You have access to this full article to experience the outstanding content available to SPE members and JPT subscribers. To ensure continued access to JPT's content, please Sign In, JOIN SPE, or Subscribe to JPT Electrical-submersible-pump (ESP) technology is a proven artificial-lift method for shallow, low-pressure reservoirs such as those found in the West Sak viscous oil field in Alaska. However, the unconsolidated nature of the West Sak sands challenges the long-term lifting performance and reliability of conventional ESP systems. The case study in this paper includes the analysis of the two generations of rigless ESP systems, quantifying the success rate in varying conditions in more than 300 rigless ESP replacements in a high-sand, high-deviation environment on Alaska’s North Slope. In 1998, the operator developed through-tubing-conveyed (TTC) ESP (TTCESP)/TTC progressive-cavity-pump (PCP) (TTCPCP) technology to allow failed pumps (ESP or PCP) to be replaced quickly and economically using conventional equipment without a rig.
Patterson, John (Patterson Consulting) | Dornan, Grant (ConocoPhillips Alaska) | Targac, Gary (ConocoPhillips) | Malone, David (AccessESP) | Cheblak, Samer (AccessESP) | Julian, Jennifer (BP Alaska) | Walker, Matthew (AccessESP)
Electrical submersible pump (ESP) technology is a proven artificial lift method for shallow, low pressure reservoirs like those found in the West Sak viscous oil field in Alaska. However, the unconsolidated nature of the West Sak sands challenges the long-term lifting performance and reliability of conventional ESP systems due to sand production. This challenging environment causes ESP pump erosion and accumulation of sand in the tubing above the pump and in the lower completion below the ESP.
This paper presents a 20-year case study of the of the world’s largest, longest-running population of thru-tubing conveyed (rigless) electric submersible pumps. Conventional ESP’s require a rig to replace a pump or motor when either fails. In "rigless" systems, some of the components (pump only for Generation 1, and pump, seal, and motor for Generation 2) can be pulled and replaced using slickline (SL), coiled tubing (CT), or tractor, depending on wellbore deviation. Generation 2 systems consist of a downhole side pocket mandrel (or docking station) with a wet-connect attached to the electric cable and deployed on 4-1/2" or larger tubing. Not only do these systems allow both the pump, seal, and motor to be retrieved without a rig, they have the significant advantage of allowing 3.80" fullbore access below the pump setting depth without pulling tubing. This allows non-rig interventions such as reperforating, production profiles, CT cleanouts, CT drilling etc. to be performed after the pump, seal, and motor are pulled with conventional SL or CT. Once the desired intervention has been completed, the pump, seal, and motor can be redeployed with SL — wet-connecting to the downhole side pocket mandrel. A well with a conventional ESP would require pulling the tubing with a rig prior to and reinstalling the tubing following any well intervention below the pump setting depth. "Rigless" technology has significantly increased production uptime and reduced the cost of ESP interventions in these wells.
The case study includes the analysis of the two generations of rigless ESP systems, quantifying the success rate in varying conditions in over 300 rigless ESP replacements in a high sand, high deviation environment on Alaska’s North Slope.
The PDF file of this paper is in Russian.
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.