration, aiming to enhance the efficiency of shale gas exploration and development in western Hubei.