Chapter 7Electric Submersible PumpsW.J. Powers, TRW Reda Pump Div.IntroductionThe electric submersible pump (ESP), sometimes called “submergible, ” is perhaps the most versatile of the major oil-production artificial lift methods. This chapter provides 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 components; selection data and methods; han
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Chapter 7 Electric Submersible Pumps W.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 chapter provides 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 components; selection data and methods; handling, installation, and operation; and troubleshooting. ESP System The ESP system comprises a downhole pump, electric power cable, and surface controls. In a typical applica- 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 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 ESP’s with “high volume” lift rates, the average ESP produces less than 1,000 B/D of total fluid in continuous operation. ESP’s are used to produce a variety of fluids and the gas, chemicals, and contaminants commonly found in these fluids. Currently ESP’s 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. ESP’s 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 protector’s ability to isolate well fluid from the motor. ESP’s are currently operated in wells with bottomhole temperatures (BHT’s) up to 350°F. Operation at elevated ambient temperatures requires special com- ponents in the motor and power cables capable of sus- tained operation at high ambient temperature. ESP’s have efficiently lifted fluids in wells deeper than 12,000 ft. The pumps can be operated in casing as small as 4.5 in. OD. Many studies indicate that ESP’s are the most efficient lift method and the most economical on a cost per lifted barrel basis. System efficiency ranges from 18 to 68 %, depending on fluid volume, net lift, and pump tn= The major disadvantage of the ESP is that it has a nar- 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.
Electric Submersible Pumps W.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 chapter provides 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 components; selection data and methods; handling, installation, and operation; and troubleshooting.
ESP System The ESP system comprises a downhole pump, electric power cable, and surface controls. In a typical applica- 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 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 ESP’s with “high volume” lift rates, the average ESP produces less than 1,000 B/D of total fluid in continuous operation.
ESP’s are used to produce a variety of fluids and the gas, chemicals, and contaminants commonly found in these fluids. Currently ESP’s 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.
ESP’s 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 protector’s ability to isolate well fluid from the motor.
ESP’s are currently operated in wells with bottomhole temperatures (BHT’s) up to 350°F. Operation at elevated ambient temperatures requires special com- ponents in the motor and power cables capable of sus- tained operation at high ambient temperature.
ESP’s have efficiently lifted fluids in wells deeper than 12,000 ft. The pumps can be operated in casing as small as 4.5 in. OD. Many studies indicate that ESP’s are the most efficient lift method and the most economical on a cost per lifted barrel basis. System efficiency ranges from 18 to 68 %, depending on fluid volume, net lift, and
pump tn= The major disadvantage of the ESP is that it has a nar-
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.
7-2 PETROLEUM ENGINEERING HANDBOOK
Fig. 7.1-Typical submergible pump application.
A typical ESP installation is shown in Fig. 7.1. The ESP system’s major surface and downhole equipment is shown. In this installation, the available surface power is transformed to the downhole power requirements by three single-phase transformers. The transformed power is supplied by a power cable to a switchboard and then through a junction box and wellhead/tubing support. The power cable is run in with the production tubing string and is banded to the tubing to prevent mechanical damage during installation and removal. The power cable is spliced to a motor flat cable, which is banded to the exterior of the pump-protector motor unit. The cen- trifugal pump is located at the top of the downhole unit. The pump is hung on the tubing string by the discharge head. Below the pump is a standard intake, which pro- vides for fluid entry to the pump. The center component is the protector. The protector both equalizes external and internal pressure and isolates the motor from the well fluid. The lowest component is the motor, which drives the centrifugal pump. Note that the downhole unit is landed above the perforations. This is necessary so that fluid entering the well flows past the motor. This flow cools the motor, which is otherwise likely to overheat and fail.
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 ESP’s in these applications is its space sav- ings when compared with conventional pump products.
ELECTRIC SUBMERSIBLE PUMPS 7-3
Fig. 7.2-Booster service application.
ESP System Components Motor
The ESP system’s 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 250°F.
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 single section or
Fig. 7.4-Bottom discharge application.
Fig. 7.3-Bottom intake application
several “tandems” bolted together to reach a specific horsepower. Motors are selected on the basis of the max- imum OD that can be run easily in a given casing size.
The standard motor housing material is heavy-wall, seamless, low-carbon steel tubing. The motor-shaft material is carbon steel. The rotors are supported by sleeve bearings made of Nitmlloy and bronze. The squir- rel cage rotor is made of one or more sections depending on motor horsepower and length. The motor stator is wound as a single unit in a fixed housing length.
The ESP is a multistage centrifugal type pump (Fig. 7.7). The type of stage used determines the design volume rate of fluid production. The number of stages determines the total design head generated and the motor horsepower required.
The materials used in manufacturing an impeller are Ni-Resist, Ryton, and bronze. Diffusers are universally manufactured of Ni-Resist. The standard shaft material is K-Monel@. Optional, high-strength shaft materials (In- conel@ and Hastalloy@) are used in deep-setting applica- tions where conventional shaft material horsepower limits are exceeded. “Bolt-on” design makes it possible to vary the capacity and total head of a pump by using
Fig. ‘IS-Shrouded application.
