Electrical submersible pumps

The electrical submersible pump, typically called an ESP, is an efficient and reliable artificial-lift method for lifting moderate to high volumes of fluids from wellbores. These volumes range from a low of 150 B/D to as much as 150,000 B/D (24 to 24,600 m³/d). Variable-speed controllers can extend this range significantly, both on the high and low side. The ESP’s main components include:

• Multistaged centrifugal pump
• Three-phase induction motor
• Seal-chamber section
• Power cable
• Surface controls

The components are normally tubing hung from the wellhead with the pump on top and the motor attached below. There are special applications in which this configuration is inverted.

As area in which ESPs are applied extensively, THUMS Long Beach Co. was formed in April 1965 to drill, develop, and produce the 6,479-acre Long Beach unit in Wilmington field, Long Beach, California. ESPs have been the primary method of lifting fluids from the approximately 1,100 deviated wells from four man-made offshore islands and one onshore site.

History of ESPs

In 1911, 18-year-old Armais Arutunoff organized the Russian Electrical Dynamo of Arutunoff Co. in Ekaterinoslav, Russia, and invented the first electric motor that would operate in water. During World War I, Arutunoff combined his motor with a drill. It had limited use to drill horizontal holes between trenches so that explosives could be pushed through. In 1916, he redesigned a centrifugal pump to be coupled to his motor for dewatering mines and ships. In 1919, he immigrated to Berlin and changed the name of his company to REDA. In 1923, he immigrated to the United States and began looking for backers for his equipment. Initially, he approached Westinghouse but was turned down because their engineers thought it would not work because it was impossible under the laws of electronics.

In 1926, at the American Petroleum Institute (API) conference in Los Angeles, two parties joined together to start the ESP industry. Just before this conference, Arutunoff had joined forces with Samual VanWert, a sucker-rod salesman who saw the potential of the new device. Together, they initiated a prototype test in a Baldwin Hills oil well. The second party involved Clyde Alexander, a vice president of a 9-year-old Bartlesville, Oklahoma, oil company—Phillips Oil Co. He was at the conference to look for ways of lifting oil from wells that also required producing large amounts of water. Arutunoff and Phillips signed a contract to field test the concept in the El Dorado field near Burns, Kansas. After a successful test, Bart Mfg. was organized. On 15 March 1930, Phillips sold his rights to Charley Brown, a Bart stockholder and executive in Marland Oil Co., and Arutunoff. This was the birth of REDA Pump Co. In 1969, REDA merged with TRW Inc., and in 1987, it was sold to Camco Intl., which merged with Schlumberger in 1998.

In 1957, a second company was established. This product line started at the Byron Jackson Pump facility in Vernon, California. Byron Jackson was a division of Borg Warner Corp. In 1959, the oilfield product line of Byron Jackson Pump was moved to Tulsa and quickly became known as a "BJ" pump. In 1979, it became Centrilift Inc., a subsidiary of Borg Warner Corp., and was moved to Claremore, Oklahoma, in 1980. Just after the relocation in 1980, Centrilift was sold to Hughes Tool Co. Then, in 1987, Hughes Tool and Baker International merged to become Baker Hughes Inc.

In 1962, Goulds Pump Oil Field Submergible Division approached Franklin Electric to find a better motor for their oilfield-pump product. By 1967, they had designed a new product and had formed a joint venture company, Oil Dynamics Inc. (ODI). In 1997, ODI was sold to Baker Hughes Inc., and its product line was merged into Centrilift’s.

The story behind the third company becomes a little more convoluted. In 1965, Hydrodynamics was formed as a part of Peerless Pump to develop an oilfield submersible product. After limited financial success, it was sold to FMC Corp. and renamed Oiline. In 1976, it was sold again, this time to Kobe, and became Kobe Oiline. Kobe was sold to Trico in 1983, but the Kobe Oiline product was spun off to Baker International, and it became Bakerlift Systems. Trico had also just purchased the Standard Pump water-well line from REDA. A side branch to this tree starts with the emergence of Western Technologies in 1978. It was sold to Dresser Industries and renamed WesTech in 1982. Then, in 1985, it was sold to Bakerlift Systems. When Baker International and Hughes merged in 1987, the US operation of Bakerlift was divested and sold to Trico, but Baker Hughes retained the international segment of the Bakerlift business. Trico’s product line was made up of equipment from Kobe Oiline, Standard Pump, WesTech, and Bakerlift Systems. It was renamed Trico Sub Services. On another side branch, ESP Inc. was formed in 1983. Wood Group purchased it in 1990. Then, in 1992, Trico Sub Services was purchased by Wood Group and was merged into ESP Inc.

