APPLICATION OF GAS LIFT AND ESP HYBRID DESIGN FOR IMPROVED OIL PRODUCTION

ABSTRACT Most gas lift and/or ESP installation programs fail due to improper selection criteria, modeling technique and lack of understanding of basic interpretation skills. Non-availability of accurate modeling results for either gas-lift, ESP and both ESP and gas-lift is the reason for the avoidable technical failures due to production decline and down times. However, the non-understanding of the behavior of oil production to installation designs of both gas-lift and ESP hybrid gives rise to severe interpretation, monitoring and management problems. The wrong perception that hybrid systems are complex and expensive is the reason why it is not often considered as an option in some oil wells. The aim of this study is to investigate the impact of the application of gas-lift and ESP hybrid design sensitivity modeling for improved oil production of a complex reservoir system in the Niger Delta using Schlumberger PIPESIM. The objectives are; to design ESP and gas-lift models in a vertical well with oil rim reservoir system using four (4) case studies which includes: well without ESP and gas lift, well with only ESP, well with only gas-lift and well with both ESP and gas-lift, to predict different operating points of flow rates and reservoir pressures of all case studies using nodal analysis calculations, to carry out comparative sensitivity analysis of gas-lift and ESP installation design case studies using tubing sizes and productivity index and to predict new mathematical correlations of both operating flow rates and reservoir pressures as functions of case studies which would be applied as technical aid tool for quick assessment of production enhancement performance for the depleted oil well. The method used was to develop four (4) case studies which includes; well without ESP, well with both top and bottom (dual) ESP, well with only bottom ESP, and well with only top ESP. These data were inputted and simulated with the PIPESIM software. Results of predicted Nodal analysis modeling of the natural flowing oil well (case A) gave maximum oil rate and pressure of approximately 1,422.219STB/day at 2,862.9psia. Results of predicted maximum oil rate with only ESP installation (case B) gave 8,241.14STB/day at 2,275.094psi for the 4inch tubing ID and liquid PI of 10STB/day/psi. Results predicted maximum oil rate with only GL installation (case C) gave 6,348.078STB/day at 2,465.192psia for same the same tubing ID and liquid PI in case B. Results predicted maximum oil rate for both GL and ESP hybrid system installation (case D) gave the highest value of 10,488.85STB/day at a much lower pressure of 2,033.282psia for same the same tubing ID and liquid PI in case B. This study shows that the GL and ESP hybrid system installation (case D) with the maximum simulated operating points (OP) and appropriate pressure is selected for best production enhancement performance. Results of the predicted model of flow rate (Q) as a function the tubing size ID (Tp) for case D gave = . − . + . + . with square regression coefficient of = . This model will improve decision making on possible technical choice of selection. However, the major findings of this study was the reduction in installation complexity and time for the combined electrical submersible pump (ESP) and gas-lift (GL) designs, which positively affected the performance of oil production. The engineering designs adopted in this study are cost effective and will save time in installation. It is recommended that more sensitivity analysis be carried out to with electrical submersible pump (ESP) and gas-lift valve systems for deviated and horizontal wells.