PETROLEUM ENGINEERING HANDBOOK
Motor Heed Showing
Power Cable Connection
Center Tandem Motor
more than one pump section. However, large-capacity pumps typically have integral heads and bases. The nominal OD of a pump will range from 3.38 to 11.25 in.
The protector’s primary purpose is to isolate the motor oil from the well fluid while balancing bottomhole pressure (BHP) and the motor’s internal pressure. There are two types of protector design-the positive seal (Fig. 7.8) and the labyrinth path (Fig. 7.9). The positive seal design relies on an elastic, fluid-barrier bag to allow for the thermal expansion of motor fluid in operation, and yet still isolate the well fluid from the motor oil. The labyrinth path design uses differential specific gravity of the well fluid and motor oil to prevent the well fluid from entering the motor. This is accomplished by allowing the well fluid and motor oil to communicate through tube paths connecting segregated chambers.
The protector performs four basic functions. The pro- tector (1) connects the pump to the motor by connecting both the housing and drive shafts, (2) houses a thrust bearing to absorb pump shaft axial thrust, (3) isolates motor oil from well fluid while allowing wellbore-motor pressure equalization, and (4) allows thermal expansion of motor oil resulting from operating heat rise and ther- mal contraction of the motor oil after shutdown.
Fig. 7.7-Pump with standard intake.
Two types of intakes are used to allow fluid to enter the pump. These are the standard intake shown in Fig. 7.7 and the gas separator intake shown in Figs. 7.10 and 7.11. A gas separator intake is used when the gas/liquid ratio (GLR) is greater than can be handled by the pump. If the gas remains in solution, the pump will perform normally. However, once the GLR exceeds a value of about 0.1, the pump may produce less head than normal. As the GLR increases above 0.1 and free gas increases, the pump will eventually “gas lock,” which usually drastically reduces fluid production and in extreme cases can damage the pump.
There are two types of gas separator intakes-the static type (Fig. 7.10) and the rotary type (Fig. 7.11). The static type induces gas separation by reversing the fluid flow direction. At the fluid entry ports, the reversal of fluid flow direction creates lower pressure that allows the gas to separate. The separated gas moves up the annulus and vents at the wellhead. The fluid, which still contains some gas, enters the separator and moves downward into the stand tube. The fluid is picked up by the rotating pickup impeller. The impeller creates a vortex, which forces dense, gas-free fluid to the outside and causes gas
to break out and move up the shaft. This provides the first stage of the pump with a higher density of fluid than if the gas broke out in the pump.
ELECTRIC SUBMERSIBLE PUMPS 7-5
Fig. 7.8-Positive seal protector Fig. 7.9-Labyrinth path protector. Fig. 7.10~-Static type gas separator
The rotary gas separator in Fig. 7.11 includes a rotary inducer-centrifuge to separate the gas and produced liq- uids. The well fluid enters the intake ports and moves in- to the inducer. The inducer increases the fluid pressure discharging into the centrifuge. The centrifuge forces the denser fluid to the outside. Gas rises from the center of the centrifuge through the flow divider into the crossover section where gas vents to the annulus and fluid is directed into the first stage of the pump.
Electric power is supplied to the downhole motor by a special submersible cable. There are two cable con- figurations: flat (or parallel) and round (Fig. 7.12). Round construction is used except where casing clearance requires the lower profile of flat construction. The standard range of conductor sizes is l/O to 6 AWG (American wire gauge). This range meets virtually all motor amperage requirements. Almost all conductors are copper.
Mechanical protection is provided by armor made from galvanized steel or, in extremely corrosive en- vironments, Moneln’. Unarmored cable is used in low- temperature (< 180°F) wells with a static BHP of less than 1,500 psi.
Cable is constructed with three individual conduc- tors-one for each power phase. Each conductor is
enclosed by insulation and sheathing material. The thickness and composition of the insulation and sheathing determines the conductor’s resistance to cur- rent leakage, its maximum temperature capability, and its resistance to permeation by well fluid and gas. Elec- tric power cable is rated to operate up to 400°F at 1,500 psi.
Round cable is also manufactured with an “I-wire.” The I-wire serves as an electrical link between a downhole instrument and surface reading/processing equipment.
Motor Flat Cable
The motor flat cable is the lowest section of the power cable string. The motor flat cable has a lower profile than standard flat power cable so that it can run the length of the pump and protector in limited clearance situations (Fig. 7.1). The motor flat cable is manufactured \yith a special terminal called a “pothead.” The function of the pothead is to allow entry of electric power into the motor while sealing the connection from well fluid entry.
The switchboard is basically a motor control device (Fig. 7.13). Voltage capability ranges from 600 to 4,900 V on standard switchboards. All enclosures are NEMA-3R
7-6 PETROLEUM ENGINEERING HANDBOOK
. . .
