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ESP system selection and performance calculations -
ESP system selection and performance calculations
Proper sizing and selection of an electrical submersible pump (/Electrical_submersible_pumps) (ESP) system is essential to efficient and cost-effective performance. Selection and
sizing of proper ESP equipment for a particular application should be based on a nine-step design procedure. [1] This page outlines the procedure as a manual process to illustrate the
ESP design steps. While it is accurate for simple water and light-crude designs, there are commercially available ESP design software programs that give accurate designs for wells
with:
High gas/oil ratios (GOR)
Viscous crudes
High temperature
Operation on variable speed controllers (VSC)
This nine-step procedure helps the engineer design the appropriate submersible pumping system for a particular well. Each of the nine steps is explained below, including gas
calculations and variable-speed operations. Specific examples are worked through in ESP design (/ESP_design).
Contents
1 Step one: basic data
2 Step two: production capacity
2.1 Productivity index
2.2 Inflow performance relationships
2.3 Step three: gas calculations
2.4 Gas volume factor
2.5 Formation volume factor
2.6 Total volume of fluids
3 Step four: total dynamic head
4 Step five: pump type
4.1 Variable-speed submersible pumping (VSSP) system and pump selection
5 Step 6: optimum size of components
5.1 Pump
5.2 Separator
5.3 Motor
5.4 Seal selection
6 Step 7: electric cable
6.1 Cable size
6.2 Cable type
6.3 Cable length
6.4 Cable venting
7 Step 8: accessory and optional equipment
7.1 Downhole accessory equipment
7.2 Motor controllers
7.3 Single-phase and three-phase transformers
7.4 Surface cable
7.5 Wellheads and accessories
7.6 Servicing equipment
7.7 Optional equipment
8 Step 9: variable speed submersible pumping system
9 Nomenclature
10 References
11 Noteworthy papers in OnePetro
12 Noteworthy books
13 External links
14 See also
15 Page champions
16 Category
Step one: basic data
The design of a submersible pumping unit, under most conditions, is not a difficult task, especially if reliable data are available. Although, if the information, especially that
pertaining to the well’s capacity, is poor, the design will usually be marginal. Bad data often result in a misapplied pump and costly operation. A misapplied pump may operate
outside the recommended range, overload or underload the motor, or draw down the well at a rapid rate that may result in formation damage. On the other extreme, the pump may not
be large enough to provide the desired production rate.
Too often, data from other wells in the same field or in a nearby area are used, assuming that wells from the same producing horizon have similar characteristics. Unfortunately, for
the engineer sizing the submersible installations, oil wells are much like fingerprints (i.e., no two are quite alike).
The actual selection procedure can vary significantly depending on the well-fluid properties. The three major types of ESP applications are wells with single-phase flow of oil and/or
water, wells with multiphase flow of liquids and gas (especially high free-gas rates), and wells producing highly-viscous fluids typically much greater than 10 cp. A list of required
data is outlined next.
Well data: Casing or liner size, weight, grade; tubing size, weight, grade type and thread, plus condition; pump setting depth (measured and vertical); perforated or openhole
interval; well plugback total depth (measured and vertical).
Production data: Wellhead tubing pressure; wellhead casing pressure; present production rate; producing fluid level and/or pump-intake pressure at datum point; static fluid
level and/or static bottomhole pressure at datum point; datum point; bottomhole temperature; desired production rate (target); GOR; and water cut.
Well-fluid conditions: Specific gravity of water; oil °API or specific gravity; specific gravity of gas; bubblepoint pressure of gas; viscosity of oil (dead); and other available
pressure/volume/temperature (PVT) data.
Power sources: Available primary voltage, frequency, and power source capabilities.
Possible production problems: Sand, scale deposition, corrosion, paraffin/asphaltenes, emulsion, gas, high reservoir temperature.
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Step
two: production capacity
ESP system selection and performance calculations -
The following is a simplification of procedures for predicting well performance. This discussion assumes little or no well skin. A damaged wellbore or other factors affects the well
flow performance.
Productivity index
When the well flowing pressure (Pwf) is greater than bubblepoint pressure (Pb), the fluid flow is single-phase flow, and the inflow performance relationship
(/Reservoir_inflow_performance) is a straight line with slope J, as given by the productivity index (PI).
