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PEH:Electrical Submersible Pumps

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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter 13 – Electrical Submersible Pumps

John Bearden, Centrilift, Baker Hughes Inc.

Pgs. 634-720

ISBN 978-1-55563-118-5
Get permission for reuse

Introduction - What Is an Electrical Submersible Pump? 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: a multistaged centrifugal pump, a three-phase induction motor, a seal-chamber section, a power cable, and 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. This chapter provides a general understanding of the ESP artificial-lift method. The topics covered include: the ESP system components and accessories, principles of operation, ESP system selection and performance calculations, installation and handling, and maintenance and troubleshooting. In addition, references are given to lead the reader to more-detailed operation and performance information.


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 Intl. 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 Intl., 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 Intl. and Hughes merged in 1987, the U.S. 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

The normal ESP system configuration is shown in Fig. 13.1. 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; and 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.

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; and fluids containing free gas, some solids or contaminates, and 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. [3] All the API recommended practices for ESPs are listed in Table 13.1, some of which are discussed later in this chapter.

Centrifugal Pump

The ESP is a multistage centrifugal type. A cross section of a typical design is shown in Fig. 13.2. The pumps function is to add lift or transfer pressure to the fluid so that it will flow from the wellbore at the desired rate. It accomplishes this by imparting kinetic energy to the fluid by centrifugal force and then converting that to a potential energy in the form of pressure.

In order to optimize the lift and head that can be produced from various casing sizes, pumps are produced in several diameters for application in the most common casing sizes. Table 13.2 lists some common unit diameters, flow ranges, and typical casing sizes in which they fit.

Functional Features Shaft. The shaft is connected to the seal-chamber section and motor by a spline coupling. It transmits the rotary motion from the motor to the impellers of the pump stage. The shaft and impellers are keyed, and the key transmits the torque load to the impeller. As was mentioned earlier, the diameter of the shaft is minimized as much as possible because of the restrictions placed on the pump outside diameter. Therefore, there are usually several shaft material options available, depending on the maximum horsepower (HP) load and corrosion protection required.

Housing. The housing is the pressure-containing skin for the pump. It holds and aligns all the components of the pump. There are several material options available for different application environments. For additional corrosion protection, there are several coatings that can be applied.

Discharge Head/Tubing Connection. The discharge head provides a female threaded connection to the production tubing. There are usually several thread forms and sizes to select from.

Several different styles of intakes can be selected. They allow for entrance of the fluid into the bottom of the pump and direct it into the first stage. Integral intakes can be threaded directly into the bottom of the housing during the manufacturing assembly process, while others are separate components, which are bolted on to the bottom pump flange.

A standard intake has intake ports that allow fluid to enter the pump. It is used when the fluid is all liquid or has a very low free-gas content. The intake shown in Fig 13.2 would be a standard intake if the reverse-flow screen were omitted.

A reverse-flow intake is used when the free-gas content in the fluid is high enough to cause pump-performance problems. The pump in Fig. 13.2 is shown with a reverse-flow design. The produced fluid with free gas flows up the outside of the reverse-flow intake screen, makes a 180° turn to enter through the perforations or holes at the top of the screen, flows back down to the intake ports and then back up to the first pump stage. These reversals in direction allow for a natural separation of the lighter gases from the liquid. The separated gas travels up the casing annulus and is vented at the wellhead. Another style is shown in the right-hand graphic of Fig. 13.3, which has a longer reversing path than does the intake with the screen.

The next step in handling free gas with an ESP involves downhole mechanical separation devices such as separator intakes. These devices take the fluid that enters its intake ports, impart a centrifugal force to it, vent the lighter-density fluid back to the annulus, and transfer the heavier-density fluid to the first pump stage. The heavier-density fluid, which is routed to the pump, has been either fully or partially degassed. Two of these devices are shown in the left-hand and center graphics of Fig. 13.3. The first device is the vortex-type separator. The produced fluid, which has already undergone some natural annular separation, is drawn into the unit through the intake ports. These can be straight intake ports, as already mentioned, or a reverse-flow-intake style. The fluid is then boosted to the vortex generator by the positive-displacement inducer. The vortex generator is generally an axial-type impeller. It imparts a high-velocity rotation to the fluid. This causes the heavier fluids (liquids) to be slung to the outer area of the flow passageway and the lighter fluids (free-gas laden) to mingle around the inner area and the shaft. The fluid then enters a stationary flow-crossover piece. The crossover has an outer annular passageway that takes the heavier-density fluids that enter it and directs them to the entrance of the pump. The lighter-density fluid that enters the inner annular passageway of the crossover is directed to the separator vents, where it exits to the casing annulus and flows up the wellbore.

The second device is a rotary centrifuge-type separator and is shown on the left in Fig. 13.3. It is similar in design to the vortex style, but it has a rotating chamber instead of the vortex generator. The chamber has several radial blades that are enclosed by an outer shroud or shell. The fluid that enters the chamber is centrifuged at very high g forces over the length of the chamber. Upon exiting the chamber, the fluid enters the flow crossover and follows the same processing as already described in the vortex style.

Flanged Connection to Seal-Chamber Section. The bottom flange of the pump bolts to the flange of the seal-chamber-section head. It maintains axial alignment of the shafts of the two units. It also allows the floating pump shaft to engage the end of the seal-chamber-section shaft so that the axial thrust produced by the pump is transferred to the thrust bearing in the seal-chamber section.

Stages. The stages of the pump are the components that impart a pressure rise to the fluid. The stage is made up of a rotating impeller and stationary diffuser. The stages are stacked in series to incrementally increase the pressure to that calculated for the desired flow rate. A graphic of the fluid flow path is illustrated in Fig. 13.4. The fluid flows into the impeller eye area and energy, in the form of velocity, is imparted to it as it is centrifuged radially outward in the impeller passageway. Once it exits the impeller, the fluid makes a turn and enters the diffuser passageway. As it passes through this passageway, the fluid is diffused, or the velocity is converted to a pressure. It then repeats the process upon entering the next impeller and diffuser set. This process continues until the fluid passes through all stages, and the design discharge pressure is reached. This pressure rise is often referred to as the total developed head (TDH) of the pump.

There are two styles of stages for the range of flow rates in which ESPs operate. The first is a radial stage. The impeller is shown in Fig. 13.5 and the diffuser in Fig 13.6. Its geometry has the flow entering the impeller or diffuser parallel to the axis of the shaft and exiting perpendicular to the shaft, or in a "radial" direction. They are sometimes referred to as "pancake" or "mushroom" stages, respectively, because of the impellers’ flat shape and the diffusers’ mushroom-shaped downthrust pedestal. A cross-sectional schematic of a radial stage is shown in Fig. 13.7.

The second is a mixed-flow stage; a typical impeller is shown in Fig. 13.8, and the diffuser is shown in Fig. 13.9. Its geometry has the flow exiting the impeller at an angle less than 90° to the shaft. A graphic of this flow path is shown in Fig. 13.10. Generally, this angle changes from near perpendicular to near axial, as the design flow rate of the stage increases for a particular-diameter unit. This relationship is shown in Fig. 13.11 .

A key feature for both styles of stages is the method by which they carry their produced axial thrust. Usually, the pumps that are under a 6-in. diameter are built as "floater" stages. On these, the impellers are allowed to move axially on the pump shaft between the diffusers. Contrary to the name given to this configuration, the impellers never truly float. They typically run in a downthrust position, and at high flow rates, they may move into upthrust. To carry this thrust, each impeller has synthetic pads or washers that are mounted to the lower and upper surfaces, as shown in the previous figures. These washers transfer the thrust load from the impeller through a liquid film to the smooth thrust pad of the stationary diffuser.

Three forces are involved in determining whether the impeller runs in downthrust or upthrust. The first is the downward force, and it is a result of a portion of the impeller discharge pressure acting on the area of the top impeller shroud. Two forces act in the upward direction. One is a result of a portion of the impeller discharge pressure acting against the bottom shroud of the impeller. The second is the force produced by the momentum of the fluid making its turn in the impeller passageway. A graphic description of the thrust forces on an impeller is shown in Fig. 13.12. Because the shaft is allowed to move axially and positions itself by contact with the seal-chamber section shaft, the fluid pressure causes a thrust load through the shaft to the seal thrust bearing. The thrust is the result of the force on the top end of the shaft (discharge pressure multiplied by the end area of the shaft) minus the force on the bottom end of the shaft (intake pressure multiplied by the end area of the shaft).

On 6-in. and larger pumps and on specially built smaller pumps, the impellers are usually fixed or locked to the shaft. These pumps are referred to as "fixed impeller" or "compression" pumps. In this configuration, all the thrust is transferred to the shaft and not to the diffuser. Therefore, the seal thrust bearing carries the load of all the impellers plus the shaft thrust. Particular care should be exercised in selecting the proper seal thrust bearing to match the fixed impeller pump conditions because these loads can be very high.

To maintain the optimum flow-path alignment between the impeller and its diffuser, the impeller is designed to maintain a downthrust position through its operating range. Usually, the impeller does not transfer into upthrust until its operating point is to the right of its maximum recommended point. Stage-specific thrust characteristics should be available from the manufacturers.

Performance Characteristics. The manufacturers state the performance of their pump stages on the basis one stage, 1.0 specific gravity (SG) water at 60- or 50-Hz power. A typical performance curve for a 4-in.-diameter radial-style pump, with a nominal best-efficiency performance flow of 650 B/D, is shown in Fig. 13.13. A mixed-flow style with a nominal flow rate of 6,000 B/D is shown in Fig. 13.14. In these graphs, the head, brake horsepower (BHP), and efficiency of the stage are plotted against flow rate on the x -axis. Head, flow rate, and BHP are based on test data, and efficiency is calculated on the basis of


where Q is given in gal/min, TDH is given in ft, and C = 3,960; or Q is given in m3/d, TDH = m, and C = 6,750.

The head/flow curve shows the head or lift, measured in feet or meters, which can be produced by one stage. Because head is independent of the fluid SG, the pump produces the same head on all fluids, except those that are viscous or have free gas entrained. If the lift is presented in terms of pressure, there will be a specific curve for each fluid, dependent upon its SG.

The dark (highlighted) area on the curve is the manufacturers recommended "operating range." It shows the range in which the pump can be reliably operated. The left edge of the area is the minimum operating point, and the right edge is the maximum operating point. The best efficiency point (BEP) is between these two points, and it is where the efficiency curve peaks. The shape of the head/flow curve and the thrust characteristic curve of that particular stage determines the minimum and maximum points. The minimum point is usually located where the head curve is still rising, prior to its flattening or dropping off and at an acceptable downthrust value for the thrust washer load-carrying capabilities. The location of the maximum point is based on maintaining the impeller at a performance balance based on consideration of the thrust value, head produced, and acceptable efficiency.

API RP11S2 covers the acceptance testing of ESP pumps. [6] It also recommends the performance tolerance limits and describes the test procedure. One should pay particular attention to the method of calculating the acceptable limits of the head/flow curve. A good layman’s description of the method is given in Lund.[7] The limit is calculated by a combination of ± 5% head and ± 5% flow.

Several parameters are used to relate the characteristics of stages of different size, under dynamically similar conditions. They show that head (H) is a function of diameter (D) to the second power and also of rotating speed (N) to the second power. Flow (Q) is a function of diameter to the third power and also a direct function of rotating speed.




The BHP curve shows the power required to drive the stage. The power is lowest at shutoff or zero flow and increases with flow. The HP also follows the relationship that is given in Eq. 13.4 for different-sized pumps under dynamically similar conditions.


Another performance-altering technique is to reduce the diameter of an impeller by trimming or cutting back its outside diameter. When this is done, the head, flow, and power are changed by the relationships shown in Eqs. 13.5 through 13.7.





For any particular-diameter-pump series, there is generally an overlap region between the radial and mixed-flow styles. A typical relationship of a family of similar-diameter stages is shown in Fig. 13.15. Notice that each style increases in efficiency as the flow rate increases, until the efficiency peaks and begins dropping off.

Seal-Chamber Section[8]

The component located below the lowest pump section and directly above the motor, in a standard ESP configuration, is the seal-chamber section (Fig. 13.16). API RP11S7 gives a detailed description of the design and functioning of typical seal-chamber sections. [9] The following discussion repeats some of this information, but it is also intended to supplement the information contained in API RP11S7. The seal-chamber section is basically a set of protection chambers connected in series or, in some special cases, in parallel. This component has several functions that are critical to the operation and run-life of the ESP system, and the motor in particular.

  • It protects the motor oil from contamination by the wellbore fluid. The motor is filled with a high-dielectric mineral or synthetic oil for electrical protection and lubrication. Well fluid migrating into the motor can potentially cause a premature electrical or mechanical failure through the reduction of the motor dielectric or lubricating properties.
  • It allows for pressure equalization between the interior of the motor and the wellbore. Its design allows for a breathing or equalization method that compensates for pressure variances caused by the submergence pressure encountered during the installation from surface pressure to downhole static pressure and the thermal expansion and contraction of the motor oil because of motor heat rise during operation.
  • It also absorbs the axial thrust produced by the pump and dissipates the heat that the thrust bearing generates.

Functional Features Shaft. Usually, there are several shaft options available, and their selection is based on the fluid environment and the HP to be transmitted. Even though a majority of the shaft is exposed only to the clean, dielectric motor oil, the top end is exposed to the wellbore fluid. Therefore, the material must be an alloy that protects the integrity and function of the shaft. This could be the entire shaft or, at a minimum, the top section that is directly exposed to the wellbore fluid.

Labyrinth Protection Chambers. This chamber design features a direct fluid interface between the wellbore fluid and the motor oil. A typical design layout is shown in Fig. 13.17. It is commonly referred to as a "labyrinth"- or "U-tube"-style chamber. It is configured to have several concentric annular volumes that form a U-tube-type communication path for fluids coming in the top of the chamber to travel through to get to the exit point at the base of the chamber. This flow path is shown schematically in Fig. 13.18. In many mild applications, it is a very effective protection design. There are several application weaknesses that need to be considered. First, there is a direct fluid interface between the motor oil and the wellbore fluid in the top chamber. This allows the motor oil to be slowly wetted through a wicking action of the wellbore fluid, thereby, slowly degrading the dielectric strength of the motor oil. In some applications, high-density blocking fluids are used to retard or eliminate this motor oil. Second, gasses can permeate into the motor oil causing potential corrosion problems or burping and excessive loss of motor oil if there is a sudden decompression. Third, the labyrinth’s effective volume decreases as the chamber is inclined. Therefore, they are not generally recommended at deviations greater than 30° from vertical.

Positive-Barrier Protection Chambers. This chamber incorporates a positive barrier between the wellbore fluid and the motor oil. The barrier is usually an elastomeric or rubber bag, which is also called a bladder. A typical design layout is shown in Fig. 13.19. The bag or bladder forms a seal between the motor oil inside the bag and the wellbore fluid between the bag and seal-chamber section’s housing. It also allows for pressure compensation by expanding and contracting in this annular area. The motor oil flow path is shown in Fig. 13.20. The barrier-style chamber is recommended for deviated-well applications. The bladder material should be resistant to the well fluids and any injected chemicals.

Mechanical Face Seals. A rotating mechanical face seal is generally located at the top of each protection chamber. A typical design is shown in Fig. 13.21. The rotating part of the face seal is sealed to the shaft by elastomeric bellows. The stationary part is sealed into the stationary component of the seal-chamber section. A spring preload force then keeps the rotating and stationary seal faces in contact. Once the unit starts rotating, a hydrodynamic fluid film is developed on the face. This film then carries the load, prevents wellbore fluid from crossing the face by the pressure-differential setup, and cools the loaded face.

Axial Thrust Bearing. This bearing carries all of the axial thrust produced by the pump and seal-chamber section. Generally, sliding-shoe hydrodynamic types are used for this application because of their robustness and ability to function totally immersed in lubricating fluid. It is composed of two main components: a stationary pad and a rotating flat disk. The stationary part has pads finished to a very close flatness tolerance, connected to a base by a thin pedestal or flexible joint. The rotating disk is also finished to a very close flatness tolerance. Several different bearing designs are shown in Fig. 13.22. They represent standard-style cast bearings for normal applications and machined bearings for intermediate- and high-load applications.

Performance Characteristics. When selecting the style and options of a seal-chamber section for an application, the user must consider the shaft torque, thrust-bearing load, volumetric motor oil expansion required, and the wellbore-fluid environment to which it will be subjected.

The shaft has to transmit, from the motor to the pump, the entire torque required by the equipment for its application. This not only includes the stabilized running torque but also the short-term torque spikes caused by unit startup and intermittent pump loads. Because the diameter of the shaft is constrained because of the maximum diameter of the unit, materials of differing mechanical properties must be used to provide different load capabilities. These materials must also provide protection from corrosive wellbore fluids.

