ESP – Electric Submersible Pumps

ESP – Electric Submersible Pumps

• Candidates

• Sizing

• Application

• Operation

• Special Uses

8/25/2015 1 George E. King Engineering

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ESP Well Candidates

• Can be run vertically to fully horizontal

• Capable of moving fluid volumes of 20,000 BPD+

• Cannot handle large amounts of gas and solids.

• Must be landed in a straight section of the wellbore.


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Electrical Submersible Pumps ESPs

• ESPs are best used moving large volumes (>500 stb/d) of low GLR fluid (<100 scf/stb). They perform best when within +/- 25% of design rate.

• ESPs are particularly attractive for water supply wells, high water-cut producers and high deliverability, under-saturated oil wells.

• ESPs have moderate run life performance that can be significantly increase by instrumenting with temperature sensors that trip the pump power supply when cooling ability (flow) drops.

• Variable frequency drives (VFD) and/or wellhead chokes can be

used to increase the range of pumping rates (50 to 190% of

optimum), but increase capital and operating costs.


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ESPs

• A submersible pump is a multi-staged centrifugal pump

connected by a short shaft to a downhole electric or

hydraulic motor.

• Each stage consists of a rotating impeller and stationary

diffuser.


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ESPs

• Each impeller and diffuser stage is about 3 to 5 in long, and there may be 50 to 500 stages in a pump.

• The ESP is a dynamic displacement pump in which the differential pressure or total dynamic head (TDH) developed by the pump is a function of pump flow rate.

• TDH is approximately the sum of the head developed by each stage, which can be obtained from the manufacturers published test data.

TDH = Ns Hs

where: Ns = number of stages

Hs = head per stage


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ESP Performance

• ESP pump characteristics are based on a constant

rotation speed, which depends on the frequency of the

AC supply:

– 3500 RPM with 60 Hertz

– 2915 RPM with 50 Hertz

• Because of high rotation speeds, sand production and

emulsions must be controlled.

• Field application of ESPs in silt producing areas (North

Africa) have been made, but start-up/shut-down cycles

had to be minimized.

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ESP Delivery Capacity

• Variables:

– Well IPR characteristics. Constant flow for cooling is essential.

– Reservoir pressure. Impacts both flow rate & gas breakout.

– Surface back-pressure. – Controls free gas at the pump.

– Electrical supply frequency –variations are a problem (lightning strikes, power stability, etc.)

– Pump size – larger pumps are more efficient, cheaper to buyt and cheaper to operate.

– Produced fluid viscosity – high viscosity decreases efficiency


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Gas Effect on an ESP

• Gas may create a gas lock condition - or insufficient fluid movement to cool the pump.

• An ESP installation should be designed to allow downhole separation of any free gas before entering the pump inlet.

• The gas is vented up the annulus in most cases. This is particularly important when the downhole gas volume exceeds 10% of the total fluid volume.

• Gas busters, downhole separators, set points below the perfs and oversized initial stages have been used to control excess gas.


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ESP Failures - Heat

• The conversion of electrical current to mechanical

energy produces significant heat.

• The produced fluids must dissipate the heat from the

pump or failures will occur. Since the downhole fluids

are often already hot, flow rate must be high to transfer

maximum heat (velocity > 1 ft/sec)

• If the pump must be set below the perfs or in large

casing (low flow velocity), a shroud is often used to

increase velocity and cool the motor.


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ESP Considerations

• A minimum BHFP of 100 to 200 psi is normally recommended to prevent cavitation or gas locking.

• A large number of restarts (50 to 200) significantly reduces run life.

• ESP cables must be supported by banding to the tubing and protected at the couplings and other pinch points.


