Cryogenic LN₂ fracturing is one of the environmentally friendly waterless fracturing technologies that promote the fracture complexity of shale gas reservoir. The water-ice phase transition under freezing condition causes frost heave in saturated shale. The effect of moisture in shale should be taken into account during cryogenic damage process. Therefore, the differences of cracking characteristics between dry and saturated shales were studied in this paper. A laboratory triaxial and high temperature fracturing system was developed for nitrogen fracturing dry and saturated shale after LN₂ injection. The influence of moisture on breakdown pressure was studied under different confining pressures (3MPa, 6MPa, 9MPa, and 12MPa) and bedding directions (parallel bedding and vertical bedding). The experimental results demonstrated that when the confining pressure increased from 3MPa to 12MPa, the breakdown pressure of dry parallel bedding after LN₂ preconditioning decreased 7.12MPa, 6.06MPa, 4.58MPa, and 3.11MPa, respectively. Therefore, LN₂ preconditioning could damage shale resulting in a lower breakdown pressure, but the effect of cryogenic damage decreased with the confining pressure increasing. The moisture in shale had little impact on nitrogen fracturing without LN₂ injection because the breakdown pressure difference between dry and saturated shales was small. However, the breakdown pressure of saturated shale after LN₂ preconditioning was always lower than that of dry shale. The breakdown pressure of saturated parallel bedding shale after LN₂ injection decreased 8.62MPa, 7.67MPa, 6.08MPa, and 4.63MPa, respectively, with the confining pressure increasing from 3MPa to 12MPa. The breakdown pressure difference between dry and saturated shales was impacted by the migration of unfrozen water and frost heave. In addition, the extent of cryogenic damage varied substantially between different bedding directions. When the confining pressure was 3MPa, the breakdown pressure of saturated parallel bedding shale reduced by 69.18 after LN₂ preconditioning, but that of saturated vertical bedding shale only decreased by 22.49. The tensile strength of shale had a greater influence on the breakdown pressure. According to the Brazilian disc test results, the tensile strength of matrix was much higher than that of bedding planes. As a result, it is useful to wet the shale in order to reduce the breakdown pressure. The fracturing direction of horizontal drilling should be consistent with the bedding direction for better cryogenic fracturing effect.

The fracturing process of sandstone is inherently complex due to its loose internal structure and deformation adaptability. Liquid nitrogen pre-injection has emerged as a promising approach to damage reservoir rocks, effectively reducing fracture pressure and establishing intricate fracture networks, thus offering a potential solution for reservoir reconstruction. To unravel the fundamental mechanisms governing sandstone fracturing behaviors following liquid nitrogen pre-injection, sandstone fracturing experiments were conducted under varying durations of liquid nitrogen injection, rock temperature, and in-situ stress conditions. The experiments showcased the evolution of injection pressure and fracture characteristics under different testing conditions, complemented by electron microscope analysis to elucidate the factors driving the complex fracture characteristics of sandstone. The findings revealed a significant decrease in fracture pressure after liquid nitrogen pre-injection, accompanied by a notable increase in the complexity of the fracture network and the roughness of the fracture surface. Moreover, prolonging the duration of liquid nitrogen injection and elevating reservoir temperature further contributed to reducing fracture pressure, consequently enhancing fracture complexity and surface roughness. Conversely, the application of confining pressure amplified fracture pressure while intensifying the degree of fracturing. Notably, the investigation highlighted the increased presence of microcracks in sandstone resulting from liquid nitrogen pre-injection, facilitating fluid diffusion during fracturing and yielding lower fracture pressures, thereby enhancing the effectiveness of sandstone reservoir reformation. The research results can provide theoretical guidance for geothermal reservoir reconstruction.

It is of great significance for the sustainable development of global energy to develop hot dry rock (HDR) geothermal resources by using enhanced geothermal system (EGS) technology. Different working fluids in EGS have different heat recovery efficiencies. Therefore, this paper takes water and CO₂ as the heat-carrying media and establishes a thermal hydraulic mechanical coupling model to simulate the heat recovery process in high-temperature rock mass. By considering the different confining pressures, rock temperature, and injection pressure, the advantages of H₂O-EGS and CO₂-EGS are obtained. The results show that with the increase of confining pressure, the heat recovery efficiency of water is significantly higher than that of CO₂, but at higher reservoir temperature, CO₂ has more advantages as a heat-carrying medium. The net heat extraction rate will increase with the increase of injection pressure, which indicates that the mass flow rate plays a leading role in the heat recovery process and increases the injection pressure of fluid which is more conducive to the thermal recovery of EGS. This study will provide a technical guidance for thermal energy exploitation of hot dry rock under different geological conditions.