bombeo electro sumergible (bes)
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tion, the downhole pump is suspended on a tubing string hung on the wellhead and is submerged in the well fluid (see Fig. 7.1). The pump is close-coupled to a submersi- ble electric motor that receives power through the power
ESPs are currently operated in wells with bottomhole temperatures (BHTs) up to 350F. Operation at elevated ambient temperatures requires special com- ponents in the motor and power cables capable of sus- tained operation at high ambient temperature.
ESPs have efficiently lifted fluids in wells deeper than umps can be operated in casing as small
Many studies indicate that ESPs are the ft method and the most economical on a barrel basis. System efficiency ranges , depending on fluid volume, net lift, and
advantage of the ESP is that it has a nar- cable and surface controls. The ESP has the broadest producing range of any ar-
tificial lift method. The standard 60-Hz producing range of the ESP extends from a low of 100 B/D of total fluid up to 90,000 B/D. Variable-speed drives can extend the producing range beyond these rates. Although most operators tend to associate ESPs with high volume
12,000 ft. The pas 4.5 in. OD. most efficient licost per liftedfrom 18 to 68 %pump tn=
The major disChapter 7
Electric Submersible PW.J. Powers, TRW Reda Pump Div.
Introduction The electric submersible pump (ESP), sometimes called submergible, is perhaps the most versatile of the ma- jor oil-production artificial lift methods. This chapterprovides the reader with a broad understanding of the key factors in selection, installation, and operation of electric submersible pumps. ESP topics covered include the ESP system; applications; ESP system componentsselection data and methods; handling, installation, and operation; and troubleshooting.
ESP System The ESP system comprises a downhole pump, electricpower cable, and surface controls. In a typical applica-lift rates, the average ESP produces less than 1,000 B/D of total fluid in continuous operation.
ESPs are used to produce a variety of fluids and the gas, chemicals, and contaminants commonly found in these fluids. Currently ESPs are operated economically in virtually every known oil field environment. The WOR is, in general, not significant in assessing an ap- plication. Relatively high gas/fluid ratios can be handled using tapered design pumps and a special gas separator pump intake. Aggressive fluids (those contain- ing HzS, CO?, or similar corrosives) can be produced with special materials and coatings. Sand and similar abrasive contaminants can be produced with acceptable pump life by using specially modified pumps and opera- tion procedures. mps
ESPs usually do not require storage enclosures, foun- dation pads, or guard fences. An ESP can be operated in a deviated or directionally drilled well, although the recommended operating position is in a straight section of the well. Because the ESP can be up to 200 ft long, operation in a bend or dogleg could seriously impact unit run-life and performance by causing hot spots where the motor rests against the casing. The ESP can operate in a horizontal position. In this case, run-life will be deter- mined by the protectors ability to isolate well fluid from the motor. row producing rate range compared with other artificial lift forms. It does handle free gas well, but the impact of large volumes of gas can be destructive to the pump. Run life can be adversely affected by a poor quality electric power supply, but this is not limited to the ESP.
Applications The ESP historically has been applied in lifting water or low oil-cut wells that perform similar to water wells. However, within this seemingly narrow segment there are many types of installations and equipment configum- tions. This section covers typical installation, booster and injection, bottom intake/discharge, cavern storage/ shrouded configuration, and offshore platforms.
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is hat Fig. 7.1-Typical submergible pump application.
A typical ESP installation is shown in Fig. 7.1. The ESsystems major surface and downhole equipmenshown. In this installation, the available surface powetransformed to the downhole power requirementsthree single-phase transformers. The transformed powis supplied by a power cable to a switchboard and ththrough a junction box and wellhead/tubing support. Tpower cable is run in with the production tubing strand is banded to the tubing to prevent mechandamage during installation and removal. The powcable is spliced to a motor flat cable, which is bandethe exterior of the pump-protector motor unit. The cetrifugal pump is located at the top of the downhole unThe pump is hung on the tubing string by the dischahead. Below the pump is a standard intake, which pvides for fluid entry to the pump. The center componis the protector. The protector both equalizes exterand internal pressure and isolates the motor from the wfluid. The lowest component is the motor, which drivthe centrifugal pump. Note that the downhole unitlanded above the perforations. This is necessary so t7-2 fluid entering the well flows past the motor. This flow cools the motor, which is otherwise likely to overheat and fail. PETROLEUM ENGINEERING HANDBOOK
These and other accessory products and system com- ponents are discussed in detail later.