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ESP – Short Run Life Causes

1. Poor handling procedures – cable breaks.

2. Inadequate flow for cooling

3. Inadequate cable insulation for the operating environment.

4. Pumping significant quantities (>10%) of free gas

5. Sand production or corrosion.

6. Frequent restarts without a soft start controller or VSD.

7. Scale formation on the pump impellers.

8. Omission of the viscosity considerations

9. Unstable supply voltage.

10. Not landing pump in a straight wellbore section.


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Artificial Lift Comparative Efficiencies

12

18

3840

52

0

10

20

30

40

50

60

Intermittent GL

Continuous GL

ESP

Hydraulic Lift

Beam Lift


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Brief Design Points for ESPs

• ESP design is a system approach:

– Tubing too small – high erosion/friction

– Tubing too large – gas slips through fluids

• Pump sizing software does not account for liquid hold-up and in extreme case a pump might be required to support a near full column of water in a dry well – pump would be understaged, operate in severe downthrust and suffer motor cooling problems.

BP ESP Best Practices Operating Guidelines - 2004 8/25/2015 13 George E. King Engineering

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Brief Design Points for ESPs

• Motors that are not matched to surface electrical systems:

– May be limited in current or voltage.

– May not be able to tune the frequency of the pump to changing reservoir conditions.


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General Design Considerations ESP Pumps

• In general, the larger the diameter of the pump, the more efficient it will be. Consult performance curve of pump.

• Highly efficient pumps may have poor performance outside a narrow recommended operating range.

• If in doubt on well flow capacity, slightly undersize pump and choke well into the operating range of pump. – Cooling reliability increased

– Thrust loading control


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General Design Considerations ESP Motors

• In general, the larger the diameter of the motor, the more efficient it will be.

• For larger diameters, motors will be shorter. Less easily damaged.

• Motor winding insulation degrades at rate proportional to its operating temperature. Operating motors at less than 100% full current load factors reduces operating temp and increase motor life.

• If workover costs are high, it is generally cost effective to over specify the motor


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Types of ESP Cable


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ESP cable pass through capability in a roller centralizer


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ESPs in High GOR Wells

• Gas separators/handlers (also called gas busters and diffusers) deployed individually or in series

• Annular venting possible in packerless completions. Reduces free gas at intake.


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ESPs in High GOR Wells

• Mixed flow stage designs are less susceptible to gas locking than equivalent radial stages.

• Should be sized to operate at total fluid flow rates (liquid and gas) at upper end of the recommended flow range.

– Maximizes natural gas lift and reduces hydrostatic head (backpressure) on pump.


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ESPs in Solids Producing Wells

• Mixed flow stages preferred.

• Abrasion resistant pump bushings and impeller coatings.

• Plugging and sticking of pump may be severe.

• Avoid shut-downs.


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Artificial LIft ESP Power Distribution

Pump

37.0%Motor

15.0%

Surface

1.5%

Cable

7.0%

Output

38.5%

Pump

Motor

Surface

Cable

Output


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ESP - Gas Solutions

• gas diffusers

• gas separators

• dip tubes

• set below the lateral


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ESP

• Problems

– depth limited

– power requirements

– cable clearance

– large casing required (large pump sizes)

– doesn’t handle gas or solids well


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ESP – Initial Design

1. Chose Production Rate (well PI, reservoir pressure and bubble point)

2. Determine bottom hole flowing pressure (bhfp) at perfs.

3. Set pump depth so that pressure at pump intake is at limit of free gas handling capacity of the pump.


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4. Check head requirement of the pump.

• Chose stage count and frequency so that pump operates at its best efficiency point.

• Frequency should be as close as possible to 60 hz to get max power from the motor.

Below 650 hz: power = rated hp x (running frequency / 60)

Above 60 hz, motor current is derated to reduce heating


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5. Check expected motor loading – if load is too high, the initial production rate is too high

and should be decreased slightly.

– If load is too low, there is potential to increase the designed flow rate

– If the flowrate takes the flowing pressure below the bubble point pressure, then a smaller motor is possible.