Fig. 7.1 l--Rotary gas separator.
Fig. 7.12~Round and parallel power cable.
(Natl. Electrical Manufacturers Assn.), which is suitable for virtually all outdoor applications. The switchboards range in complexity from a simple motor starter/discon- nect switch to an extremely sophisticated monitor- ing/control device.
There are two major construction types-elec- tromechanical and solid state. Electromechanical con- struction switchboards provide overcurrentioverload protection through three magnetic inverse time-delay contact relays with pushbutton, manual reset. Undercur- rent protection is provided by silicone-controlled rec- tifier (SCR) relays. These features provide protection against downhole equipment damage caused by condi- tions such as pumpoff, gas lock, tubing leaks, and shutoff operation.
The solid state switchboards incorporate the highly sophisticated Redalert’” motor controller. The purpose of the motor controller is to protect the downhole unit by sensing abnormal power service and shutting down the power supply if current exceeds or drops below preset limits. This is accomplished by monitoring each phase of the input power cable to the downhole motor.
The monitoring function applies to both overload and underload conditions. When a fault condition occurs, the controller shuts down the unit. It can be programmed to automatically restart the downhole motor following a user-selected time delay if the fault condition is caused by an underload. The programmed time delay can be from 1 minute up to 20 hours. Overload condition shut- down must be restarted manually, but this should be done only after the fault condition has been identified and corrected.
A valuable switchboard option is the recording am- meter. Its function is to record, on a circular strip chart, the input amperage to the downhole motor. The ammeter chart record shows whether the downhole unit is per- forming as designed or whether abnormal operating con- ditions exist, Abnormal conditions can result when a well’s inflow performance is not matched correctly with pump capability or when electric power is of poor quali- ty. Abnormal conditions that are indicated on the am- meter chart record are primary line voltage fluctuations, low amps, high amps, and erratic amps. Specific ex- amples of typical problems encountered and the associated ammeter chart pattern are discussed later.
The ESP system involves three different transformer configurations. These are three single-phase trans- formers (Fig. 7.14), one three-phase standard transformer, and one three-phase autotransformer. Transformers generally are required because primary line voltage does not meet the downhole motor voltage requirement. Oil-immersed self-cooled (OISC) trans- formers are used in land-based applications. Dry type transformers are sometimes used in offshore applications that exclude oil-filled transformers.
The ESP wellhead or tubing support is used as a limited pressure seal (Fig. 7.15). The wellhead provides a pressure tight pack-off around the tubing and power cable. High-pressure wellheads, up to 3,000 psi, use an
ELECTRIC SUBMERSIBLE PUMPS 7-7
Fig. 7.14-Single-phase transformer.
electrical power feed to prevent gas migration throughthe cable. Wellheads are manufactured to fit standardcasing sizes from 4.5 to 10% in.
Junction BoxA junction box connects the power cable from theswitchboard to the well power cable (Fig. 7.16). Thejunction box is necessary to vent to the atmosphere anygas that may migrate up the power cable from the well.This prevents accumulation of gas in the switchboardthat can result in an explosive and unsafe operating con-dition. A junction box is required on all ESPinstallations.
Accessory OptionsThe following covers two major accessory options-thepressure-sensing instrument and the variable-speeddrive.
Pressure-Sensing Instrument (PSI). The PSI providesthe operator with precise downhole pressure andtemperature data. The PSI has two components: (1) a
PETROLEUM ENGINEERING HANDBOOK
Fig. 7.16-Junction box.
downhole transducer/sending unit and a surfacereadout unit (Fig. 7.17). The downhole transducer/send-ing unit connects electrically and bolts to the base of themotor. Both pressure and temperature data are transmit-ted from the transducer/sending unit to the surfacereadout through the motor windings and the power cableon a DC carrier signal. The transducer receives operatingpower from the motor’s neutral winding. This allows theoperation of the PSI even when the motor is not running.
The major use of the PSI unit is in determining the pro-ducing potential of a well. This is accomplished bydetermining both static and dynamic reservoir pressures.By correlating the change in pressure with a given pro-ducing rate, a well’s inflow performance can be ac-curately quantified. This in turn will allow equipmentselection, which optimizes well production.
Variable-Speed Drive. The variable-speed drive (VSD)is a highly sophisticated switchboard-motor controller(see Fig. 7.18). A VSD performs three distinct func-tions. It varies the capacity of the ESP by varying the
Fig. 7.18--5OOKVA variable-speed drive.
motor speed, protects downhole components from powertransients, and provides “soft-start” capability. Each ofthese functions is discussed.
