Electrical submersible pumps, or ESPs, are ubiquitous in oil production applications. This post is a summary of two articles in World Oil’s June 2025 issue, one by personnel from Baker Hughes about the performance and lifespan benefits of its boosted gas separator, and the other by NOV personnel about the reliability benefits of its new gas processing system. Both innovations are applicable to gas-rich oil wells that can be problematic for pumps.
Baker Hughes Boosted Gas Separator
The authors from Baker Hughes
note that its new boosted gas separator can:
“…enhance fluid production, improve reservoir recovery
and enable operational flexibility. In turn, this enables safer, more efficient
and more profitable operations.”
When bottomhole pressure
drops, gas can interfere with pump operation. This is especially problematic in
oil wells with high gas-to-oil ratios (GORs). Thus, there is a need to address
high Gas Volume Fraction (GVF) conditions in ESP systems. Problems include
cycling, gas locking, and pump wear. The problems are most apparent in the
Permian and Bakken. Baker Hughes offers what they call a system-level solution:
“…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.”
“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. Standard configuration vs. boosted gas separator,
where pre-compressed gas improves separation.
Another innovation now in
common use is permanent magnet motors to run the ESPs, which results in vastly
improved efficiency. I wrote about permanent magnet motors in oilfield
applications a few months ago.
Another design enhancement
has been the use of computational fluid dynamics (CFD), which enables modeling,
simulation, and validation under different configurations.
“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.”
Fig. 3. CFD analysis shows that adding a booster pump
improves gas separation and sends more liquid to the pump across all GVF
levels.
Baker Hughes has been field
testing this boosted gas separator since October 2021, with the pump achieving
934 run days. They now have 136 ESPs in the Permian Basin and 146 in other
places around the world, with the separator installed. These are installed in
wells with variable production rates and variable GORs. One well showed
increased production of 500Bbls per day over 60 days. The chart below shows
performance improvements of the boosted gas separator over gas lift, a common
method of artificial lift that injects gas into the production tubing to reduce
fluid density and help bring hydrocarbons to the surface.
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%.
A new multiphase ESP system
has improved production in wells susceptible to gas slugs. Gas slugging can
result from undulations in well laterals, including land the well
unintentionally below the target zone and coming up into it, creating a sump
effect at the beginning of the lateral. Gas slugging can lead to gas lock,
frequent pump cycling, and motor overheating. The multiphase ESP system is
installed in 1300 locations in the U.S. and combined with the boosted gas
separator, PMMs, and an efficient gas handling pump, it can lead to significant
production increases. These solutions will remain important as the amount of
associated gas from oil wells continues to increase.
The authors also note some
future innovation projects:
“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.”
NOV’s Integrated Gas Processor (IGP) Improves Artificial
Lift and Pump Reliability
National Oilwell Varco,
or NOV, also addresses gas interference in high GOR oil wells with its
Integrated Gas Processor (IGP). The first schematic below depicts a typical ESP
configuration, and the second one depicts an IGP configuration. The IGP system
replaces the gas handler and the gas separator. The IGP combines those into one
highly efficient unit. The traditional design can prevent operators from
reducing the pump intake pressure (PIP), which can prevent pump optimization
and the associated production increases.
Fig. 1. A typical ESP installation includes a tandem gas
separator and gas handling pump.
Fig. 2. The IGP replaces the gas separator and gas handler.
“The IGP operates differently from traditional gas
handling equipment. Fluid enters a high-volume flow intake and goes into the
lower module, where proprietary Contra-Helical Pump (CHP) stages compress and
condition (homogenize) the gas and liquid. Unlike a traditional centrifugal
pump, the CHP provides two flow paths that allow gas to flow into both the
rotor and stator. The primary flow path is the helical flow, while the
secondary flow path is the fluid vortex, generated within the rotor and the
stator vanes. As a result, the CHP can ingest and condition a higher amount of
gas, as it moves through the pump. Moreover, conditioning the gas provides
buoyancy to the production fluid, increasing overall lift efficiency.”
“Then, the more homogenized gas-liquid mixture enters
the center module that features a dual-chambered gas separator, which is
strategically positioned to reduce gas recirculation and enhance gas separation
efficiency. An inducer rotates the fluid at high speed, causing the
high-density liquid to move to the outer diameter, while the low-density gas
concentrates toward the inside diameter. A crossover component diverts the free
gas to the exit ports and out into the annulus
of the well, between the IGP and casing wall, and directs the liquid into the
next stage of separation. This process repeats in the second stage of
separation, further reducing the GVF {gas void fraction} and directing the
fluid into the upper module.”
“Finally, the fluid enters the upper module for further
compression and conditioning, before moving into the primary production pump.
Both CHP and centrifugal style stages are available for the upper module.”
The tree-module system is
shown below:
Fig. 3. The three-module, all-in-one housing system is
designed to separate and prepare the gas before entering the ESP’s primary
production pump.
Below, the authors give a
case study example from the Delaware Basin, showing clear production
improvements:
“The IGP exceeded the previous gas handling equipment,
leading to a rapid rise in fluid production. Oil production rose 153%, from 136
bpd to 344 bpd, while gas production increased 224%, from 202 Mscfd to 654
Mscfd. Water production also increased 316%, from 417 bpd to 1,734 bpd, which
led to a 14% reduction in the GLR, from 365 scf/bbl to 315 scf/bbl. Meanwhile,
the PIP immediately dropped 11%, from 579 psi to 514 psi.”
Fig. 4. After installing the IGP, the Permian operator saw
an immediate increase in production and a decrease
in GLR and PIP.
As in the Baker Hughes example, the
IGP showed a marked performance improvement over gas lift. Downtime was reduced
as well. As GORs continue to increase over time in the Permian Basin, these
solutions will be deployed more and more. Longer laterals and undulating
laterals will also benefit from these solutions.
“More than 120 IGPs have been installed in
unconventional wells across the U.S., tackling the persistent challenge of gas
interference. By integrating critical gas handling functions into a single,
modular and optimized system, the proven IGP is poised to drive a new era of
enhanced production, as well as substantial improvements in operational safety,
efficiency and reliability.”
References:
Boosted
gas separator enhances ESP performance, extends service life in gassy,
unconventional wells. JOSEPH MCMANUS, MOHAMMAD MASADEH and OSCAR PADILLA, Baker
Hughes. World Oil. June 2025. Boosted
gas separator enhances ESP performance, extends service life in gassy,
unconventional wells
New
gas processing system enhances electrical submersible pump reliability. AMES
RHYS-DAVIES and JESSICA STUMP, NOV. World Oil. June 2025. New
gas processing system enhances electrical submersible pump reliability
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