As system design engineers and operators evaluate costs, maintenance requirements, environmental impact, efficiency and flexibility, they are finding more applications where multistage centrifugal pumping systems provide advantages for downhole and surface applications.
About 15 to 20 percent of almost one million wells worldwide are pumped with some form of artificial lift employing electric submersible pumps. In addition, ESP systems are the fastest growing form of artificial lift pumping technology. They are often considered high volume and depth champions among oil field lift systems.
Found in operating environments all over the world, ESPs are very versatile. They can handle a wide range of flow rates from 70-bpd to 64,000-bpd or more and lift requirements from virtually zero to as much as 15,000-ft of lift. As a rule, ESPs have lower efficiencies with significant fractions of gas, typically greater than about 10 percent volume at the pump intake. Given their high rotational speed of up to 4000-rpm and tight clearances, they are also only moderately tolerant of solids like sand. If solid-laden production flows are expected, special running procedures and pump placement techniques are usually employed. When very large amounts of free gas are present, downhole gas separators and/or gas compressors may be required in lieu of a standard pump intake.
ESP systems can be used in casing as small as 4.5-in outside diameter and can be engineered to handle contaminants commonly found in oil-aggressive corrosive fluids such as H2S and CO2, abrasive contaminants such as sand, exceptionally high downhole temperatures and high levels of gas production. Increasing water cut has been shown to have no significant detrimental effect on ESP performance. ESPs have been deployed in vertical, deviated and horizontal wells, but they should be located in a straight section of casing for optimum run life performance.
On a cost-per-barrel basis, ESPs are considered economical and efficient. With only the wellhead and fixed or variable-speed controller visible at the surface, ESP systems offer a small footprint and low-profile option for virtually all applications, including offshore installations. Table 1 provides a summary of ESP artificial lift applications.
In ESP systems, an electric motor and a multistage centrifugal pump run on a production string, connected back to a surface control mechanism and transformer via an electric power cable (see Figure 1 below). Careful consideration must be given to each downhole and surface component of the system in the design stage. An ESP can pump intermittently or continuously. Because an ESP can be easily adapted to automation and control systems, numerous surface control and communication devices are available. Additionally, the downhole components can vary depending on the specific application or conditions.
Downhole Components
Multistage Centrifugal Pump—The multistage centrifugal pump consists of stages with rotating impellers and stationary diffusers cast from a Ni-resist high-nickel iron containing both abrasion and corrosion resistant properties. Pump stages incorporate many optional features including special bearings and coatings. These features allow the pump to handle harsh abrasives, salt containing fluids that form deposits of scale and paraffin or asphaltenes that gradually coat the pump stages and disrupt normal flow. Materials used in manufacturing pump components vary depending upon the corrosive and abrasive nature of the well environment. The impellers are mounted on a shaft made of Nitronic 50, Monel, Inconell or other high-strength alloy or stainless steel. Due to limited well casing diameters, the lift or head developed by an individual stage is relatively low. Stages must be stacked together to meet the lift requirements for various applications. Each stage of the multistage centrifugal pump adds energy to the fluid in the form of increased velocity and pressure. The impeller accelerates the fluid and increases the kinetic energy, which is then converted into potential energy (pressure) in the diffuser that redirects the flow to the next impeller. Diffusers also act as a bearing surface, providing additional stability to the pump shaft. The fluid flow is described by the fundamentals of classical physics—conservation of mass, momentum and energy.
Motor—The energy to turn the pump comes from a high voltage (3 to 5 kV) alternating current source to drive a special motor that can work at high temperatures up to 500-deg F and high pressures up to 5000-psi and from deep wells up to 15,000-ft deep with high energy requirements up to 1000-hp. Submersible two-pole, squirrel cage, induction electric motors are manufactured in a variety of horsepower ratings, operating voltages and currents to meet pressure extremes and temperature requirements. The motor size is designed to lift the estimated volume of production. Wellbore fluids passing over the motor housing act as cooling agents. The motor is powered from the surface via submersible electric cable.
