Boosted gas separator enhances ESP performance, extends service life in gassy, unconventional wells

JOSEPH MCMANUS, MOHAMMAD MASADEH and OSCAR PADILLA, Baker Hughes 

The increased use of electrical submersible pumps (ESPs) is a direct result of the value that these downhole tools deliver. They enhance fluid production, improve reservoir recovery and enable operational flexibility. In turn, this enables safer, more efficient and more profitable operations. Although ESPs have the potential to substantially improve production, they are not infallible. In many basins around the world, a decline in bottomhole pressure results in gas interference. This flow instability can severely impact the performance of ESPs, resulting in reduced production or equipment challenges. 

Optimizing ESP efficiency in these conditions is complicated, but a recently introduced, boosted gas separator design, which incorporates a new gas handler pump and gas separation system, can be used in conjunction with other advanced technologies to optimize ESP performance in gassy, unconventional operating environments. This system improves lift efficiency, increases oil production and extends the ESP’s service life. 

UNDERSTANDING GAS CHALLENGE IN ESP APPLICATIONS 

Globally, ESPs face gas interference challenges, especially in unconventional reservoirs with high gas-liquid ratios (GLRs) and complex well geometries. As liquid rates decline, increased gas production leads to cycling, gas locking and pump wear, which disrupt output and reduce recovery. These issues are particularly severe in the Permian basin and Bakken formation, where advanced gas-handling solutions are critical to maintaining ESP performance and allowing operators to reach the desired drawdown. 

Service providers have attempted to address gas-related ESP challenges with varying degrees of success, using technologies such as multiphase pumps, gas-handling equipment, gas separators and ESP control algorithms that are implemented via variable speed drives (VSDs). Many of these are standalone solutions that address specific issues, but they fall short when free gas volumes increase significantly. These limitations become more pronounced in unconventional reservoirs, where complex flow dynamics and high GLRs demand more robust and adaptive systems. 

Extensive research has been conducted to tackle high Gas Volume Fraction (GVF) conditions in ESP systems. Proposed solutions include tapered pump designs, tandem gas separators combined with multiphase gas-handling pumps and VSD logic that adjusts frequency, based on motor current and/or other parameters. Multiphase helio-axial stages can effectively handle mixtures with GVFs as high as 75%, maintaining high boost pressure while increasing the fluid density delivered to the upper pump stages. Additionally, bottom feeder intakes have been introduced as a cost-effective method for mitigating gas lock, and inverted shrouded systems have proven to be impactful when resolving issues related to slugs. 

While each one of these approaches has demonstrated some success, a more integrated and comprehensive solution is required to fully optimize ESP performance and extend system life in gas-prone environments. 

SYSTEM-LEVEL SOLUTION 

Achieving reliable ESP performance in high-GLR wells requires a fully integrated system that combines multiple technologies to manage gas effectively and maintain flow stability. Vortex-style gas separators use centrifugal action to separate higher-density fluids from lower-density gas, which is then vented back to the wellbore. This prevents free gas from entering the pump intake. Gas handling and multiphase pumps improve system performance by compressing the gas-liquid mixture, reducing bubble size and preventing gas lock. These multiphase helio-axial stages can effectively handle mixtures with gas volume fractions (GVFs) up to 75%, maintaining high boost pressure while increasing the fluid density delivered to the upper pump stages. 

Fig. 1. Standard configuration vs. boosted gas separator, where pre-compressed gas improves separation.

In a standard ESP configuration, fluid flows directly through the gas separator before entering the pump stages. In a system that incorporates a boosted gas separator, the fluid is introduced through an intake, where it is compressed by a gas handler pump before entering the separator, which enhances recirculation. The pre-compressed fluid is then routed to the gas separator, before reaching the lift pump. This process improves gas separation by diluting the gas concentration and stabilizing flow, with pressure losses in the annulus offset by inducer-generated lift, Fig. 1. 

Incorporating permanent magnet motors (PMMs) significantly enhances ESP system efficiency. Traditional induction motors (IMs) typically operate at 78% to 84% efficiency, due to rotor current losses. In contrast, PMMs eliminate losses, achieving efficiencies of up to 92%. This leads to a 67% reduction in motor power loss and up to 20% lower overall system power consumption. PMMs also offer higher power density, allowing for shorter motor lengths—or greater horsepower, within the same footprint—while maintaining consistent efficiency across a wide load range.  