(/File:Vol4_page_0688_eq_001.png)....................(1)
Inflow performance relationships
If Pwf is less than Pb, resulting in multiphase flow in the reservoir, the inflow-performance-relationship (/Reservoir_inflow_performance) (IPR) method should be used. The
relationship is given by Eq. 2.
(/File:Vol4_page_0688_eq_002.png)....................(2)
This relationship was first used by Gilbert[2] and further developed by Vogel. [3] Vogel developed a dimensionless reference curve that can be used to determine the IPR curve for a
particular well. Others have developed variations of the IPR equation. (See Reservoir inflow performance (/Reservoir_inflow_performance)) .
Step three: gas calculations
The presence of free gas at the pump intake and in the discharge tubing makes the process of equipment selection much more complicated and voluminous. As the fluid (liquid/gas
mixture) flows through the pump stages from the intake to the discharge and through the discharge tubing, the pressure and, consequently, fluid properties (such as volume, density,
etc.) are undergoing continuous change. Also, the presence of free gas in the discharge tubing may create a significant "gas lift" effect and considerably reduce the required discharge
pressure or TDH of the pump.
Ideally, a well is produced with a submergence pressure above the bubblepoint pressure to keep gases in solution at the pump intake. This is typically not feasible, so the gases must
be either handled by the pump or separated from the other fluids prior to the pump intake.
It is essential to determine the effect of the gas on the fluid volume to select the proper pump and any auxiliary equipment. The following calculations yield the approximate percent
free gas by volume.
If the solution GOR (Rs), the gas volume factor (Bg), and the formation volume factor (Bo) are not available from reservoir data, they must be calculated, and there are a number of
multiphase correlations to select from. The correlation selected will affect the design, so select the one that best matches the conditions. Standings correlations for solution GOR and
formation volume factor are shown next.
Solution GOR
(/File:Vol4_page_0689_eq_001.png)....................(3)
Or, in metric,
(/File:Vol4_page_0689_eq_002.png)....................(4)
Note: pump-intake pressure should be substituted for bubblepoint pressure when calculating pump-intake conditions.
Gas volume factor
The gas volume factor, Bg, is expressed in reservoir scf/bbl gas (m3/m3).
(/File:Vol4_page_0689_eq_003.png)....................(5)
Or, in metric,
(/File:Vol4_page_0689_eq_004.png)....................(6)
Formation volume factor
The formation volume factor, Bo , represents the increased volume that a barrel of oil occupies in the formation as compared to the stock-tank barrel of oil (STBO).
(/File:Vol4_page_0689_eq_005.png)....................(7)
where
(/File:Vol4_page_0689_eq_006.png)....................(8)
Or, in metric,
(/File:Vol4_page_0690_eq_001.png)....................(9)
Total
volume of fluids
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When
these three variables: Rs, Bo, and Bg are known, the volumes of oil,
water,
and free
gas canand
be determined
and calculations
percentages of- each calculated. The total volume of gas (both free
8/28/2018
ESP
system
selection
performance
and in solution) can be determined as
(/File:Vol4_page_0690_eq_002.png)....................(10)
The gas in solution at submergence pressure can be determined as
(/File:Vol4_page_0690_eq_003.png)....................(11)
The free gas equals the total gas minus the solution gas. The volume of oil (Vo) at the pump intake is equal to stock-tank barrels multiplied by Bo, the formation volume factor. The
volume of gas (Vg) at the pump intake is equal to the amount of free gas multiplied by Bg, the gas volume factor. The volume of water (Vw) in the formation is approximately the
same as stock tank barrels. Total fluid volume (Vt) can now be determined.
(/File:Vol4_page_0690_eq_004.png)....................(12)
The percentage of free gas to total volume of fluids can now be calculated as
(/File:Vol4_page_0690_eq_005.png)....................(13)
Step four: total dynamic head
The next step is to determine the total dynamic head (TDH) required to pump the desired capacity. The total pump head refers to feet (meters) of liquid being pumped and is
calculated to be the sum of: net well lift, HL; well-tubing friction loss, Ft; and wellhead pressure head, Hwh. The simplified equation is written as
(/File:Vol4_page_0690_eq_006.png)....................(14)
Step five: pump type
Refer to the manufacturer’s catalog for pump types, ranges, and pump-performance curves (60 Hz and 50 Hz). On the basis of expected fluid production rate and casing size, select
the pump type that will, at the expected producing rate, be operating within the pump’s operating range and near to the pump’s peak efficiency.
