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Electric Submersible Pumps
D. R. Davies
Institute of Petroleum Engineering, Heriot-Watt University
Revised 2010
HWU MSc. PT - David Davies
Lecture Objectives • • • • •
At the end of the lecture, you should be able to: Identify the components of an Electric Submersible Pump (ESP). Describe the preferred applications and the mode of operation of the ESP. Select well conditions suitable for ESP installation as preferred Artificial Lift option. Evaluate the advantages of an instrumented ESP completion. Make an initial ESP Completion Design
Revised 2010
HWU MSc. PT - David Davies
Electrical Submersible Pump (ESP) A downhole centrifugal pump which lifts the produced fluids to the surface. • Subsurface equipment – Electric motor, Downhole Sensors, Protector or seal, Gas separator, Pump, Cable • Surface equipment – Junction box, Switchboard or Variable speed controller, Pump Monitoring Instruments, Transformers Revised 2010
HWU MSc. PT - David Davies
-High Voltage electricity supply - VFD: soft start & speed control - Vent box - Wellhead penetrator - Cable - Pump unit {many (10-100) rotating centrifugal impellers with stationary diffusers driven by shaft } - Pump intake - Protector/Seal (barrier, motor oil expansion, thrust absorber) - Electric Motor - Sensors (signal via cable) Revised 2010
HWU MSc. PT - David Davies
General Characteristics of ESPs • Can be designed to pump at very high flow rates (up to 100,000 BPD) & high pressure boost (up to 6,000 psi) • Often more efficient than other AL techniques • Relatively expensive • Sensitive to solids and free gas • ESPs can run several years with favorable conditions • ESP repair almost always requires a Heavy Workover Revised 2010
HWU MSc. PT - David Davies
Revised 2010
HWU MSc. PT - David Davies
Revised 2010
HWU MSc. PT - David Davies
Electric Submersible Pumps Applications • ESPs can be installed in deviated wells at angles up to 80o
Revised 2010
HWU MSc. PT - David Davies
Electric Submersible Pumps Applied to Injection Wells HWU MSc. PT - David Davies
Revised 2010
ESP Motors • Generally 3 phase and 2 pole motors. • Consists of two main parts: the Rotor and Stator. • Pump performance is dependent on the frequency of the electrical power. – The higher frequency the better the performance – Designed to run at 60 Hz in USA & 50 Hz elsewhere – may run at other frequencies (VFD). • Requires sufficient cooling from fluid flow past the motor to operate properly. • Size ranges from 20 Hp to 1200 Hp Revised 2010
HWU MSc. PT - David Davies
ESP Motor Problems
• • • • •
Major causes of motor overheating & pump failure Overloading Well pumped off Gas locked Stuck pump Lack of cooling – Tubing or casing leak, scale, motor laying against the casing HWU MSc. PT - David Davies
Revised 2010
Motor Protector or Seal • An important ESP downhole component (often overlooked) • Provides pressure equalization system for the motor. • Provides seal system to protect the motor winding from the well fluids • Absorbs a significant portion of the up- & down-thrust force. • Two basic equipment designs: – Labyrinth Labyrinth: not suited to highly deviated wells or when motor oil is denser than borehole fluid. – Bag Bag: not suited to environments which are aggressive to rubber. Revised 2010
HWU MSc. PT - David Davies
Centrifugal Pump • Multiple stages • Each stage consists of an impeller and a diffuser • Impeller provides kinetic energy by throwing fluid to the edge of the impeller • Diffuser changes kinetic energy into potential energy (pressure) by reducing the fluid velocity HWU MSc. PT - David Davies
Revised 2010
Pump Unit
Revised 2010
HWU MSc. PT - David Davies
Gas Handling • Efficiency of standard ESP centrifugal impeller reduces when gas fraction > 20% • Mixed flow impellers can handle up to 40% vol. gas • Greater Gas / Liquid ratios require rotary gas separator or gas anchor (shroud) • Vented casing required HWU MSc. PT - David Davies
Revised 2010
Junction Box • Vents gas that diffuses out of well via the cable • Prevents the gas from diffusing through cable and creating an explosion hazard in the switchboard
