A downhole submersible motor provides power to the pump. The motor is typically a two-pole, three-phase, squirrel-cage induction electric motor available in a variety of operating voltages, currents and horsepower ratings ranging from 7.5 kW to more than 750 kW. Motor size is dictated by the amount of power required to drive the pump to lift the estimated volume of produced fluid out of the well. Wellbore fluids passing over the motor housing act as cooling agents.
A seal section between the pump intake and the motor houses the thrust bearing that carries the axial thrust developed by the pump. The seal also isolates and protects the motor from well fluids and equalizes the pressure in the wellbore with the pressure inside the motor.
In wells characterized by relatively high gas-to-oil ratios (GORs) and low bottomhole pressures, produced fluids may contain quantities of free gas. Submersible pumps are susceptible to operational problems, including cavitation or gas locking in high-volume free gas environments, which may shorten pump run life. In these applications, a gas separator is installed at the intake section of the pump to separate the gas from the well fluid before it enters the pump. If the amount of free gas exceeds a designated limit, a gas handling device may also be installed downstream of the separator.
To ensure optimal ESP performance, operators may install downhole sensors that continuously acquire real-time system measurements such as pump intake and discharge pressures and temperatures, vibration and current leakage rate. Typically, users monitor pumps through supervisory con-trol and data acquisition (SCADA) systems, which act as central repositories of data from all downhole sensors and can initiate actions through linked controls or alerts. When it detects a pump reading that is outside preset levels, a sensor alerts the operator in real time and can be enabled to make settings changes to the pump via remote control.
Power is provided from the surface to the motor via a specially con-structed three-phase electric cable designed for downhole environments. To limit cable movement in the well and to support its weight, the cable is banded or clamped to the production tubing.
Electric submersible pump surface components include an electric supply system. Onshore, electricity is typically provided by a commercial power distribution system. A transformer may be required to convert the electricity provided via commercial power lines to match the voltage and amperage requirements of the ESP motor. Offshore, ESP operations require a portable power source such as a diesel generator.
Intelligent, remote terminal, unit-programmable controllers and drives at the surface maintain the proper flow of electricity to the pump motor. Major controller types include fixed-frequency switchboards, soft-start controllers and variable speed controllers; application, economics and the preferred level of control dictate the choice of controller.
A variable speed drive (VSD) reads the downhole data recorded by the SCADA system and scales back or ramps up the motor speed to optimize a balance of pump efficiency and production rate. The drive allows the pump to be operated continuously or intermittently or be shut off in the event of a significant operational problem. The direct speed control afforded by the VSD increases system efficiency and the run life of the ESP system while reducing the incidence of downtime.
Advantages and Disadvantages
In many field applications, ESP systems provide several operational advantages over other forms of artificial lift. An ESP is especially appropriate for moderate-to-high production rate wells, including highly deviated wells and remote, sub-sea deepwater wells. The pumps can be manufactured from high-grade, corrosion-resistant metallurgies for application in well environments with high-GOR fluids, high temperatures and fluids containing corrosive acid gases.
Electric submersible pumps provide increased production while han-dling high water cuts brought on by pressure maintenance and secondary recovery operations. The systems are quiet and safe and require a smaller surface footprint than that of some other lift systems, making them a preferred option in offshore and environmentally sensitive areas. ESP systems can be configured with flexibility to accommodate the dynamic evolution of fluid properties and flow rates during the life of the well and can operate with pump intake pressure of less than 1 MPa [100 psi].
However, a number of operational challenges must be considered when running ESPs. Even though ESP systems can be built with special abrasion-resistant metallurgies and upgraded radial bearing materials and configuration, ESP run times can be severely compromised in high sand and solids content environments. Performance also degrades when pumping viscous fluids or high gas-to-liquid ratio mixtures. The development of more efficient downhole gas separation and gas handling devices has improved ESP applications in flow streams containing high volumes of free gas, but those devices add to completion costs.
Although ESP systems can operate at 0° to 90° inclinations, their application is restricted by the well curvature through which they must pass during deployment and landing. ESP manufacturers must use dogleg severity to determine the stress and deflection of the ESP components to ensure proper installation and operation is possible.
Although ESP motors are built on voltages that typically range from 460 to 4,200 V at 60Hz for oilfield applications, most ESPs use higher voltage motors. As a result, a higher voltage power supply is needed at the surface to compensate for the voltage drop in the power cable, which can be signifi-cant in deep installations requiring long power cables.
Pump efficiency peaks when a pump is operating at the flow rate corre-sponding to the best efficiency point (BEP) on the pump performance curve; efficiency decreases at flow rates above or below the BEP. As the production rate continues to drop, the ESP may need to be pulled and replaced with a lift system better suited to lower production rates; for onshore applications, a suitable replacement might be a rod pump or PCP. Below a rate of approxi-mately 25 m3/d [150 bbl/d], ESPs are usually not an economic lift option.
The industry is developing robust pump designs that will extend the appli-cability of ESP systems in environments with high-solids flow streams. Other research initiatives are focused on improved reliability designs at the component level and integrated systems and on advanced operating surveil-lance and control algorithms to significantly increase ESP system run life.
To improve the economics of ESPs in remote offshore wells, the industry is investigating more cost-effective means of deploying and pulling equip-ment. A rigless intervention using low-cost standard slickline, coil tubing or downhole tractor conveyance would avoid the high expense and long wait times for a dedicated rig. Using this option, an operator can deploy or retrieve the ESP assembly in a matter of hours and minimize production losses. Ultimately, developments such as this will enable a greater number of operators to maximize well production.
Oilfield Review Spring 2013: 25, no. 1.
Copyright © 2015 Schlumberger.
For help in preparation of this article, thanks to George Waters, Oklahoma City, Oklahoma, USA, and Diego Narvaez, Houston.