The bottom hole fluctuating pressure has a large influence on the wellbore instability. To address this problem, firstly, according to the principle of seepage mechanics, we established a calculation model of the change in pore pressure around the wellbore radius under fluctuating pressure; then, through laboratory rock mechanics test and rock damage mechanics theory analysis, the change law of formation strength under the action of static hydration and dynamic damage are determined; finally, based on the theory of rock mechanics in porous media, a quantitative evaluation method for the risk of wellbore instability under fluctuating pressure is established and the changing pattern of wellbore instability risk is analyzed. The results show that the pore pressure around the well shows a trend of fluctuation increase under fluctuating pressure, and there is a certain lag in the fluctuation of pore pressure inside the formation; the longer the muddy shale is immersed in drilling fluid, the greater the reduction in strength; the reduction is greater in the early stage of immersion, and the reduction in strength in water-based drilling fluid is greater than that in oil-based drilling fluid. At the beginning of the pressure cycle, the formation damage variable and compressive strength gradually increase and decrease with the increase of the pressure cycle number; after several cycles, the magnitude of change gradually decreases with the increase of the cycle number. When the bottom hole pressure fluctuates at a certain period, the greater the fluctuation, the shorter the period of wellbore stability; when the bottom hole pressure fluctuates at a certain range, the smaller the fluctuation period, the faster the borehole enters the high-risk period, while the shortest period of wellbore stability occurs when the fluctuation period is smallest; and when the wave cycle is in the middle, the wellbore stability period is the longest.

The borehole wall stability of depleted reservoirs is a key problem that restricts the deeper potential exploitation of old oilfields. Based on these, according to the seepage and elastic mechanics theory of porous media, combined with laboratory rock mechanics experiments, the dynamic evaluation model of geomechanical parameters of the old reservoir is established, and on this basis, the evaluation method of wellbore stability of new wells in the old reservoir is established, and the changing laws and influencing factors of the wellbore stability of the old reservoir are quantitatively evaluated. The research shows that reservoir pressure, reservoir porosity, effective stress coefficient, strength, in situ magnitude, and direction were all changed due to long-term exploitation; both collapse and fracture pressure decreased, the loss risk of drilling fluid was increased, and safe drilling azimuth was changed. The results can guide reasonable choices such as well position, track and mud density, and strengthening sealing while drilling in order to ensure wellbore stability effectively.

The intersection behavior of hydraulic fractures and single natural fractures has been studied in detail; however, in fractured reservoirs, natural fractures are numerous and interlaced and the intersection of hydraulic fractures and multiple natural fractures occurs during the fracturing process. This intersection behavior is more complex and there is a lack of research on this topic at present. In this study, a numerical simulation model of the interaction between hydraulic fractures and a series of natural fractures was established, the main factors that affect the formation scale of a fracture network during the hydraulic fracturing of a fractured reservoir were studied using the numerical simulation method, and the parameters were also studied. The results showed that the natural fracture trend, in situ stress difference, and injection flow rate have an impact on the scale of a fracture network. The larger the in situ stress difference, the smaller the scale of the fracture network, which gradually changes from multiple clusters of fractures to single fractures. The larger the injection flow rate, the larger the scale of the fracture network. In the uniform stress field, the direction of a natural fracture is closer to the direction of principal stress, so the lower the fracture extension pressure, the smaller the scale of the network. On the contrary, the farther away from the principal stress direction, the lower the fracture extension pressure and the higher the extension pressure, the larger the scale of the fracture network.