Motor Controller • • • • • • •
Starts and stops the motor Provides current recording (amp chart) Downhole sensor readout possible Enables remote monitoring and control Provides under and overload protection Automatic shutdown following pump-off or gas-lock Provision for automatic restart possible
Revised 2010
HWU MSc. PT - David Davies
Check and Drain Valves • Check valve is installed to: – prevent back spin – reduce the volume of debris falling through pump – reduce pump out time • Drain valve: – avoids pulling wet string – enables well killing by circulation HWU MSc. PT - David Davies
Revised 2010
• Measurements include: – – – –
Sensor Package
Fluid intake & motor temperature Pump suction / discharge pressures & temperatures Vibration Current leakage
• Provides data on pump / motor operating conditions • Prevents dangerous motor conditions e.g. well pumped off & attempt motor restart under backspin conditions due to unloading of fluid in string • Data triggers alarms - analysed at wellsite or main office • Provides continuous FBHP measurements - data transmitted to the surface via the power cable • Well test analysis after each pump shut down HWU MSc. PT - David Davies Revised 2010
The “Y” Tool
gives access below the ESP
Bypass (Y-Tube) Applications: • Well stimulation • Cased hole logging & perforating • Setting bridge plugs (water shut off) • Setting/recovering downhole memory gauges • Revised Running and retrieval bridge plugs, downhole sampling HWU MSc. PT -etc. David Davies 2010
Basic Pump Selection • Max. Pump pressure is 6,000 psi • Total Dynamic Head equals:
Revised 2010
+ Fluid Hydrostatic head from ESP to the surface is product of: - (average) fluid density (ρ) - ESP vertical depth (TVD) - acceleration due to gravity (g) + Friction loss in the tubing (Pfth) + The surface pressure (Psurf) required to overcome flowline back pressure (may be a high value e.g. satellite wells 50 miles from the host platform) HWU MSc. PT - David Davies
Pump Performance • The “pump head”, or increase in pressure per stage (∆P), is expressed in terms of the pressure generated by an equivalent column of water (h). ∆P = ρ*g*h N.B. This needs correction for any changes in viscosity • Pump power = pump rate * the generated pump head or Mechanical Power = work done / time = q*∆P • Converted to required electric motor power via pump efficiency (E) E = hydraulic power / mechanical Power • Operate Pump operation within 10% of max. efficiency Revised 2010
HWU MSc. PT - David Davies
Pump Performance Chart
• ESP is a dynamic pump: – pump rate is high for low pressure head generation – pump rate is low for high pressure head generation Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (1) • The pipe friction loss (∆Pf) is given by: 2 L ν ∆pf = ( f )( ρf ) d 2g
where f is the friction factor, v is the fluid velocity and g the acceleration due to gravity {32.173 (ft/s2) (lbm/lbf)} • v is calculated from the pipe dimensions while the friction factor is found from the Moody Diagram • ∆Pd =Pm +∆Pf +∆PHH is the pump discharge pressure where Pm is the safety margin • Pump intake pressure = Pin = FBHP = Pres - Q/PI Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (2)
• Pump performance chart shows head per stage (H) and Power {Kilowatt} or brake horsepower per stage (BHP) {where 1 BHP = 0.746 KW} • Check robustness of design against a wide range of (possible) future operating conditions Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (3) • Pump performance chart is at 2,915 rpm & 50 Hz 2
pump rate (2) pump speed (2) = pump rate (1) pump speed (1)
,
hydrostatichead(2) pumpspeed(2) = hydrostatichead(1) pumpspeed(1) 3
&
motor power (2) pump speed (2) = motor power (1) pump speed (1)
• Variable Frequency Drive alters electricity frequency Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (4)
• Select optimum seal section & cable • Reliable ESP operation requires correct ESP design • Reliability or “Mean time before failure” increases with of failed equipment HWU MSc. PT - David Davies Revised evaluation 2010
Ammeter Chart normal operation Chart shows: • Motor starts with initial current surge • Steady operation thereafter Revised 2010
