Virtual Session 2 COPYRIGHT...ESP Design and Equipment Selection: Nine Steps** 1. Basic data 2....

Virtual Session 2

Electrical Submersible Pumps Fundamentals

Manual Design

ESP Design Example

Production and Completions ═══════════════════════════════════════════════════════════════════════════════════


©PetroSkills, LLC. All Rights Reserved. _________________________________________________________________________________________________________

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ESP Design and Equipment Selection: Nine Steps**

1. Basic data2. Production capacity3. Gas calculations4. Total dynamic head5. Pump type6. Optimum size of components7. Electric cable8. Accessories and optional equipment9. Variable speed drive

** Centrilift

Data Collection

1. Well Data• Casing or liner size and weight API CASING 7 IN.

O.D. 29 #/FT. (ID 6.184 in, Drift ID 6.059 in.) Set at 7100 Ft.

• Tubing size, type and thread:, API TUBING 2-7/8 IN. O.D. EUE 8 RD THREADS (NEW), 6.5 lb/ft. (ID 2.441 in., Coupling OD 3.668 in.)

• Perforated or open hole interval 6950 – 7050 Ft. (2118.4 – 2148.8 m)

• Pump setting depth (measured & vertical) 6500 Ft. (1981.2 m)

• Well Deviation Survey VERTICAL WELL

2. Production Data• Wellhead tubing pressure 100 PSIG (689.475 kPa)• Wellhead casing pressure NA• Present production rate • Producing fluid level and/or pump intake• pressure• Static bottom-hole pressure 3000 PSI (20684.27 kPa)• EST LIQ PI 1.4 BPD/PSI dp (0.0323 m3/d/kPa)• Datum point 7000 FT (2133.6 m)• Bottom-hole temperature 200 °F (93 °C)• Desired production rate 2400 STBPD (381.568

m3/day)• Gas-oil ratio FGOR = 250 SCF/STB (44.5 m3/m3)• Water cut 80%

4. Well Fluid Conditions• Specific gravity of water 1.06• Oil API or specific gravity 35 °API• Specific gravity of gas 0.75 (Air = 1.0) • Bubble-point pressure 1250 psig (8618.446

kPa)• Viscosity of oil• PVT data

5. Power Sources• Available primary voltage 12,470 VOLTS

THREE PHASE• Frequency 60 Hz• Power source capabilities

6. Possible Problems• Sand• Deposition• Corrosion• Paraffin• Emulsion• Gas• Temperature• Other constraints (if any)NONE EXPECTED




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Production Capacity

Using the PI of 1.4 BPD/psi (0.03228 m3/d/kPa) calculate PwfPwf = 3000 – (2400/1.4) = 1286 psi (8866.658 kPa)The Pwf > Pbp, hence use of PI method is good

Calculate Pump intake pressureFluid SG = (0.8*1.06)+(0.2*0.85) = 1.02Pump intake pressure, PIP = Pwf – {(Head, ft * SG)/2.31 ft/psi }PIP = 1286 – {(500 * 1.02)/2.31} = 1065 psi (7342.916 kPa)

As PIP

Example:GOR = 250 scf/stbSGgas = 0.75Oil Gravity = 35o APIBHT = 200o F

Standing’s Correlation – Bubble Point Pressure

Pbp = 1300 psia**


**Pbp value already supplied as 1265 psia

Finding the Bubble Point pressure starting with Solution GOR


Standing’s Correlation – Bubble Point Pressure


PIP = 1080 psia**

Using the Bubble Point correlation to estimate the GOR at pump intakeExample:GOR = 250 scf/stbSGgas = 0.75Oil Gravity = 35o APIBHT = 200o F




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Standing’s Correlation – Oil Formation Volume Factor

Bo = 1.17 reservoir bbl/STB


Finding Bo for pump inlet conditions

Gas Calculations (2)

Determine gas volume factor (Bg) as follows:

Assuming 0.85 Z Factor and using the reservoir temperature (200°F or 660°R at pump intake), Bg = (5.04*0.85*660)/1080= 2.62 bbl/Mscf

