Using ESP systems for artificial lift

Pumps & Systems, April 2008

In the oil and gas industry, electric submersible pump (ESP) systems are probably best known as an effective artificial lift method of pumping production fluids to the surface. ESPs are especially effective in wells with low bottomhole pressure, low gas/oil ratio, low bubblepoint, high water cut or low API gravity fluids.Over the last several years, ESP technology has developed a reputation as a low-maintenance, cost-effective alternative to vertical turbine, split case and positive displacement pumps in various fluid-movement surface applications in the petroleum industry.

Artificial Lift Technologies

Artificial lift uses some means to increase the flow of liquids (i.e., crude oil or water with some amount of gas included) to the surface of a production well. This is usually achieved by (1) a mechanical device inside the well, such as a pump; (2) decreasing the weight of the liquid/gas mixture via high pressure gas or (3) improving the lift efficiency of the well via velocity strings. An artificial lift system is needed in wells with insufficient pressure in the reservoir to boost the liquid to the surface. Also, these systems are sometimes used in flowing wells to increase the naturally occurring flow rate.

More than 60 percent of producing oil wells require some type of assisted lift technology to produce the recoverable oil. Several artificial lift (or pumping) technologies are employed, including plunger lift, beam/sucker rod pumps, gas lift, progressive cavity pumps (PCP) or electric submersible pumps.

Plunger Lift

This artificial lift method is used primarily in gas wells to remove relatively small volumes of liquid. Functionally, a plunger-lift system provides a mechanical interface between the produced liquids and gas. Using the well's own energy for lift, liquids are pushed to the surface by the movement of a free-traveling piston (plunger) traveling from the bottom of the well to the surface. This mechanical interface eliminates liquid fallback, which boosts the well's lifting efficiency. In turn, the reduction of average flowing bottomhole pressure increases inflow.

Plunger travel is normally provided by formation gas stored in the casing annulus during a well shut-in period. As the well is opened and the tubing pressure decreases, the stored casing gas moves around the end of the tubing and pushes the plunger to the surface. This intermittent operation is repeated several times per day.

Sucker Rod Pumps

Beam pumps, rod pumps or sucker rod pumps refer to an artificial lift system that uses a surface power source to drive a downhole pump assembly. A beam and crank assembly at the surface (often called a "pump jack") creates reciprocating motion, which is converted to a vertical motion in a sucker-rod string that connects to the downhole pump assembly. The pump contains a plunger and valve assembly to impart vertical fluid movement. Due to its long history, sucker rod pumping is a very popular means of artificial lift. Roughly two-thirds of the producing oil wells around the world use this type of lift. Limitations to this system technology arise with deeper and/or more deviated wells. Sucker rod pumps are not generally considered applicable to offshore installations.

Gas-Lift Systems

Gas-lift systems that inject gas into the crude are sometimes used in conjunction with surface operating reciprocating pumps or horizontal centrifugal pumps. However, these systems become far less efficient in deeper, deviated wells. Gas-lift systems often increase the degree of component flow constriction caused by scaling and paraffin crystal accumulation. Additionally, these techniques require an abundant supply of gas to be stored at the surface. Gas that is separated and vented is not easily retained for re-injection, and gas that is re-injected rapidly becomes contaminated with oxygen, carbon monoxide and hydrogen sulphide that can corrode production string components. Older gas-lift systems (sometimes prominent in offshore applications) burdened with high water cut are being converted more frequently to ESP systems.

Progressive Cavity Pumps

The PCP is a closely related technology to the ESP. PCPs consist of a helical bore that rotates inside a similar helical cavity. The rotation of the bore creates cavities with negative pressure (vacuum) to open and close, forcing fluid up through the pump body. The PCP offers proven performance in extracting crude oil at high viscosity. However, PCPs are vulnerable to damage from abrasive materials and are limited to well depths of approximately 5000-ft. PCPs do not perform well in deviated wells.

ESP Systems

About 15 to 20 percent of almost one million wells worldwide are pumped with some form of artificial lift employing electric submersible pumps. In addition, ESP systems are the fastest growing form of artificial lift pumping technology. They are often considered high volume and depth champions among oil field lift systems.

Found in operating environments all over the world, ESPs are very versatile. They can handle a wide range of flow rates from 70-bpd to 64,000-bpd or more and lift requirements from virtually zero to as much as 15,000-ft of lift. As a rule, ESPs have lower efficiencies with significant fractions of gas, typically greater than about 10 percent volume at the pump intake. Given their high rotational speed of up to 4000-rpm and tight clearances, they are also only moderately tolerant of solids like sand. If solid-laden production flows are expected, special running procedures and pump placement techniques are usually employed. When very large amounts of free gas are present, downhole gas separators and/or gas compressors may be required in lieu of a standard pump intake.

