Managed pressure density reduction is the key step of managed pressure cementing (MPC) technology, which is of great significance to ensure the safety of cementing construction. Managed pressure density reduction process can be divided into primary density reduction process and segmental density reduction process. In the field application, the segmental density reduction process is more applicable and in higher demand, so how to accurately predict the pressure field of the wellbore in the process of segmental density reduction has become the key of this technology. Combined with the segmented density reduction process which is“first down, then down, then down again”, the Lagrangian method was used to deduce the descriptive equation for the structure of the annular slurry column. Experiments on the rheology of drilling fluid at high temperature (220 ℃) and high pressure (180 MPa) were carried out. It was found that when the temperature was less than 140 ℃, the temperature had a significant effect on the rheology; when the temperature was greater than 140 ℃, the temperature had a smaller effect on the rheology.In this regard, considering the mutual influence of temperature, pressure and rheology, a prediction model of temperature and pressure field in the wellbore during the whole process of segmented density reduction was established. The model was validated using the measured wellhead pressure, and the maximum relative error was less than 3.6%. Compared with the traditional model, the model in this paper makes up for the lack of its process applicability and has higher prediction accuracy. Based on the well X data, the key parameters of the two segmented density reduction processes are predicted, and the results show that: the distribution of fluid type in the annulus is affected by the initial slurry column structure, displacement and other factors, and the time required for the three density reduction operations is 5.24 h, 5.12 h and 4.78 h, respectively; the wellbore temperature field is significantly affected by the working conditions, and the maximal difference in the annulus temperature at the same location under different working conditions is 35.1 ℃; the time required for the three density reduction processes is more 1.42 h, but in the first density reduction process, the bottomhole pressure is lower, so it is not easy to leak the formation; using the model in this paper to design the wellhead back pressure, the bottom hole pressure can be guaranteed within the safe range. The results of the study can provide theoretical support for accurate prediction and fine control of wellbore pressure during the MPC segmental density reduction stage.

Ultra-deep and complex formations are characterized by narrow safety density windows and challenging well control. The combined use of multiple well-killing methods or temporary adjustments to well-killing strategies is becoming common. However, conventional well-killing models often struggle to calculate the parameters required for these special cases. In this paper, a boundary matrix for well-killing fluid density and volume is proposed to unify the driller’s method, the engineer’s method, and the weight-while-circulating method. Furthermore, a dynamic unified well-killing model is developed to enable the synergistic regulation of multiple well-killing methods. The model also can be applied with or without accounting for gas dissolution. Using this model, it is able to dynamically track key parameters during well killing and shut in the well at any time to determine the standpipe and casing pressures. The results indicate that the casing pressure drops to zero before the well-killing fluid returns to the annulus wellhead, and continued injection of the fluid leads to a gradual increase in standpipe pressure, a phenomenon not previously accounted for. The discrepancy between the actual and calculated standpipe/casing pressures after shut-in can be utilized to assess whether the downhole gas kick is effectively controlled. Through real-time adjustments to the boundary matrix, updated well-killing parameters can be derived for conventional method, multi-method combination, temporary strategy modification, and other well-killing scenarios. The model was applied to two field wells under water- and oil-based drilling fluids. No secondary downhole complications occurred during well killing, and the calculated pressure curves closely matched the measured construction pressure curves, confirming the model’s reliability and applicability. This study provides valuable theoretical guidance for enhancing well control safety in ultra-deep and complex formations.

The multiphase flow characteristic is one of the most concerning problems during solid fluidization exploitation of marine natural gas hydrate reservoirs. In this research, a new transient gas–liquid–solid multiphase flow model with hydrate phase transition was developed. Meanwhile, this model considered the coupling relationship among convective heat transfer, hydrate dynamic decomposition, and multiphase flow. The model can simulate the change of flow pattern from solid−liquid to gas–liquid–solid flow, and describe the distribution character of volume fraction of phase, wellbore temperature and pressure, and hydrate decomposition rate during transportation. The simulation results indicate that the hydrate decomposition region in the wellbore gradually expands, but the hydrate decomposition rate gradually decreases during the solid fluidization exploitation of hydrate. When mining time lasts for 4 h, and the bottom hole pressure decreases by about 0.4 MPa. Increasing NaCl concentration in seawater helps expand hydrate decomposition regions and improves the wellbore hydrate decomposition rate. When the NaCl mass fraction in seawater reaches 15%, it will raise the hydrate decomposition regions to the whole wellbore. In addition, the higher the wellhead backpressure, the lower the decomposition area and decomposition rate of hydrate in the wellbore. When wellhead backpressure reaches 2 MPa, the volume fraction of gas near the wellhead will reduce to about 12%. This work is expected to provide a theoretical basis for the development of marine hydrate reservoirs.