HWU MSc. PT - David Davies
Monitoring ESP Operation – the ammeter Chart shows: • Motor starts with initial current surge as it “speeds up” • Current demand begins to oscillate after period of steady production as well “pumped-off” • Pump shuts down • Cycle repeated after well shut-in to allow fluid level to build up Revised 2010
HWU MSc. PT - David Davies
Modern ESP Motor & Pump Condition Monitoring
Chart shows: • Pump discharge pressure increase & suction decrease • Discharge pressure oscillates while surface choke adjusted • Motor vibration follows same pattern • Motor temperature increases HWU MSc. PT - David Davies Revised 2010
New Technology
Coiled Tubing Deployed ESP
• Cable on outside (conventional) of Coiled Tubing • 2010Coiled Tubing allows rapid replacement of HWUfailed MSc. PT - ESP David Davies Revised
New Technology Coiled Tubing Deployed ESP • Cable can also be installed on inside of CT – simpler & faster installation – can be installed in live well
Revised 2010
HWU MSc. PT - David Davies
New Technology - Auto “Y” Tool
Revised 2010
HWU MSc. PT - David Davies
New Technology Dual Zones & Dual Pumps • Upper & lower zones produced simultaneously & independently via own ESP • Completion configurations • tubing/annulus • concentric completion • dual tubing HWU MSc. PT - David Davies
Revised 2010
New Technology Dual Pump • Second pump increases maximum installed pump power • For wells with limited access e.g. high cost, offshore operations – lower ESP replaces Upper ESP upon failure – auto “Y”tool operation allows transfer between ESPs without workover Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (1) Well conditions
HWU MSc. PT - David Davies
Revised 2010
Example ESP Design (2) Pipe Friction at the planned rate
2 L ν ∆pf = ( f )( ρ f ) d 2g
F = 0.03 2 7000 3.28 ∆Pf = ( 0.03)( 0.433) = 81psi 0.188 2.32.173
Total pressure required above pump
∆Pd =Pm +∆Pf +∆PHH
∆Pd = 50 + 81 + (0.433 psi/ft) (7000 ft) = 3162 psi Flowing Bottom Hole Pressure PIn = PR - Q/PI = 1700 - 1400/2 = 1000psi Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (3)
HWU MSc. PT - David Davies
Revised 2010
Example ESP Design (3)
• Head per stage at 1400 b/d is 58 ft Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (3)
• Head per stage at 1400 b/d is 58 ft • Power per stage at 1400 b/d is 0.52 BHP HWU MSc. PT - David Davies
Revised 2010
Example ESP Design (4) Number of pump stages (N) required & motor power @ 2,915 rpm
N=
( psi ) ( 3162-1000 ) Pd -PIn = = 86stages H ( ft ) *0.433 ( psi/ft ) 58*0.433
• HHP = 86 (stages)*0.52 (BHP/stage)*(γf) = 45 HHP {no correction for fluid density (γf) is required} • The pump electric motor may now be chosen. • Allow for power loses in the motor & oversize to increase run life • Choosing a pump speed other than 2,915 rpm introduces extra complications Pump rate of an ESP is proportional to the speed Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (5) • Pump performance chart is at 2915 rpm & 50 Hz pump rate (2) pump speed (2) = pump rate (1) pump speed (1)
,
hydrostatic head (2) pump speed (2) = hydrostatic head (1) pump speed (1)
2
3
&
motor power (2) pump speed (2) = motor power (1) pump speed (1)
• VFD drives alter electricity frequency Revised 2010
Nodal Analysis relates pump intake curve & well PI
HWU MSc. PT - David Davies
Example ESP Design (6)
• PI = 2 b/d/psi What is effect Well b/d PI? Q of = 1400 – Fluid level is 1000psi or 2310 ft above the pump
• Q = 1190 b/d if PI = 1 b/d/psi • Well is “pumped off” if PI = 0.5 b/d Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (6) • Well “pumping-
off will damage pump very quickly • Cable selection depends on: – Power required – Voltage, – Max Temp. – Etc.
• See API RP 1154 Revised 2010
HWU MSc. PT - David Davies
Lecture Summary • • • • •
During this lecture we have: Identified the components of an Electric Submersible Pump (ESP). Described the preferred applications and the mode of operation of the ESP. Selected well conditions suitable for ESP installation as preferred Artificial Lift option. Identified the application areas where an ESP is NOT suitable. Evaluated the advantages of an instrumented ESP completion.