The thrust-bearing performance is a function of the load that is transferred to it and the viscosity of its lubricating oil. The load transmitted from the pump can be calculated on the basis of the pump geometry and the TDH produced for the application. For "floater" pumps, the shaft load is always down and is equal to the cross-sectional area of the top of the shaft multiplied by the discharge pressure of the pump (Pdischarge) minus the cross-sectional area of the bottom of the shaft multiplied by the pump intake pressure (PIP). For "fixed" impeller pumps, the load is equal to the shaft force, as just calculated, plus the summation of all the impeller thrust forces. The impeller thrust forces can be roughly calculated, as previously described in the pump-stage section, or obtained from the pump manufacturer.

The hydrodynamic thrust bearing depends on developing and maintaining a fluid film between the stationary pads and the rotating disk. This fluid film actually carries the load, not the running of the disk against the pads. In fact, if contact is made between the two components, heat is generated and rubbing can become severe enough to start bearing failure, even seizure. To maintain the proper film thickness, both the viscosity of the lubricating oil and the operating temperature of the thrust bearing are critical. Most manufacturers provide a range of lubricating oils, so the proper viscosity range can be provided at the estimated operating downhole temperature.

The seal-chamber section also adds HP load to the motor. It is usually a low value and significant only on lower-HP applications. Because each style of seal-chamber section has its own characteristics, the manufacturer should be consulted for these values.

The seal-chamber section also has to handle the volumetric expansion and contraction of the motor oil. This volume includes everything from the top of the seal-chamber section to the bottom of the motor. This expansion and contraction is a result of the changing temperatures and pressures the unit undergoes during operation. During installation, the unit goes from surface ambient conditions to wellbore setting-depth conditions. The impact of the increase in pressure does not have a significant impact on the volume occupied by the motor oil, as long as the unit is vented of air properly during filling. The temperature, on the other hand, causes the volume to change significantly. As the motor oil heats up during installation, it expands, and the volume that cannot be contained in the seal-chamber section, whether labyrinth or bag style, is vented from the top chamber into the wellbore annulus. When the ESP is started, it undergoes further temperature rise until it reaches its stabilized operating point. During this stabilization, it continues to vent any expanding volume of motor oil. Once it reaches a stabilized operation, the venting stops and the seal-chamber section and motor run at almost equal pressure with the wellbore. The next significant event is when the ESP shuts down. At this point, the motor oil temperature starts dropping from the operating temperature back down to the wellbore ambient. The pressure also increases from wellbore flowing to static. Once again, the temperature change has the largest impact and, in this case, on fluid contraction.

On a labyrinth style, well fluid is pulled back into the first chamber as the motor oil contracts back along its communication paths (Fig. 13.18). As long as the contraction volume does not exceed the volume of the first chamber, well fluid is contained in the first chamber. If the fluid contraction exceeds the chamber volume, well fluid is drawn into the second or lower chamber. With multiple thermal cycles, the well fluid can slowly be drawn towards the seal-chamber section thrust bearing and motor where it can be fatal or, at least, reduce the total run-life of the equipment. Because of the method of breathing, the labyrinth style is not recommended for well deviations greater than 30°. When the labyrinth chamber is tilted or inclined, the effective length of the labyrinth or U-tube communication path is shortened, effectively reducing the volume of the chamber.

The bag style, with its positive barrier, maintains a physical separation of the motor oil and wellbore fluid during expansion and contraction. Upon contraction, the cylindrical bag collapses around the center of the chamber, absorbing the contraction. Then, on a recycle or temperature increase, the bag expands to its original position before any motor oil venting is allowed. A more detailed explanation of these processes is found in the API RP11S7 document. [9]

In recent years, many operators have begun to run multiple seal-chamber sections in series. This gains additional chambers or more protection between the well-fluid entry point and the motor. While this is true, it must be balanced with the fact that more motor oil fluid volume is also being added. More motor oil volume means more expansion and contraction. Because the first chamber volume is fixed, there is a better chance of operating over the capacity of this chamber. Therefore, the selection of which style seal-chamber section to use and how many to run is dependent upon the application. The proper selection is to choose the one in which the operational expansion cycle uses only a portion of the first chamber. In some very severe applications, seal-chamber sections with the first two bag chambers communicated in parallel instead of series have been used in an effort to handle the wellbore-fluid contraction volume.


The ESP motor is a two-pole, three-phase, squirrel cage, induction design. [10][11] A two-pole design means that it runs at 3,600-rpm synchronous speed at 60-Hz power or roughly 3,500-rpm actual operating speed. It operates on three-phase power at voltages as low as 230 and as high as 5,000, with amperages between 12 and 200. Generally, the length and diameter determines the motors HP rating. Because the motor does not have the power cable running along its length, it can be manufactured in diameters slightly larger than the pumps and seal-chamber sections and still fit in the same casing bores. Typical diameters and rated HP ranges are shown in Table 13.3. A cross section of a motor is shown in Fig. 13.23.

Functional Features Wound Stator. A wound stator comprises an unwound stator, electrical windings, and insulation and encapsulation systems. The unwound stator has thousands of electrical-grade steel laminations stacked in the housing and is compressed to hold them aligned and stationary. The laminations are die-punched with a center bore for the rotating components to fit into and 18 winding slots for the winding wire. Each slot is insulated with a very-high-dielectric-strength polyamide insulation material. This slot insulation provides winding-to-stator (turn-to-ground) electrical protection.

Insulated copper wire called "magnet" wire or "mag" wire is then wound into each slot to form three separate phase coils displaced at 120° intervals. The insulation on the mag wire provides wire-to-wire (turn-to-turn) electrical protection. Also, at the end of the lamination stack, where the coil has to make a 180° winding turn ("end turn"), insulation is placed between the first winding phase and the motor housing and then between each phase. This protects for phase-to-phase faults.

After the mag-wire winding and insulation is complete, the wound stator is then encapsulated with either a solid-fill epoxy or varnish coating. The encapsulation process fills the voids left in the slots and around the end-turn coils. This provides several important functions. First, it mechanically holds the windings to resist movement that causes wire-to-wire rubbing and possible damage to the wire’s insulation. Second, it adds dielectric strength to the slot winding and end turns. Third, it significantly improves the overall thermal conductivity for better heat dissipation from the motor core through the slots to the motor housing skin. And last, it protects the winding from an attack by contaminates such as wellbore fluid. The last two are less significant for the varnish coating method. As its name implies, it is just a thin coating, mainly on the surfaces of the lamination slots and the mag wire, and has voids where motor lubricating oil accumulates, reducing both the thermal conductivity and the dielectric strength.

The length of the wound stator determines the number of rotors, which also determines the nameplate HP for a given-diameter motor. Within each given length or HP, there are numerous voltage/amperage combinations. Typically, there are various selections running from low voltage/high amperage to high voltage/low amperage. Voltages range from 440 to 4,000+, and amperages typically range from 15 to 150+ amps. The relationship of the HP, voltage, and amperage is  


Shaft. The shaft transmits the torque produced by the rotors, keeps all the rotating components aligned axially, and provides a path for the cooling and lubricating oil to the radial bearings and rotors. The shaft is generally tubular material, and the hollow core allows for the motor oil to communicate from the motor head and base areas to the hotter radial bearing and rotor areas. Because the shaft is completely immersed in clean oil, exotic corrosion-resistant materials are not required. Typically, the shaft material is alloyed carbon steel. Its straightness is also critical because of its close rotating clearances and high speed.

Rotor. Ideally, the rotor should be one continuous component that runs the length of the stator lamination bore. This would cause tremendous dynamic-instability problems because of the very large rotor length-to-diameter ratio. Therefore, the rotors are constructed in short segments with radial support bearings placed between them for dynamic stability. Rotors are constructed by stacking hundreds of thin, electrical-grade laminations between two metal end rings. Copper rotor bars are inserted into the lamination slots, the whole stack is compressed, and the rotor bar’s ends are mechanically bonded to the end rings. This results in the "squirrel cage" rotor. The center bore of the rotor has an axial-keyway groove for engaging the axial key stock mounted on the motor shaft. This locks the rotor to the shaft for torque transmission but allows axial movement for thermal growth.

Radial Bearings. A sleeve-type-bearing system provides the alignment and radial support for the long shaft and rotor assembly. The sleeve part of the journal is keyed to the shaft and rotates with the shaft. The stationary part of the bearing has a bore in which the sleeve runs. It has an outside diameter (OD) that has a small clearance with the stator-lamination inside diameter. Also, the stator laminations at the bearing locations are made of nonmagnetic material to reduce the rotating magnetic field and the rotational forces tending to rotate the radial bearing. In some designs, an elastomer ring or locking key is located between the bearing OD and the stator inside diameter (ID) to prevent or retard any relative rotation. If rotation does occur, the bearing may start wearing into the stator until contact with the phase mag wires causes an electrical short.

Motor Head. The motor head contains the electrical termination for the connection of the three-phase windings to the electrical power cable. This connection is made in an insulated cavity either by a male/female plug-in design or a motor-wire to power-cable-wire splice. Also, a small thrust bearing is located in the head. It is designed to carry the weight of the shaft and rotor stack during startup and maintains the axial position of the rotors and radial bearings relative to the stator.

Performance Characteristics. The performance of a submersible motor is usually characterized by the manufacturer’s performance curve. An example is shown in Fig. 13.24. The curve represents typical motor performance for a given motor diameter, based on the average of several tests. To get the curve data, a motor is loaded across a broad HP load range with a dynamometer. A detailed description of these tests is given in Cashmore.[12] Data collected include: three-phase voltage, amperage, kilowatts, speed or rpm, motor torque, motor temperature rise, and fluid velocity past the motor. The motor amperage, rpm, efficiency, and temperature rise are especially important for the proper application of any motor. Even though the motor temperature rise is measured during the dynamometer test, it is not generally plotted on the motor characteristic curve. This is because it is a critical parameter in the proper application of the motor, and its value is affected by several application conditions.

Amperage. The motor current is nearly linear with HP loading and is one of the easiest parameters to measure. Because of this, it is the most useful for determining the actual loading of the motor. On the basis of nameplate current rating of the motor and the amperage curve of the motor characteristics, an output HP can be determined. Calculate the percentage of nameplate amps in which the motor runs, and determine the percent of nameplate HP the motor is developing.

Revolutions per Minute (RPM). The rotational speed or RPM of the motor at its application load point is very important in determining the operating point or output of the pump. The pump-performance curve used in determining the head and flow output of the pump for its application is based on a pump-motor speed of 3,500 RPM. If the RPM varies from 3,500, the pump flow will vary with the ratio of the speed, and the flow rate will vary with the ratio of the speed squared. (See Eqs. 13.1 and 13.2.) Once again, by knowing the percent of nameplate amps, the motor speed can be read from the motor characteristic curve. Even though this RPM change is usually small, it can still impact the final motor and pump operating point for a particular application. When the pump-performance point is modified, because of the motor RPM, the pump head and flow rate change; therefore, the load on the motor is changed. Determining the final pump operating point and motor loading point becomes an iterative process.

Efficiency. Because power costs are a major part of the overall expense of operating an ESP, the efficiency of the motor is an important factor. The efficiency curve for a submersible motor has a fairly flat peak through its normal operating range but starts dropping off significantly at less than 50% loading. Note that this efficiency curve is based on the nameplate voltage being maintained at the motor. If the surface power is not optimized, the voltage delivered to the motor can vary, and the efficiency drops off. Fig. 13.25 shows the constant motor HP plotted as a function of current and voltage. It indicates that as the motor voltage is increased or decreased away from its nameplate rating, the current increases, resulting in a decrease in efficiency. Therefore, the ESP-motor operating efficiency can be optimized by adjusting the surface voltage and monitoring the motor amperage until the bottom of the current or amps curve is found.

Motor Temperature Rise. The temperature-rise data of the motor, where provided, are an indication of the average winding temperature rise above the ambient motor temperature. At test conditions, with water circulating by the motor at 1 ft/sec, submersible motors typically have rises of 50 to 100°F (10 to 38°C). Under wellbore-application conditions, the temperature rise is affected by various parameters, including: the velocity and thermal-conductivity characteristics of the production fluid flowing past the motor skin, API gravity of the crude, water cut, the percentage of free gas, fluid emulsions, fluid scaling tendencies, voltage imbalance at the motor terminals, and the use of a variable-speed drive. Typically, the industry guideline has been a 1-ft/sec flow by the motor, but there are many applications with velocities below this. The manufacturers have a method for calculating or estimating the impact of these parameters on the heat rise of their motors.

The rating of a motor or its nameplate HP is determined by its designer, on the basis of these same performance-test values. [13] Specifically, the designer is interested in the voltage, amperage, and HP ratings that provide the best motor performance for general operating conditions. Additionally, there are only three absolute limits that also influence the nameplate HP rating. These limits include mechanical, torque, and temperature.

Mechanical Limit. The mechanical constraints applied to the motor rating are determined by the maximum torsional-load capability of the design and materials. This limit is based on the mechanical strength properties and the geometry of the shaft.

Torque Limit. Here, the designer is looking at the maximum torque of the motor at rated voltage. For a particular motor design, a motor can produce only a given amount of torque for the volume of available active material. The active material is the material that contributes to producing magnetic flux. The maximum amount of torque a motor can produce is called breakdown or pullout torque. The breakdown torque of the motor is usually greater than 2.5 times the existing running torque, which poses no practical limit to the HP rating.

Changing the frequency of the electrical power can also vary the torque or HP rating of the motor. Generally, the motor’s HP rating is based on either 50- or 60-Hz power. A fixed frequency motor has a specified full-load nameplate HP at the specified nameplate voltage, as stated earlier. This same torque can be achieved at other speeds by varying the voltage in proportion to the frequency. This maintains a constant magnetizing current and flux density, which provides a constant available torque. Therefore, the HP output rating of the motor is directly proportional to the frequency or speed (Eq. 13.9) because power rating is a function of torque (ft-lbf) multiplied by speed (Eq. 13.10).




Temperature Limit. For this limit, the designer is interested in the maximum temperature rating of the insulation system and the motor bearing lubrication system. The high-tech insulation used in today’s ESP motors allows an insulation temperature rating in excess of 500°F (260°C). The limiting factor is the motor bearing system. Even though significant advances have been made in bearing design and motor oil formulations, the maximum recommended operating temperature of an ESP motor is around 400°F (205°C). There have been application incursions above this, but they have generally been made with experimental designs or in applications where a reduced ESP run-life has been accepted.

An important application point is that the proper motor oil lubricating viscosity must be maintained at the motor operating temperature. Therefore, the manufacturers provide and specify several grades of dielectric motor oils to cover the range of motor operating temperatures. Each type of oil has a minimum and maximum recommended motor operating temperature.

Power Cable

The ESP power cable transmits the required surface power to the ESP motor. Typically, it is banded or clamped to the production tubing from below the wellhead to the ESP unit because it is not designed to support its own weight. It is a specially constructed three-phase power cable designed specifically for downhole well environments. The cable design must be small in diameter, protected from mechanical abuse, and impervious to physical and electrical deterioration because of aggressive well environments. They are available in a wide range of conductor sizes or gauges. They can be manufactured in either round or flat configurations, using several different insulation and metal armor materials for different hostile well environments. Cross-sectional views of flat and round cable construction are shown in Figs. 13.26 and 13.27. There are two very good documents that fully describe the design, application, and testing of ESP submersible power cables—API RP11S5 and RP11S6. [14][15] This section will repeat some of the basic information and add supplemental information.

Functional Features[16]

Conductor. Conductors are copper wires that can be either a single solid configuration or multiple smaller strands. Solid conductors offer more advantages than their stranded counterpart. They are smaller, easier to clean and splice, do not adsorb gases, have a smoother surface to the insulation, which reduces electrical stress, and they are less expensive. Stranded cable offers more mechanical flexibility, but this is usually not an over-riding benefit. Also, unless the voids in the strand are filled, gases can migrate up or down the cable more easily.

The copper conductor is generally tinned or coated with a tin/lead alloy when it is insulated with polypropylene. In certain well environments, direct contact between copper and polypropylene can cause "copper poisoning" of the insulation, which reduces its electrical strength and degrades its physical properties. Synthetic-rubber insulation does not react with copper, so the vast majority of all rubber-insulated ESP cables are made with bare copper conductors.

