Pressure drop in a vertical or deviated borehole has been found to be due to hydrostatic changes and friction as a result of the produced fluids flowing to the surface. When oil flows upwards, the flowing pressure along the tubing string drops, and this makes gas to start liberating. Thus, multiphase flow forms in the tubing string. Hence, adequate modelling of vertical lift performance is required to predict the pressure drop and subsequently the wellbore pressure because many factors are involved [1]. In this work, sensitivity analysis of multiphase flow in a well has been carried out with the aid of PROSPER in which the most accurate correlation was chosen from twelve selected built-in correlations present in the program to predict the pressure drop via gradient matching. A sensitivity analysis of the well was further performed to investigate the parameters such as tubing diameter, gas-oil ratio and wellhead pressure that were affecting the vertical lift performance of a high water cut well. The results obtained from the correlation matching showed that Dun and Ros [2] original correlation was the best fit correlation for the well. The results of the sensitivity analysis revealed that reduction of wellhead pressure from 600 psi to 400 psi could increase liquid rate by 41%. An adjustment of wellhead pressure was found to give the most significant impact on the production rate of the well as compared to other two parameters studied.

It is important to know that analysis and selection of choke sizes for oil wells is imperative for production optimizations in reservoir management. Chokes are necessary in every wellhead completion for regulating flow from the reservoir. Random selection of choke sizes has been a bad practice. For the case study of this work, productions from 3 gas condensate wells have declined with pressure over three years. The initial reservoir pressures of 5870 psi, 4373 psi and 2248 psi, initial production rates ranging from 82.3 BOPD to 242.57 BOPD and 3.018 MMSCFD to 5.001 MMSCFD respectively, with choke sizes ranging from 22/64" to 24/64". However, these reservoir pressures have depleted over 3 years by about 100 psi to 3800 psi for each well with early water breakthrough ranging from 10% to 25% basic sediment and water (BS&W). No analysis of choke sizes selection to flow the wells at the initial stage. This research work has been carried out on pressure depletion control corresponding with its drawdown. This was achieved by modelling and simulating PVT data, completion data, IPR and VLP data and well-test data as well as sensitivity analysis with the aid of PROSPER. Results obtained indicated the need to reduce choke sizes, thereby reducing the drawdown. The reduction of choke size gave a decrease in production volume ranging from 15 to 59% for both oil and gas. However, the reduction in choke sizes also gave decrease in water production of about 92%, 100% and 22% for the respective wells. The choke size sensitivity analysis showed that continuation of the initial choke sizes on 24/64" gave a higher drawdown value above 100 psi, which increased the pull of water conning. Recommendation of the new choke sizes within 18/64" to 20/64" showed the drawdown of 79 psi, 71.5 psi and 80.5 psi. New choke size selection was recommended for the reservoir management of each well.

Production of hydrocarbon from wells drilled into oil bearing zones for sustained period of time could result in wellbore integrity damage, which is capable of shutting down oil and gas production. To detect such problems, a diagnostic operation is performed to acquire and identify the source(s) of the wellbore integrity damage. The result of this, is raw subsurface well data, requiring further qualitative interpretation to establish causes and solutions to wellbore problems. To improve the accuracy of subsurface well data qualitative interpretation, the data acquiring process must be efficient and painstakingly performed. This work outlines and describes process of acquiring data through well diagnostics. This technique is applied to a well in the Niger Delta area operational for 10 years. The production volume from the well was about 68% lesser than expected rate from the DST result. Magnetic Thickness detection (MTD) and SNT-Temperature log were deployed as a wellbore diagnostic tool. The MTD tool run in the long string of the well from 13,742ft to 10,302ft, helps in detecting End of Tubing of the short string at 10,562.6ft, corrosion detection (Tubing Wall loss) at 12% maximum, perforation depth and casing conditions. The SNT-Temperature tool was run through the entire length of the tubing. It helped in detecting tubing leak at 13,391ft, formation activity between two reservoirs at 13,530ft – 13,560ft and fluid flow from perforation depth. These diagnostic analysis helps in identifying uncertainties in the well bore, thereby postulating direct solutions for the well.