Revised 2010
HWU MSc. PT - David Davies
D. R. Davies
Institute of Petroleum Engineering, Heriot-Watt University
Revised 2010
HWU MSc. PT - David Davies
Lecture Objectives • • • • •
At the end of the lecture, you should be able to: Identify the components of an Electric Submersible Pump (ESP). Describe the preferred applications and the mode of operation of the ESP. Select well conditions suitable for ESP installation as preferred Artificial Lift option. Evaluate the advantages of an instrumented ESP completion. Make an initial ESP Completion Design
Revised 2010
HWU MSc. PT - David Davies
Electrical Submersible Pump (ESP) A downhole centrifugal pump which lifts the produced fluids to the surface. • Subsurface equipment – Electric motor, Downhole Sensors, Protector or seal, Gas separator, Pump, Cable • Surface equipment – Junction box, Switchboard or Variable speed controller, Pump Monitoring Instruments, Transformers Revised 2010
HWU MSc. PT - David Davies
-High Voltage electricity supply - VFD: soft start & speed control - Vent box - Wellhead penetrator - Cable - Pump unit {many (10-100) rotating centrifugal impellers with stationary diffusers driven by shaft } - Pump intake - Protector/Seal (barrier, motor oil expansion, thrust absorber) - Electric Motor - Sensors (signal via cable) Revised 2010
HWU MSc. PT - David Davies
General Characteristics of ESPs • Can be designed to pump at very high flow rates (up to 100,000 BPD) & high pressure boost (up to 6,000 psi) • Often more efficient than other AL techniques • Relatively expensive • Sensitive to solids and free gas • ESPs can run several years with favorable conditions • ESP repair almost always requires a Heavy Workover Revised 2010
HWU MSc. PT - David Davies
Revised 2010
HWU MSc. PT - David Davies
Revised 2010
HWU MSc. PT - David Davies
Electric Submersible Pumps Applications • ESPs can be installed in deviated wells at angles up to 80o
Revised 2010
HWU MSc. PT - David Davies
Electric Submersible Pumps Applied to Injection Wells HWU MSc. PT - David Davies
Revised 2010
ESP Motors • Generally 3 phase and 2 pole motors. • Consists of two main parts: the Rotor and Stator. • Pump performance is dependent on the frequency of the electrical power. – The higher frequency the better the performance – Designed to run at 60 Hz in USA & 50 Hz elsewhere – may run at other frequencies (VFD). • Requires sufficient cooling from fluid flow past the motor to operate properly. • Size ranges from 20 Hp to 1200 Hp Revised 2010
HWU MSc. PT - David Davies
ESP Motor Problems
• • • • •
Major causes of motor overheating & pump failure Overloading Well pumped off Gas locked Stuck pump Lack of cooling – Tubing or casing leak, scale, motor laying against the casing HWU MSc. PT - David Davies
Revised 2010
Motor Protector or Seal • An important ESP downhole component (often overlooked) • Provides pressure equalization system for the motor. • Provides seal system to protect the motor winding from the well fluids • Absorbs a significant portion of the up- & down-thrust force. • Two basic equipment designs: – Labyrinth Labyrinth: not suited to highly deviated wells or when motor oil is denser than borehole fluid. – Bag Bag: not suited to environments which are aggressive to rubber. Revised 2010
HWU MSc. PT - David Davies
Centrifugal Pump • Multiple stages • Each stage consists of an impeller and a diffuser • Impeller provides kinetic energy by throwing fluid to the edge of the impeller • Diffuser changes kinetic energy into potential energy (pressure) by reducing the fluid velocity HWU MSc. PT - David Davies
Revised 2010
Pump Unit
Revised 2010
HWU MSc. PT - David Davies
Gas Handling • Efficiency of standard ESP centrifugal impeller reduces when gas fraction > 20% • Mixed flow impellers can handle up to 40% vol. gas • Greater Gas / Liquid ratios require rotary gas separator or gas anchor (shroud) • Vented casing required HWU MSc. PT - David Davies
Revised 2010
Junction Box • Vents gas that diffuses out of well via the cable • Prevents the gas from diffusing through cable and creating an explosion hazard in the switchboard
Motor Controller • • • • • • •
