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ESP optional components
There are components provided by the ESP manufacturers and other suppliers that provide additional mechanical and electrical protection, monitoring, or performance enhancements in the operation of an artificial lift system using electrical submersible pumps. Installation of such components on all wells may not be justified, but their use on key wells should be carefully considered.
- 1 Downhole sensors
- 2 ESP packers
- 3 ESP wellheads
- 4 Centralizers/protectorilizers
- 5 Check/drain tubing valves
- 6 Motor shroud/recirculation systems
- 7 Screens and filters
- 8 Y-tool or bypass
- 9 References
- 10 Noteworthy papers in OnePetro
- 11 External links
- 12 See also
- 13 Page champions
- 14 Category
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 total developed head (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.
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.
Typically, ESP packers are used when there is a requirement or a need for it to be set above the ESP system (Fig. 1). 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.
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 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, motor lead extension (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. 2, 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 inside diameter (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 outside diameter (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.
Fig. 2-ESP-motor shroud systems (after Centrilift).
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. 3), 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. 2. 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.
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. 4. 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.
Fig. 4-Y-tool (after Centrilift).
- Submersible Pump Handbook, fifth edition. 1994. Claremore, Oklahoma: Centrilift.
Noteworthy papers in OnePetro
Dudley, R. W. (1989, May 1). Reperforation of North Sea Electric-Submersible-Pump Wells With An ESP/Y/Tool/TCP System. Society of Petroleum Engineers. doi:10.2118/16534-PA
Wilson, B. L. (1994, January 1). ESP Gas Separator's Affect on Run Life. Society of Petroleum Engineers. doi:10.2118/28526-MS
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