A VSD changes the capacity of the ESP by varying themotor speed. By changing the voltage frequency sup-plied to the motor and thus motor rev/min, the capacityof the pump is changed also in a linear relationship.Thus, well production can be optimized by balancing in-flow performance with pump performance. This appliesto both long-range reservoir changes as well as short-term transients such as those associated with high-GORwells. This may eliminate the need to change the capaci-ty of a pump to match changing well conditions or it maymean longer run life by preventing cycling problems.This capability is also useful in determining the produc-tivity of new wells by documenting pressure and produc-tion values over a range of drawdown rates. The changein voltage frequency can be made manually orautomatically. The VSD can operate automatically in a“closed loop” mode with a programmable controllerand PSI instrument.
The VSD also protects the downhole motor from poor-quality electric power. The VSD is relatively insensitiveto incoming power balance and regulation while pro-viding closely regulated and balanced output. The VSDwill not put power transients out to the downhole motorbut it can be shut down or damaged by such transients.Given the choice, most operators prefer to repair surfaceinstallation equipment rather than pull and run downholeequipment. Within limits, the VSD upgrades poor-quality electric power by “rebuilding.” The VSD takesa given frequency and voltage AC input, converts theAC to DC, and then rebuilds the DC to an AC
ELECTRIC SUBMERSIBLE PUMPS 7-9
waveform. The shape of the waveform is a six-step square wave.
The soft-start capability of a VSD provides two major benefits. First, it reduces the startup drain on the power system. Second, the strain on the pump shaft is significantly reduced when compared with that of a stan- dam start. This capability is valuable in gassy or sandy wells. In some cases, slowly ramping a pump up to operating speed may avoid pump damage.
Selection Data and Methods This section covers the data requirements and calculation procedures required for pump selection in a typical ESP application. The single most important factor in selection of an ESP is the input data. The data used in sizing an ESP must be accurate and reliable to ensure that the unit is properly matched to the well’s inflow performance.
The data requirements for selection of an ESP are categorized as mechanical data, production data, fluid data, and power supply.
The mechanical data include: (1) casing size and weight, (2) tubing size, weight, and thread, (3) well depth-both measured and true vertical, (4) perforations depth-both measured and true vertical, and (5) unusual conditions such as tight spots, doglegs, and deviation from true ver- tical at desired setting depth.
The casing size and weight determine the maximum diameter of the motor, pump, and protector components that will fit in the well. In general, the most efficient in- stallation is obtained when the largest possible diameter pump, in the target flow range, is selected.
The depth of the well and the perforations determine the maximum setting depth of the ESP. If the motor is to be set below the perforations, a motor shroud must be used to provide a flow of well fluid past the motor for cooling (Fig. 7.5).
The production data include: (1) current and desired pro- duction rate, (2) oil-production rate, (3) water- production rate, (4) GOR-free gas and solution gas or gas bubblepoint, (5) static BHP and fluid level, (6) pro- ducing BHP and stabilized fluid level, (7) BHT, and (8) system backpressure from flowlines, separator, and wellhead choke.
The inflow performance of a well establishes the max- imum economical and efficient rate at which it can be produced. Liquid-level data may be used as a substitute for producing pressures and rates in water wells or in low-oil-cut wells with no gas. In these cases, a straight line PI may be used as a reasonable approximation of well capacity.
Most oil wells do not exhibit a straight-line PI because of interference caused by gas. The Vogel technique’ yields a downward-sloping curve that corrects for gas in- terference. The IPR curve (Fig. 7.19) applies when wellbore pressure in the producing zone drops below the bubblepoint, which results in two-phase flow as the gas breaks out of the fluid. Again, the data obtained for this approach in sizing an ESP must be both accurate and reliable to ensure proper equipment selection.
PRODUCING RATE FRACTION OF MAXIMUM qo/q ,,max
Fig. 7.19~Inflow performance relationships curve
The fluid data include: (1) oil API gravity, viscosity, pour point, paraffin content, sand, and emulsion tenden- cy; (2) water specific gravity, chemical content, corro- sion potential, and scale-forming tendency; (3) gas specific gravity, chemical content, and corrosive poten- tial; and (4) reservoir FVF, bubblepoint pressure, and viscosity/temperature curve.
The specific gravity of the produced fluid has a direct impact on the horsepower required to turn a given size pump. Although relatively few applications encounter fluid viscosities high enough to influence pump perfor- mance, it is important to be aware that capacity, head, and horsepower correction factors may be required. In wells with a water cut of 65% or higher, the fluid will not require viscosity correction factors (except for emulsions).
The PVT data are required when gas is present. A computer program for pump selection (discussed later in this section) contains a subroutine that uses Standing’s correlations* in approximating the PVT values when ac- tual data are not available. In high-GOR applications, PVT data are very desirable because the three standard correlation estimates-Standing,* Lasater3, and Vas- quez and Beggs4-yield large differences in calculated downhole gas volume (see Chap. 22).
Electric Power Supply
The electric power supply includes: (1) voltage available and frequency, (2) capacity of the service, and (3) quali- ty of service (spikes, sags, etc.).
