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- 1. ESP Design using Realized and presented by: Omar Omrane AutographPC software hand sizing and Presentation of my graduation project:
- 2. Project plan 11 Oil and Gas general overview 2 Electrical submersible pump ESP hand sizing design ESP software design Economic study of the project 22 33 44 55 Conclusion66
- 3. 1.Gas and Oil general overview PRODUCED FLOWRATE SURFACE PRESSURE At Wellhead Pwf Po Reservoir Pressure- Pr •If Po the well will flow naturally (~6% of wells by number) < Pwf•If Po the well will require Artificial lift (~94% of wells worldwide) > Pwf 3
- 4. 1.Gas and Oil general overview Gas Lift ESP PC Pumps Hydraulic Pumps Beam pump 4
- 6. 2.Electrical submersible pump Typical ESP System Electrical Power Cable Submersible Pump Pump Intake Motor Protector 6
- 7. 2.Electrical submersible pump Centrifugal pump The heart of the ESP system: - Converts kinetic energy to potential energy Gas separator A pump protector: - Prevents high amount of free gas to enter the pump Seal section A motor protector: -Provides a reservoir for the thermal expansion of the motor's oil. -Isolates the clean motor oil from wellbore fluids Motor -Transforms electrical energy into motion Power cable -Transforms electrical energy from the surface down to the submersible components. 7
- 8. 8
- 9. 2.Electrical submersible pump Surface Equipments 9
- 11. 2.Electrical submersible pump Wellhead function -Suspends the tubing string -Controls high pressures Junction Box function - Allows for any gas to vent - Provides easy point for electrically checking Transformer function -Powers the surface equipments -Transforms and sends correct voltage to the motor controller Motor controller function - Provides soft start to the motor - Motor protection from overload and underload 11
- 13. 3. ESP Hand sizing Design Basic data Production capacity Gas calculation Total dynamic head Pump selection Protector selection Motor selection Power cable selection Motor controller selection Basic Design workflow 13
- 14. 3. ESP Hand sizing Design Well data Casing size: 9 5/8"OD (8.681" ID) Liner size: 7” OD Tubing size: 3 ½” OD(2.991” ID) Pump setting depth: 10170.48 ft Perforated hole interval: From 11023.488 ft to 11305.63 ft 1. Basic Data (Cherouq1) 14
- 15. 3. ESP Hand sizing Design Production Data Wellhead pressure: 220 Psi Bottom Hole Temperature: 197 °F Desired production rate: 3000 BFPD Gas Oil Ratio GOR: 1577 scf/stb Water Cut: 98.5 % 1. Basic Data (Cherouq1) 15
- 16. 3. ESP Hand sizing Design Well fluid condition Specific gravity of water: 1.2 Oil API°: 42.3 Specific gravity of the gas: 0.84 Bubble point pressure: 4080 Psi Bubble point temperature: 197 °F PVT data: PI= 1.8 bbl/day/psi 1. Basic Data (Cherouq1) 16
- 17. 3. ESP Hand sizing Design 2. Production Capacity (Cherouq1) Pwf PIP = 2029 psiPIP = 2029 psi PSI PIP 17
- 18. 3. ESP Hand sizing Design PIP Calculation steps Pwf =2533 PsiPwf =2533 Psi SGliquid=1.159SGliquid=1.159 Head(ft)=994 ftHead(ft)=994 ft PSI= 499 psiPSI= 499 psi FT(ft) =9.94 ftFT(ft) =9.94 ft FT(psi) =5 psiFT(psi) =5 psi 18
- 19. 3. ESP Hand sizing Design 10 per 1000ft 3000 BPD 7 in OD 19
- 20. 3. Gas Calculation (Cherouq1) 3. ESP Hand sizing Design % Free gas at pump intake = 5.81%< 10% Where 20
- 21. 3. ESP Hand sizing Design Gas Calculation steps Rs=657scf/stbRs=657scf/stb Bo= 1.87bbl/bblBo= 1.87bbl/bbl Bg =0.7 bbl/mcfBg =0.7 bbl/mcf Vg = 289 mcfVg = 289 mcf Vt = 3476 bblVt = 3476 bbl 21
- 22. 4. Total Dynamic Head 3. ESP Hand sizing Design �� �� �� TDH = 7064 ftTDH = 7064 ft 22
- 23. 4. Total Dynamic Head calcuation steps 3. ESP Hand sizing Design Pd = 438 ftPd = 438 ft Hd = 6127 ftHd = 6127 ft Ft = 498 ftFt = 498 ft 23 �� �� �� 23
- 24. 3. ESP Hand sizing Design 3000 BPD 31/2 in OD 49 per 1000ft 24