Insulation. There are two basic types of insulation used in ESP cable: polypropylene and ethylene propylene diene monomer (EPDM) synthetic rubber. Polypropylene or "poly" is the lower-temperature-rated insulation, a tougher material than rubber, and generally more cost effective. The insulation temperature rating for poly is 205°F (96°C), but it can be increased to 225°F (107°C) with the addition of an extruded protective layer of lead. [17] Above these temperatures, a rubber insulation is always required. The EPDM is the insulation of choice for synthetic-rubber-insulation cables. The compounding of the rubber, with more than twenty other ingredients, allows for it to be designed to have low oil swell, fairly low elongation, and a high modulus. By contrast, the EPDM formulated for surface power cable is not suitable for downhole oilwell service because of its excessive swell characteristic. Most high-quality EPDM-based insulation is rated for conductor temperatures up to 450°F (232°C). [18]

Insulation Protective Layers. The EPDM-insulated conductors need protection from the oilwell environment because of swelling in the oil. To provide protection from the oil and to control swelling, different types of protective layers are applied over the insulation. Starting from the lowest level of protection to the highest, these layers are discussed next.

Tapes and Braids. Thin tapes of polyvinyl fluoride are wrapped over the EPDM-insulated single conductors. The limitation of the tape is that it has an overlap that allows oil to seep through. To make the tapes more effective, a 50% overlap can be used. To add some additional containment, braids can be put over the tape. Common braid materials are nylon and polyester, which have temperature limits in water of about 250°F (121°C). More expensive engineered filaments can be used to extend this temperature rating to 300 to 400°F (149 to 205°C).

Extruded Barrier. The next level of protection is a continuous extrusion of a high-temperature plastic layer over the insulation. The extruded barrier has no overlaps to let the oil contact the insulation. In addition, it increases the electrical strength of the insulation system. It also increases the chemical resistance of the cable, and in gassy wells, it regulates the rate of decompression of wellbore gases that have saturated into the insulation. Extruded barriers are made from fluoropolymers, such as polyvinylidene fluoride (PVDF) rated up to 320°F (160°C) and fluorinated ethylene propylene (FEP) (Teflon®) rated up to 400°F.

Lead Barrier. In wells that have a damaging amount of hydrogen sulfide gas, the copper conductors can be attacked and destroyed. To protect against this, a thin layer of lead is extruded over the insulation. For poly insulation, the lead increases the maximum operating temperature of the cable. For EPDM insulation, fabric tape or a braid is placed over the lead as a manufacturing aid to minimize distortion of the lead during armoring. This step is not required for poly, because it is harder and more difficult to distort during the armoring process. Generally, lead cables are manufactured in flat configurations but can be made in round configurations for added containment and protection.

Jacket. The jacket is designed to protect the insulation from physical damage. Also, in round cables, the jacket fills the space between the insulated conductors and the inside of the armor so that the armor can effectively contain the whole cable from oil and decompression swelling. Typical jacket materials include nitrile and EPDM rubber. Nitrile rubber has an operating temperature of 280°F (138°C) and is very resistant to oil swelling. As discussed in the insulation section, the EPDM rubber’s properties can be varied by its compounding but is rated up to 400°F (205°C), and it swells in oil.

Armor. The metal armor that is wound around the three insulated conductors (flat cable) or the jacketed conductors (round cable) has a primary function of providing mechanical protection to the insulated conductors. On round cable, it has the added function of providing additional containment protection for oil swelling and gas decompression. The armor is usually made of mild galvanized steel, which is applicable to non- to mildly-corrosive wells. The galvanized armor is usually offered in several thicknesses, which increases the mechanical and corrosion protection. In more-corrosive applications, specialty metals are available, such as stainless steel and other alloys.

Flat Construction. The typical construction and geometry of the ESP flat power cable is shown in Fig. 13.26. It has the three insulated conductors laying parallel with armor wrapped around them, providing a lower profile when the clearance between the casing ID and production-tubing outside diameter (OD) is limited. Flat cable is not suitable for containing oil swell or gas decompression forces because of the interstices between the single conductors. If the insulation or jacket expands on a flat cable, it will deform the armor, bending it apart over its long axis and allowing the conductors to slide over one another. Insulation and jacket expansion can cause insulation splitting, leading to potential electrical failure. Flat cables, by virtue of their parallel conductor configuration, have an inherently induced imbalance. Flat-cable induced voltage and current imbalance is usually not a practical consideration in lengths less than 10,000 ft, unless the well is very hot and is pushing the thermal limits of the motor.

Round Construction. Round cable is superior to flat cable because it provides more protection to the conductors. Its typical construction and geometry are shown in Fig. 13.27. Round cable provides superior containment to the cable core, enabling it to better withstand decompression and oil swell forces without damage. Because pressure is naturally contained in a round shape and the space between the insulation and the inside of the cable armor is filled with jacket material, the cable armor acts to restrain and prevent any insulation expansion because of oil swell or gas-decompression expansion. Round cable is also naturally impedance balanced because of the equidistant spacing between the conductors. Therefore, there are no voltage or current imbalance issues affecting the motor.

Motor Lead Extension (MLE). The motor lead extension cable, also referred to as the motor flat, is a specially constructed, low-profile, flat cable. It is spliced to the lower end of the round or flat main power cable, banded to the side of the ESP pump and seal-chamber section, and has the male termination for plugging or splicing into the motor electrical connection. Because of its need for low profile, it requires compact construction. It generally has a thin layer of high-dielectric-strength polyamide material wrapped or bonded directly to the copper conductors. This allows for a thinner layer of insulation material, allowing for a lower profile. The MLE is generally selected on the basis of equipment: casing clearance and the voltage capacity requirement.

Performance Characteristics. The cable materials for the wellbore application should be selected from the guidelines already provided and by the cable manufacturer. These guidelines include:
  • Insulation up to 205°F (96°C) uses polypropylene insulated cables. Over 205°F and up to 450°F (232°C), it utilizes synthetic rubber insulated cables.
  • Gassy wellbores use a cable that provides protection from decompression damage. This is a construction that adds hoop strength to the insulation to contain the insulation from expanding and rupturing. Generally, tapes and braids, as well as extruded barriers, provide this protection.
  • Hydrogen sulfide (H2S)—generally lead barrier cables are used to protect the copper conductor from damage.

Once the proper cable materials have been determined for the wellbore environment, the only remaining variable is the conductor size. The conductor size can be optimized on the basis of motor voltage/amperage rating and the casing clearance. Because there are several motor voltage/amperage combinations available for the HP required for the application, the selection of the cable to match the motor can be based on either the surface switchgear and transformer available or the most favorable economic evaluation. The testing methods and acceptance criteria are discussed and provided in Standard 1017[19]

Cable Voltage Drop. Because of conductor resistance, there will be a voltage drop from the surface supply to the motor terminals. The voltage drop of a particular gauge cable can be determined from the cable voltage drop vs. the amperage graph shown in Fig. 13.28. This value is for a conductor temperature of 77°F (25°C) and a length of 1,000 ft. To determine the conductor temperature in its application, a power cable ampacity chart must be used. There is a separate curve for each conductor gauge and round or flat configuration. An ampacity plot for No. 2 American Wire Gauge (AWG) solid, round cable is shown in Fig. 13.29. In it, the various conductor temperatures are plotted against the current carried and the maximum well temperature. The temperature correction factor for the cable voltage drop can then be calculated with Eq. 13.11.


where TCF is the temperature correction factor for cable, and Tconductor is the wellbore temperature at the ESP setting depth. This calculation provides a worst-case cable-voltage loss because it assumes that the entire cable conductor is at the same temperature. Computer sizing programs actually provide a closer estimation of the voltage drop because they consider the wellbore-temperature gradient from the wellhead to the ESP-setting depth and additional wellbore heating caused by the ESP-efficiency losses.

Once the voltage drop of the cable has been determined, the voltage available at the motor terminals can be calculated (surface supply voltage minus cable voltage drop). If the voltage delivered to the motor terminals is low compared to the motor nameplate voltage (typically < 50 to 60%), there could be motor starting issues. One should contact the motor manufacturer for application assistance in this case. If the motor HP and the cable length are known, the graphs, shown in Fig. 13.30, can be used for a quick approximation in the selection of motor voltage and cable size.

Motor Controllers

The surface controller provides power to the ESP motor and protects the downhole ESP components. There are three types of motor controllers used on ESP applications and all are generally specifically designed for application with ESPs. They include the switchboard, soft starter, and the variable speed controller. All units vary in design, physical size, and power ratings. They are offered in two versions: indoor, NEMA 1 and outdoor, NEMA 3. Normally, all utilize solid state circuitry to provide protection, as well as a means of control for the ESP system.

Motor controller designs vary in complexity from the very simple and basic to the very sophisticated, which offer numerous options to enhance the methods of control, protection, and monitoring of the ESP operation. The selection of the type of controller and optional features depends on the application, supporting economics, and the preferred method of control.

Fixed-Frequency Switchboard. The switchboard, fixed-speed controller, or across-the-line starter consists of a manual fused disconnect switch or circuit breaker, a motor starter, and a control power transformer. Because this controller is only a switch and does not modify the input voltage or current, it provides full-rated, instantaneous voltage to the downhole ESP system. The low inertia characteristics of the ESP allow for it to be at full rated speed within 0.200 seconds. During this starting process, the ESP motor can draw between 4 to 8 times its nameplate, or rated current, allowing it to produce several times its rated torque. This can cause excessive electrical and mechanical stresses on the ESP equipment in some situations. Normally, on deep-set systems with long lengths of power cable, the voltage drop, because of the cable, allows for a reduction in these stresses.

Functional Features. Disconnect Switch. The manual disconnect switch allows for the primary power to be shut off from the outside of the unit. It is also fused to provide circuit protection in case of power surges.

Control Power Transformer (CPT). The CPT generally has multiple taps for selection of a range of output voltages. This allows a switchboard to be used within its rated range for different voltage- and amperage-rated motors.

Recording Ammeter. The recording ammeter historically has been a pen-type chart recorder that plots one leg of the three-phase current. Currently, there are digital monitoring systems available that monitor all three-phase currents. They also have capability to store the monitored data in memory and display these data in graphical format.

Control Module. These are solid-state devices that offer basic functions necessary to monitor and operate the ESP in a reliable manner. The unit examines the inputs from the CPT and other input signals and compares them with preprogrammed parameters entered by the operator. Some of the functions include overload and time-delayed underload protection, restart time delay, and protection for voltage or current imbalance. Additional external devices can be connected, which provide for downhole pump intake pressure protection, downhole motor temperature protection, surface tank high/low level controls, line pressure switches, and others.

Soft-Start Controllers. The soft starter is designed to reduce the high electrical and mechanical stresses that are associated with starting ESP systems. Typically, these are systems that are either on very short cables or are very high HP relative to their mechanical rating. The soft starter is similar to a standard switchboard, except that it is designed to drop the voltage to the motor during the initial startup phase. The drop-in voltage reduces the inrush current, thus "softening" the starting characteristic. These devices use either primary reactors or solid-state devices to control the amount of power delivered to the motor as it is coming up to speed. A soft starter typically extends the time for the motor to reach full speed from 0.200 seconds of the across the line switchboard to 0.500 seconds. After this startup period, the soft-start system switches off and the controller becomes a normal switchboard.

Most ESP design and application software programs evaluate the downhole system for these electrical and mechanical stresses and will advise as to whether a soft start is recommended. If a system is too soft, a motor could be damaged because of cogging or failure to reach starting speed.

Variable Speed Controllers.[20] A variable speed controller (VSC), also referred to as a variable speed drive, designed for use with ESP systems, was first used in the late 1970s. Since that time, the industry has seen a significant increase in their use. This increase has been a result of the benefits that variable speed ESP operations can bring to the artificial-lift application. With the benefits comes an increase in the complexity and cost of the total system. Therefore, to properly apply and receive the maximum benefit, the end user should understand both the potential benefits and cautions in using VSCs. Benefits include: a broadened application range of the ESP pump, optimal efficiency of the downhole system, maximum well production, electrical isolation of the downhole equipment from surface power disturbances, reduced starting stresses, production matched with surface processes, and maintenance improvements for operations in high free-gas applications. Cautions include: higher initial-capital cost, increased design complexity, interface with the electrical utility, additional motor heating, potential increase in voltage stresses, and possibly higher electrical cost.

One should appreciate and understand the potential for problems or damage to the downhole equipment if certain types of VSCs are not applied and operated correctly. Since the introduction of the first VSC, the design has been simplified and reliability increased. Also, the user understanding of the system and user friendliness of the VSC have been greatly increased. Both the benefits and cautions are discussed in more detail in Sec. 13.3.6.

VSCs used with ESPs should be designed for the specific requirements of the downhole ESP motor and pump. This is because of the unique design and characteristics of the downhole centrifugal pump and submersible motor as compared to their surface counterparts. Generally, the VSC is designed to provide a constant volts/hertz output through a broad range of frequency variations. The magnetic flux that is generated in the stator of the submersible motor and passes through the rotors is directly proportional to the voltage and inversely proportional to the frequency of the applied power. The result is a constant magnetic flux density in the motor. Because the output torque of the motor is proportional to the magnetic flux density, the motor is a constant-torque variable-speed device. Also, because of its low inertia characteristics and unique rotor design, it does not have the same high-operating-speed restrictions as a typical surface induction motor. Therefore, a VSC is typically applied to frequencies from 30 to 90 Hz, with its minimum and maximum frequencies restricted only by the mechanical limitations of the downhole ESP equipment.

Functional Features. The fundamental building blocks of variable speed technology are an input rectifier or converter, a DC bus, and an output inverter, as shown in Fig. 13.31. In general, a converter is a piece of electrical equipment that changes electrical energy from one form to another. It may change the voltage and current magnitudes, change AC to DC or DC to AC, and change the frequency. VSCs applied to ESP equipment are AC to AC converters. They convert the input 460 volts, 60-Hz power (380 to 460 volts, 50 Hz) to output 40 to 480 volts, 10- to 120-Hz power.

Input Rectifier (Converter). This unit converts the input AC voltage and current to DC current and power. Current input rectifiers contain either diode bridges or silicon controlled rectifiers (SCRs). There are several types of input rectifiers, which are discussed next.

First, there is the three-phase full bridge rectifier. This most common rectifier in high-power electronics uses six devices, which are usually diodes or SCRs, to form the bridge. Two of the devices are connected to each of the incoming power phases. One device connects to the positive DC bus and the other to the negative bus. Each of these devices conducts during either the positive or negative half cycle of its respective phase. This means that we get two pulses on each incoming phase; thus, in total, it is a six-pulse converter. These converters are somewhat invariant and can cause input current total harmonic distortion (THD) levels of 25 to 35%.

Multipulse converter rectifiers are also used. They reduce input current harmonics in high-power electronic equipment. Most systems used today are multiple three-phase bridge rectifiers connected in parallel via phase or time-shifted power supplies. In multipulse systems, two pulses per phase are still achieved. Thus, the pulse number is always twice its input phase number. A phase-shifted power supply is accomplished by using a phase-shifting transformer. The transformer is connected to three-phase power and, through a vector combination of these three phases, develops the required number output phases. The most common multiphase system is a twelve-pulse bridge. It uses two six-pulse converters that are phase-shifted by 30 degrees. Normally, this converter can reduce the THD to a level of about 8%. Higher-pulse number converters further reduce the input current distortion levels. For example, an eighteen-pulse converter will produce less than 3% THD.

DC Bus. The DC bus of the VSC is composed of passive, noncontrolled devices. Typical elements include inductors, capacitors, and resistors. These devices form a damped low-pass filter to smooth the DC voltage and current that is provided from the input rectifier. Depending on the design of the VSC, the DC bus provides a smooth DC voltage or current source to the output inverter. Typically, in medium-horsepower VSC units, the DC bus is composed of multiple inductors, capacitors, and/or resistors to achieve the design voltage and current ratings. Some designs include only inductors; others have only capacitors and resistors, while some have all three. The selection of the design and size of the components determines the effect of the VSC’s input current distortion and its overall performance.

Output Inverter. The output inverter converts the DC power provided by the DC bus to a variable-frequency, AC power. This inverter can be either a voltage or current source inverter. In a voltage source inverter, the output voltage waveform is controlled, and the load applied determines the output current waveform. The current source inverter is just the opposite. In it, the output current waveform is controlled, and the load applied determines the output voltage waveform. Most VSCs for ESP applications use the voltage source inverter.

Current Source Inverters. In a current source inverter, large inductors are used to supply a current source to the inverter. The current is normally controlled by an SCR. The current source inverter controls only the output frequency of the drive, while the input converter controls the current and voltage. The inverter may operate in six steps or with pulse-width-modulated (PWM) inverters.

Voltage Source Inverters. In a voltage source inverter, large banks of capacitors act as low impedance DC voltage sources for the inverter. The inverter changes the DC voltage by one of several switching methods. These methods generally fall into two categories: a variable voltage inverter (VVI) or constant voltage inverter (CVI). A VVI usually employs a controlled rectifier to control the DC bus voltage and, thereby, the output voltage of the inverter. In a CVI, the output is controlled by the method of switching.