1100 to 1900 100 to 450 280 to 550 320 to 575 375 to 650 500 to 900 600 to 1150 760 to 1250 975 to 1650 950 to 1800
1200 to 2050 1400 to 2450 2100 to 3700 3400 to 5000
950 to 1600 1050 to 1800 2600 to 4500 1500 to 2500 2000 to 3100 2100 to 3400 2200 to 3700
4200 to 6600
45 to 80 68 to 111
105 to 175 139 to 250 175 to 302
16to72 45 to 87 51 to 91 60 to 103 80 to 143 95 to 183
121 to 199 155 to 262 151 to 286 191 to 326 223 to 390 334 to 588 540 to 795 151 to 254 167 to 286 445 to 715 238 to 397 318 to 493 334 to 541 350 to 568
4500 to 7250 5500 to 8500 8000 to 12000 9200 to 16400 6000 to 9500 8000 to 12250
12800 to 19500 16000 to 25000 12000 to 24000 19000 to 32500 24000 to 47500 35000 to 59000 53600 to 95800
666 to 1049 715 to 1153 874 to 1351
1272 to 1908 1463 to 2607
954 to 1510 1272 to 1948 2035 to 3100 2544 to 3795 1908 to 3816 3021 to 5167 3816 to 7552 5564 to 9380 8521 to 15240
The power data are important because they partially determine transformer and switchboard requirements. Frequency influences pump rotation speed, capacity, and head.
Once the required data have been gathered and ana- lyzed, the next ESP selection step is to determine the well’s production capacity at a given pump-setting depth. This involves analysis of the inflow performance data as well as desired production rate. Two key factors that must be considered are the minimum pump intake pressure (net positive suction head), which the well will permit without pumpoff or gas lock, and the producing rate, which draws the fluid level down to an optimal level.
The next selection step is to determine the total dynamic head (TDH). TDH is the sum of: (1) the true vertical lift distance from the producing fluid level to the surface, (2) friction loss in the tubing string, and (3) discharge pressure head at the wellhead. The design TDH determines the number of stages required in a
pump. Selection of a specific pump involves identifying a
pump of the largest possible diameter that can be run in the well. The pump should have the target capacity
within its recommended operating range and close to its peak efficiency. The initial pump capacity selection can be made from Table 7.1.
The individual pump curve should then be reviewed to determine the optimal producing range and the proximity of the design producing rate to the pump’s peak efficien- cy (see Fig. 7.20 for a typical pump performance curve). It is very important to choose a producing rate that is in the recommended capacity range of the specific pump. When a pump operates outside this range, premature failure can result.
Once a pump is chosen, the number of stages required can be calculated using the lift-feet-per-stage data from the performance curve.
ns = number of design stages, Z = total dynamic head, ft, and
L, = lift per stage, ft.
ELECTRIC SUBMERSIBLE PUMPS 7-1 1
d *a” 0
YI 15 1w 125 150
Fig. 7.20-Typical pump performance curve.
The horsepower required by the pump design then can be calculated. To accomplish this, the horsepower re- quired per stage is read from the specific pump perfor- mance curve. The required motor horsepower is deter- mined by multiplying the horsepower required per stage by the number of design stages. The performance curve horsepower data apply only to liquids with a specific gravity of 1.0. For other liquids (other specific gravities), the water horsepower also must be multiplied by the specific gravity of the fluid pumped. Thus we have the following equation for the motor horsepower calculation.
Phm = motor horsepower, Phs = horsepower per stage,
ns = number of design stages, and 0~ = specific gravity of fluid.
Once the design motor horsepower is determined, specific motor selection is based on setting depth, casing size, and motor voltage. Although the cost of the motor is generally unrelated to voltage, overall ESP system cost may be lowered by using higher-voltage motors in deep applications. This lower cost can sometimes occur because a higher voltage can lower the cable conductor size required. A smaller-conductor-size, lower-cost cable can more than offset the increased cost of a higher- voltage switchboard. Setting depth is a major variable in motor selection because of starting and voltage drop losses that are a function of the motor amperage and cable conductor size.
Cable selection variables are amperage, voltage drop, annulus clearance, ambient well temperature, and corro- sion conditions. The standard maximum voltage drop is limited to 3OV/lOC!fl ft. If voltage drop exceeds this value, a larger conductor size should be used. Round cable normally is used unless tubing collariannulus clearance dictates flat or parallel construction. The max- imum operating temperature of a cable in relation to the specific well’s ambient temperature determines the specific type of cable. Armor and lead sheathing may be recommended for wells with mechanical or clearance problems or corrosive gas such as Hz S.
The surface electrical equipment (switchboard and transformers) selection is based on the required motor horsepower, voltage, amperage, voltage loss, and cable size. The surface voltage is. the sum of the downhole motor no-load voltage plus the voltage losses resulting from cable size and other component losses. Voltage losses associated with transformers range from 2.5 to 6%, depending on the manufacturer. Additional im- pedance is associated with VSD transformer sizing. Transformers must also be selected on the basis of the primary voltage available and the required hookup method-AA, YA, or YY.
