Most hilly areas are dotted with gullies, some of which contain plenty of water, especially in rainy seasons. Once surface water penetrates the underground working face, it will lead to an increased water inflow of the working face. Even worse, it may induce water and sand burst accidents. To prevent geological disasters such as water and sand burst and ensure the safe production in coal mines, it is necessary to reveal the development law of “two zones” in the overburden caused by shallow-seam fully mechanized top coal caving high-intensity mining in hilly areas with exposed bedrock and timely grasp the communication between the water-flowing fractured zone (WFFZ) and the water in surface gullies. In this study, the working face P2 of the exposed bedrock surface in the Coal Mine DN is taken as the research object. First, the characteristics of overburden movement and the law of exposed bedrock surface movement in areas with exposed bedrock were investigated through similar simulation. Meanwhile, the temporal–spatial evolution of overburden movement caused by shallow-seam fully mechanized top coal caving high-intensity mining was clarified, and the mode of overburden movement was revealed. Moreover, the reason why the water inflow of the underground working face increases suddenly was theoretically explained. The following conclusions were drawn: Under shallow-seam fully mechanized top coal caving high-intensity mining, the WFFZ of the working face P2 is directly connected to the exposed bedrock surface, and the movement of the overburden is subject to the typical “two-zone” mode. The development height of the WFFZ is greater than the value in the traditional “three-zone” mode calculated according to the empirical formulas. The ratio of the WFFZ height to the mining thickness is 43.75. Under the “two-zone” mode, a water-flowing channel exists in the overburden near the open-off cut and the stopping line. When the surface water source is in the right position, the water inflow of the underground working face will increase suddenly.

It is difficult to exploit low-permeability reservoirs, and CO₂ flooding is an effective method to improve oil recovery from low permeability reservoirs. However, in the process of CO₂ flooding, acidic fluids dissolved in formation water will react with rock to cause dissolution and precipitation, resulting in pores and precipitates, changing the evolution law of seepage channels, destroying formation integrity, and affecting the effect of CO₂ oil displacement. The change in rock’s physical properties and the mass transfer law between CO₂-water-rock are unclear. This paper considers the coupling effects of seepage, mechanics, and chemistry when CO₂ is injected into the formation. The mass transfer model of CO₂-water-rock in the geochemical reaction process is established on this basis. The physical properties of the reservoir after CO₂ injection are quantitatively studied based on the microscopic mechanism of chemical reaction, and the migration law of solute in the reservoir rock during CO₂ flooding under the coupling effects of multiple fields is clarified. The experimental results show that with the increase in reaction time, the initial dissolution reaction of formation rocks will be transformed into a precipitation reaction of calcite, magnesite, and clay minerals. The porosity and permeability of the rocks near the well first increase and then decrease. The far well end is still dominated by dissolution reactions, and the average values of formation porosity and permeability show an upward trend. Although the dissolution reaction of CO₂-water-rock can improve the physical properties of reservoir rocks to a certain extent, the mutual transformation of the dissolution reaction and precipitation reaction further exacerbates the heterogeneity of formation pore structure, leading to the instability of CO₂ migration, uneven displacement, and destruction of formation stability. The research results of this paper solve the problem of quantitative calculation of physical parameters under the coupling effect of multiple fields after CO₂ injection into reservoirs and can predict the changes in formation physical properties, which can provide a certain theoretical basis for evaluating formation integrity and adjusting CO₂ injection under the condition of CO₂ flooding.

Large-scale staged hydraulic fracturing stimulation technology is an effective method to increase shale oil and gas recovery. However, cracks will appear along with the cementing interface and expand under the drive of fluid while hydraulic fracturing, failing wellbore sealing. To solve this problem, the synchronous propagation model of hydraulic fractures and cementing interfacial cracks in hydraulic fracturing is established. The Newton iteration method and displacement discontinuity method are used to solve the propagation length of each fracture, and the effects of cement sheath parameters and fracture parameters on the interface failure range are studied. The results show that when multiple hydraulic fractures expand, the interfacial cracks are also affected by “stress shadow,” offering an asymmetric expansion, and the cementing interfacial cracks in the area between hydraulic fractures are easier to expand. The failure range of interface between the hydraulic fractures expands rapidly if the cement elastic modulus increases from 5 GPa to 10 GPa; while the cement elastic modulus is higher than 10 GPa, the failure area is mainly affected by the number of hydraulic fractures; the failure range is not affected by the number of hydraulic fractures if the hydraulic fracture spacing is less than 10 m or more than 30 m; while the crack spacing is between 10 m and 30 m, the more the number of hydraulic fractures, the easier it is to cause the interface failure range to increase and connect. The research results can provide a theoretical basis for the optimization of cement slurry systems and fracturing parameters.