Tight oil reservoirs are characterized by low porosity, low permeability, and low saturation, making it difficult to achieve economic development through conventional water injection. This study experimentally evaluated different injection media and oil displacement methods and used nuclear magnetic resonance methods to explain the micro mechanisms of oil displacement during different oil displacement processes. The experiments showed that supercritical CO₂ flooding and supercritical CO₂ and active water alternating flooding were much more useful for low-permeability reservoirs compared with conventional water flooding. This technology can increase the recovery rate by more than 12.0%, which is 33.24% higher than the rate achieved with conventional water injection. In addition, it can effectively improve the rapid increase in water content caused by the rapid advance in the water front during the water injection process. The NMR results indicated good consistency for the recovery efficiency of pores under different oil displacement conditions. When the aperture varied between 0.1 µm and 1 µm (type III), the utilization rate was highest, followed by type IV (1–10 µm), type II (0.01–0.1 µm), and type I (0.001–0.01 µm). By comparison, conventional water and CO₂ alternating flooding was more effective for type III pores, increasing oil recovery by 12.58%, while active water + CO₂ alternating flooding can further drive oil, increasing oil recovery by 33.24% and greatly displacing oil in micro-pores and macro-pores.

Hydraulic fracturing technology served as the primary method for efficiently developing deep shale resources. During hydraulic fracturing, the thermal stress caused by the injection of fracturing fluid which has low temperature had significantly effected on the propagation of multiple hydraulic fractures in deep shale reservoirs. Due to the unclear mechanisms governing multi-fracture propagation in deep shale reservoirs, this study proposed a hydraulic fracturing model for multi-fracture propagation based on the principles of linear elastic fracture mechanics. The model was employed to investigate how formation properties and operational parameters influenced the expansion of multiple hydraulic fractures. The findings revealed that thermal stress fracturing caused by low-temperature fluid injection significantly affected the rock breakdown pressure and fracture initiation timing. Specifically, when the reservoir temperature exceeded 180°C, the breakdown pressure decreased substantially, and the fracture initiation occurred much earlier. Moreover, an increase in rock thermal conductivity further reduced both the breakdown pressure and the propagation pressure, alleviating the "stress shadow" effect on intermediate fractures and promoting more uniform fracture growth. Furthermore, when the reservoir temperature surpassed 180°C and the thermal conductivity exceeded 1.3 W/(m·K), the influence of horizontal stress difference and cluster spacing on multi-fracture propagation diminished sharply—by more than 40%. This condition facilitated tight containment of the deep shale reservoir and significantly expanded the stimulated reservoir volume. These findings not only enriched and refined the theoretical understanding of hydraulic fracturing in deep shale reservoirs but also provided a valuable reference for optimizing fracturing parameters in the development of deep oil and gas reservoirs.

Hydraulic fracturing technology serves as the primary method for efficiently developing deep shale resources. During hydraulic fracturing, the thermal stress caused by the injection of fracturing fluid, which has low temperature, has a significant effect on the propagation of multiple hydraulic fractures in deep shale reservoirs. Due to the unclear mechanisms governing multi-fracture propagation in deep shale reservoirs, this study proposed a hydraulic fracturing model for multi-fracture propagation based on the principles of linear elastic fracture mechanics. The model was employed to investigate how formation properties and operational parameters influenced the expansion of multiple hydraulic fractures. The findings revealed that thermal stress fracturing caused by low-temperature fluid injection significantly affected the rock breakdown pressure and fracture initiation timing. Specifically, when the reservoir temperature exceeded 180 °C, the breakdown pressure decreased substantially, and the fracture initiation occurred much earlier. Moreover, an increase in rock thermal conductivity further reduced both the breakdown pressure and the propagation pressure, alleviating the “stress shadow” effect on intermediate fractures and promoting more uniform fracture growth. Furthermore, when the reservoir temperature surpassed 180 °C and the thermal conductivity exceeded 1.3 W/(m K), the influence of horizontal stress difference and cluster spacing on multi-fracture propagation diminished sharply—by more than 40%. This condition facilitated tight containment of the deep shale reservoir and significantly expanded the stimulated reservoir volume. These findings not only enriched and refined the theoretical understanding of hydraulic fracturing in deep shale reservoirs but also provided a valuable reference for optimizing fracturing parameters in the development of deep oil and gas reservoirs.