ESP systems can be used in casing as small as 4.5-in outside diameter and can be engineered to handle contaminants commonly found in oil-aggressive corrosive fluids such as H2S and CO2, abrasive contaminants such as sand, exceptionally high downhole temperatures and high levels of gas production. Increasing water cut has been shown to have no significant detrimental effect on ESP performance. ESPs have been deployed in vertical, deviated and horizontal wells, but they should be located in a straight section of casing for optimum run life performance.

On a cost-per-barrel basis, ESPs are considered economical and efficient. With only the wellhead and fixed or variable-speed controller visible at the surface, ESP systems offer a small footprint and low-profile option for virtually all applications, including offshore installations. Table 1 provides a summary of ESP artificial lift applications.

Table 1. ESP Artificial Lift Application Summary.

The Anatomy of an ESP System

In ESP systems, an electric motor and a multistage centrifugal pump run on a production string, connected back to a surface control mechanism and transformer via an electric power cable (see Figure 1 below). Careful consideration must be given to each downhole and surface component of the system in the design stage. An ESP can pump intermittently or continuously. Because an ESP can be easily adapted to automation and control systems, numerous surface control and communication devices are available. Additionally, the downhole components can vary depending on the specific application or conditions.


Figure 1. Multistage Centrifugal PumpDownhole Components Multistage Centrifugal Pump—The multistage centrifugal pump consists of stages with rotating impellers and stationary diffusers cast from a Ni-resist high-nickel iron containing both abrasion and corrosion resistant properties. Pump stages incorporate many optional features including special bearings and coatings. These features allow the pump to handle harsh abrasives, salt containing fluids that form deposits of scale and paraffin or asphaltenes that gradually coat the pump stages and disrupt normal flow. Materials used in manufacturing pump components vary depending upon the corrosive and abrasive nature of the well environment. The impellers are mounted on a shaft made of Nitronic 50, Monel, Inconell or other high-strength alloy or stainless steel.

Due to limited well casing diameters, the lift or head developed by an individual stage is relatively low. Stages must be stacked together to meet the lift requirements for various applications. Each stage of the multistage centrifugal pump adds energy to the fluid in the form of increased velocity and pressure. The impeller accelerates the fluid and increases the kinetic energy, which is then converted into potential energy (pressure) in the diffuser that redirects the flow to the next impeller. Diffusers also act as a bearing surface, providing additional stability to the pump shaft. The fluid flow is described by the fundamentals of classical physics—conservation of mass, momentum and energy.

Motor—The energy to turn the pump comes from a high voltage (3 to 5 kV) alternating current source to drive a special motor that can work at high temperatures up to 500-deg F and high pressures up to 5000-psi and from deep wells up to 15,000-ft deep with high energy requirements up to 1000-hp. Submersible two-pole, squirrel cage, induction electric motors are manufactured in a variety of horsepower ratings, operating voltages and currents to meet pressure extremes and temperature requirements. The motor size is designed to lift the estimated volume of production. Wellbore fluids passing over the motor housing act as cooling agents. The motor is powered from the surface via submersible electric cable.

Temperature extremes and contaminants are primary causes in early motor failure. Completely sealed, a downhole ESP motor must have exceptional capabilities to dissipate or withstand severe inner core temperatures—requiring high temperature insulation ratings. The method of assembly and quality of the winding, including the pattern, are critical design characteristics. The winding process—including the resin used, the application process and the steps taken to prevent voids—are critical measures in constructing a motor that can withstand destructive energies encountered downhole.   

Seal Section—The seal section is located between the motor and the intake and performs the following functions:

  • Houses the thrust bearing that carries the axial thrust developed by the pump
  • Isolates and protects the motor from well fluids
  • Equalizes the pressure in the wellbore with the pressure inside the motor
  • Compensates for the expansion and contraction of motor oil due to internal temperature changes  

Seal sections can be used in tandem configurations for increased motor protection. They are available in bag type and labyrinth-style designs to meet specific applications. Gas Separator/Compressor—The intake section of a submersible pump functions as a suction manifold, feeding the well fluid to the pump. In standard applications, an intake section can be a simple inlet hole adapter attached between the seal section and the pump housing. In applications with higher gas/oil ratios (GOR) and lower bottom-hole pressures, the well fluid may contain significant amounts of free gas. A gas separator, designed to separate the gas from the well fluid before it enters the pump, replaces the intake section in such applications.In applications where the amount of free gas cannot be handled efficiently by rotary gas separators, tandem rotary gas separators, a high-volume separator or a gas compressor can be used. Use of a gas compressor introduces a compression chamber downstream from tandem gas separators. The compression chamber allows free gas to be compressed back into the solution while simultaneously breaking large gas bubbles into an increasingly homogenized solution, which a submersible pump can handle without gas locking. Downhole Sensor—A rugged downhole sensor and companion surface interface unit enables reliable, accurate retrieval of critical real-time system and wellbore performance parameters. Multi-data channel sensors can measure intake pressures, wellbore and motor oil or winding temperature, pump discharge pressure, vibration, current leakage and flow rate. ESP system control and alarms are achieved by real-time monitoring of actual downhole readings, reducing nuisance shutdowns caused by inaccurate overload and underload amp load settings. Surface interface can be accomplished via permanent digital readout, handheld data logger or laptop computer. Remote monitoring of data from web-based computers is also possible. 

