Marginal fields require production optimization and proper management due to uncertainties surrounding the size, reserves and operational strategies and costs. One of the ways of achieving optimal development is by using an efficient artificial lift method early or later in the field life, that will increase recovery and profitability. However, knowing the best artificial lift method to use for a situation could sometimes be challenging. In this study, a techno-economic comparison of Continuous Gas Lift (CGL) and Electrical Submersible Pumps (ESP) was carried out for a marginal oil field in the Niger Delta to choose the optimal method. Well and reservoir models were built to generate production forecasts under natural flow, CGL and ESP. Economic models were formulated, incorporating cost for each artificial lift method, oil price and estimated revenue from oil and gas sales to determine the Net Present Value (NPV), Internal Rate of Return (IRR) and Profitability Index (PI). Risk and sensitivity analyses were carried out. When natural flow was not feasible and artificial lift preferred, CGL was characterized by high initial capital while ESP tended to have higher operating cost. Ultimate Recovery (UR) increased by 8.6% with the use of ESP but by 6.7% with CGL. The ESP also gave an NPV of $1.48 Million, IRR of 46.0% and PI of 1.50 while CGL gave an NPV of $2.03 Million, IRR of 31.4 and PI of 1.49. Higher profits were obtained when the artificial lift methods were installed after natural flow had been exhausted. Profitability of the marginal field using artificial lift was affected by oil price, fiscal terms and the cost of the lift methods.
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