Starts and stops the motor Provides current recording (amp chart) Downhole sensor readout possible Enables remote monitoring and control Provides under and overload protection Automatic shutdown following pump-off or gas-lock Provision for automatic restart possible
Revised 2010
HWU MSc. PT - David Davies
Check and Drain Valves • Check valve is installed to: – prevent back spin – reduce the volume of debris falling through pump – reduce pump out time • Drain valve: – avoids pulling wet string – enables well killing by circulation HWU MSc. PT - David Davies
Revised 2010
• Measurements include: – – – –
Sensor Package
Fluid intake & motor temperature Pump suction / discharge pressures & temperatures Vibration Current leakage
• Provides data on pump / motor operating conditions • Prevents dangerous motor conditions e.g. well pumped off & attempt motor restart under backspin conditions due to unloading of fluid in string • Data triggers alarms - analysed at wellsite or main office • Provides continuous FBHP measurements - data transmitted to the surface via the power cable • Well test analysis after each pump shut down HWU MSc. PT - David Davies Revised 2010
The “Y” Tool
gives access below the ESP
Bypass (Y-Tube) Applications: • Well stimulation • Cased hole logging & perforating • Setting bridge plugs (water shut off) • Setting/recovering downhole memory gauges • Revised Running and retrieval bridge plugs, downhole sampling HWU MSc. PT -etc. David Davies 2010
Basic Pump Selection • Max. Pump pressure is 6,000 psi • Total Dynamic Head equals:
Revised 2010
+ Fluid Hydrostatic head from ESP to the surface is product of: - (average) fluid density (ρ) - ESP vertical depth (TVD) - acceleration due to gravity (g) + Friction loss in the tubing (Pfth) + The surface pressure (Psurf) required to overcome flowline back pressure (may be a high value e.g. satellite wells 50 miles from the host platform) HWU MSc. PT - David Davies
Pump Performance • The “pump head”, or increase in pressure per stage (∆P), is expressed in terms of the pressure generated by an equivalent column of water (h). ∆P = ρ*g*h N.B. This needs correction for any changes in viscosity • Pump power = pump rate * the generated pump head or Mechanical Power = work done / time = q*∆P • Converted to required electric motor power via pump efficiency (E) E = hydraulic power / mechanical Power • Operate Pump operation within 10% of max. efficiency Revised 2010
HWU MSc. PT - David Davies
Pump Performance Chart
• ESP is a dynamic pump: – pump rate is high for low pressure head generation – pump rate is low for high pressure head generation Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (1) • The pipe friction loss (∆Pf) is given by: 2 L ν ∆pf = ( f )( ρf ) d 2g
where f is the friction factor, v is the fluid velocity and g the acceleration due to gravity {32.173 (ft/s2) (lbm/lbf)} • v is calculated from the pipe dimensions while the friction factor is found from the Moody Diagram • ∆Pd =Pm +∆Pf +∆PHH is the pump discharge pressure where Pm is the safety margin • Pump intake pressure = Pin = FBHP = Pres - Q/PI Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (2)
• Pump performance chart shows head per stage (H) and Power {Kilowatt} or brake horsepower per stage (BHP) {where 1 BHP = 0.746 KW} • Check robustness of design against a wide range of (possible) future operating conditions Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (3) • Pump performance chart is at 2,915 rpm & 50 Hz 2
pump rate (2) pump speed (2) = pump rate (1) pump speed (1)
,
hydrostatichead(2) pumpspeed(2) = hydrostatichead(1) pumpspeed(1) 3
&
motor power (2) pump speed (2) = motor power (1) pump speed (1)
• Variable Frequency Drive alters electricity frequency Revised 2010
HWU MSc. PT - David Davies
Simplified Pump Design (4)
• Select optimum seal section & cable • Reliable ESP operation requires correct ESP design • Reliability or “Mean time before failure” increases with of failed equipment HWU MSc. PT - David Davies Revised evaluation 2010
Ammeter Chart normal operation Chart shows: • Motor starts with initial current surge • Steady operation thereafter Revised 2010
HWU MSc. PT - David Davies
