Predictive modeling of wellbore pressure during the managed pressure cementing segmented density reduction step
LIU Jinlu, LI Jun, LIU Gonghui, LI Ning, ZHANG Quan, ZHOU Bao, SUN Hongyu
1 Petrochina Tarim Oilfield company, Korla 841000, China 2 College of Petroleum Engineering, China University of Petroleum-Beijing, Beijing 102249, China 3 R&D Center for Ultra Deep Complex Reservior Exploration and Development, CNPC, Korla 841000, China 4 Engineering Research Center for Ultra-deep Complex Reservoir Exploration and Development, Xinjiang Uygur Autonomous Region, Korla 841000, China 5 Xinjiang Key Laboratory of Ultra-deep Oil and Gas, Korla 841000, China
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.
