Optimizing Highly Deviated Wells in Egypt: Cost-Effective Transition from High-Power ESP to Reciprocating Rod Pumping with Continuous Rod

Abstract

Abstract In Egypt's oil and gas industry, rod-driven artificial lift systems (ALS) are traditionally considered suitable only for vertical wells. Electrical Submersible Pumps (ESP) has been the preferred choice for highly deviated wells due to the high costs associated with tubing leaks and sucker rod failures. However, ESPs are expensive and consume significant power. Over time, the operational expenses of ESPs can become prohibitive, making the well economically unviable due to high power consumption and costly workover interventions. This study proposes an optimal ALS solution to reduce power consumption, workover intervention costs, and lifting expenses in Egypt's highly deviated wells. The BED 3-26 well is a highly deviated and deep well with a dogleg severity of 8.44°/100ft and a side load of 900 lbf. Producing approximately 250 barrels of fluid per day (BFPD) from perforation depths around 10,000 feet, this well has been equipped with an ESP since 2020 due to its high DLS value and depth. A comprehensive investigation, including production history, workover history, deviation survey, and intervention reports, revealed that ESP cable failure is the primary cause of failure, accounting for over 95% of incidents, with the remaining 5% due to pump broken shafts. The maximum run life was 90 days. The high operating costs of ESPs, due to frequent workover and high-power requirements, prompted the operator to seek a more cost-effective solution. This research demonstrates that combining Reciprocating Rod Pumping (RRP) with continuous rod is an effective approach for overcoming the limitations of rod-driven ALS in aggressive wellbore geometries in Egypt. The results show that transitioning from an expensive ESP system to a more cost-effective RRP with continuous rod solution can expedite the return on investment. Compared to previous lift systems, this solution reduced capital expenses by 39%, flow losses by 41%, power usage by 70%, and increased the time between failures by 411%. The well has been operating continuously, producing 250 BFPD for 460 days without any costly interventions, compared to 90 days with the ESP system.