Integrated Automation and Intervention Solutions for Extended ESP Run Life in Complex Reservoir Environments

Abstract A remote field that was discovered in 1970 relies on natural flow, supplemented by electric submersible pumps (ESPs) in some wells, to produce oil from a thin-limestone reservoir. With extensive faulting and low permeability, the primary recovery mechanism is solution gas drive. ESP systems previously struggled to achieve optimal run life, prompting the development of integrated solutions to extend the run life in challenging conditions. Detailed failure analysis proved that the primary cause of ESP failures was motor overheating, exacerbated by inadequate reservoir influx. Therefore, a comprehensive integrated intervention workflow was developed to optimize ESP operation within this complex environment. First, a dual approach to stimulate the reservoir formation encompassed acid treatment and fracturing with rod-shaped proppant to mitigate the risk of proppant flowback and premature ESP failure. Addressing challenges such as deep reservoir pressure decline and a high gas-oil ratio, a wide range of a mixed-stage pump types and multiphase gas handlers were installed. Additionally, motor derating, tailored ESP shrouds, and variable speed drive technology were employed to optimize ESP operation. This included continuous 24/7 monitoring and remote control for enhanced performance. The successful implementation of the workflow has delivered historical ESP run life exceeding 1 year in the field, coupled with sustained oil production. The first deployed ESP system yielded an average daily oil rate of 520 BOPD, prompting the extension of the approach to an additional four wells, resulting in a total rate of 3,750 BOPD. Continuous monitoring of well performance, facilitated by an automated workflow, has enabled the maintenance of optimal operating conditions. This includes fine-tuning the ESP running frequency to each well's performance, accounting for variations in well flowing pressure and reservoir fluid properties, such as different bubble points leading to varying gas-lock settings. Continuous monitoring and remote operation have minimized downtime to a remarkable 4.5%, which was mainly due to scheduled maintenance of the power system. This result verifies the effectiveness of the implemented solutions in optimizing field performance and maximizing hydrocarbon recovery. The success of this approach has sparked interest in its application to similar reservoir environments, potentially unlocking additional oil potential in nearby fields. This promising prospect underscores the potential impact of our findings on the broader oil production landscape, paving the way for enhanced reservoir management and increased hydrocarbon recovery in comparable geological environments.