- 25. 5. Pump Selection requirement 3. ESP Hand sizing Design 520 m3/d520 m3/d 68%68% 1.34 Hp1.34 Hp =37.73 ft=37.73 ft =188=188 =293.651 Hp=293.651 Hp 25
- 26. 3. ESP Hand sizing Design 520 M3/d 11.5 M 68 % 1KW P37 performance curve 26
- 27. 3. ESP Hand sizing Design SSD 139 50No:6 No:16 Number of stages =189 Number of stages =189 27
- 28. 6. Seal Section selection specifications 3. ESP Hand sizing Design 28
- 29. 6. Seal Section selection specification 3. ESP Hand sizing Design 1.9 2 119 GSB3 29
- 30. 7. Motor selection specifications 3. ESP Hand sizing Design 297.051 Hp297.051 Hp 2758 Volt2758 Volt 77 Am77 Am 89.9%89.9% 30
- 31. 7. Motor selection Baker catalog 3. ESP Hand sizing Design 2758 V/77 Am 334Hp Selected Motor horse power Selected Motor horse power 31
- 32. 8. Cable selection (Cherouq1) 3. ESP Hand sizing Design 198 °F 77 Am 260 °F 32
- 33. 8. Cable selection 3. ESP Hand sizing Design C76243C76243 4 AWG4 AWG 5KV5KV 1.19 in1.19 in 33 RoundRound
- 34. 8. Cable selection Baker catalog 3. ESP Hand sizing Design 4 AWG Cable SizeCable Size 1.18 in Cable dimensionCable dimension 5KV Cable RatingCable Rating 34
- 35. 9. Motor Controller Selection 3. ESP Hand sizing Design 487 KVA487 KVA 533 Am533 Am 35
- 36. 9. Motor Controller Selection Baker catalog 3. ESP Hand sizing Design 519 KVA 624 AM Motor controller KVA Motor controller KVA Motor controller Amp Motor controller Amp 36
- 38. 4. ESP software design Well data screen capture TDH=1910 mTDH=1910 m Well 38
- 39. Pump selection screen capture 4. ESP software design Pump type: 538P31 seriesPump type: 538P31 series Pump Pump stages = 129Pump stages = 129 Pump power = 267.1 HpPump power = 267.1 Hp Pump frequency = 59.7 HzPump frequency = 59.7 Hz 3064 bbl/d 1940 M Flowrate at the surface =3064 bbl/dFlowrate at the surface =3064 bbl/d 39
- 40. 4. ESP software design Motor selection screen capture Motor Motor power = 300 HpMotor power = 300 HpMotor voltage = 3510 VMotor voltage = 3510 VMotor amperage = 55 amMotor amperage = 55 am Motor load = 89.83 %Motor load = 89.83 % Motor type: 450MSP1 seriesMotor type: 450MSP1 series 40
- 41. 4. ESP software design Seal section selection Seal Seal: 513 series GSB3Seal: 513 series GSB3 41
- 42. 4. ESP software design Cable selection Cable Cable: 4AWG CELR 5KV ratingCable: 4AWG CELR 5KV rating 42
- 43. 4. ESP software design Motor Controller selection Motor Controller Motor controller: 8600-VT 494 KVA 750 AMPMotor controller: 8600-VT 494 KVA 750 AMP Motor controller amperage = 750 amMotor controller amperage = 750 amMotor controller KVA = 494 KVAMotor controller KVA = 494 KVA Step up ratio = 9.254Step up ratio = 9.254 43
- 45. 4. Economic Study Net Present Value NPV: the sum of all project cashflows, discounted back to a common point in time NPV = 1409000 $ > 0NPV = 1409000 $ > 0 The project is profitable 45
- 46. 5.Conclusion This project focused mainly the outflow performance that’s mean the use of a lifting system to regain well production. It can be extended to discuss other alternatives dealing with inflow performance of the well to enhance reservoir capacity like (Hydraulic fracture and acid job) 46
- 47. 5.Conclusion 47
Editor's Notes
- #4: Definition of the well performance If Po &lt; Pwf, the well will flow naturally (~6% of wells by number) If Po Pwf, the well will require Artificial Lift (~94% of wells worldwide) Wells repartition in the world: 5 % flowing naturally and 95 % don&apos;t flow naturally. For this reason artificial lift systems involved in petroleum word. The major forms of artificial lift are Artificial Lift is needed when reservoir pressures do not sustain acceptable flow rates or there is no fluid flow at all. Lift process transfers energy downhole or decreases fluid density in the wellbore to reduce hydrostatic pressure on formations.
