June 2020 /// Vol 241 No. 6

Special Focus

New approach extends electrical submersible pump life

An integrated service strategy, combining advanced system design and targeted chemical treatments, extends ESP run life and lowers replacement costs.

Xiaonan (Lawrence) Lu, Laszlo Soos, Dr. Sunder Ramachandran, Joseph McManus, Baker Hughes

With the exploration and production industry facing low oil prices and a severe halt to global drilling activity, brownfields will likely be the major contributor to oil production in the near term. This reality places greater emphasis on keeping operating costs low and maximizing the uptime of production equipment like artificial lift systems.

Electrical submersible pumping is a versatile, widely used artificial lift method known for reliably lifting moderate-to-high volumes of fluids from wells, Fig. 1. While electrical submersible pumps (ESP) are highly adaptable to applications including deviated wells, offshore, and environmentally sensitive areas, their efficiency and run life in harsher operating environments can be severely compromised, which threatens the economics of the producing asset.

Fig. 1. A typical Permian basin-type completion, showing the position of the ESP in the well.
Fig. 1. A typical Permian basin-type completion, showing the position of the ESP in the well.


The condition of the produced fluid poses several potential threats to the long-term operation of an ESP. For example, producing wells with high quantities of sand and formation solids generate an abrasive-slurry flow that raises the risk of abrasion wear on the internal surfaces of the ESP. Impingement-induced metal loss on downhole lift equipment, tubing and pipelines is well-known and has been widely studied.1 One solution, limiting production rates to keep overall fluid velocities lower, may help extend run life by reducing the severity of particle impingement and abrasion. But it is far from ideal, since it can lead to curtailed production and a loss of revenue from the well.

Deploying ESPs in corrosive wells also threatens long-term system operability. Corrosion can arise in different ways and from different sources. Experience has shown that ESPs working in high-temperature, high-shear, and saline environments, with elevated concentrations of carbon dioxide (CO2) or hydrogen sulfide (H2S), are prone to failure—both in the ESP itself and in the cable providing electrical power to the downhole system.2

Another oilfield corrosion mechanism comes in the form of microbiologically influenced or induced corrosion. It is caused by sulfate-reducing bacteria and other forms of anaerobic and aerobic bacteria. These bacteria can lead to pitting corrosion on the ESP’s metal surfaces, and can form slimy residues that plug downhole equipment and the formation itself.

Wells with scaling, asphaltene or paraffin-forming tendencies also have a negative impact on an ESP system’s performance and run-life. Scale formation in the ESP can plug the flow passages of the pump stages and can adhere to the outside surfaces of the motor, thus causing the unit to run at an elevated temperature.

Asphaltene and paraffin deposition also can impair ESP operations. Asphaltenes have presented problems leading to ESP failures and tubing plugging, particularly in CO2-miscible gas flooding applications.3 These problems can often be minimized by using a downhole inhibitor-chemical treatment.

If these challenges are not addressed properly, they will lead to more frequent workovers, to repair or replace the ESP. Such challenges become even costlier in fields that lack personnel with sufficient expertise in ESP operation, production optimization, event analysis, and failure prediction.


Maximizing the long-term productivity of a well requires lift solutions that are customized to the well—its production profile, fluid composition, temperature and pressure—and chemical treatments that mitigate the challenges described above. Baker Hughes offers comprehensive lift systems and production chemicals that, taken together, can optimize each well’s production rates, with fewer failures and workovers.

Fig. 2. Every stage of the extreme-duty pump is built with tungsten-carbide flanged sleeves and bushings.
Fig. 2. Every stage of the extreme-duty pump is built with tungsten-carbide flanged sleeves and bushings.

Sand solutions. The first consideration to extending ESP run life in high-solids environments typically centers on proper material selection. In some cases, the proper design and application of ESPs with abrasion-resistant inserts is sufficient to extend run time.

This was the case for a U.S. operator in the Rocky Mountains region, who experienced significant downtime and extensive damage to several ESP installations in wells containing formation sand in the produced fluid. ESP run time under these harsh conditions averaged 73 days, and workover-related downtime resulted in 2,600 bbls of lost oil production over an eight-month period.

