When using topside choking to eliminate severe slugging in offshore pipeline–riser systems, the resulting stability and effectiveness depend critically on the choice of variables in the associated control model. In this study, both potential process variables and manipulated variables are investigated via manual choking experiments. Monotonicity and linearity are adopted as principles for selecting the optimal variables, and the availability of signals in an offshore field is also considered. Both amplitude-domain and time-domain variables are studied, of which five are recommended as the process variable, while the resistance factor of the choking valve is the optimal manipulated variable; other variables may act as auxiliary variables in the control model. How to determine the set value of the process variable is also discussed. Validation experiments with automatic control show that the optimized variables enable faster stabilization. This study offers a reference for the design of slugging control for offshore fields.

Topside choking is a common way to eliminate severe slugging flow in pipeline riser systems in offshore oil and gas fields. However, a lack of fundamentals in two-phase flow gives rise to difficulty in the model selection of valves and the effective control of the valves. In this study, the prediction of the valve opening required for slugging control based on measurable parameters is investigated experimentally and theoretically. It is found that the resistance coefficient factor of the valve is almost the same for pipeline risers and simple vertical pipes when severe slugging is eliminated. Therefore, fluid parameters can be approximated by the conditions of a simple vertical pipe. The target of control is to achieve dual-frequency fluctuation, and it is quantitatively converted to the pressure drop of the valve. Based on these two empirical enclosures, the valve opening can be worked out by using the gas fraction model and the theoretical model of valve flow resistance. The non-slip model is found to be better than the drift-flux model in the final prediction of the optimal valve opening. An explicit model for the calculation of the optimal resistance factor and the corresponding valve opening is established, making it more convenient to select the valve in the design stage of offshore oil and gas exploitation. The average absolute error of the proposed model is +0.01%, which is smaller than the simulation performed by OLGA 7.0 software (+4.91% before tuning and +0.08% after tuning). A field case with a flexible S-shape riser proves the good applicability of the model (with a deviation smaller than ±2%). The applications of the prediction model in the model selection of the valve and uncertain factors in the operation are also discussed.