Variable Voltage Inverters. VVI drives are most generally six step inverters. The unit consists of six switches, each turning on and off one time during every output cycle. The name comes from the fact that each cycle is divided into six 60° periods. During each period, there is a unique combination of power devices activated. This results in a phase-to-phase voltage waveform that has six identifiable "steps" to approximate a sine wave (Fig. 13.32). This is also referred to as a "quasisine wave" inverter. The inverter controls only the output frequency, and the electrical stresses on the power devices are significantly reduced over other output topologies.

Pulse-Width-Modulated Inverters. PWM inverters also consist of six switches, but they switch many times per output cycle to control both the output voltage and frequency. The voltage waveform is divided into many small time periods that range from several hundred to several thousand (Fig. 13.33). During each period, the instantaneous output voltage is approximated by a square wave at some duty cycle. A 100% duty cycle would represent full voltage, while 0% would represent zero voltage.

To generate a sine wave, these pulses start at zero width and build, sinusoidally, to 100% duty cycle at the 90° point on the waveform. Then, they would decrease in width sinusoidal to zero at the 180° point of the waveform. The output voltage level is the integral of these pulse widths of DC bus voltage height over any given cycle. This integration is performed by the inductance of the motor, and the resultant current waveform becomes more and more sinusoidal as more pulses are used. To vary the average voltage, each pulse width is multiplied by a scale factor (to get half the output voltage, each pulse must be one-half its original width).

The electrical stresses on the power devices of a PWM inverter are significantly higher than a six-step inverter. Each switching transition causes high losses in the power devices, occurring hundreds or thousands of times per cycle. Therefore, extra care must be taken to ensure that these electrical stresses are managed properly.

Control Module. This unit functions the same as explained in the switchboard section. When used with a VSC, the controller can be programmed to provide some speed adjustment depending on certain input conditions. If the input indicates the unit is approaching or is in a shut-down parameter range, the controller could send a signal to the VSC to change its frequency, within its preprogrammed, allowable frequency range. If this specific parameter moved back into its preprogrammed operating range, the controller would maintain this VSC frequency until the next input parameter occurrence. In most cases, there is a preset time function for this adjustment to take effect; otherwise the unit would shut down.

Application Considerations

Because of the relationship of the performance of a centrifugal pump to its rotational speed (Eqs. 13.2 through 13.4), the VSC allows for wider flexibility of the downhole ESP system. The effect on pump operation is shown in Fig. 13.34. This is the same pump that is represented in the 60-Hz fixed-speed performance curve of Fig. 13.14. This allows the designer to select the flow rate and speed of the system on the initial design. For this pump stage, it can be operated between 1,800 B/D at 30 Hz (minimum recommended operating point) and 10,200 B/D at 90 Hz (maximum recommended operating point). The benefits of VSC usage are discussed next.

Broadened Application Range. On fixed-speed operation, a pump stage has a recommended minimum and maximum flow rate. Beyond these points, the pump can operate in a detrimental run-life or reliability area. By operating at reduced frequency, the minimum recommended operating point is reduced, and, at higher frequencies, the maximum operating point is increased. This allows the application of ESPs in low-productivity-index (PI) wells and higher flow rates to be obtained from small bore casings. It also allows a limited inventory of pumps to be applied over a broader flow range.

ESP Efficiency Optimization. Either when an ESP system is initially designed or after it is deployed, adjusting the frequency of the unit can maximize the total system efficiency. In light of wellbore PI uncertainties, this allows the operator some flexibility between the requirements of the initial design and the actual operating conditions of the equipment in the wellbore.

Maximize Well Production. If the well PI is greater than that for the original design, either through data error or changing wellbore parameters, the ESP operating point can be increased with a VSC. The HP rating of the motor limits the frequency increase. Remember, the HP load from the pump increases with the cube of the frequency ratio, and the HP capability of the motor increases directly to the speed ratio. Therefore, the designer must consider using an oversized motor if there is a potential need of higher flow rates.

Minimum Well Production. If the well PI is lower than that for the original design, the ESP operating point can be decreased with the VSC. The TDH of the pump is the limiting factor on the minimum VSC frequency. The produced head of the pump decreases with the square of the frequency ratio. Therefore, the designer must consider initially oversizing the pump lift, if there is a potential for reduced-frequency operation.

There may also be cases where the ESP is operated at reduced frequency to reduce stresses on the reservoir. This could prevent reservoir damage or control the influx of unconsolidated sand or frac materials because of sudden pressure differentials across the wellbore face.

ESP Electrical Isolation. In a fixed-speed ESP application, the downhole motor is connected directly to the power source via the switchboard contactor, with isolation only from the transformer and cable impedances. When a VSC is connected, automatic isolation occurs. The input converter and output inverter are decoupled or isolated by the DC bus. Also, high-energy transients open fuses or destroy solid-state semiconductor devices in the VSC instead of potentially damaging the electrical components (motor, cable, electrical penetrators downhole).

Matching Surface Processes. If the well has any surface processing constraints, the wellhead flow and/or pressure can be controlled by the operating frequency. This would include items such as tank level control and flowline pressure. Also, where multiple wells are manifolded together and a constant flow rate is desired, any drop off in the rate of one or more wells can be made up by an increase in speed to one or more wells.

Reduced Starting Stresses. With a VSC, maximum current starting levels can be controlled. At startup, the frequency to produce minimum starting torque can be used with a controlled ramp up to operational speeds and power settings. This produces the optimum soft start. With any added benefits and capabilities, there are also some cautions.

Increased Design Complexity. The ESP application design becomes much more complex with the use of a VSC and, in all practicality, requires the use of a design software program to do it properly.

Utility Interface. When using a VSC, it is desirable not to feedback problems to the utility-power system that could interact with other users on the system. The problems could include a poor input power factor or high-input current distortion (harmonics). A poor power factor leads to unnecessarily high-input current levels, thereby reducing the overall capacity to serve other loads. Input current distortion, which is injected into the power system, can reduce the life of other equipment connected to the system or cause electronic devices to malfunction. Leuthen[20] gives a detailed description of the impact of VSCs on these two utility concerns—how each VSC topology measures up and the method to control or diminish the impact. The guidelines for the harmonic control of electrical power systems is provided in the Inst. of Electrical and Electronic Engineers (IEEE) Stand. 519-1992. [21]

ESP Interface. To fully achieve the benefits that a VSC can bring to an ESP application, care must be taken to understand its impact on the downhole system and minimize any potential damaging influences. Several concerns include: excessive motor heating, increased voltage stress, and maximization of motor torque performance.

Motor Heating. Excessive motor heat can impact the motors performance and, in the long term, its overall life. Operation of an ESP motor with a VSC causes additional heating from two main sources: increased winding losses because of higher current values and increased core losses because of high-frequency components. Because all drives provide a modified sine wave to the motor, it is distorted and contains other frequency components. Therefore, the total current values of VSC operation over across-the-line values are higher. This increased current level produces higher resistive losses in the motor windings, causing increased heat. Increased core losses, because of the changes in applied terminal voltage, also result in higher motor temperatures. When the motor core experiences changes in the applied terminal voltage, the magnetic dipoles must realign to the new magnetic field present. Every time this happens, the friction of the motion of the dipoles releases heat. Therefore, it is important to minimize the subcycle voltage fluctuations at the motor terminals, although testing has shown heat rise to be very small.

Increased Voltage Stress. Even though the VSC is a buffer to input power surges or spikes, their power inverters have the potential to generate higher peak voltages than those from a true sinusoidal voltage source. This is because inverters are inherently digital in nature rather than analog. Basically, the output can only change in discrete voltage steps and the transition from step to step happens very rapidly. When this power is applied to the complex impedance of a downhole ESP system, the natural response is a damped sine wave and the resultant ringing is a normal response. On a VVI drive, the ringing has time to decay to zero between each vertical edge of the waveform. On a PWM waveform, the vertical edge of the VSC output waveform can occur on top of the ringing of a previous vertical edge. Under the worst conditions, this effect can produce peak voltages in multiples of the original applied voltage, and they can occur many times per cycle. This impact can be reduced by the application of filters on the output side of the VSC and step-up transformer. Each PWM application should be reviewed for this potential condition, but, generally, the user should be concerned about high-voltage and -horsepower equipment and long lengths of cable.

Motor Torque. The ESP motor has the capability to deliver a large percentage of its full torque capability over a wide speed range. It is important to examine the VSC’s capability to deliver the necessary current to achieve required torque levels. Any of the VSC types can be matched to the ESP motor when properly set up.


There are components provided by the ESP manufacturers and other suppliers that provide additional mechanical and electrical protection, monitoring, or performance enhancements. Installation of such components on all wells may not be justified, but their use on key wells should be carefully considered. Several of these components are listed next.

Downhole Sensors. Because the ESP operates in a hostile and confined environment, monitoring how it operates is very difficult. Additionally, it is also difficult to find sensors and electronics that operate reliably and long term under the range of downhole conditions required. The ESP’s reliability or run-life is directly related to the continual monitoring of its operating parameters and the wellbore conditions. Not only is this information critical to the run-life, but it is also important for the evaluation of the application design of the ESP system in the hole. This evaluation can provide guidance on possible operational changes that can be made to optimize the current system or the ESP design changes needed to optimize the application. If ESP systems were fully instrumented and continuous monitoring systems employed, improvements in run-life and operational performance would be improved significantly. But, to do this, the wellbore economics has to support it.

Sensors are available for mounting internally in the ESP components or externally as an attachment to the system. The signals from these sensors are communicated to the surface readout module by a separate instrument wire, "I"-wire, or by a signal imposed on one leg of the ESP power cable.

Typically, the standard ESP application only provides the opportunity to monitor surface parameters, such as three-phase amps and volts, wellhead pressure, and, to a limited extent, flow rate. Therefore, the protection and evaluation possibilities are reduced. Today, there are sensor packages available that provide measurement and monitoring of the following parameters.

Pump Intake or Casing Annulus Pressure. This information provides wellbore static pressure and the well flowing pressure at the production rate. If the measurement is sensitive enough, it can also provide excellent well drawdown information.

Internal Motor Temperature. This measurement is critical not only to the protection of the motor but also in selecting the correct motor HP rating and lubricating oil for the application. If a loaded motor is running close to its maximum temperature rating, some operational steps could be implemented to reduce its load and temperature. Also, the next unit in the hole could be derated or sized with a larger motor to run underloaded. Likewise, if the motor is running cool, there are future opportunities to install a smaller motor. Additionally, sudden temperature spikes or long-term gradual changes are an indication of changing equipment performance or wellbore conditions, which may need evaluation.

Pump Discharge Pressure. This parameter provides a reading on the discharge pressure of the pump. This reading and the pump intake pressure provide a measurement of the TDH of the pump. Comparing this value to the design TDH, hydraulic performance of the pump can be monitored and continually evaluated. Additionally, for gassy and/or viscous fluids, pump-performance correction factors can be established or verified for that particular wellbore condition.

Pump Discharge Temperature. This measurement provides the temperature of the discharge fluid from the pump. The production fluid is heated as a result of the heat rejected by the motor and pump inefficiencies. The fluid heat rise through the pump can be used to calculate the fluid volumetric increase and the viscosity change of the fluid. Once again, sudden spikes or longer-term changes can provide warnings of potential problems.

Downhole Flow Rate. Downhole flowmeters are available that provide flow-rate measurements from the pump discharge. This is an excellent tool, when compared to the surface flow rate, for evaluating ESP performance and warning of potential problems. Because surface flow rate is not generally continuously monitored, this can be a piece of information for enhanced ESP protection. In multiphase-fluid (gassy) applications, the selection and calibration of the flowmeter is important because of the difficulty in accurately measuring this fluid.

Equipment Vibration. There have been several applications that have used downhole vibration sensors. Unless there is a sudden step change in the measurement, this parameter is difficult to evaluate. There is a possibility that, with more case histories, this can become a good evaluation tool.

ESP Packers. Typically, ESP packers are used when there is a requirement or a need for it to be set above the ESP system (Fig. 13.35). Their use normally prevents venting free gas up the annulus, unless a vented packer is used. Packers can be shallow set or deep set, depending on design requirements or regulations. ESP packers have an electrical power cable feed-through feature added to the normal wellbore packer functions. A bore for an electrical feed-through mandrel is provided. Mating connectors are attached to the cable from the surface and another to the cable below the packer for connecting to the mandrel. This design allows for the maintenance of a pressure barrier, while still allowing for electrical power communication to the motor.

Packers are used with ESP systems when there is a need to isolate the annular area above the ESP and/or provide a positive barrier between the pressurized wellbore fluid and the area above the packer. Isolating the area above the packer is done to segregate two separate zones or prevent or reduce the rate of wellbore fluid corrosion damage to the casing. With a deep-set packer, operational precautions must be observed to prevent damage to the ESP system. With a deep-set packer, the volume contained between the packer and pump intake is usually small. Upon startup, the ESP can evacuate this volume quickly, causing a sudden drop from wellbore static to flowing pressure. This causes sudden decompression to the cable and internal volumes of the seal-chamber section and motor, especially if they have been saturated with solution gas. This decompression can cause expansion and insulation damage to the cable. If it is severe enough, it can result in extensive expulsion of motor oil from the seal-chamber section and motor, possibly rupturing elastomer seals and bags.

ESP Wellheads. The wellhead is designed to support the weight of the subsurface equipment and to maintain the surface annular control of the well. It is selected on the basis of casing and tubing size, maximum recommended load, surface pressure, and the power cable pass-through requirements. There are two cable pass-through designs. The first uses the compression of elastomer grommets around the power cable jacket to provide a low-pressure seal. It is used in many areas where the well has a zero to low gas/oil ratio (GOR). In areas where the annular pressure can be high or where safety requires a positive pressure barrier, the electrical feed-through mandrel design is used. A feed-through mandrel mounts in a cavity of the wellhead, sealing the annular pressure and providing electrical connection points above and below the wellhead. Mating electrical connectors (pigtails) are spliced to the upper end of the downhole power cable and to the surface power cable.

Centralizers/Protectorilizers. Centralizers are sometimes used when the ESP is installed in a deviated wellbore or into a tapered-string casing. Its function, when used in a deviated wellbore, is to be a contact point with the casing and allow the ESP unit to have some standoff clearance. They are typically located at the bottom of the ESP unit and, in some cases, at points along its length or at the discharge tubing. They have to be constructed so as not to restrict the flow by the motor and to the pump intake. Generally, they are designed with at least three radial fins attached to either tubing, for the top and bottom unit or to metal straps, which can be attached around the ESP body. Centralizers are also used when an ESP is deployed into a tapered-string casing. Its function is to help guide the unit into and through the casing step to reduce the chance of mechanical damage. It is normally a finned configuration with the bottom end tapered or bull nosed.

Protectorilizers are used to protect the power cable, MLE, and any small hydraulic or electrical communication line from mechanical damage in deviated or restricted-clearance casing. Along the ESP unit, they are normally attached at the unit’s flanged connection points and either cradle or cover the MLE and communication lines, so they become the rub points. Protectorilizers are clamped or strapped onto the production tubing for the same purpose. They are usually at the coupling points and midjoint. They also provide axial support to the power cable and replace the cable bands.

Check/Drain Tubing Valves. A check valve is used in the production tubing string, generally two to three joints above the pump discharge, to maintain a full column of fluid above the pump. This may be desired to eliminate the time it takes to raise the fluid from its static fluid level to the surface ("pump-up time") or the protective shutdown time for fluid fallback. Normally, each time an ESP cycles off, the fluid falls back from the surface to its static fluid level. On restart, it again has to lift the fluid from its static point to the surface. Holding the fluid in the tubing can eliminate this. Also, when the fluid is falling back, it causes the de-energized pump to spin backwards. If power is applied during this period, damage to the ESP could result. Generally, a backspin sensor or restart timer is used on the motor controller for premature restart protection.

The use of a check valve should be reviewed in gassy or high-GOR wells and wells that produce significant solids. In a gassy well, when the unit shuts down, a gas cap can form under the check valve and be held there by the fluid column above the check. If the gas cap volume is large enough to extend down to or below the pump intake, the pump will be immediately gas locked and unable to pick up a prime. When there are solids (especially sand) entrained in the production fluid and the ESP is shut down, the solids fall back in the production tubing and settle either on the check valve or into the pump discharge. This could either plug the tubing above the check valve or the pump. Therefore, the use of a check valve in fluids with solids should be reviewed.