The protector selection variables are motor and pump series, motor horsepower, and well temperature. Nor- mally the protector is the same series as the pump and motor. Large horsepower motors (150 hp and larger) may require a larger oil capacity. For large horsepower motors, a positive seal double-bag model or a tandem “labyrinth path” model is used. An ambient well temperature of 250°F or higher generally requires the use of the labyrinth path protector.
ESP equipment selection in high-water-cut, low-GOR wells is relatively straightforward. Equipment selection
7-12 PETROLEUM ENGINEERING HANDBOOK
Fig. 7.21--Shipping boxes positioned at the wellsite.
in high GOR or viscous crude wells, however, can bevery complicated. One ESP manufacturer has developeda sophisticated computer program to provide comprehen-sive analysis of alternative equipment selections in suchsituations. It can be used to select equipment or toevaluate previously selected equipment. This capabilitymeans that, over time, the engineer can evaluate thepump fit as well as changes in conditions. If well inflowperformance changes significantly, the sizing of thedownhole equipment may need to be checked both to op-timize production and to prevent premature failure.
The computer program contains analytic models forpump performance, reservoir response, and fluidcharacteristics. It uses the Chew and Connally5 correla-tions for live fluid viscosity based on the quantity of gasin solution. Another option uses Orkiszewski’s6 two-phase vertical flow model to compute pump dischargepressure and horsepower required. Standing’s? correla-tions are used to provide surrogate PVT data when actualvalues are not available.
Handling, Installation, and OperationThis section provides recommended practice on thehandling, installation, and operation of an ESP system.Because both safety and economic run life are dependenton correct procedures, the importance of following therecommended practice cannot be overemphasized.
The downhole components-motor, pump, protector,and intake-are shipped in a metal shipping box (Fig.7.21). The shipping boxes are painted red on the end thatshould be placed toward the wellhead when the equip-ment is delivered to the wellsite. The shipping boxesshould be lifted with a spreader chain or bridled with asling at each end. Severe equipment damage can resultfrom dropping, dragging, or bouncing the boxes. Theshipping boxes should never be lifted by the middle ofthe box only.
The cable reel should be lifted by using an axle and aspreader bar (Fig. 7.22). If a fork lift is used, the forksshould be long enough to support both reel rims when thereel is picked up from an end. The ends of the cableshould be covered or sealed to protect them from theelements.
Transformers and switchboards are provided with lift-ing hooks. To avoid damage, the recommended practiceis to lift with a spreader bar to maintain a vertical posi-tion. Variable-speed drives are normally skid-mountedwith fork lift slots and lifting eyes. Some VSD modelsare manufactured with pull bars.
Additional information on ESP handling and installa-tion procedures is available in “API RecommendedPractice for Electric Submersible Pump Installations.”8
InstallationThere are three segments to every ESP installation.These are well preparation, site layout, and run-in andstartup of equipment. The well-preparation procedure in-
Fig. 7.22-Cable reel lifting procedures.
ELECTRIC SUBMERSIBLE PUMPS 7-13
volves determining the downhole clearance conditions.Site layout prescribes equipment and rig locations aswell as size and capacity. Running equipment in the welland startup procedures define the steps in equipmenthandling, test procedure, and responsibility of the rigcrew and servicemen.
Prior to beginning installation of the ESP equipment,the well must be cleared of any tubing, rods, packers,etc., that would prevent the downhole equipment fromreaching target setting depth. The casing flange andwe11head should be examined for burrs or sharp edges.This is very important in small-diameter casing becausecable damage can be caused by burrs or edges catchingcable bands.
A gauge ring should be run in (particularly in 4.5-in.casing) to below the setting depth of the downhole equip-ment. If gauging indicates tight spots, a scraper orreamer should be used to remove the obstruction (scale,paraffin, burrs, or partially collapsed casing). This willensure adequate clearance for the ESP downhole equip-ment as it is run into the well.
The blowout preventer (BOP), if used, should bechecked for adequate clearance as well as burrs andsharp edges. Cut-out rams are available for most tubingand cable sizes. They should be installed in the BOP forwell control in the event of a kick during equipmentinstallation.
The pulling rig should be centered over the well asclosely as possible. A guide wheel/cable sheave shouldbe secured safely to the rig mast no higher than 30 to 45ft above the wellhead. The guide wheel should be at least54 in. in diameter.
The cable reel or spooling truck should be positionedabout 100 ft from the wellhead in direct line of sight ofthe rig operator. One person should be responsible forthe cable operation. The responsibilities of this personare to ensure that there is minimum tension on the cable(the cable should be run at the same speed as the tubing),that the cable is kept clear of power tongs during tubingmakeup or break, and that no one stands in front of thecable reel/spooler.
The cable junction box must be located at least 15 ftfrom the wellhead (Fig. 7.16). The switchboard must belocated a minimum of 50 ft from the wellhead and 35 ftminimum from the junction box. The junction box nor-mally is located 2 to 4 ft above ground level to ensureadequate air circulation and easy access. The junctionbox must never be located inside a building.
