To circumvent the numerous deficiencies inherent to water-based fracturing fluids and the associated greenhouse effect, CO₂ fracturing fluids are employed as a novel reservoir working fluid for reservoir reconstruction in unconventional oil fields. Herein, a mathematical model of CO₂ fracturing crack propagation based on seepage–stress–damage coupling was constructed for analysing the effects of different drilling fluid components and reservoir parameters on the crack propagation behaviour of low permeability reservoirs. Additionally, the fracture expansion mechanism of CO₂ fracturing fluid on low permeability reservoirs was elucidated through mechanical and chemical analysis. The findings demonstrated that CO₂ fracturing fluid can effectively facilitate the expansion of cracks in low-permeability reservoirs, and thickener content, reservoir pressure, and reservoir parameters were identified as influencing factors in the expansion of reservoir cracks and the evolution of rock damage. The 5% CO₂ thickener can increase the apparent viscosity and fracture length of CO₂ fracturing fluid to 5.12 mPa·s and 58 m, respectively, which are significantly higher than the fluid viscosity (0.04 mPa·s) and expansion capacity (13 m) of pure CO₂ fracturing fluid. Furthermore, various other factors significantly influence the fracture expansion capacity of CO₂ fracturing fluid, thereby offering technical support for fracture propagation in low-permeability reservoirs and enhancing oil recovery.

The efficient exploitation of marine oil and gas resources holds significant potential to mitigate the current severe energy crisis. Regrettably, incidents, such as gas kick and even blowouts, can significantly impact normal development activities. The displacement kill method is one effective strategy for well control in deep-water areas. In this study, the detailed mathematical method for determining kill parameters involved in the kill operation by using the displacement kill method was proposed. Of course, this includes both cases: one where the kill fluid leaks during the kill process and another where no leakage occurs. Meanwhile, its applicability was verified through comparison with experimental results. Then, evolution characteristics of kill parameters, when killing fluid leakage occurs and when it does not occur, were analyzed. Finally, factors, such as pit gain and shut-in casing pressure, affecting the kill parameters of kill operation, were explored. It was found that the experimental and calculated results show great similarity, although there are slight differences between them. The total kill time in the simulation is 44 s shorter than that in the verification experiment. This indicates that the model established in this study is suitable for simulating the process of kill operation using the displacement kill method. In addition, the investigation results show that leakage of kill fluid increases the difficulty of the kill operation and prolongs the operation time. The number of kill cycles in the presence of kill fluid leakage is one more than that when there is no fluid leakage, resulting in an additional 70 min of total duration. Furthermore, the increase in pit gain and the rise in shut-in casing pressure can also pose challenges to the kill operations. The total kill time will be extended by 164 min when the mud pit gain increases from 20 m³ to 50 m³. The number of kill cycles rises by two when the shut-in casing pressure is increased from 5 MPa to 20 MPa. To ensure the safety of the drilling operation in abnormally high-pressure reservoirs, it is crucial to monitor parameters such as casing pressure during the drilling process and timely well control measures.

Natural gas hydrates represent a promising clean energy source with vast reserves. Their efficient development is crucial for ensuring the sustainable advancement of human society. However, wellhead instability occurred in the long-term development, which poses a significant challenge that impacts its commercial development. In the present work, the properties of hydrate-bearing sediments were experimentally investigated. It was found that the elastic modulus, cohesion, and internal friction angle of hydrate-bearing sediments exhibit an increase with the effective stress. As an example, when the effective stress increases from 0 MPa to 25 MPa, the normalized elastic modulus exhibits a rise from 1.00 to 1.36. Conversely, the Poisson’s ratio, permeability, and porosity demonstrate a decline in accordance with this trend. As an example, both normalized porosity and permeability decrease to values below 0.40 as the effective stress increases to 25 MPa. Based on the experimental results and previous work, a comprehensive model for describing the effect of both hydrate saturation and effective stress on physical parameters was obtained. Subsequently, a multi-field coupled investigation methodology was developed to evaluate wellhead stability during the long-term development of hydrate-bearing sediments, and the evolution characteristics and mechanisms of wellhead instability were numerically explored. It reveals that development operation using the vertical wellbore decomposes hydrates in the surrounding sediments only within a radius of 19.52 m, which significantly undermines the wellhead stability. Moreover, the wellhead system not only sinks with sediment subsidence but also experiences additional sinking due to the failure of bonding between the wellhead system and sediments. Furthermore, the latter accounts for a significant portion, amounting to approximately 68.15% of the total sinking under the research conditions. This study can provide methodological prerequisites for exploring the impact of various factors on wellhead stability during the long-term hydrate development process.

The fast settling rate of solid particles in the CO₂ fracturing fluid is a serious obstacle to ensuring the smooth progress of reservoir stimulation during conventional energy extraction, exerting a critical influence on enhancing both transformation efficiency and crude oil recovery. In this study, a fluid–solid coupling numerical model was developed, incorporating reservoir conditions and fluid properties, to simulate the settling behavior of solid particles in geological reservoir fluids. In addition, the effects of various geological factors and fluid parameters on particle settling were systematically examined. Furthermore, molecular dynamics theory, together with the analysis of intermolecular bonding interactions, was employed to elucidate the underlying mechanisms governing particle settling under different conditions. The findings of this study have the potential conclusion that the numerical model constructed in this study showed a high degree of fit (98.7%) with the experimental data, demonstrating the high applicability and good match of the numerical model. Furthermore, CO₂ viscosity is a significant factor influencing the differential settling of particles in reservoir fluids, and CO₂ fracturing fluid at 8 mPa·s can reduce the settling distance and velocity of solid particles to 3.2 m and 0.21 m/s, respectively. Simultaneously, both high reservoir pressure and a rough surface can effectively suppress the settling behavior of solid particles in CO₂ fracturing fluid, reducing the settling distance to 3.4 cm and 3.8 cm, respectively. However, the utilisation of high-temperature reservoirs at 383 K has been demonstrated to reduce the particle settling distance to 3.5 cm, a phenomenon that is evidently not conducive to the stimulation of deep, high-temperature reservoirs. The findings of this research endeavour have the potential to provide fundamental data for the utilisation of CO₂ fracturing fluids in reservoir stimulation and EOR.