This paper describes the development, history, and successful deployment of the world's two deepest through-tubing-conveyed electrical submersible pumps (TTCESPs). These are the first TTCESPs deployed inside of 7-in. casing. Electrical submersible pumps (ESPs) are a form of artificial lift that consists of a pump, motor, and electric cable, typically deployed by a rig and connected to electric power at surface. Their advantage is that they create greater drawdown than other forms of artificial lift, thus achieving higher production rates. However, conventional ESPs require expensive workover rigs to replace pumps, the component that fails most frequently. ConocoPhillips Alaska developed TTCESP technology to replace failed pumps rapidly and economically. In this system, a rig conventionally deploys the electric cable, motor, and seal sections with a special latching device for the pump. The pump is pulled and replaced with slickline (wireline) or coiled tubing, eliminating the requirement of a rig.

The original through-tubing-conveyed (TTC) systems were developed for 7⅝-in.-cased wells. During approximately the past 10 years, it was common belief that they could not be deployed at the Milne Point field in Alaska because of the limitations of its smaller wells (7-in., 26-lbm/ft casing). This paper discusses the enabling technologies that were developed to allow running TTCESPs in 7-in. casing, including a wellhead spoolpiece and low-clearance ESP clamps.

West Sak TTCESP run-time data indicate that the time between rig workovers (RWOs) will increase from 3.5 to 6 years. Pumps can be replaced for 5–10% of rig costs without the safety and environmental impacts associated with rigs. Additionally, production impacts while waiting for a rig are eliminated because slickline and coiled-tubing units are readily available on the North Slope of Alaska. TTC pumps can easily be upsized or downsized to optimize pump flow rate because of changes in production rates. This technology is of interest in areas where rig costs are high, including Arctic, remote, and offshore locations. It is also beneficial where rig availability is low.

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