Volume of free gas at pump intake: TG = (STBOPD * FGOR)/1000 Mscf

• Tg = (2400*0.2) * 250 / 1000 = 120 Mscf/d

Solution gas using Rs at pump intake, • Sg = (STBOPD * Rs)/1000 = (480*208)/1000 = 100 Mscf/d

Volume of free gas at pump intake• Fg = Tg – Sg = 120 – 100 = 20 Mscf/d




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Gas Calculations (3)

Volume of oil (Vo) at pump intake• Vo = STBOPD * Bo (RB/STB) = 480 * 1.17 = 561.6 BOPD

Volume of free gas at pump intake• Vg = Fg Mscf * Bg bbl/Mscf = 20 * 2.62 = 52.4 BGPD

Volume of water at pump intake• Vw = STBLPD * BSW = 2400*0.8 = 1920 BWPD

Total volume of oil gas water at intake• Vt = Vo + Vg + Vw = 2534 BFPD• This is the volume the ESP should be designed for.

Percentage of free gas present at pump intake, GVF= (52.4/2534)*100 = 2%. Gas separator is not required (

Total Dynamic Head

Calculate TDH (feet) asTDH = Hd + Ft + Pd

For the Design Example:• Assume Surface casing pressure : 0 psig • Mid perf depth : 7000 ft. (2133.6 m)• Pump set depth: 6500 ft. (1981.2 m)• FLOP = 2410 ft. (734.568 m)• Dynamic fluid level, Hd : 4090 ft (1246.632 m)• For 2534 BFPD and 2-7/8” new tubing, Pipeline frictional loss =

48*6.5 = 312 ft (95.097 m)• Ft = 312 ft (95.097 m)• Assume Flowing wellhead pressure = 100 psig (689.475 kPa)• Pd = 100 * (2.31/1.02) = 226 ft (68.884 m)• TDH = 4090 + 312 + 226 = 4628 ft. (1410.614 m)

Pump Discharge Pressure

Example:TDH = 4628 ft = 2048 psi (14120.46 kPa)

PDP = PIP + Pump ∆P

PDP = 1065 + 2048 = 3113 psi (21463.38 kPa)

(PDP)3113 psig

(PIP)1065 psig

(Pwf)1286 psig

FWHP100 psig Pressure

Dep

th, F

t TVD

Pump Depth

Mid-perf Depth

6500

7000




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Equipment Combination Sizing Options

Equipment Combination Sizing Options




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Pump Type Selection

Preliminary Equipment Combination Selection• Pump Size 538 Series (Pump OD: 5.38 in.)• Protector Size 513• Motor Size 562

538P23 pump has good efficiency at 2550 BFPD Also take into account of

• Fluid characteristics, gas, viscosity; • Well Conditions, Abrasives, Scale etc.• Radial flow Type / Floater construction may be sufficient for this

application

Pump Performance Curve




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Determination of Pump Stages

From the Pump Curve • Head = 51.5 ft (15.697 m) per stage• Number stages = TDH / (Head per stage)• Number stages = 4628 / 51.5 = 90 stages• Using pump technical data, a pump housing with 90+ stages should

be selected

From the Pump Curve • Horse power = 1.5 HP per stage

Pump Housing Options




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Pump Housing Selection

From the Pump Curve • Head = 51.5 ft (15.697 m) per stage• HP = 1.5 HP per stage• Number stages = TDH / (Head per stage)• Number stages = 4628 / 51.5 = 90 stages• Using pump technical data, Housing no.7 with 95 stages capacity

will be selected

Horse power requirement• Brake Horse Power = BHP per stage * No. of Stages * Sp. gravity• BHP = 1.5* 95 * 1.02 = 145 HP

Selection of Pump intake, Seal Sections

Pump Intake: Separator not required for initial conditions

• Consider life of the well operations; include separator if needed and estimate HP requirements

Select suitable pump intake if separator not needed

Seal Section: Select 513 Series suitable seal section (housing OD: 5.13 in.) Add the HP required for the seal section and estimate total HP

requirement




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Check Max Pressure / HP Limits