Temperature extremes and contaminants are primary causes in early motor failure. Completely sealed, a downhole ESP motor must have exceptional capabilities to dissipate or withstand severe inner core temperatures—requiring high temperature insulation ratings. The method of assembly and quality of the winding, including the pattern, are critical design characteristics. The winding process—including the resin used, the application process and the steps taken to prevent voids—are critical measures in constructing a motor that can withstand destructive energies encountered downhole.
Seal Section—The seal section is located between the motor and the intake and performs the following functions:
Gas Separator/Compressor—The intake section of a submersible pump functions as a suction manifold, feeding the well fluid to the pump. In standard applications, an intake section can be a simple inlet hole adapter attached between the seal section and the pump housing. In applications with higher gas/oil ratios (GOR) and lower bottom-hole pressures, the well fluid may contain significant amounts of free gas. A gas separator, designed to separate the gas from the well fluid before it enters the pump, replaces the intake section in such applications.In applications where the amount of free gas cannot be handled efficiently by rotary gas separators, tandem rotary gas separators, a high-volume separator or a gas compressor can be used. Use of a gas compressor introduces a compression chamber downstream from tandem gas separators. The compression chamber allows free gas to be compressed back into the solution while simultaneously breaking large gas bubbles into an increasingly homogenized solution, which a submersible pump can handle without gas locking.
Downhole Sensor—A rugged downhole sensor and companion surface interface unit enables reliable, accurate retrieval of critical real-time system and wellbore performance parameters. Multi-data channel sensors can measure intake pressures, wellbore and motor oil or winding temperature, pump discharge pressure, vibration, current leakage and flow rate. ESP system control and alarms are achieved by real-time monitoring of actual downhole readings, reducing nuisance shutdowns caused by inaccurate overload and underload amp load settings. Surface interface can be accomplished via permanent digital readout, handheld data logger or laptop computer. Remote monitoring of data from web-based computers is also possible.
Power Cable—Available in flat or round configurations, specially engineered and manufactured cable systems provide dependability in the harsh, hot, gassy and corrosive conditions found in most downhole ESP applications. A variety of materials, duty ranges and constructions allow selection of a particular cable for specific applications. The cable is connected to the top of the motor, runs up the side of the pump, is strapped to the outside of every joint of tubing from the motor to the surface of the well and is extended on the surface to the control junction box. In most cases, the cable is flat as it stretches from the motor up beside the pump to the tubing, at which point the flat cable is spliced to a round one.
Most power cables have a metal shield to protect them from damage. Proper selection of cabling can greatly enhance the overall system performance, since substantial power losses can occur in conducting power across a cable that may extend as long as 15,000-ft, nearly three miles.
Tubing Head—The tubing head is designed to support the downhole tubing string and provide a seal to permit the power cable to pass through the wellhead. This seal is usually designed to hold a minimum of 3000-psi.
Fixed or Variable Speed Controllers and Drives—Intelligent RTU programmable controllers (fixed speed or variable speed) maintain the proper flow of electricity to the pump motor. They allow the well to be operated continuously or intermittently, or be shut off. They also provide protection from power surges or other electricity changes.
A variable speed drive (VSD) offers ESP systems continuous duty variable flow and pressure control, which in turn increase productivity, process control flexibility and energy savings. Direct speed control over the pump motor provides maximum system efficiency and reduced maintenance when compared with across the line (full voltage) operation. The VSD provides the essential reduced voltage starting characteristics of a soft starter combined with continuous duty variable frequency operation. This directly results in increased life of the mechanical equipment and reduced incidence of downtime.
Transformers—A transformer is an electrical device that takes electricity of one voltage and changes it into another voltage. Transformers are usually located at the edge of the lease site. The transformer changes electricity provided via commercial power lines to match the voltage and amperage requirements of the ESP motor.
Electrical Supply System—Electricity is generally provided by a commercial power distribution system. The highest available voltage produces the most efficient performance. In offshore applications, the nature of the power supply is strictly dependant on a portable source—namely that of a diesel generator. In a situation where generator-fed power is the primary supply, strict design requirements must be recognized in order to prevent a costly, time-consuming failure and/or redesign and retrofit. Selection of the generator requires careful calculation of the system power requirements it is meant to supply.