Baker Hughes worked with the operator to develop a lift system that could withstand the highly abrasive sand while decreasing workovers and increasing production. The solution comprised installing an ESP built with abrasive-resistant tungsten carbide-flanged sleeves and bushings at each stage, which decreased both radial wear and down thrust, Fig. 2.

Fig. 3. An impeller without abrasion-resistant module protection showed significant wearing of its skirt ring and lower shroud of the inlet side after just 110 days of operation (left). The extreme-design impeller exhibited minimal wear after 644 days of run time (right).
Fig. 3. An impeller without abrasion-resistant module protection showed significant wearing of its skirt ring and lower shroud of the inlet side after just 110 days of operation (left). The extreme-design impeller exhibited minimal wear after 644 days of run time (right).

The new pump withstood the well’s highly abrasive downhole conditions. Run time increased to 644 days, an 800% increase compared to the run life of non-abrasion-resistant pumps, Fig. 3. The solution lowered the operator’s ESP lifting costs from $37/bbl to less than $2/bbl of oil.

Abrasion-resistant inserts in ESP systems can help protect the internals of the pump from abrasive wear. Outside of the ESP and in carbon steel tubing, high solids can contribute to significant erosion corrosion. In these instances, the use of corrosion inhibitors is a proven solution.4

Mitigating scale. Preventing scale formation in ESP systems often requires implementing some combination of scale-resistant coatings and scale inhibitors.

An operator in California wanted to increase production from three wells that were on rod lift and averaged 57 bopd, combined. An analysis of rod samples from the wells revealed significant calcium carbonate scale deposits. Long perforation intervals in the shale formations made reliable chemical treatment challenging.

The service provider and operator worked together to develop an alternative ESP method that would decrease operating expenses and increase production. The ESP system would have to reliably operate in wells at a TVD of approximately 6,000 to 7,000 ft and be designed with scale-inhibition capabilities. The solution included a Baker Hughes FLEXPump series ESP with a protective, scale-resistant coating and coupled to a variable speed drive (VSD). The pump was designed with a balancing technology that improved thrust efficiency and provided a wider operating envelope for the system, with possible flowrates ranging from 350 to 1,250 bfpd.

A scale inhibitor also was introduced to the system on a continuous basis. To overcome the difficulty posed by the long perforation intervals, chemical usage was doubled or tripled during scale squeezes. The continuous treatment injection rate was increased or decreased, based on scaling tendency results determined from frequent water analysis or scale samples taken from the well.

The ESP coating, coupled with the continuous inhibitor treatment, reduced scale growth in the pump and kept scale in the liquid phase, as it was carried through the ESP system. As a result, workover and rig costs were reduced dramatically. At the same time, the ESP’s wider operating range provided flexibility for low flowrates and increased production 79%, from 57 bopd with rod lift to 102 bopd. This successful, first application prompted the operator to install additional ESP systems in other rod-lifted wells.

Controlling corrosion. The optimal corrosion mitigation strategy for ESP systems in corrosive well environments includes some combination of proper metallurgy, coatings, and chemical corrosion inhibitor and biocide treatments. While ESPs constructed of abrasion- or corrosion-resistant alloys are a cost-effective strategy in some wells, other production scenarios will require deploying conventional ESPs with corrosion inhibitor.

Wells with high CO2 and/or H2S content generate a highly corrosive environment that typically requires continuous injection of corrosion inhibitor. Laboratory screening tests are required to select the right inhibitor product and suitable concentration range. An ongoing monitoring system also must be in place to optimize chemical dosage in the well and allow for adjustments in the treatment program, should production conditions change.

