Optimum tubing size prediction model for vertical multiphase flow during flow production period of oil wells

Abstract

Abstract Optimum tubing size (OTS) selection was traditionally done by using nodal analysis to perform sensitivity analysis on the different tubing sizes. This approach was found to be both cumbersome and time-consuming. This study developed a user-friendly and time-efficient OTS prediction computer model that could allow Petroleum Production Engineers to select the best tubing size for any vertical oil well. The tubing size selection was based on the present operating flow rate, economic considerations and future operating flow rate as defined by the OTS selection criteria of this study. The robustness of the model was tested using tubing sizes ranging from 0.824 to 6.0 inch in a vertical well producing from both saturated and undersaturated oil reservoirs. The 2.750-inch tubing was found the OTS for both scenarios. In the validation, the results obtained from the novel OTS prediction model and Guo et al. (Petroleum production engineering: a computer-assisted approach, Gulf Professional Publishing, Cambridge) spreadsheet program using the Poetmann–Carpenter method were in excellent agreement for operating flow rate but not for operating pressure. Furthermore, the novel OTS prediction model was in excellent agreement with the same spreadsheet program based on modified Hagedorn–Brown correlation for both operating flow rate and pressure. The results showed that the model developed in this study is reliable and can be used in the field for vertical oil wells. The new model could as well inform the Production Engineer when the well would need artificial lift for economic production of the well. It was recommended that Newton–Raphson and modified Hagedorn–Brown methods be used in future study.

Keywords

• Optimum tubing size prediction
• Vertical multiphase flow
• Inflow performance relationship
• Tubing performance relationship
• Operating flow rate
• Operating pressure