Where two or more pump types have similar efficiencies at the desired volume, certain conditions determine the pump choice:
Pump prices and corresponding motor sizes and prices may differ somewhat. Normally, the larger-diameter pump and motor are less expensive and operate at higher
efficiencies.
When the well’s capacity is not known, or cannot be closely estimated, a pump with a "steep" characteristic curve should be chosen. If the desired volume falls at a point where
two pump types have approximately equal efficiency, choose the pump type that requires the greatest number of stages. Such a pump will produce a capacity nearest the desired
volume even if the well lift is substantially more or less than expected.
If gas is present in the produced fluid, a gas separator may be required to achieve efficient operation. Note that the free gas is vented up the casing annulus. Refer to Step 3 to
determine the effect of gas on the produced volume. The adjusted volume affects pump selection and the size of the other system components.
In wells where the fluid is quite viscous and/or tends to emulsify, or in other extraordinary circumstances, some pump corrections may be necessary to ensure a more efficient
operation. In such cases, contact the manufacturer for engineering recommendations.
Variable-speed submersible pumping (VSSP) system and pump selection
Under the previous or other pumping conditions, also consider the VSSP system. Such systems must be justified. For instance, if the production rate is not accurately known, a VSSP
system may be applicable. A VSC effectively converts a single pump into a family of pumps, so a pump can be selected for an estimated range and adjusted for the desired production
level, once more data are collected.
Review Step 9 when considering the VSSP system. Variable-frequency performance curves are included in most manufacturers’ information. The VSSP system with the VSC may
provide additional economies of capital expenditure and operating expenses and should be considered in Step 6. The VSC and transformers for the VSSP system are discussed in
Steps 8 and 9.
Step 6: optimum size of components
ESP components are built in a number of sizes and can be assembled in a variety of combinations. These combinations must be carefully determined to operate the submersible
pumping system within production requirements, material strength, and temperature limits. While sizing components, refer to the manufacturer for the following information:
equipment combinations in various casings, maximum loading limits, maximum diameter of units, velocity of a fluid passing a motor, shaft HP limitations at various frequencies.
Pump
Refer to the manufacturer’s performance curve of the selected pump type, and determine the number of stages required to produce the anticipated capacity against the previously
calculated total dynamic head. Usually, performance curves for 60-Hz, 50-Hz, and variable-frequency operations are provided in the manufacturer’s catalog. The pump characteristic
curves are stage performance curves based on water with a specific gravity of 1.0. At the intersection of the desired production rate (bottom scale) and the head-capacity curve
(vertical scale), read the head value on the left scale. Divide this value into the TDH to determine the number of stages: total stages = TDH/(head/stage).
Separator
Refer to the manufacturer’s catalog for gas-separator information. Make the necessary adjustments in HP requirements and housing length.
Motor
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To select
the proper motor size for a predetermined pump size, the BHP ESP
required
by theselection
pump must
determined. The
HP per stage
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system
andbeperformance
calculations
- is obtained by referring to the performance curve
for the selected pump. The BHP required to drive a given pump is easily calculated by the following formula: BHP = total stages × (BHP/stage) × SG.
Refer to the manufacturer’s information for motor specifications. Select a motor size that closely meets the design conditions. The maximum load conditions should not exceed 110%
of rating. Minimum operating loads should not put the motor into an idle condition, otherwise protection monitoring is nullified. Manufacturers should be contacted for specific
operating ranges. Typically, operators try to select a motor that operates in the range from 70 to 100% of its rating.
Seal selection
Refer to a manufacturer’s catalog for selection of the proper seal section.
Step 7: electric cable
ESP electric cables are normally available in conductor sizes 1, 2, 4, and 6. These sizes are offered in both round and flat configurations. Several types of armor and insulation are
available for protection against corrosive fluids and severe environments.
Cable selection involves the determination of cable size, cable type, and cable length.
Cable size
The proper cable size is dependent on combined factors of voltage drop, amperage, and available space between tubing collars and casing.
Refer to the cable voltage drop curve (samples are shown in Fig 1[4] ) for voltage drop in cable. At the selected motor amperage and the given downhole temperature, the selection of
a cable size that gives a voltage drop of less than 30 volts per 1,000 ft (305 m) can be used as a guideline. This curve determines the necessary surface voltage (motor voltage plus
voltage drop in the cable) required to operate the motor.