The ESP manufacturer’s field representative checks allequipment before installation. During installation hisresponsibility is to supervise the pulling and/or runningof the downhole equipment. All equipment delivered tothe wellsite is checked to determine that all componentsnecessary to complete the installation have arrived andare not damaged. The ESP manufacturer’s fieldrepresentative will perform the following checks andprocedures.
1. Remove shipping box covers and record all compo-nent serial numbers from nameplates (Fig. 7.23).
2. Check casing, wellhead, and packoff material.3. Check the switchboard for proper fuses, potential
transformer setup, and current transformer ratios.4. Check all couplings for shaft diameter and spline
3. Check flat cable length, size, and pothead type.6. Check power transformers for correct primary and
secondary voltage rating.7. Confirm that the pump design setting depth and
capacity match the well conditions.8. Check the power cable and flat cable with in-
struments and high-voltage megger.Once the equipment, cable, and verification pro-
cedures are completed, the assembly and run-in ofdownhole equipment can begin. The manufacturer’sfield representative directs the assembly and checksequipment as it is being run in. The steps of assemblyand checks of equipment can be summarized as follows.
1. Assemble motor, protector, intake, and pump.2. Fill the motor/protector assembly with motor oil.3. Mechanically check free rotation of downhole
components.4. Check electrical connection and test the motor,
power cable, and flat cable pothead.5. Correct torque of connecting bolts.6. Band cable to tubing string.7. Splice cable or repair damaged cable.8. Connect power cable to junction box and
switchboard.9. Pack off wellhead.10. Complete flowline connections and valve
position.Once the run-in procedures are completed and final
electrical tests completed, the manufacturer’s represen-tative will complete the electrical connections. Theswitchboard underload and overload adjustments are setaccording to the conditions expected for each well. Thepump is then started. Fluid pump-up time, load and no-load voltage, and amperage on each phase are recorded.Phase rotation should be checked carefully to ensure thatthe pump is rotating in the correct direction.
The quantity of production of oil, gas, and watershould be monitored on startup and regularly for the timerequired to achieve stability. A careful study should bemade on a pump installation that does not produce asdesigned. As much information as possible should begathered to aid in specific identification of the problemand appropriate remedial action. This will ensure thatsubsequent installations will provide satisfactory runlife.
PETROLEUM ENGINEERING HANDBOOK
Fig. 7.24-Normal ammeter chart.
Pulling equipment out of a well involves essentially the reverse process of run-in. The equipment and cable should be handled with the same care as new because they are still valuable. Cable damage and missing bands should be recorded at the depth they occurred to aid in subsequent repair and evaluation. If the equipment failure is judged to be premature, the condition of cable, flat cable, pump rotation, and motor/protector fluid may be useful in determining the cause of the failure.
Troubleshooting This section outlines a recommendation for identification and solution of typical ESP problems. The only way a failure can be analyzed and its cause determined is by data collection. When a problem occurs you simply can- not have too much information.
Information that should be routinely compiled on each ESP well includes production data (such as water, oil, and gas), run life, unit starts and stops, dynamic and static fluid level, and pump setting and perforation depth. Information also should be obtained on ammeter charts, well conditions (abrasives, corrosives, HzS etc.), electric power quality (surges, sags, balance, negative sequence voltages, etc.), visual observations of equip- ment and cable condition on prior pulls, reasons for equipment pull (failure, workover, size change, etc.), and BHT.
When an ESP well is first put on production, data should be collected daily for the first week, weekly for the first month, and a minimum of monthly after the first month. Production data during the first month are very important because they will indicate whether the pump is performing as designed. If a downhole pressure instru- ment is installed, operating BHP is equally important.
The major source of information when troubleshooting an ESP installation is the recording ammeter. The re- cording ammeter is a circular strip-chart accessory
Fig. 7.25-Normal startup chart.
mounted in the switchboard that records the amperage drawn by the ESP motor (Fig. 7.13). A number of changes in operating conditions can be diagnosed by in- terpreting ammeter records. The following addresses ammeter chart “reading”and typical problem situations.
A normal chart (Fig. 7.24) is smooth, with amperage at or near motor nameplate amperage draw. Actual opera- tion may be either slightly above or below nameplate amperage. However, as long as the curve is symmetric and consistent over time, operation is considered normal.
A normal startup will produce a chart similar to that shown in Fig. 7.25. The startup “spike” is caused by the inrush surge as the pump comes up to operating speed. The subsequent amperage draw is high but tren- ding toward a normal level. This is principally a result of the fluid level being drawn down to the design TDH, resulting in a high but declining amperage draw.
Operating ESP amperage will vary inversely with voltage. If system voltage fluctuates, the ESP amperage will fluctuate inversely to maintain a constant load (Fig. 7.26). The most common cause of this type of fluctua- tion is a periodic heavy load on the primary power system. This load usually occurs when starting up another ESP or other large electric motor. Simultaneous startup of several motors should be avoided to minimize the impact on the primary power system. Ammeter spikes also can occur during a thunderstorm that is ac- companied by lightning strikes.