6. Iterate the design. • If rate is decreased, the bhfp will increase and the pump

can be raised in the well to keep the same intake pressure (if needed to optimize flow).


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ESP – Final Design

1. Pump operating at free gas limit

2. The motor is fully loaded

3. Pump flowrate is as close as possible to BEP

4. Motor is close to 60 hz

5. Cable heat, volts drop, motor shaft torque, pump shaft torque, and pump housing pressure differential are OK.

6. Pump position is not across doglegs.


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Cable Protection - Cable run on the outside of tubing

• Use clamp-on cross-coupling protectors. If bands are used, band 4 ft above and below coupling.

• Avoid use of most types of mid joint clamps for the majority of applications – they can turn and slide, damaging ESP cables.

• Use extra care in any banding to fasten the ESP cable to the tubing. Clamps are preferred to banding because of problems leaving broken banding materials in the well.


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Cable Protection - Cable run on the outside of tubing

• COUNT – count and record the number of bands and clamps as the ESP is run. Count them as they come out so you have an idea of what is remaining in the hole.


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ESP Startup Procedures

1. If a restart, correct what caused trip.

2. Allow time for pressure across pump to equalize. Backflowing fluid will cause the pump to backspin,


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BP Global ESP summary

ESP Global active/inactive summary

0

50

100

150

200

250

300

Gupco Forties China DZO VEN Wytch Farm Indonesia Milne point PAE

Active Esp

Inactive Esp

Production Gross(mboed)

Asset Active Esp Inactive Esp Total ESP Production Gross(mboed) Production Net(mboed)

Forties 9 12 21 9.6 9.312

DZO VEN 34 3 37 18 18

Gupco 6 0 6 5 2.38

China 20 3 23 14 3.43

Indonesia 16 102 118 2.9 1.334

PAE 291 0 291 11.4 6.84

Wytch Farm 36 5 41 55 37.2955

Milne point 110 12 122 45 45

Sidanco 700 1800 2500 50 12.5

Total 1222 1937 3159 210.9 136.0915

•Some areas have low oil but high gross fluids(water)e.g PAE 386mbpf/d

•Some areas rely on ESP’s as water source wells (China/Gupco/Harding)


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ESP Sealing Options

• Labyrinth Seals

– Avoid in high angle wells.

• Bag seals

– Avoid in vertical wells, especially if the well fluids will react with the seals.

• Tandem Seals

– Increased reliability. Friction increased?


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Special Case – Coiled Tubing Deployed ESP - Qatar Example

