CO₂ enhanced shale gas recovery (CO₂-ESGR) draws worldwide attentions in recent years with having significant environmental benefit of CO₂ geological storage and economic benefit of shale gas production. This paper is aimed at reviewing the state of experiment and model studies on gas adsorption, competitive adsorption of CO₂/CH₄, and displacement of CO₂-CH₄ in shale in the process of CO₂-ESGR and pointing out the related challenges and opportunities. Gas adsorption mechanism in shale, influencing factors (organic matter content, kerogen type, thermal maturity, inorganic compositions, moisture, and micro/nano-scale pore), and adsorption models are described in this work. The competitive adsorption mechanisms are qualitatively ascertained by analysis of unique molecular and supercritical properties of CO₂ and the interaction of CO₂ with shale matrix. Shale matrix shows a stronger affinity with CO₂, and thus, adsorption capacity of CO₂ is larger than that of CH₄ even with the coexistence of CO₂-CH₄ mixture. Displacement experiments of CO₂-CH₄ in shale proved that shale gas recovery is enhanced by the competitive adsorption of CO₂ to CH₄. Although the competitive adsorption mechanism is preliminary revealed, some challenges still exist. Competitive adsorption behavior is not fully understood in the coexistence of CO₂ and CH₄ components, and more experiment and model studies on adsorption of CO₂-CH₄ mixtures need to be conducted under field conditions. Coupling of competitive adsorption with displacing flow is key factor for CO₂-ESGR but not comprehensively studied. More displacement experiments of CO₂-CH₄ in shale are required for revealing the mechanism of flow and transport of gas in CO₂-ESGR.

Hydrogen is a promising clean energy source with geological reserves widely distributed globally, offering an annual flow exceeding 23 trillion grams. However, natural hydrogen extraction wells face unique safety challenges compared to conventional oil and gas wells. This paper reviews well safety concerns such as tubing/casing damage, cement/sealant failure, and excessive annular pressure buildup. Key issues include hydrogen embrittlement, microbiological corrosion, H₂-cement reaction, and H₂-rubber degradation, which can lead to mechanical failures. The review explores potential solutions like metal coatings, rubber fillers, and cement additives to mitigate these problems. It also emphasizes the need for further research to validate these solutions under real-world conditions. Addressing these challenges is crucial for the safe and efficient extraction of natural hydrogen.

The tight sandstone oil reservoirs characterized by the low porosity and permeability must be hydraulically fractured to obtain the commercial production. Nevertheless, the post-fracturing production of tight oil reservoirs is not always satisfactory. The influence mechanism of various factors on the fracture propagation in the tight oil reservoirs needs further investigation to provide an optimized fracturing plan, obtain an expected fracture morphology and increase the oil productivity. Thus, the horizontal well fracturing simulations were carried out in a large-scale true tri-axial test system with the samples from the Upper Triassic Yanchang Fm tight sandstone outcrops in Yanchang County, Shaanxi, China, and the results were compared with those of fracturing simulations of the shale outcrop in the 5th member of Xujiahe Fm (abbreviated as the Xu 5th Member) in the Sichuan Basin. The effects of the natural fracture (NF) development degree, horizontal in-situ stress conditions, fracturing treatment parameters, etc. on the hydraulic fracture (HF) propagation morphology were investigated. The results show that conventional hydraulic fracturing of the tight sandstone without NFs only produces a single double-wing primary fracture. The fracture propagation path in the shale or the tight sandstone with developed NFs is controlled by the high horizontal differential stress. The higher stress difference (<12MPa) facilitates forming the complex fracture network. It is recommended to fracture the reservoir with developed NFs by injecting the high-viscosity guar gum firstly and the low-viscosity slick water then to increase the SRV. The low-to-high variable rate fracturing method is recommended as the low injection rate facilitates the fracturing fluid filtration into the NF system, and the high injection rate increases the net pressure within the fracture. The dual-horizontal well simultaneous fracturing increases the HF density and enhances the HF complexity in the reservoir, and significantly increases the possibility of forming the complex fracture network. The fracturing pressure curves reflect the fracture propagation status. According to statistical analysis, the fracturing curves are divided into types corresponding to multi-bedding plane (BP) opening, single fracture generation, multi-fracture propagation under variable rate fracturing, and forming of the fracture network through communicating the HF with NFs. The results provide a reference for the study of the HF propagation mechanism and the fracturing design in the tight sandstone reservoirs.