Care must be taken to select monitoring locations that provide the most accurate representation of the conditions experienced by the ESP. It also is important to select a corrosion monitoring technique that affords a fast response time in the event of a problem. Electrical resistance (ER) measurement techniques are fast enough to allow for optimization and changes to the type of corrosion inhibitor used. The reliability and rugged construction of ER probes makes them suitable for downhole deployment, closer to the ER system. In fact, the service provider has developed a prototype ER probe that can be integrated into the ESP system for continuous downhole monitoring and the delivery of actionable data, to improve maintenance scheduling and mitigate problems before damage occurs.5

An operator in the Williston basin area, in North Dakota’s Bakken, faced production scenarios that included high-salinity brines with calcium deposits, wells with high amounts of CO2, and temperatures reaching more than 300° F. In addition, the ESP system generated a high-shear environment, contributing to frequent corrosion failures.

Upon reviewing these field conditions, the service provider’s application engineers recommended a corrosion inhibitor formulated specifically for high-temperature and high-shear conditions. The inhibitor was screened in laboratory tests, using a brine taken from the Bakken field that was heated to 300° F. The new inhibitor provided better inhibition, compared to the operator’s incumbent product in these tests. Further testing showed no solid formation nor product separation at temperatures of 400° F, making the inhibitor suitable for ESP systems in high temperatures.

The inhibitor was then tested in two wells in the field, and compared to the performance of two untreated wells. The ESPs in the untreated wells had an average run time of 122 days, while the two wells treated with the high-temperature inhibitor had ESP run times of 188.5 days—an increase of 54%. Furthermore, the inhibitor reduced the percentage of joints with more than 30% wall loss. These results convinced the operator that the new inhibitor would reliably improve the long-term operation of its ESPs and increase production volumes from its wells.

Minimizing asphaltene and paraffin impacts. Mitigating asphaltene and paraffin challenges typically requires careful selection of the proper materials of construction for the pump’s seals, applying a downhole inhibitor-chemical treatment, or both.

An operator in Canada selected the downhole inhibitor treatment option for a CO2 flood-enhanced oil recovery (EOR) operation. The operator experienced frequent ESP equipment damage and production losses, due to asphaltene fouling. With the shortened run life of the ESP systems driving up its CAPEX spend, the operator required an alternative to the incumbent asphaltene inhibitor program, which was supplied by another service provider.

The operator’s engineering group worked with the local Baker Hughes production team to develop a production optimization solution that paired the service provider’s existing ESP equipment, which was already installed in the field, with a customized asphaltene inhibitor treatment program.

Fig. 4. The production optimization solution increased ESP run life in every well and lowered ESP replacement CAPEX by 80%.
Fig. 4. The production optimization solution increased ESP run life in every well and lowered ESP replacement CAPEX by 80%.

The customized treatment was designed and trialed on five of the operator’s most problematic wells. The incumbent chemical was replaced with the new inhibitor treatment, which was applied on a continuous basis. Once in place, the optimized chemical treatment helped increase the run life of the ESP systems by 36%, to 390%, with an average increase of 133% across the five trial wells, Fig. 4. When an ESP failure finally occurred, a teardown analysis showed no presence of asphaltene solids, which suggested that the new inhibitor program eliminated asphaltene fouling in the ESP systems.

The production optimization solution improved ESP system run life by more than 100% and helped the operator reduce its ESP system replacement CAPEX spending by 80% over a five-year period. Annual oil production increased across the five trial wells, with a corresponding reduction in lifting costs.

Treatment options for unique applications. Certain field conditions require service providers to develop novel treatments to ensure the long-term integrity of downhole assets in cost-effective ways. For example, wells with multiple production issues—such as scale and corrosion—might only have one capillary tube installed for chemical delivery. This has prompted the development of multifunctional chemicals that include corrosion inhibitors, scale inhibitors, and other additives in the same formulation and which can be delivered down a single capillary. Such combination products have been deployed in ESP-lifted wells in the Permian basin, where they successfully prevented the deposition of scale on the tubing and in the pump and mitigated against corrosion.6

In situations in which a well must be shut-in, corrosion risks can cause irreversible damage to the ESP and other downhole equipment. A good well pickling strategy can help keep the downhole equipment protected during shut in. Such a strategy, which includes corrosion inhibitors that mitigate against localized, sour, and microbiologically-influenced corrosion, helps ensure that a well can be brought back online without incurring workover and repair costs.