Additionally, PMMs generate significantly less heat under high gas conditions, due to their high efficiency and lower current draw during low-load operations. This thermal advantage reduces the risk of overheating and improves reliability in high gas operations. Furthermore, their inherently low idle current eliminates the need to disable current control and rely solely on motor temperature for protection, simplifying system design and enhancing operational stability in challenging environments. 

When paired with intelligent drive controls, the boosted gas system can dynamically adapt to changing well conditions, optimizing uptime, drawdown and recovery. 

THE ROLE OF CFD IN SYSTEM DESIGN OPTIMIZATION 

To evaluate the effectiveness of a system using a boosted gas separator system, engineers applied computational fluid dynamics (CFD) modeling, to simulate flow behavior and validate performance improvements under different well conditions and with different equipment configurations. 

Fig. 2. Separation efficiency vs. liquid inlet flowrate.

In one evaluation, CFD analysis was applied to compare the gas separation efficiency and GVF distributions in standard and boosted gas separator configurations of the tandem 400 series gas separator GM2HV, with the GH6000 gas handler pump used in the enhanced setup. Results consistently showed that incorporating a booster pump significantly improved separation efficiency across all GVF levels and flowrates. 

The most notable improvements in separator efficiency were observed at liquid rates above 2,000 bpd, representing a typical 40% increase over traditional gas separators. This improved separation enables ESPs to sustain a throughput of 3,000 bpd, while achieving bottomhole pressures as low as 1,000 psi, in wells producing more than 1,000 MMscfd. As a result, drawdown and production are maximized in high-GVF unconventional environments, Figs. 2 and 3. 

Fig. 3. CFD analysis shows that adding a booster pump improves gas separation and sends more liquid to the pump across all GVF levels.

PERFORMANCE IN THE FIELD 

The first ESP-boosted gas separator installation in the Permian basin was carried out in October 2021, with the pump achieving more than 934 run days. Since then, 136 ESPs have been installed with the proprietary boosted gas separator design. 

This system has operated under challenging conditions, with an average gas-liquid ratio exceeding 1,000 scf/bbl and liquid production rates ranging from 300 bpd to 3,000 bpd. In the areas of the United States outside the Permian, Baker Hughes has run 146 ESPs with booster designs, with GLR ranging between 1,300 and 2,600 scf/bbl, yielding liquid production rates ranging from 450 bpd to 1,200 bpd. 

In one installation in the Permian basin, the boosted system improved gas separation by an average of 26%, and it increased oil production by approximately 30,000 bbl across three wells in the first 60 days. The system was installed to address climbing gas levels that were preventing drawdown and impeding production. By separating more gas than a standard ESP system, the booster configuration generated an additional $2 million in revenue during the first two months of operation. Based on these results, the operator expanded the use of the system to additional wells, to further increase production from the field. 

Similar results were achieved in an installation in the Bakken shale. The existing well required an ESP system at a depth of 9,500 ft (2,889 m), with downhole temperatures ranging from 270°F to 280°F (132°-138°C). The ESP needed to produce 900 bpd to 1,000 bpd in a sandy, gassy environment, with a gas-to-liquids ratio of 500–1,800 scf/stb. The pump intake pressure had to be reduced to below 400 psi in the gassy environment, so a standard ESP was not a viable option. 

One major operator in the Permian basin faced limited gas availability, unstable gas lift (GL) performance and declining oil output. GL is a widely used artificial lift method that injects gas into the production tubing, to reduce fluid density and help lift hydrocarbons to the surface. While effective in many scenarios, GL can be limited by gas supply constraints, unstable performance and reduced drawdown capability. Due to the inherent limitations of GL, it may not always achieve the drawdown levels needed to meet production targets. 

Fig. 4. This chart shows the average oil production before and after ESP installation, demonstrating that installing ESPs in these six wells increased oil production in all of them by an average 90%.

Field data from multiple operators has shown that switching from GL to ESPs can lead to significant production gains. In some cases, ESPs were able to lower bottomhole pressure by up to 1,000 psi, compared to GL, enabling operators to unlock greater production potential. In one case study, economic analysis showed that converting from GL to ESP generated a net revenue of $3.7 million per year, which is 40% higher than GL. 