Motor Shroud/Recirculation Systems. Shrouds, as shown in Fig. 13.36, are used to redirect the flow of production fluid around the ESP system. The shroud assembly is made up of a jacket (a length of casing or pipe), a hanging clamp and sealing retainer for the top, and a centralizer for the bottom. The jacket dimensions are selected on the basis of shroud location relative to the production source and the function of the shroud. But, at a minimum, the shroud should extend to below the bottom of the motor. The shroud ID has to allow for the insertion of the ESP with flow clearance to allow for proper cooling velocities without choking or excessive pressure drop to the flow. The shroud OD must have sufficient clearance with the casing ID to assure reliable deployment and proper flow from the well perforations to the pump intake. Fluid pressure drop in this annular area, similar to the shroud-to-ESP annular area, can be significant enough to impact the pump intake conditions.

The most commonly used shroud configuration is shown in the left graphic of the same figure. In this configuration, the ESP is set below perforations and the shroud directs the production flow down and back up by the motor for cooling. Otherwise, the fluid would be pulled down to the pump intake, leaving the motor in stagnate fluid with heat rise concerns. The purpose of setting below perforations is to increase the production rate for the same pump intake pressure or to serve as a simple reverse-flow gas-separation system. In the gas-separation application, the configuration depends on the free gas flowing from the perforations taking the path of least resistance—up the open casing annulus, instead of down to the bottom of the shroud. One caution, in this configuration, is not to use a gas-separation intake on the pump. The vented free gas from the separation intake would recycle to the bottom of the shroud, increasing the free-gas ratio to the pump and decreasing the cooling of the motor.

This configuration is not recommended for setting above perforations in an application with free gas. But where the ESP and casing annular area is large, creating too low a cooling flow, a shroud can be used to increase the production-fluid cooling velocity. For those special cases of setting above perforations and the problem of free gas, an inverted shroud (right graphic in the figure) has proved successful in separating free gas from the fluid that is directed back down to the pump intake.

In wells that have a diameter restriction because of tapered casing, liners, or screens, a stinger can be attached to the bottom of the shroud to position the intake below perforations and down into the restriction. A stinger is a section of tubing, usually smaller in diameter than the shroud, which is attached to the bottom of the shroud and provides fluid communication from the wellbore to the interior of the shroud. This configuration is shown in the center graphic of the figure. The pressure drop through the stinger must be calculated to check for possible choking of the pump and also for an increase in the free gas liberated, causing gas interference issues with the pump and cooling issues with the motor.

Screens and Filters. Screens and filters are used with ESP systems to prohibit the flow of large solids into the pump intake. In one configuration (shown on the intake of Fig. 13.2), a mesh screen or perforated metal sheet is wrapped or mounted over the pump intake ports. The mesh or perforation size has to be small enough not to allow the passage of large particles, but large enough not to cause a flow restriction. The size of particle that must be screened is a function of the flow-passageway clearances through the pump. If a shroud is used, a screen can be used to cover the open intake area at the bottom of the shroud.

Filters have also been used on ESP applications. The simplest method is to use a motor shroud with a stinger, shown in the center graphic of Fig. 13.36. The stinger is sealed at the end, perorated along its length, and a filter element or gravel pack is inserted into or around the stinger. The production fluid then has to pass through the stinger filter prior to entering the pump intake.

Several cautions must be mentioned if screens or filters are used. The open area of the screen must be several times larger than that of the open area of the pump intake ports. This allows for proper flow without choking when, not if, the screen starts building up debris and plugging. This is also the case with the filters. Also, remember that the separated debris has to go somewhere and that is generally in the rathole below the ESP. The rathole must be large enough to hold the amount of debris expected over a period of time. This is because if it starts building up on the ESP, it can cause motor heat problems, eventual complete plugging of the intake ports, and difficulty in pulling the unit. Plugged screens and filters may cause severe pump and motor problems, if not designed and applied correctly.

Y-Tool or Bypass. The Y-tool allows for treating or working below the ESP through a bypass. A configuration of the system is shown in Fig. 13.37. The "Y" is somewhat of a misnomer because it is just an offset layout. The bypass tube is on axial centerline with the production tubing string. This allows the work string to have a straight shot through and out the bypass tube from the production tube. Typical sizes for these bypass tubes are 1.995 to 2.441 in. (50.67 to 62.00 mm) ID. The ESP is connected to the offset path of the crossover head and hangs parallel to the bypass tube. Clamps secure the ESP and bypass tube together. During normal operation of the ESP, the bypass is sealed off with a blanking plug seated in a landing nipple, set just below the Y-tool head or by a flapper valve in the cross-over head. The blanking plug can be set and retrieved with wireline or coiled tubing. Y-tool systems are provided and best suited for 7-in. and larger casing applications.

Optional ESP Configurations

What has been described up to this point is the standard ESP configuration. It has the pump, seal-chamber section, and motor attached to the production tubing, in this order from top down. In some wellbore completions and unique ESP applications, the arrangement and configuration of the system is modified. Some of these applications are listed next.

Inverted Bottom-Intake ESP. An inverted-unit configuration has the motor on top, attached to the tubing string; seal-chamber section underneath the motor; and the pump on bottom (Fig. 13.38). For a bottom-intake design, the production fluid is drawn in the intake ports located at the very bottom of the ESP system and discharged out of ports located just below the connection to the seal-chamber section. Because the discharged production fluid cannot flow through the seal-chamber section and motor, it has to exit into the casing or liner annulus and flow past these units. Once above the motor, it can continue flowing up the annulus or be ported back into the production tubing string. Additionally, the casing annulus communication flow path, between the intake and discharge ports, has to be sealed to prevent recirculation. Generally, the intake is stung into the casing packer to seal this path. This configuration is typically used for applications in which the intake needs to be located as low as possible, cavern or mine applications, annular flow designs, coiled tubing with internal power cable, or cable-deployed ESP systems.

The ESP design has to be modified from the standard unit design. In this application, the seal-chamber section and motor have to equalize with the high-pressure discharge conditions. This requires that all the sealing and breathing paths be able to handle the sudden high-pressure, high-velocity startup and shutdown surges.

Inverted Bottom-Discharge ESP. This design is configured the same as the inverted bottom-intake ESP system with the exception that the pump stages are inverted to pump down (Fig. 13.39). Once again, the intake and discharge fluid communication path in the casing annulus has to be closed. Generally, the pump discharge, on the bottom of the ESP assembly, is stung into an isolation packer. The wellbore production fluid is transferred from above this packer to below under high enough pressure to inject into the lower formation. This configuration is typically used for injection of water into a disposal zone.

Special designs that incorporate downhole hydrocyclone separators have been used to separate some of the water from the wellbore fluid (Fig. 13.40). In this case, the reduced-water-content oil is pumped to the surface, and a significant portion of the deoiled water is injected into a disposal zone.

Dual ESP. A dual-ESP configuration is one in which two or more ESP systems are installed concurrently in the same wellbore. One configuration uses a Y-tool with the first ESP attached, as described in the previous Y-tool section, and a second ESP system attached to the bottom of the bypass tube or to another Y-tool bypass head (Fig. 13.41). For a triple system, another Y-tool is attached to the bottom of the first bypass tube, allowing for a third unit to be incorporated. Each ESP system requires its own cable and control system.

A second configuration has the first ESP system connected to the production tubing with a sealed shroud or can around the entire unit (Fig. 13.42). The next ESP system is attached to the bottom of the first unit’s shroud. In this configuration, the lower unit’s discharge feeds the upper unit’s intake so as to set up stepped fluid pressurization.

Parallel Production. A Y-tool, dual ESP system can be used for high-flow-rate applications in which the required HP is too great for one unit or it is desirable to split the total HP requirement into two or more segments. In this case, all the units are operating and discharging into the production tubing at a common pressure, with the total flow rate being a summation of the flow of each individual unit.

Series Production. A dual-ESP system can also be used for high total-developed-head requirements. This is where the lift requirement or pressure increase across the pump is beyond the equipment design limitations. By connecting the ESP systems in series, large pressure increases can be achieved for the desired flow rate while staying within each individual unit’s HP and burst-pressure limitations (Fig. 13.42).

Backup Unit. This concept also utilizes the Y-tool configuration, but only one ESP system operates at a time. The other units are held in backup until the operating unit either fails or is shutdown voluntarily. To prevent recirculation flow through the nonoperating unit, a plug has to be set in the Y-tool flow path. These systems are used in high-cost workover areas to reduce the total number of interventions and operating costs.

Booster ESP. The ESP can also be used as a pressure boost system for surface applications. They can handle a wide variety of fluid conditions and do not have the pressure pulsation attribute associated with positive-displacement-type pumps.

Canned System. This configuration is basically an ESP installed in a shallow well or can (Fig. 13.43). The low-pressure fluid is fed into the can annulus, and the ESP boosts the pressure. It is used primarily for flowline or pipeline pressure boost and for fluid disposal or injection purposes.

Surface Horizontal System. This configuration utilizes an ESP centrifugal pump driven by a surface electric motor, engine drive, or other primary mover. It is generally mounted on a skid for stability and alignment (Fig. 13.44). It can provide a nonpulsating flow and a wide flow range with the use of a variable-speed drive.

Pipeline-Insert System. In this configuration, the ESP is inserted into a parallel section of piping. Fluid can then either flow directly through the pipeline or can be valved to bypass through the pump leg section for pressure boosting.

Through-Tubing-Conveyed ESP. In applications where pump wear and intervention costs are a major concern, a through-tubing-deployed pump is an option. The configuration is shown in Fig. 13.45. The motor and seal-chamber section are deployed on the bottom of a tubing string. The power cable is connected to the motor and deployed with the tubing, locating and protecting it in the casing/tubing annulus. The pump section is then deployed by a work string, typically wireline or coiled tubing, and latched onto the seal-chamber section. Thereafter, workovers, because of pump issues, can be done at a lower expense with wireline or coiled-tubing rigs, instead of regular jointed-tubing workover rigs.

Harsh-Environment Options

ESPs are typically thrust into more difficult and harsh wellbore environments as production conditions change. Harsh or severe conditions include multiphase fluids or high GOR wells, fluids with abrasive particles, viscous fluids, high-temperature wellbores, corrosive fluids, and scale and asphaltenes. With this movement, the demands on the equipment design functions, materials, and operational processes increase. The run-life of the entire system can be affected if proper designs for these applications are not used.

Multiphase Flow.[22][23][24][25][26][27] The presence of free gas in the produced fluid does affect the performance of the ESP pump. Generally, a pump is designed to handle incompressible fluids (liquids), and a compressor is designed to handle compressible fluids (gases). The performance or efficiency of both will suffer if they are required to handle a multiphase fluid (liquid and free gas). Typically, as the amount of free gas to total volume of the pumped fluid increases, the pump-stage head and flow both deteriorate. [22]

Performance Variables. The amount of free gas that an ESP pump can handle is a function of the following variables: pump-stage geometry, operating point of the pump stage, control by a fixed-speed or variable-speed drive, pump-intake flowing pressure, and wellbore geometry.

Pump-Stage Geometry. The gas handling capability of a centrifugal pump stage increases with flow rate or stage specific speed—a nondimensional design parameter. In other words, as the stage style moves from radial to mixed flow (Fig. 13.11), the gas-handling capability increases.

Pump Operating Point. The most stable operating region for a pump stage on gassy fluid is from the maximum recommended flow rate back to its BEP. As the flow rate moves from the BEP toward the minimum recommended operating point, the potential for gas interference affecting pump performance is increased.

VSC Operation. The VSC allows for some additional flexibility and reduction in unit shutdowns that are related to pump gas locking. Tests have shown that the pump gas-handling capability increases slightly with increasing speed. If the pump load decreases and the motor amps drop, indicating an initiation of gas lock, the VSC can be programmed to speed up for a short period to attempt to clear the gas-lock situation. If it clears and the load picks back up, the VSC would then return to its set operating frequency. If it does not clear, the unit would then shut down on an underload situation and restart on the time out delay.

Pump-Intake Pressure. The gas handling capability of the pump is very sensitive to pump-intake pressure. An empirical correlation[26] for the relationship of the amount of free gas a pump can handle and the fluids flowing pressure was established from numerous tests on a variety of pump stages. A graphical representation of this correlation is shown in Fig. 13.46. The area under the curve represents stable operation, and the area above indicates potential gas-interference and -locking regions.

Wellbore Geometry. The natural and mechanical separation of free gas from the flowing fluid is a function of the wellbore geometry. The annular area between the casing and the ESP unit and the fluid flow rate determines the flowing fluid velocity. The natural annular gas separation decreases as the velocity increases. Also, whether the casing is horizontal, inclined, or vertical determines the flow regime of the multiphase fluid and influences its natural separation characteristics. The efficiency of annular separation is still unknown, and additional research must be done in this area.

Optimal ESP Configurations for Gas Handling. Optimal ESP configurations for gassy applications are listed next. Depending on the severity of the application, they can be used individually or in multiple combinations.

Tapered Pumps. Tapered pumps utilize several different sets of pump stages in the same pump housing or pump string. Generally, the first section of stages is mixed-flow style because they can handle a higher percentage of free gas. As the gassy fluid is pressurized through each of these first stages, the total fluid volume decreases because of the compression of the free gas. When the flow rate nears the BEP flow rate of these stages, a second set of stages is selected. Generally, a good design can be accomplished with two or three sets of stages in the taper.

Mechanical Separation. The vortex and rotary separation intake components, which were discussed in the pump section, are used here to add centrifugal separation to the gassy fluid that enters the intake section. Because there are so many variables that affect their effectiveness or efficiency, the manufacturers should be contacted for separation efficiency values or guidelines. These units can also be used in tandem to accomplish series separation.

Motor Shrouds. Not only can motor shrouds be used to raise the velocity of the production fluid by the motor for increased cooling, they can also be used to assist with annular separation of the free gas in the produced fluid. The different styles and their uses were discussed in the section on motor shrouds and recirculation systems.

Recirculation Pump. In a completion scheme where there is insufficient clearance to run a shrouded unit below perforations, a recirculation pump can be used. A recirculation pump bleeds a small portion of the pumped fluid off and circulates it down below the motor by a small-diameter hydraulic tube. This establishes a small flow in the rathole where the motor is set. By properly designing the bleed flow, cooling flow by the motor can be maintained. Since the perforations are above the unit and pump intake, natural annular gas separation can be maximized.

Although there are guidelines from the manufacturers for ESP configurations for gassy applications, the area still remains somewhat of a black art. Since there are so many variables that affect an ESP’s ability to perform in a gassy application, the best method is for the operator to select what they feel is the best solution, based on prior field experience or the manufacturer’s guidelines. Once the equipment is operational, field tests on each wellbore can be conducted to test that specific ESP configuration under those specific wellbore conditions.

Abrasive Slurries.[28][29] The standard ESP pump does not tolerate abrasive particles in the pump fluid. The amount of tolerance is directly related to the aggressiveness of the solids or sand. The aggressiveness is a function of the percentage of the solid substance that is harder than the material of the pump components, the size and shape of the particles, and the concentration of solids in the fluid. The most aggressive solids are those with a high solids concentration ( > 1% by weight ), a large percentage of the solids sample being quartz (harder than the base stage and bearing material), a majority of the sample under a 100-mesh sieve size (able to get into the bearing and sealing areas easier and faster), or quartz grain shapes that are angular or barbed. On the other extreme, there are cases where very round, smooth, soft sands are relatively benign to the operation of the pump.

Performance Impact of Abrasives. There are three types of wear that impact the pump stage and its performance. They are listed next and prioritized in order of importance or impact.

Radial Wear. As the slurry wears the radial-support bushing system of the pump, it loses its lateral stability. This allows the rotating parts to start interfering with the stationary parts. Vibration increases, and it starts impacting the top of the seal section where the first mechanical shaft face seal is located. Once vibration and radial movement start to influence the face seal, leakage starts across the sealing face. This initiates a path for the well fluid to progress toward the motor.

Downthrust Wear. On the floating-style stages, the abrasive slurry migrates into the downthrust bearing pad area of the pump stage. The stationary diffuser thrust pad starts boring into the impeller thrust washer area. Once it breaks through the lower shroud of the impeller, the impeller loses part of its work to recirculation flow. As the diffuser pad bores further into the impeller passageway, it also blocks a portion of the impeller flow path, thus restricting the remaining flow.

Erosion Wear. As with any abrasive-slurry flow along a twisting path, erosion wear takes place. Although it is not usually associated with the failure of the pump, it is a potential failure mode and a concern, especially when modifications have been made to the pump to address the radial and downthrust wear modes. Erosion wear not only damages the stage pieces, it also wears any surface with which it comes into contact. Severe cases have resulted in the wear perforating the pump or production-tubing walls and dropping units in the well.

Optional ESP Configurations for Abrasives. Depending on the severity of the application, the following design options can be used individually or in combination.