(/File:Vol4_Page_657_Image_0001.png)
Fig. 1-ESP-power-cable voltage drop (after
Centrilift).[4]
Finally, check the manufacturer’s information to determine if the size selected can be used with the proposed tubing and well casing sizes. The cable diameter plus tubing-collar
diameter must be less than the ID of the casing. To determine the optimum cable size, consider future equipment requirements that may require the use of a larger-sized cable.
Where power cost is a major concern, kilowatt-hour loss curves can be used to justify the cable selection. Although power rates vary widely, this information is valuable in
determining the economics of various cable sizes.
Optimization procedures [5][6] are based on finding the least value of total operating costs over the expected life of the cable. The total operating cost is the sum of the capital and
operating expenses and these vary with cable size. Since an increase of the conductor size involves increased capital costs but decreased operating costs, a cable providing the
minimum of total costs can surely be found. It is easy to see that, contrary to the rules previously used, the smallest possible size may not be the best selection.
Cable type
Selection of the cable type is primarily based on fluid conditions, bottomhole temperature, and space limitations within the casing annulus. Carefully select the type of cable for
hostile environments. Refer to the manufacturers catalog for cable specifications. Where there is not sufficient space to run round cable, use electric cable with a flat configuration.
The flat cable configuration induces a voltage imbalance. If it is significant, a transition splice may be required. Verify this with the manufacturer.
Cable length
The total cable length should be about 100 ft (30 m) longer than the measured pump setting depth to make surface connections a safe distance from the wellhead. Check the voltage
available at the motor terminal block to avoid the possibility of low voltage starts. The available motor terminal voltage is the surface supply voltage minus the cable voltage drop.
Cable venting
In all wells, it is necessary to vent gases from the cable prior to the motor controller to avoid explosive conditions. A cable venting box is available to protect the motor controller
from such gases.
Step 8: accessory and optional equipment
Downhole accessory equipment
Flat cable (motor lead extension). Select a length at least 6 ft (1.8 m) longer than the pump intake (standard or gas separator) and seal section for the motor series chosen. Refer to the
manufacturer’s information for dimensions.
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cable guard (optional). Choose the required number for 6-ft (1.8-m)ESP
guard
sections
to at leastand
equal
the flat-cable
length. Do not
system
selection
performance
calculations
- use guards for installation of a 400 series pump
and seal section with 5 1/2-in. outside diameter (OD) and 20-lbm casing, and a 513 series pump and seal section with 6 5/8-in. OD and 26-lbm casing.
Cable bands. Use one 30-in. (76-cm) cable band every 2 ft (60 cm) for clamping flat cables to pumps. The 22-in. (56-cm) length can be used for all tubing/cable combinations
through 3½-OD tubing. For 4 1/2-in.- and 5 1/2-in.-OD tubing, use 30-in. (76-cm) bands. One band is required for each 15 ft (5 m) of setting depth. Refer to the manufacturer’s
information for dimensions.
Swaged nipple, check valve, and drain valve (optional). Select these accessories on the basis of required ODs and type of threads.
Motor controllers
Motor controllers (/ESP_surface_motor_controllers) are typical state-of-the-art digital controls consisting of two components.
System unit. This unit performs all the shutdown and restart operations. It is mounted in the low-voltage compartment of the control panel.
Display unit (optional). This unit displays readings, set points, and alarms. It is normally mounted in the amp chart enclosure for easy access. It provides all the basic functions, such
as underload, overload, phase imbalance, phase rotation, and many other parameters including password and communication protocols.
Single-phase and three-phase transformers
The type of transformer selected depends on the size of the primary power system and the required secondary voltage. Three-phase isolation stepup transformers are generally
selected for increasing voltage from a low-voltage system, while a bank of three identical single-phase transformers is usually selected for reducing a high-voltage primary power
source to the required surface voltage.
On existing systems, some ESP units operate without the use of an additional transformer. For new installation of units with higher voltages, it is usually less expensive to install three
single-phase transformers, connected wye, to eliminate the auto-transformer.
In choosing the size of a stepup transformer or a bank of three single-phase transformers, Eq. 15 is used to calculate the total kilowatts/volts/amps (KVA) required.
(/File:Vol4_page_0693_eq_001.png)....................(15)
Surface cable
Choose the approximate length required for connecting the controller to the primary power system or transformer. Two pieces are generally required for installations using an autotransformer. Size should equal the well cable size, except in the case of stepup or auto-transformer, where the primary and secondary currents are not the same.