ESP system

Examples of normal ESP system configuration are shown in Figs. 1 and 2. It shows a tubing-hung unit with the downhole components comprising of:

• A multistage centrifugal pump with either an integral intake or separate, bolt-on intake
• A seal-chamber section
• A three-phase induction motor, with or without a sensor package

The rest of the system includes a surface control package and a three-phase power cable running downhole to the motor. Because of the ESP’s unique application requirement in deep, relatively small-bore casings, the equipment designer and manufacturer are required to maximize the lift of the pump and the power output of the motor as a function of the diameter and length of the unit. Therefore, the equipment is typically long and slender. The components are manufactured in varying lengths up to approximately 30 ft, and for certain applications, either the pump, seal, or motor can be multiple components connected in series.

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  Fig. 1-ESP system configuration [after Centrilift Graphics, Claremore, Oklahoma (2003)].

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  Fig. 2—Schematic of typical ESP system. [Courtesy of Schlumberger (REDA).]

Throughout their history, ESP systems have been used to pump a variety of fluids. Normally, the production fluids are crude oil and brine, but they may be called on to handle:

• Liquid petroleum products
• Disposal or injection fluids
• Fluids containing free gas
• Some solids or contaminates
• CO₂ and H₂S gases or treatment chemicals

ESP systems are also environmentally esthetic because only the surface power control equipment and power cable run from the controller to the wellhead are visible. The controller can be provided in a weatherproof, outdoor version or an indoor version for placement in a building or container. The control equipment can be located within the minimum recommended distance from the wellhead or, if necessary, up to several miles away. API RP11S3 provides the guidelines for the proper installation and handling of an ESP system. All the API recommended practices for ESPs are listed in Table 1.

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  Table 1

Advantages

ESPs provide a number of advantages.

• Adaptable to highly deviated wells; up to horizontal, but must be set in straight section.
• Adaptable to required subsurface wellheads 6 ft apart for maximum surface-location density.
• Permit use of minimum space for subsurface controls and associated production facilities.
• Quiet, safe, and sanitary for acceptable operations in an offshore and environmentally conscious area.
• Generally considered a high-volume pump.
• Provides for increased volumes and water cuts brought on by pressure maintenance and secondary recovery operations.
• Permits placing wells on production even while drilling and working over wells in immediate vicinity.
• Applicable in a range of harsh environments.

Disadvantages

ESPs have some disadvantages that must be considered.

• Will tolerate only minimal percentages of solids (sand) production, although special pumps with hardened surfaces and bearings exist to minimize wear and increase run life.
• Costly pulling operations and lost production occur when correcting downhole failures, especially in an offshore environment.
• Below approximately 400 B/D, power efficiency drops sharply; ESPs are not particularly adaptable to rates below 150 B/D.
• Need relatively large (greater than 4½-in. outside diameter) casing size for the moderate- to high-production-rate equipment.

Long life of ESP equipment is required to keep production economical.

Components of an ESP system

• ESP centrifugal pump
• ESP seal section
• ESP motors
• ESP power cable
• ESP surface motor controllers
• ESP optional components

Installation and handling

Although there can be many factors that influence or directly affect the run-life of an ESP system, proper installation and handling procedures are critical. The recommended installation and handling procedures are detailed in API RP11S3. In addition to these, manufacturers should be contacted for specific recommendations on their equipment.

Maintenance and troubleshooting

Operating, maintenance, and troubleshooting recommendations are covered in API RP11S. Additionally, much can be learned from the disassembly of the ESP components after they are pulled from the well. This is true whether they are in reusable condition or have been through a catastrophic failure. The equipment and the wellbore always indicate items that can be changed or improved. API RP11S1 provides guidelines on the disassembly of ESP components and the evaluation of the findings. Also, each ESP manufacturer has recommendations and guidelines on this topic.

Baillie provides a practical checklist for optimizing the life of an ESP system. It covers all the critical or sensitive steps, from the design and manufacture to the operational procedures. There have been several papers written that deal with literature on ESP application problems and solutions. These papers summarize and categorize ESP reference literature by a number of different application or problem topics. They are an excellent bibliography set for troubleshooting application-related problems or issues.

Noteworthy papers in OnePetro

Lea, J. F., Wells, M. R., Bearden, J. L., Wilson, L., & Shepler, R. (1994, January 1). Electrical Submersible Pumps: On and Offshore Problems and Solutions. Society of Petroleum Engineers. doi:10.2118/28694-MS

Powers, M. L. (1994, May 1). The Depth Constraint of Electric Submersible Pumps. Society of Petroleum Engineers. doi:10.2118/24835-PA

Scott, P. A., Bowring, M., & Coleman, B. (1991, January 1). Electrical Submersible Pumps in Subsea Completions. Society of Petroleum Engineers. doi:10.2118/23050-MS

Online multimedia

Noonan, Shauna. 2013. Electric Submersible Pump (ESP) Reliability. https://webevents.spe.org/products/electric-submersible-pump-esp-reliability

External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Alternate ESP configurations

Use of ESPs in harsh environments

ESP system selection and performance calculations

PEH:Electrical_Submersible_Pumps

Page champions

Jose Caridad, BSME & MSc ME