About 15 to 20 percent of almost one million wells worldwide are pumped with some form of artificial lift employing electric submersible pumps. In addition, ESP systems are the fastest growing form of artificial lift pumping technology. They are often considered high volume and depth champions among oil field lift systems.
Found in operating environments all over the world, ESPs are very versatile. They can handle a wide range of flow rates from 70-bpd to 64,000-bpd or more and lift requirements from virtually zero to as much as 15,000-ft of lift. As a rule, ESPs have lower efficiencies with significant fractions of gas, typically greater than about 10 percent volume at the pump intake. Given their high rotational speed of up to 4000-rpm and tight clearances, they are also only moderately tolerant of solids like sand. If solid-laden production flows are expected, special running procedures and pump placement techniques are usually employed. When very large amounts of free gas are present, downhole gas separators and/or gas compressors may be required in lieu of a standard pump intake.
ESP systems can be used in casing as small as 4.5-in outside diameter and can be engineered to handle contaminants commonly found in oil-aggressive corrosive fluids such as H2S and CO2, abrasive contaminants such as sand, exceptionally high downhole temperatures and high levels of gas production. Increasing water cut has been shown to have no significant detrimental effect on ESP performance. ESPs have been deployed in vertical, deviated and horizontal wells, but they should be located in a straight section of casing for optimum run life performance.
On a cost-per-barrel basis, ESPs are considered economical and efficient. With only the wellhead and fixed or variable-speed controller visible at the surface, ESP systems offer a small footprint and low-profile option for virtually all applications, including offshore installations. Table 1 provides a summary of ESP artificial lift applications.
The Anatomy of an ESP System
In ESP systems, an electric motor and a multistage centrifugal pump run on a production string, connected back to a surface control mechanism and transformer via an electric power cable (see Figure 1 below). Careful consideration must be given to each downhole and surface component of the system in the design stage. An ESP can pump intermittently or continuously. Because an ESP can be easily adapted to automation and control systems, numerous surface control and communication devices are available. Additionally, the downhole components can vary depending on the specific application or conditions.
Downhole ComponentsMultistage Centrifugal Pump—The multistage centrifugal pump consists of stages with rotating impellers and stationary diffusers cast from a Ni-resist high-nickel iron containing both abrasion and corrosion resistant properties. Pump stages incorporate many optional features including special bearings and coatings. These features allow the pump to handle harsh abrasives, salt containing fluids that form deposits of scale and paraffin or asphaltenes that gradually coat the pump stages and disrupt normal flow. Materials used in manufacturing pump components vary depending upon the corrosive and abrasive nature of the well environment. The impellers are mounted on a shaft made of Nitronic 50, Monel, Inconell or other high-strength alloy or stainless steel. Due to limited well casing diameters, the lift or head developed by an individual stage is relatively low. Stages must be stacked together to meet the lift requirements for various applications. Each stage of the multistage centrifugal pump adds energy to the fluid in the form of increased velocity and pressure. The impeller accelerates the fluid and increases the kinetic energy, which is then converted into potential energy (pressure) in the diffuser that redirects the flow to the next impeller. Diffusers also act as a bearing surface, providing additional stability to the pump shaft. The fluid flow is described by the fundamentals of classical physics—conservation of mass, momentum and energy.
Motor—The energy to turn the pump comes from a high voltage (3 to 5 kV) alternating current source to drive a special motor that can work at high temperatures up to 500-deg F and high pressures up to 5000-psi and from deep wells up to 15,000-ft deep with high energy requirements up to 1000-hp. Submersible two-pole, squirrel cage, induction electric motors are manufactured in a variety of horsepower ratings, operating voltages and currents to meet pressure extremes and temperature requirements. The motor size is designed to lift the estimated volume of production. Wellbore fluids passing over the motor housing act as cooling agents. The motor is powered from the surface via submersible electric cable.
Temperature extremes and contaminants are primary causes in early motor failure. Completely sealed, a downhole ESP motor must have exceptional capabilities to dissipate or withstand severe inner core temperatures—requiring high temperature insulation ratings. The method of assembly and quality of the winding, including the pattern, are critical design characteristics. The winding process—including the resin used, the application process and the steps taken to prevent voids—are critical measures in constructing a motor that can withstand destructive energies encountered downhole.
