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Alternate ESP configurations
Electrical submersible pumps focuses on 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. This page discusses some of these alternate ESP configurations.
An inverted-unit configuration has (Fig. 1)
- Motor on top, attached to the tubing string
- Seal-chamber section underneath the motor
- Pump on bottom
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
- 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.
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. 2). 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. 3). 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.
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 ESP optional components, and a second ESP system attached to the bottom of the bypass tube or to another Y-tool bypass head (Fig. 4). 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. 5). 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.
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.
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. 5).
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.
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.
This configuration is basically an ESP installed in a shallow well or can (Fig. 6). 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. 7). It can provide a nonpulsating flow and a wide flow range with the use of a variable-speed drive.
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.
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. 8. 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.
Noteworthy papers in OnePetro
Dinkins, W. R., Tetzlaff, S. K., Patterson, J. C., Hunt, H. L., Nezaticky, P. P., Rodgers, J. T., & Chambers, B. (2008, January 1). Thru Tubing Conveyed ESP Pump Replacement: Live Well Intervention. Society of Petroleum Engineers. doi:10.2118/116822-MS
Kuoh, H. L., Kang, M., & Staal, T. W. (2009, January 1). A Coiled-Tubing-Deployed Intelligent ESP Dumpflood System. Society of Petroleum Engineers.
Puckett, R., Solano, M., & Krejci, M. (2004, January 1). Intelligent Well System with Hydraulic Adjustable Chokes and Permanent Monitoring Improves Conventional ESP Completion for an Operator in Ecuador. Society of Petroleum Engineers. doi:10.2118/88506-MS
Szemat Vielma, W. E., Drablier, D., & Petry, M. L. (2012, January 1). ESP Retrievable Technology: A Solution to Enhance ESP Production While Minimizing Costs. Society of Petroleum Engineers. doi:10.2118/156189-MS
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Jose Caridad, BSME & MSc ME