ELECTRIC SUBMERSIBLE PUMPS 7-15
Fig. 7.26-Startup spikes chart.
Fig. 7.27-Gas lock chart
Gas locking occurs as fluid level drawdown approaches the pump intake and intake pressure is lower than the bubblepoint. This situation is shown in Fig. 7.27. This ammeter chart shows a normal startup and amperage decline as the fluid level is drawn down. However, the chart shows erratic fluctuations as gas breaks out near the pump beginning at approximately 6: 15 a.m. As the fluid level continues to draw down, cyclic loading of both free gas and fluid slugs leads to increasingly wider amperage fluctuations, ultimately resulting in shutdown at approx- imately 7: 15 a.m. because of undercurrent loading.
Fig. 7.28-Fluid pumpoff chart.
Fig. 7.29-Short duration cycling.
There are three possible remedies for gas locking. The first is to install a gas separator intake and/or a motor shroud. The second is to lower the setting depth of the pump (but not lower than the perforations unless the motor is shrouded). The third remedy is to reduce the production rate of the pump by using a surface choke (but ensure that the production rate remains within the recommended range for that pump). It is entirely possi- ble that none of these solutions is satisfactory. The pump should be replaced with a pump that does not draw down the fluid level or reduce intake pressure below the bubblepoint.
7-16 PETROLEUM ENGINEERING HANDBOOK
Fig. 7.30-Gassy or emulsion conditions.
Fig. 7.31-Debris or solids in a well.
Another possible solution is to add a VSD to the ex- isting system. The VSD controls the speed of the pump, which in turn controls the pump capacity. Thus the pump output can be fine-tuned to protect against pumpoff and gas lock while contributing to improved pump life.
Fluid pumpoff occurs typically when an ESP is too large in relation to the inflow capacity of the well. This condi- tion is illustrated in Fig. 7.28. This chart shows a normal startup at 7:00 a.m. and normal operation until approx- imately 10:00 a.m. Then amperage draw begins to fall
Fig. 7.32-Overload shutdown condition.
slowly until the underload setting is reached and the pump is shut down about 2:15 p.m. Subsequent automatic restarts at 4:15 p.m. and 8:15 p.m. produce similar results.
The remedial actions are much the same as those listed for gas lock and, in addition, a well stimulation treat- ment may increase the well’s productivity closer to a match with the pump.
In general, cycling an ESP is not conducive to optimal run life. As a temporary measure, the amount of time delay before automatic restart can be increased if the switchboard is equipped with a Redalert motor con- troller. This may allow the fluid volume to build up to prevent a high frequency of shutdown occurrence. Nevertheless, the pump and well are not compatible and the pump size should be checked on the next changeout or the well worked over to improve productivity.
A form of frequent, short-duration cycling is shown in Fig. 7.29. This shows an extreme pumpoff condition. While the initial reaction is to suspect a badly oversized pump, them may be another cause. If a fluid level sound- ing, taken immediately after pump shutdown, indicates fluid over the pump, the problem may be a tubing leak or a restricted valve or discharge line. A tubing leak typically is accompanied by a somewhat low discharge pressure and low surface production rate. If shutdown is caused by a plugged valve or discharge line, tubing pressure should be abnormally high.
A gassy but normal producing well is shown in Fig. 7.30. The continuous amperage fluctuations result from alternating free gas and heavy fluid pumping. Generally this condition results in a reduction of stock-tank barrels in relation to pump design rate. This figure is also typical of an emulsion. The amperage fluctuations are caused by the frequent, temporary blockage of the pump intake. If
ELECTRIC SUBMERSIBLE PUMPS 7-17
it is an emulsion block, spikes are normally lower or below the normal amperage line.
Solids and Debris
When debris or solids are found in a well, the amperage will display fluctuations immediately after startup. This condition is shown in Fig. 7.3 1. Typically when solids such as sand, scale, or weighted mud are found in a well, special care must be taken on startup to avoid pump damage. It may be necessary to put backpressure on the well to prevent excess amperage until the kill fluid is removed and/or sand production begins to decline to a safe volume.
A pump will also automatically shut down in an overload condition. This condition is shown in Fig. 7.32. However, when an overload condition shutdown occurs the unit must not be restarted until the cause of the overload has been identified and corrected. Some motor controller overload-detection circuits contain a built-in time delay, ranging from 1 to 5 seconds at 500% of the set point to 2 to 30 seconds at 200% of the set point. However, they will not automatically restart the unit on an overload condition. A restart attempt in an overload condition can destroy the downhole equipment if the cause of the overload is not identified and corrected first.
The most common causes of an overload condition are increased fluid specific gravity, sand, emulsion, scale, electric power supply problems, worn equipment, and lightning damage.
References 1, Vogel, J.V.: “Inflow Performance Relationships for Solution-Gas