Compression Pumps. For many years, this was the answer for abrasive applications. In a compression or "fixed-impeller" pump, the impellers are fixed to the shaft or stacked hub to hub so there is no axial movement. With all the impellers fixed relative to the shaft, the whole impeller stack can be raised slightly so that it does not run into contact with the downthrust or upthrust pads on the diffuser. This pump design eliminates the downthrust wear mode. When it is used in conjunction with hardened journal bearings, it also addresses radial wear problems. There are several issues with compression pumps. First, they are very difficult to assemble properly. Because an ESP pump is a very long, multistaged assembly, it is very difficult to locate all of the impellers and still have the needed minimum shaft axial movement. Also, now, the thrust of each impeller is transferred to the shaft and is added to the normal shaft thrust produced by the discharge pressure on the top area of the shaft. The thrust bearing in the seal-chamber section is required to carry this additional thrust. Additionally, as the sealing areas of the pump stage wear, the downthrust also increases. Therefore, the selection of the proper thrust bearing is critical, and the anticipated thrust must be calculated on the basis of the maximum thrust seen from worn stages.

Thrust and Radial Protection. In this modification, the base material in the radial and downthrust areas of the stage is replaced with inserts of hardened materials. The materials are usually tungsten or silicon carbides, or ceramics. This results in a pump with both radial and downthrust protection but is built in a floater style.

Erosion Protection. Currently, this area is under development, but some coatings, heat treatments, surface hardening, and hard-material liners have had limited-to-moderate success.

Generally, the abrasive production fluid does not impact the motor and seal-chamber section. There could be minor erosion worries because of the flow velocities of the production fluid by the outside surfaces of both units. Also, if the top shaft’s mechanical face seal in the seal-chamber section is exposed and operates in the production fluid, hardened stationary and rotating seal faces are recommended.

Viscous Crude and Emulsions. ESPs are also used to lift viscous fluids, commonly referred to as heavy and extra-heavy crudes. Viscosity is defined as the resistance of a fluid to movement as a result of internal friction. Resistance causes additional internal losses in a centrifugal pump. The increases in internal losses of a centrifugal pump affect each performance parameter.

Performance Impact of Fluid Viscosity. Effect on Flow Capacity. Flow capacity of a given pump stage diminishes rapidly with a relatively small increase in viscosity. The rate of correction tends to moderate as viscosity continues to increase. The amount of correction is also dependent on stage geometry, and the decrease in capacity is more exaggerated for radial flow stages.

Effect on Head. The total dynamic head at the BEP diminishes on a moderate curve as viscosity increases. It is affected to a lesser extent than flow capacity. The head at zero flow remains relatively constant. Fig. 13.47 shows various head vs. flow-rate curves for an ESP pump stage rated for about 2,100 B/D on water.

Effect on Horsepower. BHP increases rapidly with increasing viscosity but tends to level off because of diminishing flow rate and total dynamic head (Fig. 13.48).

Effect on Efficiency. Efficiency decreases in proportion to the changes in flow capacity, TDH, and HP, in terms of Eq. 13.1 (Fig. 13.49).

There are several published methods for estimating the effect of viscosity on the head, flow rate, and BHP of a centrifugal pump. These "standard" correction factors are usually not accurate for the specific small-diameter, multistage design of ESP pumps. Therefore, most manufacturers have established corrections through testing for each pump stage type in their product line. These correction factors are based on dead-oil viscosity values for the fluid at pump-intake conditions. When applying these corrections to the pump, the following should also be considered.

Effects of Gas. When gas saturates into the crude, it reduces the viscosity of the fluid. Some amount of gas is helpful in reducing fluid viscosity, but an excessive amount of free gas is disruptive to well fluid production. Gas tends to migrate out of highly-viscous fluid slowly. Therefore, a higher percentage of gas tends to pass through the pump with the produced well fluid. In an application with gas, the designer must be aware of two viscosity values. The first is the dead-oil viscosity. This is the viscosity of the crude at dead or completely degassed conditions. The other is the live-oil viscosity. It is the apparent viscosity of the gas-saturated crude and the viscosity that affects the pump performance in a well with gas. There are several dead-oil and saturated-oil viscosity correlations that can be used during the design process. The correlation selection should be based on modeling of the actual wellbore performance.

Effect of Temperature. Temperature has a dramatic effect on the viscosity of the crude oil. Therefore, it is critical to the ESP design process that the fluid temperature in the wellbore at the pump setting depth is known. This determines the fluid viscosity and pump-performance correction factors at the first pump stage. Additionally, the inefficiency of the pump results in additional heat loss to the fluid and surrounding wellbore. This incremental elevation in temperature from stage to stage through the pump moderates the impact of the fluid viscosity on the total pump performance. Therefore, the designer should, at a minimum, use an average viscosity for the fluid through the pump for sizing applications. A more accurate method is to calculate the performance on a stage-by-stage basis, using the fluid input conditions to each stage. Most design software programs use this method.

Effects of Water. With the incursion of water or brine into the wellbore, the viscosity of the oil/water mixture can increase, sometimes dramatically when emulsions occur. The shear forces on the fluid mixture, as it flows through the formation, perforations, or centrifugal pump, can cause an emulsion. Because thousands of molecular structures with different chemical and physical properties exist in crude oils, it is virtually impossible to predict viscosity characteristics on the basis of oil and water cuts. A default viscosity correction factor for emulsions, referenced in many petroleum engineering textbooks and references, has been used for many years with questionable results.[30] The correction factor is shown graphically in Fig. 13.50. The curve provides for a progressive increase in the viscosity multiplier, up to 15, as the water cut increases. It then drops to 1, indicating the emulsion has inverted or become water-wetted. Use of this correction factor in viscous applications has indicated that it is too severe. Recent work has shown that because of the complexity of emulsion characteristics, it is best to run carefully controlled baseline laboratory tests on reservoir crude and brine samples to develop an emulsion correction curve. [31]

ESP Options for Fluid Viscosity. Several options are available for improving the performance of the ESP pump when applied to viscous crudes.

Dilution. Some success has been achieved with diluent injection. In this process, a lighter crude or refined product, such as diesel, is injected from the surface via a separate hydraulic line to a point below the ESP or directly into the pump intake. This effectively cuts the viscosity of the wellbore fluids. The amount of injected diluent depends on the desired final mixture viscosity. This type of viscosity reduction also reduces the surface flowline losses, which reduces the required wellhead pressure or the need for diluent injection at the wellhead. Using a diluent fluid is an effective, but expensive, approach.

Temperature Increase. The temperature of the reservoir or near-wellbore area can be artificially raised to make the viscous crude more mobile. The most successful method for adding heat has been through steam injection or soaking, although trials have been made with resistive, induction, and microwave technologies. This reduces the viscosity of the crude, but it also raises concerns in high-temperature operations.

Chemical Injection. Viscosity-reduction and emulsion-breaking chemicals can be injected from the surface by hydraulic injection lines. This impacts the fluids in the annulus and through the pump but not very far back into the reservoir.

Water Injection. When emulsions are encountered through a certain water-cut range, additional water can be injected to increase the water cut of the produced fluid, moving it out of the high-viscosity correction area. Field trials on this concept were conducted in the mid-1980s and were successful in reducing the fluid viscosity and increasing the ESP performance.

High Temperature. Another trend has been the application of ESPs into higher-temperature reservoirs. Typically, these are reservoirs that are either deeper or artificially heated. Standard ESP systems are commonly applied to well ambient temperatures of 250°F (121°C). Even with a velocity greater than 1 ft/sec, the temperature rise above ambient conditions will be about 50°F (10°C) for water and 90°F (32°C) for oil—higher if fluids contain gas.

Systems that have minor modifications or optional features are applied in ambient temperatures up to 350°F (177°C). Additional research and field testing is being done on systems that operate in ambient temperatures above 350°F. For these units, the motor and seal-chamber section have the most significant design changes. The design areas of concern in the motor include the insulation system, mechanical bearing system, and the internal lubrication and cooling system. The seal-chamber section modifications include the mechanical journal and thrust bearing systems, internal lubricating system, and, in positive-barrier styles, the elastomeric bag. Also, the selection of a power cable rated for elevated temperature service is critical.

Since the early 1990s, the focus on the application of submersible motors in high-temperature wells has not been entirely on the ambient wellbore temperature, but rather the internal operating temperature of the motor. This is because, even in what would be considered a relatively cool well, a misapplied design can possibly operate at dangerously high internal operating temperatures. Most of the ESP application software programs calculate the expected motor operating temperatures, or the manufacturer can be contacted to provide this information. The calculation of the motor operating temperature involves many variables, which were mentioned in the previous motor-heat-rise section. Historically, this calculation has been made at the stabilized design operating point of the motor. Recently, new computerized programs have allowed the ESP system operating conditions to be dynamically modeled from the static startup condition to the stabilized-flow operating point. This has allowed the designer to identify potentially dangerous transient operating conditions and to provide for options to eliminate or reduce their impact.

If the operator is operating an ESP at elevated motor operating conditions, it is suggested that a downhole motor-temperature monitoring system be run. This monitor provides warning of any high-temperature excursions of the downhole system so that remedial action is taken before potential catastrophic damage occurs.

Corrosion. The application expansion of ESPs into more corrosive wells has required the industry to provide enhanced corrosion-protection options. In the early years, the normal protection scheme for mild-corrosion applications was the use of protective coatings. These were either epoxy paint, babbit spray, or stainless-steel/high-alloy metal flame spray. Each of these has the disadvantage of the potential for mechanical damage during the installation handling process and deployment through the casing. The need for a higher-level corrosion-resistant ESP was first recognized with the application of units into carbon dioxide (CO2) enhanced-recovery reservoirs in the late 1970s. From this need, the first-generation corrosion-resistant ESP unit was developed. Current units use high-chromium alloys in the components exposed to the wellbore fluids.

Another source of corrosion is hydrogen sulfide, H2S. The H2S mainly attacks copper-based alloys of the pump, seal-chamber section, and cable. This type of corrosion can be controlled by replacing the copper-based alloy components with suitable materials or by isolating them from exposure to the well fluid and gases. When CO2, H2S, and hot brine are combined, unpredictable corrosion results may appear. With small changes in the concentration of CO2 and/or H2S and temperature, corrosion could even vary significantly from well to well within the same reservoir.

Another corrosion mechanism that has been around the oil field for years, but has been misunderstood or misdiagnosed, is microbiologically influenced or induced corrosion. [32] It is caused by sulfate-reducing bacteria, as well as other forms of anaerobic and aerobic bacteria. The four common types found in oil wells and affecting ESPs are anaerobic sulfate-reducing bacteria (SRB), anaerobic acid-producing bacteria, aerobic acid-producing bacteria, and slime-forming bacteria. The SRB and anaerobic/aerobic acid-producing bacteria species attach themselves to the surface of the ESP components and cause direct and indirect corrosion and severe pitting. The slime-forming species can cause some minor corrosion but is noted more for downhole formation and equipment plugging.

Scale and Asphaltenes. If the well has scaling or asphaltene-forming tendencies, these can be detrimental to the performance and run-life of the total ESP system. Because of the characteristics of the ESP system, there are pressure and temperature changes, which provide a mechanism for scales to form or precipitate out of solution. Typically, scales cause two problems. They plug the flow passageways of the pump stages, reducing or stopping the flow entirely. They also adhere to the outside surfaces of the motor and seal-chamber section, reducing the heat-transfer rate, causing both units to run hotter. Asphaltenes generally only cause plugging of the pump stages. Both problems can be reduced, but not totally eliminated, by applying synthetic coatings to the surfaces affected or by using a downhole inhibitor-chemical treatment.

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. [3] 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. [33] 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. [4] Also, each ESP manufacturer has recommendations and guidelines on this topic.

Baillie[34] 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. [35][36][37][38] 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.

ESP System Selection and Performance Calculations

The sizing and selection procedure is from a published nine-step design procedure. [39] The overview provides a step-by-step process for evaluating and selecting the proper ESP equipment for a particular application. This is a manual procedure used to illustrate the ESP design steps. While it is accurate for simple water and light-crude designs, there are commercially available ESP design software programs that give accurate designs for wells with high GORs, viscous crudes, high temperature, and/or operation on VSCs.

This nine-step procedure helps one design the appropriate submersible pumping system for a particular well. Each of the nine steps is explained in the sections that follow, including gas calculations and variable-speed operations. The nine steps are listed next.

  • Step One: Basic Data—Collect and analyze all the well data that will be used in the design.
  • Step Two: Production Capacity—Determine the well productivity at the desired pump setting depth, or determine the pump setting depth at the desired production rate.
  • Step Three: Gas Calculations—Calculate the fluid volumes, including gas at the pump-intake conditions.
  • Step Four: TDH—Determine the pump discharge requirement.
  • Step Five: Pump Type—For a given capacity and TDH, select the pump type that will have the highest efficiency for the desired flow rate.
  • Step Six: Optimum Size of Components—Select the optimum size of pump, motor, and seal section, and check equipment limitations.
  • Step Seven: Electric Cable—Select the correct type and size of cable.
  • Step Eight: Accessory and Optional Equipment—Select the motor controller, transformer, tubing head, and optional equipment.
  • Step Nine: The Variable-Speed Pumping System—For additional operational flexibility, select the variable-speed submersible pumping system.

Step One: Basic Data

The design of a submersible pumping unit, under most conditions, is not a difficult task, especially if reliable data are available. Although, if the information, especially that pertaining to the well’s capacity, is poor, the design will usually be marginal. Bad data often result in a misapplied pump and costly operation. A misapplied pump may operate outside the recommended range, overload or underload the motor, or draw down the well at a rapid rate that may result in formation damage. On the other extreme, the pump may not be large enough to provide the desired production rate.

Too often, data from other wells in the same field or in a nearby area are used, assuming that wells from the same producing horizon have similar characteristics. Unfortunately, for the engineer sizing the submersible installations, oil wells are much like fingerprints (i.e., no two are quite alike).

The actual selection procedure can vary significantly depending on the well-fluid properties. The three major types of ESP applications are wells with single-phase flow of oil and/or water, wells with multiphase flow of liquids and gas (especially high free-gas rates), and wells producing highly-viscous fluids typically much greater than 10 cp. A list of required data is outlined next.

  • Well Data: Casing or liner size, weight, grade; tubing size, weight, grade type and thread, plus condition; pump setting depth (measured and vertical); perforated or openhole interval; well plugback total depth (measured and vertical).
  • Production Data: Wellhead tubing pressure; wellhead casing pressure; present production rate; producing fluid level and/or pump-intake pressure at datum point; static fluid level and/or static bottomhole pressure at datum point; datum point; bottomhole temperature; desired production rate (target); GOR; and water cut.
  • Well-Fluid Conditions: Specific gravity of water; oil °API or specific gravity; specific gravity of gas; bubblepoint pressure of gas; viscosity of oil (dead); and other available pressure/volume/temperature (PVT) data.
  • Power Sources: Available primary voltage, frequency, and power source capabilities.
  • Possible Production Problems: Sand, scale deposition, corrosion, paraffin/asphaltenes, emulsion, gas, high reservoir temperature.

Step Two: Production Capacity

The following is a simplification of procedures for predicting well performance. This discussion assumes little or no well skin. A damaged wellbore or other factors affects the well flow performance.

Productivity Index. When the well flowing pressure (Pwf) is greater than bubblepoint pressure (Pb), the fluid flow is single-phase flow, and the inflow performance relationship is a straight line with slope J, as given by the PI.


Inflow Performance Relationships. If Pwf is less than Pb, resulting in multiphase flow in the reservoir, the inflow-performance-relationship (IPR) method should be used. The relationship is given by Eq. 13.13.


This relationship was first used by Gilbert[40] and further developed by Vogel. [41] Vogel developed a dimensionless reference curve that can be used to determine the IPR curve for a particular well. Others have developed variations of the IPR equation. (See the chapter on inflow and outflow in this section of the Handbook).

Step Three: Gas Calculations

The presence of free gas at the pump intake and in the discharge tubing makes the process of equipment selection much more complicated and voluminous. As the fluid (liquid/gas mixture) flows through the pump stages from the intake to the discharge and through the discharge tubing, the pressure and, consequently, fluid properties (such as volume, density, etc.) are undergoing continuous change. Also, the presence of free gas in the discharge tubing may create a significant "gas lift" effect and considerably reduce the required discharge pressure or TDH of the pump.

Ideally, a well is produced with a submergence pressure above the bubblepoint pressure to keep gases in solution at the pump intake. This is typically not feasible, so the gases must be either handled by the pump or separated from the other fluids prior to the pump intake.

It is essential to determine the effect of the gas on the fluid volume to select the proper pump and any auxiliary equipment. The following calculations yield the approximate percent free gas by volume.

If the solution GOR (Rs), the gas volume factor (Bg), and the formation volume factor (Bo) are not available from reservoir data, they must be calculated, and there are a number of multiphase correlations to select from. The correlation selected will affect the design, so select the one that best matches the conditions. Standings correlations for solution GOR and formation volume factor are shown next.