Monitoring ESP Operation – the ammeter Chart shows: • Motor starts with initial current surge as it “speeds up” • Current demand begins to oscillate after period of steady production as well “pumped-off” • Pump shuts down • Cycle repeated after well shut-in to allow fluid level to build up Revised 2010
HWU MSc. PT - David Davies
Modern ESP Motor & Pump Condition Monitoring
Chart shows: • Pump discharge pressure increase & suction decrease • Discharge pressure oscillates while surface choke adjusted • Motor vibration follows same pattern • Motor temperature increases HWU MSc. PT - David Davies Revised 2010
New Technology
Coiled Tubing Deployed ESP
• Cable on outside (conventional) of Coiled Tubing • 2010Coiled Tubing allows rapid replacement of HWUfailed MSc. PT - ESP David Davies Revised
New Technology Coiled Tubing Deployed ESP • Cable can also be installed on inside of CT – simpler & faster installation – can be installed in live well
Revised 2010
HWU MSc. PT - David Davies
New Technology - Auto “Y” Tool
Revised 2010
HWU MSc. PT - David Davies
New Technology Dual Zones & Dual Pumps • Upper & lower zones produced simultaneously & independently via own ESP • Completion configurations • tubing/annulus • concentric completion • dual tubing HWU MSc. PT - David Davies
Revised 2010
New Technology Dual Pump • Second pump increases maximum installed pump power • For wells with limited access e.g. high cost, offshore operations – lower ESP replaces Upper ESP upon failure – auto “Y”tool operation allows transfer between ESPs without workover Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (1) Well conditions
HWU MSc. PT - David Davies
Revised 2010
Example ESP Design (2) Pipe Friction at the planned rate
2 L ν ∆pf = ( f )( ρ f ) d 2g
F = 0.03 2 7000 3.28 ∆Pf = ( 0.03)( 0.433) = 81psi 0.188 2.32.173
Total pressure required above pump
∆Pd =Pm +∆Pf +∆PHH
∆Pd = 50 + 81 + (0.433 psi/ft) (7000 ft) = 3162 psi Flowing Bottom Hole Pressure PIn = PR - Q/PI = 1700 - 1400/2 = 1000psi Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (3)
HWU MSc. PT - David Davies
Revised 2010
Example ESP Design (3)
• Head per stage at 1400 b/d is 58 ft Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (3)
• Head per stage at 1400 b/d is 58 ft • Power per stage at 1400 b/d is 0.52 BHP HWU MSc. PT - David Davies
Revised 2010
Example ESP Design (4) Number of pump stages (N) required & motor power @ 2,915 rpm
N=
( psi ) ( 3162-1000 ) Pd -PIn = = 86stages H ( ft ) *0.433 ( psi/ft ) 58*0.433
• HHP = 86 (stages)*0.52 (BHP/stage)*(γf) = 45 HHP {no correction for fluid density (γf) is required} • The pump electric motor may now be chosen. • Allow for power loses in the motor & oversize to increase run life • Choosing a pump speed other than 2,915 rpm introduces extra complications Pump rate of an ESP is proportional to the speed Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (5) • Pump performance chart is at 2915 rpm & 50 Hz pump rate (2) pump speed (2) = pump rate (1) pump speed (1)
,
hydrostatic head (2) pump speed (2) = hydrostatic head (1) pump speed (1)
2
3
&
motor power (2) pump speed (2) = motor power (1) pump speed (1)
• VFD drives alter electricity frequency Revised 2010
Nodal Analysis relates pump intake curve & well PI
HWU MSc. PT - David Davies
Example ESP Design (6)
• PI = 2 b/d/psi What is effect Well b/d PI? Q of = 1400 – Fluid level is 1000psi or 2310 ft above the pump
• Q = 1190 b/d if PI = 1 b/d/psi • Well is “pumped off” if PI = 0.5 b/d Revised 2010
HWU MSc. PT - David Davies
Example ESP Design (6) • Well “pumping-
off will damage pump very quickly • Cable selection depends on: – Power required – Voltage, – Max Temp. – Etc.
• See API RP 1154 Revised 2010
HWU MSc. PT - David Davies
Lecture Summary • • • • •
During this lecture we have: Identified the components of an Electric Submersible Pump (ESP). Described the preferred applications and the mode of operation of the ESP. Selected well conditions suitable for ESP installation as preferred Artificial Lift option. Identified the application areas where an ESP is NOT suitable. Evaluated the advantages of an instrumented ESP completion.
Revised 2010
HWU MSc. PT - David Davies
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