Booster and Injection
Fig. 7.2 displays a booster application. In this applica- tion, a standard pump-protector motor unit is used to lift fluid from a flowline or other source and simultaneously provide injection pressure for a waterflood, pipeline, or other purpose. In a booster application, the unit is set in a short piece of casing, usually near the surface. This con- figuration can be used for water injection, power fluid, fluid transfer, water disposal, or as a tailgate booster.
Injection applications usually lift fluids from an aquifer at normal depths and inject the produced water into a producing zone in the same well or a second well. Injection systems can provide pressure greater than 3,000 psi. The production rate of the pump can be designed to closely match the injectivity characteristics of a reservoir during lillup.
Bottom Intake and Bottom Discharge
Fig. 7.3 displays a bottom intake configuration. In bot- tom intake applications, the well fluid enters the pump through a stinger landed in a permanent packer. The pump and motor sections are inverted from typical posi- tions. The well fluid is produced up the annulus instead of the conventional tubing string. This configuration is used where casing clearance limits production volume because of tubing friction loss or pump diameter in- terference. Because the bottom intake pump can be suspended by small-diameter, high-tensile-strength tub- ing, output and efficiency are significantly improved.
Fig. 7.4 shows a bottom discharge configuration. The bottom discharge pump typically is used to inject water from a shallow aquifer into a deeper producing zone. This eliminates surface flowlines and pumping equip- ment completely. In this configuration, the pump and motor sections are inverted from a typical position. The pump produces the fluid through a tubing stinger landed in a permanent packer in the injection zone. Thus, the in- jection pressure is the sum of the interzonal hydrostatic head and the output pressure of the pump.
Shrouded Configuration/Cavern Storage
Fig. 7.5 displays a standard downhole unit that has been fitted with a shroud. Depending on the exact configura- tion, a shroud can serve two purposes: (1) direct fluid past the motor for cooling and (2) allow free gas to separate from the fluid before entering the pump intake. This configuration is useful in low-volume, high- gas/fluid-ratio wells where drawdown is critical. A shroud allows the pump to be set below the perforations or producing formation. Other examples are cavern or platform leg storage where a unit is suspended in the fluid on tubing and the shroud provides the necessary motor cooling-fluid flow.
Both drilling and production platforms include ESP equipment. Typical applications are mud mixing, washdown, fire protection, sump pumps, water supply,
and off-loading crude oil from storage. The major reason for the use of ESPs in these applications is its space sav- ings when compared with conventional pump products.
ELECTRIC SUBMERSIBLE PUMPS
Fig. 7.2-Booster service application.
ESP System Components Motor
The ESP systems prime mover is the submersible motor (see Fig. 7.6). The motor is a two-pole, three-phase, squirrel-cage induction type. Motors run at a nominal speed of 3,500 revimin in 60-Hz operation. Motors are filled with a highly refined mineral oil that provides dielectric strength, bearing lubrication, and thermal con- ductivity. The standard motor thrust bearing is a fixed- pad Kingsbury type. Its purpose is to support the thrust load of the motor rotors. Other types are used in high- temperature applications above 250F.
Heat generated by motor operation is transferred to the well fluid as it flows past the motor housing. A minimum fluid velocity of 1 fi/sec is recommended to provide ade- quate cooling. Because the motor relies on the flow of well fluid for cooling, a standard ESP should never be set at or below the well perforations or producing zone unless the motor is shrouded (Fig. 7.5).
Motors are manufactured in four different diameters (series) 3.75,4.56, 5.40, and 7.38 in. Thus, motors can be used in casing as small as 4.5 in. Sixty-Hz horsepower capabilities range from a low of 7.5 hp in 3.7%in. series to a high of 1,000 hp in the 7.38-in. series. Motor construction may be a s