This Permian basin operator converted six gas-lifted wells to ESPs across two well pads. Numerical simulations and nodal analysis confirmed that ESPs could deliver deeper drawdown and higher flowrates, making them a preferred solution during a well’s early to mid-life stages, Fig. 4. 

The chart in Fig. 4 shows the average oil production before and after ESP installation, demonstrating that installing ESPs in these six wells increased oil production in all six wells by an average 90%. 

A new multiphase ESP system also has improved production in unconventional, horizontal wells, where large gas slugs are a common challenge. The slugs accumulate in lateral undulations and release unpredictably, disrupting ESP operations, triggering gas locking, frequent pump cycling, and motor overheating, which result in repeated shutdowns, lower production, and a shorter run life for the ESPs. The proprietary, multiphase ESP system addresses these challenges with a fully encapsulated design that naturally separates gas slugs from the production stream before they reach the pump. This configuration stabilizes flow, minimizes nonproductive time, and safeguards system components during installation in deviated wellbores. The system has been proven in more than 1,300 installations across the United States, where it has extended ESP run life, increased uptime and significantly improved production performance. 

By combining a high-efficiency gas handler pump—capable of operating at gas volume fractions up to 75%—with a boosted gas separator that improves gas separation by approximately 25%, the system helps mitigate gas locking, reduce motor temperatures and enhance ESP stability and reliability. When further optimized with advanced technologies—such as wide-range efficient pumps, PMMs, real-time optimization software, and intelligent variable frequency drive controls—the system provides a comprehensive approach to managing high GLR conditions and improving overall well performance.  

CONTINUING TO MOVE THE NEEDLE ON PRODUCTION 

Associated gas production from unconventional wells is expected to persist. Baker Hughes is committed to providing solutions that improve well productivity by developing new technologies aimed at mitigating the challenges posed by high-gas conditions and extending the run life of ESPs. 

Ongoing innovation is supported by a $40-million advanced research and testing facility, equipped with full-scale test wells, specialized labs and comprehensive manufacturing capabilities that make it possible to rigorously validate artificial lift technologies under real-world conditions. This includes testing for gas and sand detection and handling, to ensure the reliability and performance of next-generation ESP systems—such as the boosted gas solution—under complex multiphase flow environments. 

Innovations like the FusionPro—an advanced variable speed drive that incorporates sophisticated controls specifically designed for gassy environments—are in development, along with a boosted gas separator system for high-temperature applications and a next-generation gas separation technology, offering improved gas handling capabilities, set to launch later this year.  

JOSEPH MCMANUS is a seasoned expert with 20 years of experience in the oil and gas industry. Throughout his career, he has held diverse roles in sales, operations, engineering leadership, business development and product management. He currently serves as a product line manager at Baker Hughes, where he specializes in artificial lift systems, particularly ESPs. Mr. McManus holds a master’s degree in chemical engineering and an MBA, both from the University of Tulsa. 

OSCAR PADILLA is a seasoned energy industry expert with nearly two decades of experience in the oil and gas sector. He currently serves as the Global Product Line manager - Artificial Lift Thermal and Water Systems and High-Speed ESPs at Baker Hughes. Throughout his career, Mr. Padilla has held a variety of leadership roles across sales, operations and talent development. He began his journey at Baker Hughes in sales and operations for drill bits, later transitioning to lead recruitment and university relations for Oilfield Services in Latin America. The majority of his career has been dedicated to managing sales and operations for artificial lift systems, with significant experience in both Mexico and Canada. Mr. Padilla holds a degree in mechanical and electrical engineering from Universidad Iberoamericana, in León, Mexico. 

MOHAMMAD MASADEH is a Service Delivery technical manager for Baker Hughes, based in Midland, Texas. With 20 years of experience in the oil and gas industry across the Middle East, North Africa and the United States. Mr. Masadeh has managed large ESP programs for major international oil companies, with an emphasis on improving ESP run life and production. He has served as a technical support expert for GE Oil and Gas, and then Baker Hughes, since 2015, aiding operators in ESP selection and optimization. Mr. Masadeh received his bachelor’s degree in electronics engineering from Hashemite University in Amman, Jordan, and he is dedicated to enhancing service delivery and driving industry innovation.