• Arco Field (Al Rayyan)– Schlumberger Service


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8/25/2015

Qatar Example: Reservoir Fluid Properties

• Oil Gravity - 23o API

• GOR < 50 scf/bbl

• Viscosity > 10 cp

• BHT 155 0 F

• TVD 3,000 - 4,500 ft

• H2S 3.5%

• CO2 3.5%

35 George E. King Engineering

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8/25/2015

Qatar Well Characteristics • 9-5/8 Casing

• 7 liner

• SCSSV, Chemical Injection, Permanent Guage

• Pump in Tangent Section (0, 38 - 63) deg

• Horizontal Section Though the Pay Zone

• Cable Internal

• Seating Shoe

• Bottom Intake

• Annular Flow


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8/25/2015

Initial Well Completion Schematic

7" Liner x 4-1/2" Tubing Crossover

Chemical Injection MandrelGuage MandrelSCSSV

9-5/8" Casing

Seating shoe

7" Liner

Locking discharge head

Universal Motor Base

CT and Power Cable

Lower Connector

Motor

Protector

Pump

Intake

Lower Protector


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8/25/2015

Learnings

• Lower Connector needs improving – Short due to well fluid influx

• Well head problems – unplugging due to movement

• Cable Suspension – additional splices during workovers

• Protector – Well fluid into motor


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8/25/2015

AL Rayyan ESP Performance - All ESP Pulls

95

350

95

103

339

420

153

46

113

602

108

49

50

42

194

84

235

304

327

8

189

281

72

448

485

232

220

377

79

315

153

2

22

0

30

60

90

120

150

180

210

240

270

300

330

360

390

420

450

480

510

540

570

600

630

660

690

720

750

780

810

840

870

900

930

960

990

1020

1050

1080

1110

1140

1170

1200

1230

1260

1290

AR-4

AR-5

AR-6

AR-7

AR-9

AR-10

AR-14

AR-15

days since project start

9 November, 1996

Start date

28 February, 2000

End date

pump - metal LC LC elective - replace LC elective - increase ESP size

elective - w ater shut-off motor burn

motor-brush w ire LC motor burn Spinning diffusers

elective - replaceburst disc LC LC protector shaft spinning diffusers, UMB shaft, dropped pump, rig w orkover

motor burn UMB shaft hanger penetrator

spinning diffusers motor-rotor strike

motor burn

motor burn Elective Pull - Acid Job

coiled tubing - cable external


coiled tubing - cable internal, installed cable external after stimulation


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8/25/2015

Lower Connector

• Redesigned

– uses field attachable components

– feed through

– seals motor from CT ID

– mechanical release

• Tested

– Pressure

– Shock loading

• Implemented in Q4 1997

– No electrical failures to date 42

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8/25/2015

Wellhead Disconnect

• Power cable unplug from well head penetrator – movement of 1/2”

• Solution - Add wellhead extension – Added power cable

• Result - No electrical wellhead failures


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8/25/2015

Horizontal

Well Head


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8/25/2015

Cable Suspension

• Cable Anchors

– Move due to deformation

– Require splice during workovers

Power cable

Cable support system

Coiled tubing


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8/25/2015

Cable Suspension Solution

• Friction Deployed System

– relies on friction

between power cable and CT ID

– Simplifies cable

installation

– Developed model to predict slippage


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8/25/2015

Friction Deployed Testing

• 5,000 ft vertical well

• Simulated ESP equipment

• Load cell at the lower connector

• No fluid in CT

• Multiple runs

• Cut to measure slippage

• Electrically test power cable


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8/25/2015

Downhole Load Down Hole 3, 9/22/98 @1:21 pm

-400

-350

-300

-250

-200

-150

-100

-50

0

50

100

150

0 1000 2000 3000 4000 5000 6000

Depth (ft)

Lo

ad

(lb

s)

{Neg

ati

ve #

's =

Co

mp

ress

ion

}


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8/25/2015

Testing Results

• Compressive loads acceptable

• Slippage measured - 150” @ 10,000 ft

• Model verified

• Installed in 3 wells


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8/25/2015

Protector

• Well fluid in motor

– H2S

– Sludge

• Used several configurations

• Redesign

• Installed in 6 wells

– Running +300 days


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8/25/2015

Bolt on Head

Pump

Protector

Motor

UMB

Conventional ESP

Equipment

CTDESP Cable Internal with

Shrouded Intake

CTDESP Cable Internal

with Seating Shoe and

Discharge Head

Power Cable

Coiled Tubing

Coiled Tubing Lower

Connector

7” x 23#/ft CSG

Motor

Power Cable

Coiled Tubing

Coiled Tubing

Lower Connector

7” x 23#/ft CSG

Motor

Motor

UMB

UMB

Protector Protector

Discharge Head

Pump

Seating Shoe &

Lockdown Discharge

HeadPump

Intake

Thrust Section

Intake and

shroud hanger

Thrust Section

5-1/2” Shroud

with Seal Stinger

Packer

Figure 1 - Equipment Comparison Schematics


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8/25/2015

Figure 2 - Cable External Equipment

The equipment in Figure 2 can be interchanged

with the equipment above the motor in the

CTDESP systems shown in Figure 1. This allows

cable external to be run as either a shrouded

intake systems or a seating shoe system . The

well head configuration is different to handle the

cable outside the coiled tubing.

