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.

Water-based fracturing fluid has recently garnered increasing attention as an alternative oilfield working fluid for propagating reservoir fractures and transporting sand. However, the low temperature resistance and stability of water-based fracturing fluid is a significant limitation, restricting the fracture propagation and gravel transport. To effectively ameliorate the temperature resistance and sand-carrying capacity, a modified cross-linker with properties adaptable to varying reservoir conditions and functional groups was synthesized and chemically characterized. Meanwhile, a multifunctional collaborative progressive evaluation device was developed to investigate the rheology and sand-carrying capacity of fracturing fluid. Utilizing molecular dynamics simulations, the thickening mechanism of the modified cross-linker and the sand-carrying mechanism of the fracturing fluid were elucidated. Results indicate that the designed cross-linker provided a high viscosity stability of 130 mPa·s and an excellent sand-carrying capacity of 15 cm² at 0.3 wt% cross-linker content. Additionally, increasing reservoir pressure exhibited enhanced thickening and sand-carrying capacities. However, a significant inverse relationship was observed between reservoir temperature and sand-carrying capacity, attributed to changes in the drag coefficient and thickener adsorption. These results verified the effectiveness of the cross-linker in enhancing fluid viscosity and sand-carrying capacity as a modified cross-linker for water-based fracturing fluid.

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.

To mitigate the influence of wellbore heat transfer on the physicochemical properties of water-based fracturing fluids in the high-temperature environments of low-permeability shale reservoirs, this study investigates the fluid filtration behavior of water-based fracturing fluids within the wellbore under such reservoir conditions. A wellbore heat-transfer model based on solid–liquid coupling was constructed in order to analyse the effects of different reservoir and wellbore factors on fluid properties (viscosity and filtration volume) in the water-based fracturing fluids. Concurrently, boundary conditions and control equations were established for the numerical model, thereby delineating the heat-transfer conditions extant between the water-based fracturing fluid and the wellbore. Furthermore, molecular dynamics theory and microgrid theory were utilised to elucidate the mechanisms of the alterations of the fluid properties of the water-based fracturing fluids due to wellbore heat transfer in low-permeability shale reservoirs. The findings demonstrated that wellbore heat transfer in low-permeability shale reservoirs exerts a pronounced influence on the fluid viscosity and filtration volume of the water-based fracturing fluids. Parameters such as wellbore wall thickness, heat-transfer coefficient, radius, and pressure differential introduce distinct variation trends in these fluid properties. At the microscopic scale, the disruption of intermolecular hydrogen bonds and the consequent increase in free molecular content induced by thermal effects are the fundamental mechanisms driving the observed changes in viscosity and fluid filtration. These findings may offer theoretical guidance for improving the thermal stability of water-based fracturing fluids under wellbore heat-transfer conditions.

Some drawbacks of the hydraulic fracturing technology included the water pollution and reservoir destruction, hindered its development and application in shale reservoirs. CO₂ fracturing fluid is considered to be an excellent substitution to conduct the fracturing operation because of its cheapest, enhance gas production and environment friendly. However, the low viscosity and high filtration property of pure CO₂ are viewed as a huge challenge to develop CO₂ fracturing technology. In this paper, we synthesize a modified silicone as a CO₂ thickener to investigate the effect of different thickener parameters, temperature, and pressure on the CO₂ filtration property in low permeability reservoirs. This is a working theory which is based on the organic synthesis and unconventional oil and gas exploration. We carry out several studies which have demonstrated that the CO₂ filtration coefficient deceased as an increase of CO₂ thickener and carbonyl group content, molecular weight, and pressure. When the temperature rises, an increasing filtration coefficient of liquid CO₂ was presented. Physical parameters of thickener display a significant impact on CO₂ filtration coefficient. A thickener with a reasonable chemical structure significantly was not only improving the CO₂ viscosity but also the filtration coefficient has. It was also found that fracturing fluid viscosity is the ultimate factor that changes the CO₂ filtration property.