As market forces push operators to find further field optimization opportunities, service providers must advance new solutions that improve the operating efficiency of their artificial lift and chemical treatment systems.

One major advancement area is focused on automated solutions and remote surveillance and control. For example, Baker Hughes has remote artificial lift monitoring solutions that provide real-time transmission and review of artificial lift operational data. The solution platform affords improved communication and collaboration between engineers and operators with real-time diagnostics and analytical capabilities. The platform lets the operator make more informed operations decisions with fewer trips to the field and reduced well intervention costs and downtime.

On the chemical treatment side, remote chemical automation and tank monitoring services improve chemical service efficiency with minimal human interaction. Chemical pump controllers sense when conditions change downhole and then automatically adjust the chemical feed rate accordingly. In addition, wireless tank level monitors measure product availability and chemical tank usage, which can be accessed from any secure Internet connection, to improve the chemical ordering process.

Advances such as these, incorporated into a comprehensive ESP and treatment chemical service offering, will be key to helping operators optimize their field production while weathering current market challenges.


  1. Jordan, K., “Erosion in multi-phase production of oil and gas,” CORROSION/98, Paper No. 58, Houston, Texas, NACE International, 1998.
  2. Lea, J. F., M. R. Wells, J. L. Bearden, “Electrical submersible pumps: On and offshore problems and solutions,” SPE paper 28694-MS, presented at the SPE International Petroleum Conference and Exhibition of Mexico, Veracruz, Mexico, Oct. 10-13, 1994.
  3. Yin, Y. R., A. T. Yen, S. Asomaning, “Asphaltene inhibitor evaluation in CO2 floods: Laboratory study and field testing,” SPE paper 59706-MS, presented at SPE Permian basin Oil and Gas Recovery Conference, Midland, Texas, March 21-23, 2000.
  4. Ramachandran, S., R. Peppeard, M. H. Nguyen and T. Hinojosa, “Corrosion inhibition in high-velocity, sand-containing pipelines and its implication on economic chemical treatment,” CORROSION/2004, Paper No. 04660, Houston, Texas, NACE International, 2004.
  5. Chandran, A. “Asset optimization using downhole corrosion sensor for electrical submersible pumps,” SPE paper 188448-MS, presented at the Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, Nov. 13-16, 2017.
  6. Rogers, P., B. Lundy, S. Ramachandran, J. Ott, D. Poelker, D. Lee, C. Stevens, C. Bounds, M. Sullivan, “Multifunctional chemical for simultaneous dissolution of iron sulfide, corrosion inhibition, and scale inhibition” SPE paper 193619-MS, presented at the SPE International Conference on Oilfield Chemistry, Galveston, Texas, April 8-9, 2019.

The Authors ///

Xiaonan (Lawrence) Lu is a senior product manager for the Baker Hughes Artificial Lift Systems business. He has 16 years of experience in artificial lift, with broad expertise across conventional, unconventional, subsea, thermal recovery and specialty applications. Mr. Lu holds a degree from Petroleum University in China, and has authored multiple patents.
Laszlo Soos manages the Integrity Management product line within the Baker Hughes Oilfield and Industrial Chemicals business. During his 17-year tenure at Baker Hughes, he has held various roles in technology, sales and operations, working in Europe, Turkey and the U.S. Mr. Soos is a graduate of the Technical University of Budapest, Hungary.
Dr. Sunder Ramachandran Ramachandran is a technology advisor for the Baker Hughes Oilfield and Industrial Chemicals business. He began his tenure with Baker Hughes in 1996. Dr. Ramachandran received the Distinguished Service Award from National Association of Corrosion Engineers (NACE) in 2019 and will receive the Technical Achievement Award from NACE in 2020. He holds a PhD in chemical engineering from Colorado State University.
Joseph McManus is a product line manager within the Baker Hughes Artificial Lift business. He has worked in various roles throughout that business since 2004 and holds a degree from the University of Tulsa.

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