- #5: Why we choose ESP ? Making artificial lift decisions is primarily a process of choosing the lift method most applicable to expected surface, reservoir, fluid and operational conditions. We chosse ESP for these reason: - - - -
- #7: Typical ESP sustem contains electrical power cable, submersible pump, pump intake, Protector and a motor.
- #10: Shown here is the surface related equipment required for most down-hole electrical submergible pump systems.
- #11: Shown here is the surface related equipment required for most down-hole electrical submergible pump systems.
- #12: - the equipment that is installed at the surface of the wellbore. It’s purpose is to suspend the tubing string in the well, and to monitor and control high pressures conditions often present within the well.
- #20: In our case friction losses are determined directly from this chart
- #21: The main objective of this step is to galculate the percentage of free gas : the gas which is not dissoved in the solution
- #22: The main objective of thsi step is to determine the pump intake pressure in psi. First of all we calculate bottom hole flowing pressure Pwf using reservoir pressure, deqired rate and the productivity index , then the distance between midperforation zone and pump depth that will be converted to pressure in Psi. Flowing from the bottom hole to the pump setting depth the fluid loses considerable pressure on the way. For this reason we must consider a friction losses to the intake . Finally we obtain Pump intake pressure is equal to bottom hole flowing pressure minus the pressure due to the distance PSI minus friction losses.
- #23: Total Dynamic Head TDH= Hd+Fc+Pd * Hd is vertical distance between WH and flowing fluid level. * Ft is the head required to overcome friction loss in the tubing. P= FdV2/2gcD. * Pd is the head required to overcome WHP and facility Pressure could be converted to head in ft as follows: H (ft)= psi/(psi/ft) or psi x 2.31/SG
- #24: Total Dynamic Head TDH= Hd+Fc+Pd * Hd is vertical distance between WH and flowing fluid level. * Ft is the head required to overcome friction loss in the tubing. P= FdV2/2gcD. * Pd is the head required to overcome WHP and facility Pressure could be converted to head in ft as follows: H (ft)= psi/(psi/ft) or psi x 2.31/SG
- #25: Total Dynamic Head TDH= Hd+Fc+Pd * Hd is vertical distance between WH and flowing fluid level. * Ft is the head required to overcome friction loss in the tubing. P= FdV2/2gcD. * Pd is the head required to overcome WHP and facility Pressure could be converted to head in ft as follows: H (ft)= psi/(psi/ft) or psi x 2.31/SG
- #26: Refer to the Backer hughes catalog pump performance curve at 50 and 60 HZ and based on the designed rate 3000 barrel per day , we choose the pump which operates at its nearest peak efficiency and within the operating range.
- #27: Refer to the Backer hughes catalog pump performance curve at 50 and 60 HZ and based on the designed rate 3000 barrel per day , we choose the pump which operates at its nearest peak efficiency and within the operating range.
- #45: This will demonstrate if the project is profitable and sustainable, and therefore if it should receive our interest and confidence
- #47: this project focused mainly the outflow performance of the that’s mean the use of a lifting system to regain well production, this project can be extended to discuss other alternatives dealing with inflow performance of the well to enhance reservoir capacity like (Hydraulic frac and acid job