Housing Burst Pressure Limit• With closed discharge, head developed = 71 ft/stage• Max head developed by pump = 71*95 = 6745 ft. (2055.876 m)• Max pressure developed by pump = 2981 psi (20553.27 kPa)• The pump housing pressure rating = 5600 psi (38610.64 kPa)Housing burst pressure limit not exceeded

Shaft HP • Pump and Gas separator HP limit = 360 HP (max for Standard shaft,

60 Hz supply)• Actual = 145 HP Shaft HP limit not exceeded

Check Seal / Protector Design• Total thrust generated by pump = S/I Pump PSI x Shaft area

= 2981 * 0.6016 sq in. (Shaft dia is 7/8”) = 1793 pounds (813.3 kg)• Make sure the selected seal can withstand beyond this limit

Selection of Motor




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Selection of Motor

Select the high voltage (thus low current) motor that will have lower cable losses, thus requiring smaller conductor size cables

For the well temperature (200°F), for the 60 Hz service, a 562 KMHJ Series should be sufficient

Referring to the Technical Data on Motors, the next higher power motor is 161 HP

Of the three options available for the 161 HP, the motor with 1406 Volts, 72 amps will be used

• All operating parameters are well within their recommended ranges (e.g. thrust bearing, shaft HP, housing burst pressure and fluid velocity).

• Single motor is sufficient

Selection of Cable Size




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Applying Temperature Correction

Electric Cable Size

The proper cable size is governed by the motor amperage, voltage drop, and space available between the tubing collar and casing drift

Guideline is to select a cable size with a voltage drop of less than 30 volts per 1,000 ft. (304.8 m)

For the motor amps (72 A) Cable #2 has a voltage drop of 21 x 1.26 = 26.5 volts/1,000 ft. (304.8 m) and will be selected




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Selection of Cable Insulation Type

Ranking of insulation materials

Model Max Tdeg. F

Min Tdeg. F

Flat Round

Insulation Jacket Application

CTT 190 -40 F Thermo-plastic

Thermo-plastic

Shallow wells, Water wells, Low CO2 Light ends

CPN 205 -30 F/R Poly-propylene

Nitrile General

CPL 225 -40 F Poly-propylene

Lead Gassy Wells, High CO2 H2S

CEN 280 -30 F/R EPDMw/Tape

Nitrile Low to Moderate Gassy Conditions

CEE 400 -60 F/R EPDM EPDM w/Tape, Braid

Moderate Gassy

CEB 300 or 400 R EPDMw/Extruded Fluro-polymer

EPDM Gassy Wells

CEL 450 -40 F/R EPDM Lead w/Bedding Tape

Hot Gassy Wells

Electric Cable

Cable # 2 has been selected• Estimated voltage drop of 26.5 volts/1,000 ft. (304.8 m)• Insulation Spec: CENR (Centrilift EPDM, Nitrile, Galvanized Armor,

Round):

Surface voltage required = Nameplate voltage + Cable loss= 1406 + (26.5*6.6) = 1581 V (using 100 ft cable more than the ESP set depth)

Also calculate length of flat cable (MLE) required

Size AWG KV Rating Nominal Dimension Weight

2 5 1.31 in. (33.3 mm) 1.51 lb/ft (2.25 Kg/m)




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Accessories

Accessories: The flat guards cable bands and other downhole accessories will

be ordered Downhole gauge equipment Wellhead feedthrough A cable vent box must be installed between the wellhead and the

motor controller to prevent gas migration to the controller Motor controller: KVA = (Surf voltage * Amps *1.732)/1000

= (1581*72*1.732)/1000 = 197.2 The need for VSD should be investigated for current conditions as

well as near future conditions and ordered as required Transformer and surface cable should be ordered

Recall - the surface set up options

Switchboard

Variable Speed Drive (VSD)

Generation System

Step-downTransformer

Switchboard Junction Box ESP

high voltageInput power(11-15kV)

250 – 4000V input atfixedfrequency(50/60 Hz)

high voltage input power (11-15kV)

380V or 480 V input at fixed frequency (50/60 Hz)