Figure 2. Power CablesPower Cable—Available in flat or round configurations, specially engineered and manufactured cable systems provide dependability in the harsh, hot, gassy and corrosive conditions found in most downhole ESP applications. A variety of materials, duty ranges and constructions allow selection of a particular cable for specific applications. The cable is connected to the top of the motor, runs up the side of the pump, is strapped to the outside of every joint of tubing from the motor to the surface of the well and is extended on the surface to the control junction box. In most cases, the cable is flat as it stretches from the motor up beside the pump to the tubing, at which point the flat cable is spliced to a round one. Most power cables have a metal shield to protect them from damage. Proper selection of cabling can greatly enhance the overall system performance, since substantial power losses can occur in conducting power across a cable that may extend as long as 15,000-ft, nearly three miles.   

Surface Components

Tubing Head—The tubing head is designed to support the downhole tubing string and provide a seal to permit the power cable to pass through the wellhead. This seal is usually designed to hold a minimum of 3000-psi.   

Fixed or Variable Speed Controllers and Drives—Intelligent RTU programmable controllers (fixed speed or variable speed) maintain the proper flow of electricity to the pump motor. They allow the well to be operated continuously or intermittently, or be shut off. They also provide protection from power surges or other electricity changes.

A variable speed drive (VSD) offers ESP systems continuous duty variable flow and pressure control, which in turn increase productivity, process control flexibility and energy savings. Direct speed control over the pump motor provides maximum system efficiency and reduced maintenance when compared with across the line (full voltage) operation. The VSD provides the essential reduced voltage starting characteristics of a soft starter combined with continuous duty variable frequency operation. This directly results in increased life of the mechanical equipment and reduced incidence of downtime.

Transformers—A transformer is an electrical device that takes electricity of one voltage and changes it into another voltage. Transformers are usually located at the edge of the lease site. The transformer changes electricity provided via commercial power lines to match the voltage and amperage requirements of the ESP motor.   

Electrical Supply System—Electricity is generally provided by a commercial power distribution system. The highest available voltage produces the most efficient performance. In offshore applications, the nature of the power supply is strictly dependant on a portable source—namely that of a diesel generator. In a situation where generator-fed power is the primary supply, strict design requirements must be recognized in order to prevent a costly, time-consuming failure and/or redesign and retrofit. Selection of the generator requires careful calculation of the system power requirements it is meant to supply.

Surface Applications

Figure 3. Surface pumping systems features a multistage centrifugal pump based upon downhole ESP technology.

Electric submersible pump (ESP) systems are now providing specific solutions to a wide range of surface fluid-movement applications. These systems feature a direct-drive, multistage centrifugal design suited for most high-pressure, low- to medium volume and environmentally sensitive applications. Building on the rugged oil field ESP technology, these surface pumping systems (SPS) (Figure 3) have developed a reputation as an alternative to vertical turbine, split-case (SC) and positive displacement (PD) pumps.

Table 2 provides a comparison of the SPS to both positive displacement reciprocating and centrifugal split-case (SC) pumps. While some of the issues listed impact initial design considerations, others provide a comparison of long-term operational differences.

Table 2. SPS vs. other surface pumping technologies.Offering a low surface profile coupled with quiet vibration-free operation, these surface pumps can be electric-, gas- or diesel-powered. They can typically handle up to 2000-gpm (64,000-bfpd) and discharge pressures ranging up to 6000-psi. They feature design flexibility that facilitates onsite installation and maintenance with minimal site preparation.

SPS technology has proven effective for numerous fluid-handling applications in the petroleum industries, including:

  • Produced water injection
  • Produced water disposal
  • Waterflood injection
  • Wash water circulation 
  • Pipeline booster
  • CO2 flood injection/booster
  • Crude oil transfer
  • NGL/propane, ethane, amine and other gas services
  • Condensate transfer
  • FPSO fluid handling
  • Power fluid pumps for downhole jet/hydraulic pumps


As system design engineers and operators evaluate costs, maintenance requirements, environmental impact, efficiency and flexibility, they are finding more applications where multistage centrifugal pumping systems provide advantages for downhole and surface applications.