Seal Section—The seal section is located between the motor and the intake and performs the following functions:
- Houses the thrust bearing that carries the axial thrust developed by the pump
- Isolates and protects the motor from well fluids
- Equalizes the pressure in the wellbore with the pressure inside the motor
- Compensates for the expansion and contraction of motor oil due to internal temperature changes
Gas Separator/Compressor—The intake section of a submersible pump functions as a suction manifold, feeding the well fluid to the pump. In standard applications, an intake section can be a simple inlet hole adapter attached between the seal section and the pump housing. In applications with higher gas/oil ratios (GOR) and lower bottom-hole pressures, the well fluid may contain significant amounts of free gas. A gas separator, designed to separate the gas from the well fluid before it enters the pump, replaces the intake section in such applications.In applications where the amount of free gas cannot be handled efficiently by rotary gas separators, tandem rotary gas separators, a high-volume separator or a gas compressor can be used. Use of a gas compressor introduces a compression chamber downstream from tandem gas separators. The compression chamber allows free gas to be compressed back into the solution while simultaneously breaking large gas bubbles into an increasingly homogenized solution, which a submersible pump can handle without gas locking.
Downhole Sensor—A rugged downhole sensor and companion surface interface unit enables reliable, accurate retrieval of critical real-time system and wellbore performance parameters. Multi-data channel sensors can measure intake pressures, wellbore and motor oil or winding temperature, pump discharge pressure, vibration, current leakage and flow rate. ESP system control and alarms are achieved by real-time monitoring of actual downhole readings, reducing nuisance shutdowns caused by inaccurate overload and underload amp load settings. Surface interface can be accomplished via permanent digital readout, handheld data logger or laptop computer. Remote monitoring of data from web-based computers is also possible.
Power Cable—Available in flat or round configurations, specially engineered and manufactured cable systems provide dependability in the harsh, hot, gassy and corrosive conditions found in most downhole ESP applications. A variety of materials, duty ranges and constructions allow selection of a particular cable for specific applications. The cable is connected to the top of the motor, runs up the side of the pump, is strapped to the outside of every joint of tubing from the motor to the surface of the well and is extended on the surface to the control junction box. In most cases, the cable is flat as it stretches from the motor up beside the pump to the tubing, at which point the flat cable is spliced to a round one.Most power cables have a metal shield to protect them from damage. Proper selection of cabling can greatly enhance the overall system performance, since substantial power losses can occur in conducting power across a cable that may extend as long as 15,000-ft, nearly three miles.
Tubing Head—The tubing head is designed to support the downhole tubing string and provide a seal to permit the power cable to pass through the wellhead. This seal is usually designed to hold a minimum of 3000-psi.
Fixed or Variable Speed Controllers and Drives—Intelligent RTU programmable controllers (fixed speed or variable speed) maintain the proper flow of electricity to the pump motor. They allow the well to be operated continuously or intermittently, or be shut off. They also provide protection from power surges or other electricity changes.
A variable speed drive (VSD) offers ESP systems continuous duty variable flow and pressure control, which in turn increase productivity, process control flexibility and energy savings. Direct speed control over the pump motor provides maximum system efficiency and reduced maintenance when compared with across the line (full voltage) operation. The VSD provides the essential reduced voltage starting characteristics of a soft starter combined with continuous duty variable frequency operation. This directly results in increased life of the mechanical equipment and reduced incidence of downtime.
Transformers—A transformer is an electrical device that takes electricity of one voltage and changes it into another voltage. Transformers are usually located at the edge of the lease site. The transformer changes electricity provided via commercial power lines to match the voltage and amperage requirements of the ESP motor.
Electrical Supply System—Electricity is generally provided by a commercial power distribution system. The highest available voltage produces the most efficient performance. In offshore applications, the nature of the power supply is strictly dependant on a portable source—namely that of a diesel generator. In a situation where generator-fed power is the primary supply, strict design requirements must be recognized in order to prevent a costly, time-consuming failure and/or redesign and retrofit. Selection of the generator requires careful calculation of the system power requirements it is meant to supply.