380V / 480 V output at desiredfrequency

output voltage for ESP at desired frequency

Generation System

Step-downTransformer

Variable Speed Drive

Step-up Transformer

Junction Box

ESP




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ESP Sizing Summary

The basic ESP sizing process is as follows:1. Assume a design flowrate (STB/day), water-cut, WHP, ESP setting

depth and IPR 2. From the IPR, determine Pwf3. Calculate upwards to find PIP 4. Calculate downwards from WHP to find PDP 5. Calculate pump P = PDP – PIP 6. Pump TDH (ft) = Pump P / Fluid gradient (psi/ft)7. Find average flowrate (Qpump) in pump (RB/day), this includes oil

gas and water volumes, all in BBL/day8. Select pump size from casing I.D. and pump operating range9. From pump operating curves, read head per stage delivered at

Qpump10.Calculate no. of stages required = TDH / (head per stage)11.From pump operating curves, read power required per stage at

Qpump

ESP Sizing Summary (2)

12.Calculate total motor horsepower required = power per stage x no. of stages x fluid S.G.

13.Select appropriate protector (seal) configuration 14.Evaluate requirement for gas separator15.Select voltage/amps combination for selected motor size16.Select cable size from amps required 17.Specify cable protectors or banding for cable18.Determine KVA rating of switchboard or VSD19.Review the calculations if VSD is opted for, and make necessary

changes20.Order additional equipment (e.g., Wellhead feedthrough, Vent box,

Downhole data package, etc.) as required

Note: The completion will become more complex if a production packer / Y-tool or smart elements are included




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Precautions and Procedures

ESP Start up

ESP Commissioning Precautions

Unit to be started in a controlled manner and closely observed till it stabilizes

Useful tools for monitoring: • Downhole pressure sensor• Surface pressure gauge and choke

Historical settings: • Overloads set at about 115% • Under-loads at 80%

– It may be necessary to adjust this during start up

Of the normal running current




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ESP Commissioning Guidelines

1. Set the in-line valves in the correct position2. If the well is flowing before starting the unit, the flow must be

stopped by closing the choke 3. If the well was killed using heavy kill fluid then the amperage

will be high while pumping the high density fluid. The current has to be carefully monitored until the kill fluid has been removed from tubing

4. ESP turning in correct direction will be confirmed by surface pressure (pump should not be back-spinning)

5. If current is getting too high or fluctuating in a manner which is causing concern, then the motor should be shut down and the problem investigated

6. Test the well to know the producing rate – Ensure pump is operating within the recommended operating range• Control production rate using choke if required

7. Observe the parameters vs. time in a chart

0

10

40

50

60

70

90

100

500

2000

2500

300080

3500

Current Wellhead Temperature Wellhead Pressure Intake Pressure Discharge Pressure

ESP Start

First Indicationof Flow

Controlling Pressure with Choke

Take Note of Shut-In SuctionPressure

Both Pressures decrease

DischargePressure

IntakePressure

Wellhead Pressure

Current

150030

201000

Wellhead Temperature

Example: ESP Commissioning Chart




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ESP Routine Start

If the unit was stopped, wait for 30 minutes before restarting Observe the ESP performance in the chart All data are important when starting units

0

30

50

60

90

100

500

201000

10

40

1500

2000

2500

3500

Current Wellhead Temperature Wellhead Pressure Intake Pressure Discharge Pressure

Normal RunningConditions

Min 30 Minutewait

ESP Start

300080First Indication of Flow

70

Controlling Pressure with Choke

Check Pressure has Equalised

Example: ESP Routine Start-up




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The detailed design for ESP system was demonstrated with a well example

• Should accommodate the production requirements for a reasonable period (3-4 years). Possible changes production rate, GOR, water cut etc. during this period should be factored in

• Lot of communication and information-sharing between various teams of the operator and with the ESP supplier will be required

The ESP commissioning / start up procedure was reviewed

There is significant value in reviewing the ESP and well parameters together to achieve long run life and profitable operations

Session Summary

ESP design to accommodate

required flexibility

Good surveillance required during

start up and running of ESP




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Virtual Session 2 COPYRIGHT...ESP Design and Equipment Selection: Nine Steps** 1. Basic data 2....

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Transcript of Virtual Session 2 COPYRIGHT...ESP Design and Equipment Selection: Nine Steps** 1. Basic data 2....