Wellheads and accessories
Select the wellhead on the basis of casing size, tubing size, maximum recommended load, surface pressure, and maximum setting depth. Electric cable passes through the wellhead
where pressure fittings are not required.
Electric-feed-through (EFT) mandrels are also available. The electric cable is spliced to pigtails. The EFT wellheads seal against downhole pressure and prevent gas leaks at the
surface.
Servicing equipment
Cable reels, reel supports, and cable guides. Select the size of cable reel required to handle the previously selected cable size. Select a set of cable-reel supports on the basis of cablereel size. Cable guides are designed to handle cable sizes 1 through 6. Normally, customers retain one cable reel, one set of reel supports, and one cable guide wheel for future use.
Shipping cases. Select the type and length of the case required accommodating the previously selected motor, pump, gas separator, and seal.
Optional equipment
Bottomhole sensing device. The downhole sensor provides continuous measurement of parameters such as:
Wellbore pressures
Wellbore or ESP temperature
Discharge flow rates
Water contamination of the motor
Equipment vibration
Automatic well monitoring. Motor controllers are available for the continuous monitoring of pump operations from a central location.
Step 9: variable speed submersible pumping system
The ESP system can be modified to include a variable-frequency controller (/ESP_surface_motor_controllers) so that it operates over a broader range of capacity, head, and
efficiency. Most of the ESP manufacturers and several third parties have computerized pump-selection programs to assist in VSSP-system selection; what follows is a basic
explanation of the principles involved.
Variable frequency. The VSC is commonly used to generate any frequency between 30 and 90 Hz. Pump-performance curves for frequencies other than 60 Hz can be generated with
the affinity laws (Eqs. 2 through 4 in ESP centrifugal pumps (/ESP_centrifugal_pump)). The output rating of the motor is also affected by the operating frequency (Eq. 3 in ESP
motors (/ESP_motors)).
A set of curves can be developed for an arbitrary series of frequencies with these equations, as shown in the variable-frequency performance curves at the end of this step (Fig. 2).
Each curve represents a series of points derived from the 60-Hz curve for flow and corresponding head points, transformed using the previously mentioned equations.
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ESP system selection and performance calculations -
(/File:Vol4_Page_694_Image_0001.png)
Fig. 2-FC-1200 stage variable-speed performance
curve [after Centrilift Graphics, Claremore,
Oklahoma (2003)].
Suppose we are given the following data at a frequency of 60 Hz: rate = 1,200 B/D; head = 24.5 ft (from FC-1200 curve at 1,200 B/D); BHP = 0.34 BHP (from FC-1200 curve at
1,200 B/D). If a new frequency of 50 Hz is chosen, the data will be: new rate = (50/60) × 1,200 B/D = 1,000 B/D; new head = (50/60)2 × 24.5 ft = 17 ft; and new BHP = (50/60)3 ×
034 BHP = 0.20 BHP.
By performing these calculations at other production rates, a new curve for 50-Hz operation can be plotted. Start by locating the existing points on the one-stage 60-Hz curve:
Q1 rate, B/D: 0; 950; 1,200; 1550; and 1,875.
H1 head, ft: 32, 28.6, 24.5, 15, and 0.
Efficiency, %: 1, 63.5, 64, 49, and 0.
Following the previous equations, calculate the corresponding values at 50 Hz:
Q1 rate, B/D: 0; 792; 1,000; 1,292; and 1,563.
H1 head, ft: 22.2, 19.9, 17, 10.4, and 0.
Efficiency, %: 0, 63.5, 64, 49, and 0.
Plotting these coordinates gives the one-stage FC-1200 head-capacity performance curve an operation at 50 Hz. Similar calculations provide coordinates for curves at other
frequencies, as shown by the FC-1200 variable-speed performance curve (Fig. 2). The vortex-shaped window is the recommended operating range for the pump. As long as the
hydraulic requirement falls within this range, the pump is within the recommended operating range.
