High intervention costs to replace electric submersible pump (ESP) completions and high deferral production caused by ESP failures in offshore and remote locations are driving the efforts to increase ESP reliability around the world. ESP designs vary considerably depending on the application, for example, unconventional resource, heavy oil, high temperature, and high abrasives. Because of the wide range of ESP applications, the equipment specification requires a tailored solution for each application to increase reliability. This paper presents typical failures and the evolution of ESP technology deployed in the North Sea as well as the enhancements proposed to increase system reliability. The equipment improvements are based on failure analysis performed in the strings pulled from the North Sea. A large ESP population is analyzed, including 219 installations and 162 failures. Survival analysis enabled splitting the population into subsystems and analyzing the ESP performance individually after each major change in equipment specification. This approach made it possible to confirm the effectiveness of the changes and quantify the increase in reliability after each investment in equipment enhancement. It was also possible to identify the "less reliable" subsystem to focus on further improvements.

An operator planned to install ESPs to overcome high water cut and minimize the gas supply risk for a gas lift completion at a platform in the Gulf of Mexico. The platform is an oil collection point and its continuous operation is essential during any rig-assisted interventions. To maintain platform operation, three wells were selected for deployment of rigless electrical submersible pump (ESP) replacement systems to avoid the future use of a workover rig. The challenge was to allow a single-trip ESP deployment using the crane facilities with existing height limitations. A special surface connection system was designed to allow long ESP sections to connect under pressure at the wellhead. The technology is based on a propriotery system and method of connecting long strings at the surface using a surface lubricator and an adapted deployment stack. The system elements are located between the pump intake and protector seal sections of a standard ESP string that can easily and economically sourced in most locations. This new technology reduces the number of wireline/slickline runs needed, and the system features allow verification of mechanical connection integrity at the surface prior to deployment in the well. The successful deployment and commissioning of a rigless ESP replacement system in the SM 130 A-26 well in the Gulf of Mexico was completed in October 2019 without incident. Prior to the deployment of the rigless ESP replacement system, it was decided to perform hydraulic stimulation operations to improve the well productivity. This operation resulted in higher than expected well inflow with increased water cut. At the time of writing this paper, the ESP system had recently failed to start due to stuck pump (possibly scale related). Due to the ability to perform a rigless system upgrade for the unanticipated well inflow conditions, the operator is planning for the first rigless replacement of the existing ESP to achieve higher flow rate during the last quarter of 2021. The successful deployment of the alternative ESP deployment technology demonstrated the potential to improve the economics of the existing production facilities by reducing production deferment, minimizing health, safety, and environment (HSE) exposure; and improving the asset value. This paper discusses the engineered solution and application of the technology required to deploy long ESP strings, modifications required for the specific well conditions, and the lessons learned during the first successful deployment of rigless ESP technology in the Gulf of Mexico. Due to the performance and capability demonstrated in the first successful installation, Talos Energy has recently installed its second rigless ESP replacement system in a recompleted zone and is planning for installing its third system in the SM 130 field in 2022.

The paper describes the methodology and specific action items developed and applied jointly by the operating company and contractor teams to achieve significant improvements in reliability (run life) and reduce power consumption in more than 300 artificially lifted wells equipped with electric submersible pumps (ESPs) in the harsh environment of Van-Yogan field in Russia, Western Siberia. The extended duration of the project, which started in January 2012 and is currently ongoing, offers a unique opportunity to review and analyze the longer-term contribution and efficacy of the various methods presented. To date, the project has delivered consistent improvements in both energy efficiency and equipment reliability, translating to substantial savings in the lifting costs for the operator. Average pump efficiency increased by 4.3 percentage points (from 60.4% to 64.7%), which is an excellent result considering the average pump flow rate decreased from 240 m3/d to 182 m3/d during the same period due to overall aging of the field. It is widely known in the industry that smaller pumps generally return lower power efficiency figures; therefore more efficient novel pump designs and operating procedures had to be introduced to facilitate this efficiency improvement. Despite continuously deteriorating well conditions under the adverse influence of scales, corrosion and production of high volumes of free gas and solids through the ESP, average pump run life was extended by 101 days since the project start date (from 335 days at the beginning of 2012 to 436 days at the end of 2015, or by more than 30%). At the same time, Mean Time Before Failure (MTBF) improved by more than 56% over the same period (from 511 to 796 days), decreasing workover costs and deferred production. The comprehensive approach includes accurate ESP selection to better match well conditions, use of high-efficiency ESP pump and motor designs, flawless field service execution, and continuous monitoring and fine tuning of equipment performance. Inspection of dismantled equipment and failure root cause analysis (RCA) plays a fundamental role to ensure that adverse well factors are properly addressed by ESP design and operating procedures.

Frequently, production from gas and gas condensate wells is negatively impacted by the wellbore accumulation of liquid – a mixture of water and condensate. As reservoir pressure and tubing gas velocity decline and produced water cut increases, heavier liquids can no longer be effectively removed from the wellbore, resulting in the liquid column build-up at the bottomhole. This creates additional backpressure on the producing formation and leads to gradual production decline, until the well completely stops producing – the condition widely known as "liquid loading". Use of smaller size tubing (velocity string) is often the simplest and most straightforward solution, but depending on reservoir properties (water cut, productivity and pressure) and well completion (vertical, slanted or horizontal) this approach may not be efficient. This paper describes the technical approach to resume continuous production from liquid-loading gas condensate wells at North Urengoy field. It is shown that Electric Submersible Pumps (ESPs) can be successfully applied to unload horizontal wells producing large amounts of water. In this application, water and condensate is lifted by the pump through the tubing string, while gas and condensate mixture is simultaneously produced through the annular space between the tubing and the casing. Reviewed in detail are the technical challenges of modeling the well and pump performance using dynamic multiphase flow simulators, and the ESP design for the pilot application in deep, horizontal gas condensate well in Russia.

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