Production Tubing Size and Gas lift Optimisation for Deepwater Subsea Development Asekhame Yadua Introduction Main Results Due to the huge costs involved in deepwater subsea development, operating companies seek to maximise production throughout the life span of such fields, in order to get quick return of investment. And the optimisation of the tubing size and gas lift operation is key to achieving this goal. Fig. 1 shows the sensitivity analysis of tubing size for Colsay 1 wells when WCT = 48% and Pwh = 0.446 Mpaa. It shows the main results of all the tubing size simulations carried out. The tubing and gas lift process are components of a system consisting of a reservoir, reservoir fluids, wellbore and tubing. Therefore, they must be compatible (carefully designed) with the other components in order to fulfil the production strategy of the operating company, as all the components affect each other’s performance (See Equations 1 and 2). Figure 3: Effect of gas lift on oil production rate. Figure 1: Sensitivity analysis of tubing size. Methodology In this study, PROSPER was used to determine the optimum tubing size and gas lift design (gas lift rate, number and spacing of valves) for two sets of wells in Chevron’s Colsay 1 and 3 reservoirs. The optimum tubing size was determined by sensitizing on water cut (0-96%), wellhead pressure (0.446-17.34 Mpaa) and tubing ID (101.6-190.5 mm), and then the optimum tubing size was used to carry out the gas lift design. Figure 2: Deviation survey showing the optimum injection depth. Conclusions The performance of a well is extremely sensitive to tubing ID. Tubing ID has the greatest impact on well performance. Lower wellhead pressures increase the risk of rapid erosion and larger tubings are more susceptible. Larger tubings are also more susceptible to unstable production. As both sets of wells have the same well geometry and optimum tubing size (139.7 mm), well geometry may be the most dominant factor influencing the optimum tubing size for a well, considering the fact that the two reservoir fluids have different properties. The deepest point in the vertical section of a horizontal well is the optimum injection depth for a gas lift operation. For the Rosebank field, the effect of gas lift will become more pronounced in the high water cut period, but it will diminish just before the wells die (WCT ~ 96%). This may be the case for other oil fields. In general, the optimum gas injection rate increases with increasing WCT. Asekhame Yadua a.yadua.10@aberdeen.ac.uk +44 (0) 7423702127 www.abdn.ac.uk MSc Oil and Gas Engineering, University of Aberdeen, King's College, Aberdeen, AB24 3FX