Nomenclature
Am
= motor amperage, amps
Bg
= gas volume factor, scf/bbl [m3/m3]
= oil volume factor, bbl/STBO
Bo
C
D
F
Ft
H
HL
Hwh
J
N
P
Pb
=
=
=
=
=
=
constant = 3,960, where Q is in gal/min, and TDH is in ft [= 6,750, where Q is in m3/D, and TDH is in m]
diameter, in. [cm]
correlating function for Eq. 7
well-tubing friction loss
head, ft [m]
net well lift
=
=
=
=
wellhead pressure head, ft [m]
slope
rotating speed, rev/min
pressure, psi [kg/cm2]
= bubblepoint pressure, psi [kg/cm2]
Pdischarge = pump-discharge pressure, psi [kg/cm2]
Pr
= well static pressure, psi [kg/cm2]
Pwf
= well flowing pressure, psi [kg/cm2]
Q
Qd
= flow rate, B/D [m3/d]
= estimated production rate
Qo
= maximum production at Pwf = 0, B/D [m3/D]
= solution gas/oil ratio, scf/bbl [m3/m3]
T
= torque, ft-lbf
Tconductor = wellbore temperature at the ESP setting depth
TC
= temperature, °C
TF
= temperature, °F
Rs
TG
= total volume of gas
TK
= temperature, K
TR
V
= temperature, °R
= voltage, volts
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= volume of free gas
Vg
= volume of gas
VIG
= volume of free gas at the pump intake
Vo
= volume of oil, bbl [m3]
Vs
= surface voltage, volts
VSG
= solution gas volume
Vt
= total volume
Vw
= volume of water
Z
ηm
= gas-compressibility factor (typically 0.50 to 1.00)
ηp
= pump efficiency
ESP system selection and performance calculations -
= motor efficiency
References
1. ↑ The Nine Step. 1999. 1-27. Claremore, Oklahoma: Centrilift.
2. ↑ Gilbert, W.E. 1954. Flowing and Gas Lift Well Performance. API Drilling and Production Practice, 143. Washington, DC: API.
3. ↑ Vogel, J.V. 1968. Inflow Performance Relationships for Solution-Gas Drive Wells. J Pet Technol 20 (1): 83–92. SPE 1476-PA. http://dx.doi.org/10.2118/1476-PA
(http://dx.doi.org/10.2118/1476-PA)
4. ↑ 4.0 4.1 Electrical Submersible Pumps and Equipment. 2001. 11. Claremore, Oklahoma: Centrilift.
5. ↑ Vandevier, J. E. 1987. Optimum Power Cable Sizing for Electric Submersible Pumps. Paper SPE 16195 presented at the Production Operations Symposium held in Oklahoma
City, March 8-10.
6. ↑ French, S. W. 1991: Optimum Cable Selection of Electrical Submersible Pumps. Paper SPE 21693 presented at the Production Operations Symposium held in Oklahoma
City, April 7-9.
Noteworthy papers in OnePetro
Takacs, G. (2011): How to Improve Poor System Efficiencies of ESP Installations Controlled by Surface Chokes. Journal of Petroleum Exploration and Production Technologies: Vol.
1, Issue 2, p 89-97. DOI 10.1007/s13202-011-0011-9
Clegg, J. D., Bucaram, S. M., & Hein, N. W. (1993, December 1). Recommendations and Comparisons for Selecting Artificial-Lift Methods(includes associated papers 28645 and
29092 ). Society of Petroleum Engineers. doi:10.2118/24834-PA
Lea, J. F., & Nickens, H. V. (1999, January 1). Selection of Artificial Lift. Society of Petroleum Engineers. doi:10.2118/52157-MS
Lee, H. K. (1988, January 1). Computer Modeling and Optimization for Submersible Pump Lifted Wells. Society of Petroleum Engineers. doi:10.2118/17586-MS
Romer, M. C., Johnson, M. E., Underwood, P. C., Albers, A. L., & Bacon, R. (2012, January 1). Offshore ESP Selection Criteria: An Industry Study. Society of Petroleum Engineers.
doi:10.2118/146652-MS
Noteworthy books
Takács G. (2009): Electrical submersible pumps manual. ISBN 978-1-85617-557-9 (/Special:BookSources/9781856175579). Gulf Professional Publishing, An Imprint of Elsevier,
440p.
External links
Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro
See also
ESP design (/ESP_design)
Electrical submersible pumps (/Electrical_submersible_pumps)
Alternate ESP configurations (/Alternate_ESP_configurations)
Use of ESPs in harsh environments (/Use_of_ESPs_in_harsh_environments)
PEH:Electrical_Submersible_Pumps (/PEH:Electrical_Submersible_Pumps)
Page champions
Jose Caridad (https://www.linkedin.com/in/jose-caridad-49080265), BSME & MSc ME
Category
Categories (/Special:Categories): 3.1.2 Electric submersible pumps (/Category:3.1.2_Electric_submersible_pumps) YR (/Category:YR)
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