Solution GOR


Or, in metric,


Note: pump-intake pressure should be substituted for bubblepoint pressure when calculating pump-intake conditions.

Gas Volume Factor. The gas volume factor, Bg, is expressed in reservoir scf/bbl gas (m3/m3).


Or, in metric,


Formation Volume Factor. The formation volume factor, Bo , represents the increased volume that a barrel of oil occupies in the formation as compared to the stock-tank barrel of oil (STBO).




Or, in metric,


Also, see chapters in the General Engineering section of this Handbook.

Total Volume of Fluids. When these three variables: Rs, Bo, and Bg are known, the volumes of oil, water, and free gas can be determined and percentages of each calculated. The total volume of gas (both free and in solution ) can be determined as


The gas in solution at submergence pressure can be determined as


The free gas equals the total gas minus the solution gas. The volume of oil (Vo) at the pump intake is equal to stock-tank barrels multiplied by Bo, the formation volume factor. The volume of gas (Vg) at the pump intake is equal to the amount of free gas multiplied by Bg, the gas volume factor. The volume of water (Vw) in the formation is approximately the same as stock tank barrels. Total fluid volume (Vt) can now be determined.


The percentage of free gas to total volume of fluids can now be calculated as


Step Four: Total Dynamic Head

The next step is to determine the TDH required to pump the desired capacity. The total pump head refers to feet (meters) of liquid being pumped and is calculated to be the sum of: net well lift, HL; well-tubing friction loss, Ft; and wellhead pressure head, Hwh. The simplified equation is written as


Step Five: Pump Type

Refer to the manufacturer’s catalog for pump types, ranges, and pump-performance curves (60 Hz and 50 Hz). On the basis of expected fluid production rate and casing size, select the pump type that will, at the expected producing rate, be operating within the pump’s operating range and near to the pump’s peak efficiency.

Where two or more pump types have similar efficiencies at the desired volume, certain conditions determine the pump choice:

  • Pump prices and corresponding motor sizes and prices may differ somewhat. Normally, the larger-diameter pump and motor are less expensive and operate at higher efficiencies.
  • When the well’s capacity is not known, or cannot be closely estimated, a pump with a "steep" characteristic curve should be chosen. If the desired volume falls at a point where two pump types have approximately equal efficiency, choose the pump type that requires the greatest number of stages. Such a pump will produce a capacity nearest the desired volume even if the well lift is substantially more or less than expected.
  • If gas is present in the produced fluid, a gas separator may be required to achieve efficient operation. Note that the free gas is vented up the casing annulus. Refer to Step 3 to determine the effect of gas on the produced volume. The adjusted volume affects pump selection and the size of the other system components.
  • In wells where the fluid is quite viscous and/or tends to emulsify, or in other extraordinary circumstances, some pump corrections may be necessary to ensure a more efficient operation. In such cases, contact the manufacturer for engineering recommendations.

The Variable-Speed Submersible Pumping (VSSP) System and Pump Selection. Under the previous or other pumping conditions, also consider the VSSP system. Such systems must be justified. For instance, in item two in the previous section, if the production rate is not accurately known, a VSSP system may be applicable. A VSC effectively converts a single pump into a family of pumps, so a pump can be selected for an estimated range and adjusted for the desired production level, once more data are collected.

Review Step 9 when considering the VSSP system. Variable-frequency performance curves are included in most manufacturers’ information. The VSSP system with the VSC may provide additional economies of capital expenditure and operating expenses and should be considered in Step 6. The VSC and transformers for the VSSP system are discussed in Steps 8 and 9.

Step 6: Optimum Size of Components

ESP components are built in a number of sizes and can be assembled in a variety of combinations. These combinations must be carefully determined to operate the submersible pumping system within production requirements, material strength, and temperature limits. While sizing components, refer to the manufacturer for the following information: equipment combinations in various casings, maximum loading limits, maximum diameter of units, velocity of a fluid passing a motor, shaft HP limitations at various frequencies.

Pump. Refer to the manufacturer’s performance curve of the selected pump type, and determine the number of stages required to produce the anticipated capacity against the previously calculated total dynamic head. Usually, performance curves for 60-Hz, 50-Hz, and variable-frequency operations are provided in the manufacturer’s catalog. The pump characteristic curves are stage performance curves based on water with a specific gravity of 1.0. At the intersection of the desired production rate (bottom scale) and the head-capacity curve (vertical scale), read the head value on the left scale. Divide this value into the TDH to determine the number of stages: total stages = TDH/(head/stage).

Separator. Refer to the manufacturer’s catalog for gas-separator information. Make the necessary adjustments in HP requirements and housing length.

Motor. To select the proper motor size for a predetermined pump size, the BHP required by the pump must be determined. The HP per stage is obtained by referring to the performance curve for the selected pump. The BHP required to drive a given pump is easily calculated by the following formula: BHP = total stages × (BHP/stage) × SG.

Refer to the manufacturer’s information for motor specifications. Select a motor size that closely meets the design conditions. The maximum load conditions should not exceed 110% of rating. Minimum operating loads should not put the motor into an idle condition, otherwise protection monitoring is nullified. Manufacturers should be contacted for specific operating ranges. Typically, operators try to select a motor that operates in the range from 70 to 100% of its rating.

Seal Selection. Refer to a manufacturer’s catalog for selection of the proper seal section.

Step 7: Electric Cable

ESP electric cables are normally available in conductor sizes 1, 2, 4, and 6. These sizes are offered in both round and flat configurations. Several types of armor and insulation are available for protection against corrosive fluids and severe environments.

Cable selection involves the determination of cable size, cable type, and cable length.

Cable Size. The proper cable size is dependent on combined factors of voltage drop, amperage, and available space between tubing collars and casing.

Refer to the cable voltage drop curve (samples are shown in Fig 13.28 ) for voltage drop in cable. At the selected motor amperage and the given downhole temperature, the selection of a cable size that gives a voltage drop of less than 30 volts per 1,000 ft (305 m) can be used as a guideline. This curve determines the necessary surface voltage (motor voltage plus voltage drop in the cable) required to operate the motor.

Finally, check the manufacturer’s information to determine if the size selected can be used with the proposed tubing and well casing sizes. The cable diameter plus tubing-collar diameter must be less than the ID of the casing. To determine the optimum cable size, consider future equipment requirements that may require the use of a larger-sized cable.

Where power cost is a major concern, kilowatt-hour loss curves can be used to justify the cable selection. Although power rates vary widely, this information is valuable in determining the economics of various cable sizes.

Cable Type. Selection of the cable type is primarily based on fluid conditions, bottomhole temperature, and space limitations within the casing annulus. Carefully select the type of cable for hostile environments. Refer to the manufacturers catalog for cable specifications. Where there is not sufficient space to run round cable, use electric cable with a flat configuration. The flat cable configuration induces a voltage imbalance. If it is significant, a transition splice may be required. Verify this with the manufacturer.

Cable Length. The total cable length should be about 100 ft (30 m) longer than the measured pump setting depth to make surface connections a safe distance from the wellhead. Check the voltage available at the motor terminal block to avoid the possibility of low voltage starts. The available motor terminal voltage is the surface supply voltage minus the cable voltage drop.

Cable Venting. In all wells, it is necessary to vent gases from the cable prior to the motor controller to avoid explosive conditions. A cable venting box is available to protect the motor controller from such gases.

Step 8: Accessory and Optional Equipment

Downhole Accessory Equipment

FlatCable (Motor Lead Extension). Select a length at least 6 ft (1.8 m) longer than the pump intake (standard or gas separator) and seal section for the motor series chosen. Refer to the manufacturer’s information for dimensions.

Flat-Cable Guard (Optional). Choose the required number for 6-ft (1.8-m) guard sections to at least equal the flat-cable length. Do not use guards for installation of a 400 series pump and seal section with 5 1/2-in. OD and 20-lbm casing, and a 513 series pump and seal section with 6 5/8-in. OD and 26-lbm casing.

Cable Bands. Use one 30-in. (76-cm) cable band every 2 ft (60 cm) for clamping flat cables to pumps. The 22-in. (56-cm) length can be used for all tubing/cable combinations through 3½-OD tubing. For 4 1/2-in.- and 5 1/2-in.-OD tubing, use 30-in. (76-cm) bands. One band is required for each 15 ft (5 m) of setting depth. Refer to the manufacturer’s information for dimensions.

Swaged Nipple, Check Valve, and Drain Valve (Optional). Select these accessories on the basis of required ODs and type of threads.

Motor Controllers. Motor controllers are typical state-of-the-art digital controls consisting of two components.

System Unit. This unit performs all the shutdown and restart operations. It is mounted in the low-voltage compartment of the control panel.

Display Unit (Optional). This unit displays readings, set points, and alarms. It is normally mounted in the amp chart enclosure for easy access. It provides all the basic functions, such as underload, overload, phase imbalance, phase rotation, and many other parameters including password and communication protocols.

Single-Phase and Three-Phase Transformers. The type of transformer selected depends on the size of the primary power system and the required secondary voltage. Three-phase isolation stepup transformers are generally selected for increasing voltage from a low-voltage system, while a bank of three identical single-phase transformers is usually selected for reducing a high-voltage primary power source to the required surface voltage.

On existing systems, some ESP units operate without the use of an additional transformer. For new installation of units with higher voltages, it is usually less expensive to install three single-phase transformers, connected wye, to eliminate the auto-transformer.

In choosing the size of a stepup transformer or a bank of three single-phase transformers, Eq. 13.26 is used to calculate the total kilowatts/volts/amps (KVA) required.


Surface Cable. Choose the approximate length required for connecting the controller to the primary power system or transformer. Two pieces are generally required for installations using an auto-transformer. Size should equal the well cable size, except in the case of stepup or auto-transformer, where the primary and secondary currents are not the same.

Wellheads and Accessories. Select the wellhead on the basis of casing size, tubing size, maximum recommended load, surface pressure, and maximum setting depth. Electric cable passes through the wellhead where pressure fittings are not required.

Electric-feed-through (EFT) mandrels are also available. The electric cable is spliced to pigtails. The EFT wellheads seal against downhole pressure and prevent gas leaks at the surface.

Servicing Equipment

Cable Reels, Reel Supports, and Cable Guides. Select the size of cable reel required to handle the previously selected cable size. Select a set of cable-reel supports on the basis of cable-reel size. Cable guides are designed to handle cable sizes 1 through 6. Normally, customers retain one cable reel, one set of reel supports, and one cable guide wheel for future use.

Shipping Cases. Select the type and length of the case required accommodating the previously selected motor, pump, gas separator, and seal.

Optional Equipment

Bottomhole Sensing Device. The downhole sensor provides continuous measurement of parameters such as wellbore pressures, wellbore or ESP temperature, discharge flow rates, water contamination of the motor, or equipment vibration.

Automatic Well Monitoring. Motor controllers are available for the continuous monitoring of pump operations from a central location.

Step 9: Variable Speed Submersible Pumping System

The ESP system can be modified to include a variable-frequency controller so that it operates over a broader range of capacity, head, and efficiency. Most of the ESP manufacturers and several third parties have computerized pump-selection programs to assist in VSSP-system selection; what follows is a basic explanation of the principles involved.

Variable Frequency. The VSC is commonly used to generate any frequency between 30 and 90 Hz. Pump-performance curves for frequencies other than 60 Hz can be generated with the affinity laws (Eqs. 13.2 through 13.4). The output rating of the motor is also affected by the operating frequency (Eq. 13.9).

A set of curves can be developed for an arbitrary series of frequencies with these equations, as shown in the variable-frequency performance curves at the end of this step (Fig. 13.51). Each curve represents a series of points derived from the 60-Hz curve for flow and corresponding head points, transformed using the previously mentioned equations.

Suppose we are given the following data at a frequency of 60 Hz: rate = 1,200 B/D; head = 24.5 ft (from FC-1200 curve at 1,200 B/D); BHP = 0.34 BHP (from FC-1200 curve at 1,200 B/D). If a new frequency of 50 Hz is chosen, the data will be: new rate = (50/60) × 1,200 B/D = 1,000 B/D; new head = (50/60)2 × 24.5 ft = 17 ft; and new BHP = (50/60)3 × 034 BHP = 0.20 BHP.

By performing these calculations at other production rates, a new curve for 50-Hz operation can be plotted. Start by locating the existing points on the one-stage 60-Hz curve:
  • Q1 rate, B/D: 0; 950; 1,200; 1550; and 1,875.
  • H1 head, ft: 32, 28.6, 24.5, 15, and 0.
  • Efficiency, %: 1, 63.5, 64, 49, and 0.

Following the previous equations, calculate the corresponding values at 50 Hz:

  • Q1 rate, B/D: 0; 792; 1,000; 1,292; and 1,563.
  • H1 head, ft: 22.2, 19.9, 17, 10.4, and 0.
  • Efficiency, %: 0, 63.5, 64, 49, and 0.

Plotting these coordinates gives the one-stage FC-1200 head-capacity performance curve an operation at 50 Hz. Similar calculations provide coordinates for curves at other frequencies, as shown by the FC-1200 variable-speed performance curve (Fig. 13.51). The vortex-shaped window is the recommended operating range for the pump. As long as the hydraulic requirement falls within this range, the pump is within the recommended operating range.

Design Example

Step One: Basic Data

The data used for this example are given next.

Well Data. K55 casing from surface to 5,600 ft: 7 in. and 26 lbm/ft; K55 liner from 5,530 to 6,930 ft: 5 in. and 15 lbm/ft; J55 EUE API tubing: 2 7/8 in. and 6.5 lbm/ft; perforations and true vertical depth (TVD): 6,750 to 6,850 ft; and pump setting TVD (just above liner top): 5,500 ft.

Production Data. Tubing pressure: 100 psi; casing pressure: 100 psi; present production rate: 850 BFPD; pump-intake pressure: 2,600 psi; static bottomhole pressure: 3,200 psi; datum point: 6,800 ft; bottomhole temperature: 160°F; minimum desired production rate: 2,300 BFPD; GOR: 300 scf/STB; and water cut: 75%.

Well Fluid Conditions. Specific gravity of water: 1.085; oil °API or SG: 32; SG of gas: 0.7; bubblepoint pressure of gas: 1,500 psi; viscosity of oil: N/A; PVT data: none.

Power Sources. Available primary voltage: 12,470 V; frequency: 60 Hz; power source capabilities: N/A.

Possible Problems. There were no reported problems.

Step Two: Production Capacity

Determine the well productivity at the test pressure and production rate. In this case, the maximum production rate is desired without resulting in severe gas-interference problems. The pump-intake pressure at the desired production rate can be calculated from the present production conditions.

Because the well flowing pressure (2,600 psi) is greater than bubblepoint pressure (1,500 psi), the constant-PI method will most probably give satisfactory results. First, one can determine the PI using the test data:




Next, we can determine the new well flowing pressure (Pwf) at the estimated production rate (Qd).




The well flowing pressure of 1,580 psi is still above the bubblepoint pressure of 1,500 psi; therefore, the PI approach should give good results. The pump-intake pressure can be determined by correcting the flowing bottomhole pressure for the difference in the pump setting depth and datum point, and by considering the friction-loss datum point and friction loss in the casing annulus. In the given example, as the pump is set 1,300 ft above the perforations, the friction loss, because of flow of fluid through the annulus from perforations to pump setting depth, is small, as compared to the flowing pressure, and can be neglected.

Because there is both water and oil in the produced fluids, it is necessary to calculate a composite SG of the produced fluids. To find the composite SG, water cut is 75%; therefore,


Oil is 25%; therefore,


The composite SG is the sum of the weighted percentages:


The pressure, because of the difference in perforation depth and pump setting depth (6,800 to 5,500 ft = 1,300 ft), can be determined as:




Therefore, the pump intake pressure is


Step Three: Gas Calculations

In this third step, one must determine the total fluid mixture, inclusive of water, oil, and free gas that is ingested by the pump. Use actual PVT data if available. For this example, Standing’s correlation was used. [5]

Determine the solution GOR (Rs) at the pump-intake pressure by substituting the pump-intake pressure for the bubblepoint pressure (Pb) in Standing’s equation. This relationship can also be found as a monograph in many textbooks or in chapters in the General Engineering section of this Handbook.




Determine the formation volume factor (Bo) with Rs and the following Standing’s equation (can also be found as a monograph).








Determine the gas volume factor (Bg) as


By assuming 0.85 Z factor (use actual PVT data if available),


Next, determine the total volume of fluids and the percentage of free gas released at the pump intake. Using the producing GOR and oil volume, determine the total volume of gas (Vg).


Using the solution GOR (Rs) at the pump intake, determine the solution gas volume (VSG).


