For unconventional oil and gas producers looking to lower drilling costs, optimize completion designs and improve wellbore stability, a popular solution is to merely drill smaller diameter wells. However, the money saved in well construction often comes at a price during production—namely, space limitations in the well prevent most conventional artificial lift technologies from being installed at the desired depth. As production rates drop, conventional lift systems must be installed higher in the well than the operator would prefer. This results in greater lifting costs, sub-optimal production rates and lower ultimate recovery from the reservoir.

This was the challenge facing an operator producing from the Wasatch Formation of the Uinta Basin. The operator set a 5-in. 18-lb liner at a total vertical depth (TVD) of 2,103 m (6,900 ft) in a 7-in. 4,724-m (15,500- ft) cased vertical well. To take advantage of the thick source rock, the operator installed a completion with a vertically perforated zone from 4,054 m to 4,694 m (13,300 ft to 15,400 ft).

The operator wanted to maximize the well’s production by setting an electric submersible pump (ESP) inside the liner as close as possible to the perforations. However, the planned setting depth was outside the range of traditional slimline ESP systems and other smaller diameter artificial lift options.

Further complications arose regarding the operating environment of the well, which included a producing gas-liquid ratio (GLR) of 500, consistently high solids production levels and a temperature of 110 C (230 F) at the desired setting depth. Even if the operator could pass the ESP through the liner and reach the setting depth, the challenge of maintaining steady operations to reduce wear on the system at these elevated temperatures still remained.

Streamlined ESP solution

Production challenges in small-diameter unconventional wells such as this prompted Baker Hughes to develop its CENtrilift PASS Slimline ESP System, a small-diameter mixed-flow pump designed using computer fluid dynamic modeling techniques. This lift system was engineered to give operators that drill smaller diameter wells the ability to overcome the space restriction limitations of other forms of lift. It was also designed to overcome the operational challenges common to other small-diameter ESPs. For example, smaller casing sizes or wellbores with restrictions often lead to limited flow rates, lower recovery and the need to change out the artificial lift system more frequently.

This lift system was engineered to give operators that drill smaller diameter wells the ability to overcome the space restriction limitations of other forms of lift.

The slimline ESP includes an extended-range pump with a stage design that reliably operates in a flow range from 50 bbl/d to 2,500 bbl/d. This wide operating range allows the pump to adapt to changing well conditions and flows, thus securing stable and sustainable production even at low flow rates. This steady, reliable operation helps increase ESP runlife, minimize system changeouts and reduce pulling costs.

The system incorporates a motor designed for improved reliability in smaller casing sizes. The motor’s magnet-wire insulation is upgraded to provide 30% greater mechanical and electrical strength. The motor head was redesigned to reduce the overall motor outer diameter, while the angle of the motor lead connection was reduced to ensure greater protection during installation.

The system also was designed with a series of gas management capabilities to avoid the problems of pump overheating and gas lock that are common when boosting production streams that contain high levels of entrained gas or gas slugs. A vortex gas separator provides a less complicated flow path and improves gas separation before the fluid stream enters the pump. In addition, the pump stages are designed with an advanced turbulence mitigation technology that increases pump efficiency while reducing gas locking.

In wells with elevated GLR levels, the system is fitted with a charge pump to boost the fluid stream before it enters the production pump. A 3.38-in. gas insurance boost pump reduces the net positive suction head required, allowing the production pump to continue operating in the low inflow pressure conditions caused by gas ingress. The boost pump is balanced for constant thrust over its entire flow range. The combined boost pump/production pump system has been shown to reliably produce fluid streams containing more than 60% gas volume fractions.

The system also comes equipped with a gas mitigation intake that combines gravity-driven natural separation with mechanical gas separation and that can be landed at any angle in the wellbore. When landed in a nonvertical position, gravity cups built into the intake shift to block the pump inlet ports on the high side of the intake where the gas accumulates. The production liquids, which are largely free of entrained gas, then pass through the lower ports to feed the pump. When landed vertically in a well, the mechanical gas separation portion of the system diverts free gas away from the pump and into the annulus.

The slimline system also incorporates several features designed to improve reliability and runlife. A carbide bearing system allows the pump to withstand elevated temperatures during short-term operations with gas slugs, and particle swirl suppression ribs in the diffuser reduce the buildup of abrasives that can lead to erosive wear. The system’s 5,800-psi burst and collapse pressure rating allows it to be set deeper in the well and closer to the reservoir for improved recovery.

Proving its potential

Baker Hughes proposed a CENtrilift PASS slimline ESP system to an operator for its Utah well and worked with it to design the optimal solution for its production goals. The system included gas management technology and a tapered slimline pump designed with the extended-range pump as well as multiphase pump stages featuring a patented split-vane impeller design that helped reduce underload shutdowns due to gas interference. The pumping system was controlled with a variable speed drive, with power supplied through a cable protected with motor lead extension protectors and a series of centralizers.

The system passed through the liner to reach the planned pump setting depth of 3,719 m (12,200 ft), which was 80% deeper than the roughly 2,073-m (6,800-ft) setting depth that would have been possible with a conventional ESP system.

Baker Hughes engineers used proprietary sizing and simulation software to estimate the production at the original, shallower setting depth. Comparing actual production at the deeper setting depth vs. the estimated production at the shallower depth, the slimline ESP system achieved an average production rate of 500 bbl/d, which was a 150% higher total production rate. Since its installation the slimline ESP has allowed the operator to achieve steady and reliable operation and production rates in high-gas, high-solids conditions.

Based on these initial results, the operator is planning a second slimline ESP installation in a similar well and continues to search for additional opportunities to apply this technology and increase production rates in other small-diameter wells.

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