Power Cable

Coiled Tubing

Modified Rope

Socket

Sealing Chamber

7” Casing

Motor


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8/25/2015

CTDESP – Bottom Intake

Property Comparisons - Conventional ESP Vs CTDESPSystems

Property

Co

nven

tion

al E

SP

on

join

ted

tub

ing

Seatin

g s

ho

e,

cab

le in

tern

al

Sh

rou

ded

inta

ke,

cab

le in

tern

al

Seatin

g s

ho

e,

cab

le e

xte

rnal

Sh

rou

ded

Inta

ke,

cab

le e

xte

rnal

Cable protected from mechanical damage No Yes Yes No No

Cable exposed to well fluids Yes No No Yes Yes

Requires one cable splice (round to flat) Yes No No No No

Allows 5.62” OD equipment inside 7” 23 lb/ft casing No Yes Yes Yes Yes

Annular flow – reduced friction pressure No Yes Yes Yes Yes

Utilize gas separators Yes No No No No

All gas must go through pump No Yes Yes Yes Yes

Potential sticking due to sand fall out No No Yes No Yes

Requires horizontal tree No Yes Yes Yes Yes

Protector and motor at discharge pressure No Yes Yes Yes Yes

Corrosion resistant materials readily available Yes No No No No

72 hours workover or less No Yes Yes Yes Yes

Requires rig or snubbing unit for workover Yes No No No No

Fast workover equipment lead time No Yes Yes Yes Yes

Lower day rate CTU vs Rig No Yes Yes Yes Yes

ESP equipment may see compressive forces No Yes Yes Yes Yes


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8/25/2015

AL Rayyan ESP Performance - All ESP Pulls

95

350

95

103

339

420

153

46

113

602

108

49

50

42

194

84

235

304

327

8

189

281

72

448

485

232

220

377

79

315

153

2

22

0

30

60

90

120

150

180

210

240

270

300

330

360

390

420

450

480

510

540

570

600

630

660

690

720

750

780

810

840

870

900

930

960

990

1020

1050

1080

1110

1140

1170

1200

1230

1260

1290

AR-4

AR-5

AR-6

AR-7

AR-9

AR-10

AR-14

AR-15

days since project start

9 November, 1996

Start date

28 February, 2000

End date

pump - metal LC LC elective - replace LC elective - increase ESP size

elective - w ater shut-off motor burn

motor-brush w ire LC motor burn Spinning diffusers

elective - replaceburst disc LC LC protector shaft spinning diffusers, UMB shaft, dropped pump, rig w orkover

motor burn UMB shaft hanger penetrator

spinning diffusers motor-rotor strike

motor burn

motor burn Elective Pull - Acid Job



coiled tubing - cable internal, installed cable external after stimulation


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8/25/2015

Uptime

• Cumulative Uptime from project start - 93.4%

• Eliminate early failures - Uptime 94.5% – LC

– Wellhead


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8/25/2015

Figure 11 - Uptime Comparison(Based on 1 Workover)

80%

85%

90%

95%

100%

6 9 12 18 24 30 36 42 48 54 60Runtime Months

% U

pti

me

CT Internal - BI 14

Day MOB, 2.5 Day

Workover

Jointed Tubing -30

Day Rig MOB, 4

Day Workover

Jointed Tubing -60

Day Rig MOB, 4

Day Workover


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8/25/2015

Figure 12 - Workover Efficiency Improvement

• Operation Time Results

» Equipment rig up

» Make up of ESP and assembly to the CT

» Deployment of ESP into the hole

» Hang off REDACoil system

0

5

10

15

20

25

30

35

40

45

50

Well 1 Well 2 Well 3 Well 4 Well 5

Time(hr)

Source: Arco/Schlumberger: Patterson, McHugh, Pursel 57 George E. King Engineering

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Documents

ESP – Electric Submersible Pumps