The difference represents the volume of free gas (VFG) released from solution by the decrease in pressure from bubblepoint pressure of 1,500 psi to the pump-intake pressure of 1,000 psi.


The volume of oil (Vo) at the pump intake is


The volume of free gas at the pump intake (VIG) in barrels is


Next, is the equation for the volume of water (Vw) at the pump intake.


The total volume (Vt) of oil, water, and gas at the pump intake can now be determined by


The ratio or percentage of free gas present at the pump intake to the total volume of fluid is


As this value is less than 10% by volume, it has only a minor effect on the pump performance, especially if most of the free gas is vented up the annulus. Use of a gas separation component is not essential in this case.

The composite SG, including gas, is determined by first calculating the total mass of produced fluid (TMPF) from the original data given.




Now that the total volume of fluid entering the first pump stage is known (2,550 BFPD) and the composite SG has been determined, we can continue to the next step of designing the ESP system.

Step Four: Total Dynamic Head

Sufficient data are now available to determine the TDH required by the pump.




The TDH required is based on the normal pumping conditions for the well application. If the well is killed with a heavier-gravity fluid, a higher head is required to pump the fluid out, until the well is stabilized on its normal production. More HP is also required to lift the heavier kill fluid and should be considered when selecting the motor rating for the application. Ft = tubing friction loss. Refer to Fig. 13.52.

Friction loss per 1,000 ft of 2 7/8-in. tubing (new) is 49 ft/1,000 ft of depth at 2,440 B/D (405 m3/d) or 4.5 m/100 m. Using the desired pump setting depth,


Hwh = desired head at wellhead (desired wellhead pressure). Using the composite SG,




Step Five: Pump-Type Selection

From the manufacturer’s catalog information, select the pump type with the highest efficiency at the calculated capacity 2,440 B/D (405 m3/d) that will fit the casing. Select the 513 series GC-2200 pump (Fig. 13.53).

The head in feet (meters) for one stage is 2,550 B/D (405 m3/d) and is 41.8 ft (13 m). The BHP per stage is 1.16. To determine the total number of stages required, divide the TDH by the head/stage taken from the curve. The number of stages = TDH/(head/stage). The number of stages = (3,556 /41.8) = 85 stages.

Refer to the manufacturer’s information for the GC-2200 pump. The housing no. 9 can house a maximum of 84 stages, 93 stages for a housing no. 10. Because the 84-stage pump is only one stage less than the calculated requirement, it should be adequate and the pump will cost less. Once the maximum number of pump stages is decided, calculate the total BHP required as




Step Six: Optimum Size of Components

Gas Separator. If a gas separator was required, refer to a catalog to select the appropriate separator and determine its HP requirement. In this example, one was not needed. If gas interference causes operating problems, a gas separator can be added on the next ESP repair.

Seal Section. Normally, the seal section series is the same as that of the pump, although there are exceptions and special adapters available to connect the units together. Here, the 513 series GSB seal section is selected.

The HP requirement for the seal depends on the TDH produced by the pump. The manufacturer’s information shows a requirement of 3.0 hp for the 513 series seal operating against a TDH of 3,556 ft. Therefore, the total HP requirement for this example is 91.5 hp for the pump, plus 3.0 hp for the seal, or 94.5 hp total.

Motor. Generally, a 500 series motor should be used with the 513 series pump. When a motor is selected, consideration should be given to choose as large a diameter unit as possible for the casing to optimize the initial cost, motor efficiency, operating costs, and repair costs. In this example select the 100-hp 562 series motor from the catalog. The motor voltage can be selected on the basis of considerations discussed next.

The high-voltage, consequently low-current, motors have lower cable losses and require smaller conductor-size cables. High-voltage motors have superior starting characteristics—a feature that can be extremely important if excessive voltage losses are expected during starting. Although, the higher the motor voltage, the more expensive is the motor.

In some cases, the savings, because of smaller cable, may be offset by the difference in motor-controller cost, and it may be necessary to make an economic analysis for the various voltage motors. However, for this example, the high-voltage motor (100 hp; 2,145 V; 27 amps) is an excellent choice. Check the manufacturers catalog and equipment information to assure that all operating parameters are well within their recommended ranges (e.g., thrust bearing, shaft HP, housing burst pressure, and fluid velocity).

Step Seven: Electric Cable

Determine Cable Size. The cable size is selected on the basis of its current-carrying capability. Using the motor amps (27) and the cable voltage-drop chart in the catalog, select a cable size with a voltage drop of less than 30 V/1,000 ft. All conductor sizes 1 through 6 fall in this category. The no. 6 cable has a voltage drop of 18.5 × 1.201 = 22.2 V/1,000 ft (305 m), and based on $0.06/kW-hr. results in a monthly I 2 R loss of $255. A no. 4 cable has 14.1 V/1,000 ft and costs $158/month. The operating cost savings of $97/month is divided into the added cost of the no. 4 over the no. 6 cable to calculate a payout. A no. 6 cable size was selected for this example.

Cable Type. Because of the gassy conditions and the bottomhole temperature, the polypropylene ("poly") cable should be used. Check to be sure the cable diameter plus tubing collar diameter is smaller than the casing ID.

Cable Length. The pump setting depth is 5,500 ft (1676.4 m), with 100 ft (30.5 m) of cable for surface connections; the total cable length should be 5,600 ft (1707 m). Check to verify that the cable length is within the manufacturer’s recommended maximum length,

Cable Venting. A cable vent box must be installed between the wellhead and the motor controller to prevent gas migration to the controller.

Step Eight: Accessory and Miscellaneous Equipment. Flat Cable-Motor Lead Extension

As described in section 13.4.8, calculate the length for the MLE. Pump length = 14.8 ft (4.51 m); seal length = 6.3 ft (1.92 m); plus, 6 ft = 6.0 ft (1.83 m) = 213.1 ft (8.26 m); select 35 ft (10.7 m) of 562 series flat cable.

Flat Guards. Cable guards are available in 6-ft sections; therefore, six sections are sufficient.

Cable Bands. The pump and seal section is approximately 20 ft (6 m) long. Twenty-two-inch (56 cm) bands are required to clamp to the housing with bands spaced at 2-ft (61 cm) intervals (10 bands). On the production-tubing string above the pump, the same length cable bands can be used. The bands should be spaced at 15-ft (4.5-m) intervals. The setting depth of 5,500 ft requires 367 bands.

Downhole Accessory Equipment. Refer to the manufacturer’s catalog for the accessories listed next.

Swaged Nipple. The pump outlet is 2 7/8 in., per the manufacturer’s information, so a swaged nipple is not required for the 2 7/8-in. tubing.

Check Valve The 2 7/8-in.-EUE, 8-round, thread check valve is recommended.

Drain Valve The 2 7/8-in.-EUE, 8-round, thread drain valve should be used (in conjunction with the check valve) to eliminate pulling a wet string.

Motor Controller The motor-controller selection is based on its voltage, amperage, and KVA rating. Therefore, before selecting the controller, one must first determine the motor controller voltage. Assume the controller voltage is the same as the surface voltage going downhole. The surface voltage (SV) is the sum of the motor voltage and the total voltage loss in the cable. (Adjust taps on the transformer to closely achieve this value.)


The motor amperage is 27 amps; the KVA can now be calculated.




The 6H-CG motor controller suits these requirements.

Transformer. The transformer selection is based on the available primary power supply (12,470 V), the secondary voltage requirement (2,269 V) and the KVA requirement (106 KVA). Choose three 313.5 KVA single-phase transformers as shown in the manufacturer’s catalog.

Surface Cable. Select 50 ft (15.2 m) of no. 1 cable for surface connection to transformers.


Step One: Variable-Speed Pumping System

Use the previous example, and design a new system using a VSC. To help justify the use of a VSC, two new conditions were added. First, assume that we need to maintain a constant oil production (575 BOPD), although, reservoir data indicate we should see an increase in water cut (75 to 80%) over the next few months. Next, to satisfy our economic justification in using the VSC, we must optimize the initial cost and size of the downhole assembly.

To maintain oil production as the water cut increases, we must determine the maximum desired flow rate with 80% water.




Step Two: Production Capacity

We can now calculate the pump intake pressure at the maximum rate of 2,875 B/D. First, make the assumption that even though the water cut changes, the well’s PI will remain constant. Now, determine the new well flowing pressure (Pwf) at the maximum desired production rate (Qd).




The new well flowing pressure of 1,175 psi is slightly below the bubblepoint pressure of 1,500 psi; therefore, the PI approach should still give good results.

The pump-intake pressure can be determined the same as before, although, a new composite specific gravity must be calculated.



The composite SG is the sum of the weighted percentages:


The pressure because of the difference in perforation depth and pump setting depth (6,800 + 5,500 ft = 12,300 ft) can be determined as




Therefore, the pump-intake pressure (PIP) can now be determined as


Step Three: Gas Calculations

Next, determine the total fluid mixture that will be ingested by the pump at the new maximum desired flow rate (2,875 B/D). Determine the solution GOR (Rs) at the pump-intake pressure or by substituting the pump-intake pressure for the bubblepoint pressure (Pb) in Standing’s equation. [5]




Determine the formation volume factor (Bo) with the Rs from Standing’s monograph (see the General Engineering section of this Handbook ) or use Standing’s equation[5]








Determine the gas volume factor (Bg) as


Assuming a 0.85 Z factor,


Next, determine the total volume of fluids, and the percentage of free gas released at the pump intake. Using the producing GOR and oil volume, determine the total volume of gas (TG).




Using the solution GOR (Rs) at the pump intake, determine the solution gas volume (VSG).


The difference represents the volume of free gas (VFG) released from solution by the decrease in pressure from the bubblepoint pressure of 1,500 psi to the pump intake pressure of 1,000 psi.


The volume of oil (Vo) at the pump intake is




The volume of free gas at the pump intake is




The volume of water (Vw) at the pump intake is




The total volume (Vt) or oil, water, and gas at the pump intake can now be determined





The ratio or percentage of free gas present at the pump intake to the total volume of fluid is




As this value is greater than 10% by volume, there is significant free gas to affect pump performance; therefore, it is recommended that a gas separator be installed. Next, we must assume the gas separator’s efficiency. At 15% free gas, a 90% efficiency of separation is used on the basis of the manufacturer’s gas-separator performance information.

The percentage of gas not separated is 10%.




Total volume of fluid mixture ingested into the pump is






The amount of free gas entering the first pump stage as a percent of the total fluid mixture is




As the free gas represents only 2% by volume of fluid being pumped, it has little significant effect on the well fluid composite SG and may be ignored for conservative motor sizing.

Now that the total volume of fluid entering the first pump stage is known (2,973 BFPD) and the composite SG has been determined, we can continue to the next step of designing the ESP system.

Step Four: Total Dynamic Head

Sufficient data are now available to determine the TDH required at the maximum desired flow rate (2,973 B/D). The TDH for the minimum desired flow rate (2,550 B/D) was previously determined to be 3,556 ft.


where HL = the vertical distance in feet between the estimated producing fluid level and the surface, and


From Fig. 13.52 , friction loss per 1,000 ft of 2 7/8-in. tubing (new) is 60 ft/1,000 ft of depth at 2,973 B/D (405 m 3 /d), or 4.5 m/100 m. Using the desired pump setting depth,


Hwh = the discharge pressure head (desired wellhead pressure). Using the composite SG,






Step Five: Pump-Type Selection

The hydraulic requirements for our variable speed pumping system have been determined. Those requirements are the minimum hydraulic requirement (flow rate 2,550 B/D; total dynamic head 3,556 ft) and maximum hydraulic requirement (flow rate 2,973 B/D; total dynamic head 4,746 ft).

In the economic justification for using the VSC, the size of the downhole unit was determined. This was done using the guidelines discussed next.

As the operating frequency increases, the number of stages required to generate the required lift decreases. The closer the operation is to the best efficiency point, the lower the power requirement and power cost.

A fixed frequency motor of a particular frame size has a maximum output torque, provided that the specified voltage is supplied to its terminals. The same torque can be achieved at other speeds by varying the voltage in proportion to the frequency. This way the magnetizing current and flux density will remain constant, and so the available torque will be a constant (at no-slip RPM). As a result, power output rating is directly proportional to speed because power rating is obtained by multiplying the rated torque with speed. Using the variable-speed performance curves, select a pump that will fit in the casing so the maximum flow rate (2,973 B/D) falls at its BEP. The GC-2200 satisfies these conditions at 81 Hz.

Next, select the head per stage from the curve. It indicates 86 ft/stage. With the maximum TDH requirement of 4,746 ft, the number of pump stages required can be determined. The number of stages = the maximum TDH /head per stage and = 4,746 /86 = 55 stages. A 55-stage GC-2200 meets our maximum hydraulic requirement. To determine if it meets our minimum hydraulic requirement, divide the minimum TDH requirement by the number of stages. The minimum head per stage = 3,556 /55 = 64.7 ft/stage. Plotting the minimum head/stage (64.7 ft) and the minimum flow rate (2,550 B/D) on the curve indicates an operating frequency of 70 Hz. Note, the minimum hydraulic requirement is also near the pump’s BEP.

Next, using the VSC curve for the GC-2200 find the BHP/stage at the 60-Hz BEP (1.12 hp). To calculate the BHP at the maximum frequency use Eqs. 13.112 and 13.113.




Because a rotary gas separator was selected (which is a centrifugal machine using HP), it will add additional load to the motor. The HP requirement also changes by the cube function. Referring to the manufacturer’s information, the 513 series rotary gas separator requires 5 hp at 60 Hz.


Total BHP for the pump and separator = 157.6 + 12.8 = 170.4 hp. With Eqs. 13.115 and 13.116, the equivalent 60-Hz BHP for both the pump and gas separator can be calculated:




Select the appropriate model seal section and determine the HP requirement at the maximum TDH requirement. Select a motor that is capable of supplying total HP requirements of the pump, gas separator, and seal. In this example, a 562 series motor with 130 hp; 2,145 volts; and 35 amps was selected.

Using the technical data provided by the manufacturer, determine if any load limitations were exceeded (e.g., shaft loading, thrust bearing loading, housing burst pressure limitations, fluid velocity passing the motor, etc.).

Next, select the power cable and calculate the cable voltage drop. On the basis of the motor current (35 amps) and the temperature (160°F), no. 6 cable can be used. Adding 200 ft for surface connections, the cable voltage drop is written as


We can now calculate the required surface voltage (SV) at the maximum operating frequency as




Note that the surface voltage is greater than standard 3KV cable. Therefore, 4KV or higher cable construction should be selected. Sufficient data are available to calculate KVA.




Referring to the manufacturer’s catalog, select the model 2200-3VT, 200 KVA, NEMA3 (outdoor enclosure) VSC. All other accessory equipment should be selected as in the previous example.


Am = motor amperage, amps
Bg = gas volume factor, scf/bbl [m3/m3]
Bo = oil volume factor, bbl/STBO
C = constant = 3,960, where Q is in gal/min, and TDH is in ft [= 6,750, where Q is in m3/D, and TDH is in m]
D = diameter, in. [cm]
F = correlating function for Eq. 13.18
Ft = well-tubing friction loss
H = head, ft [m]
HL = net well lift
Hwh = wellhead pressure head, ft [m]
J = slope
N = rotating speed, rev/min
P = pressure, psi [kg/cm2]
Pb = bubblepoint pressure, psi [kg/cm2]
Pdischarge = pump-discharge pressure, psi [kg/cm2]
Pr = well static pressure, psi [kg/cm2]
Pwf = well flowing pressure, psi [kg/cm2]
Q = flow rate, B/D [m3/d]
Qd = estimated production rate
Qo = maximum production at Pwf = 0, B/D [m3/D]
Rs = solution gas/oil ratio, scf/bbl [m3/m3]
T = torque, ft-lbf
Tconductor = wellbore temperature at the ESP setting depth
TC = temperature, °C
TF = temperature, °F
TG = total volume of gas
TK = temperature, K
TR = temperature, °R
V = voltage, volts
VFG = volume of free gas
Vg = volume of gas
VIG = volume of free gas at the pump intake
Vo = volume of oil, bbl [m3]
Vs = surface voltage, volts
VSG = solution gas volume
Vt = total volume
Vw = volume of water
Z = gas-compressibility factor (typically 0.50 to 1.00)
ηm = motor efficiency
ηp = pump efficiency


g = gas
o = oil
t = total
w = water


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SI Metric Conversion Factors

bbl × 1.589 873 E – 01 = m3
cp × 1.0* E – 03 = Pa•s
ft × 3.048* E – 01 = m
°F (°F – 32)/1.8 = °C
gal × 3.785 412 E – 03 = m3
hp × 7.460 43 E – 01 = kW
in. × 2.54* E + 00 = cm
lbf × 4.448 222 E + 00 = N
lbm × 4.535 924 E – 01 = kg
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.