Thru-Tubing Conveyed Rigless ESP Technology: A 20-Year Case History of Wireline Retrievable ESPs.

Abstract

Abstract 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.