Submersible pump electric

1. System and Equipment
Overview
Electric Submersible
Pumping Systems
Prof. SSP SINGH

2. •A high-volume production tool that
can operate in extremely deep wells.
•Consist of a rotating, highly
engineered series of components.
•Demands very little surface space
and can operate in highly deviated
wells.
•When properly designed each
system requires little or no
maintenance during
its run life.

3.  Connected and driven by the motor via
the shaft connection of the seal and gas
separator
 Pump consists of stages that move the
fluid through the pump and up into the
production string
- Each stage consists of 1 impeller and 1
diffuser
- The impeller is the driver of the fluid
while the diffuser directs the flow.

4.  Impellers are connected to the
pump shaft and turn when the
motor is on.
 Impeller transfers the fluid
upward to each impeller above it,
through the pump discharge and
into the production string.
 Each impeller is housed within a
diffuser.
 The diffuser directs the flow of the
fluid from each impeller
Impeller

5. Typical
range
maximum
Operating
depth
1,000’ -
10,000’
TVD
15,000’
TVD
Operating
volume
200 - 20,000
BPD
30,000 BPD
Operating
temperature
100° - 275° F 400° F
Wellbore
deviation
10° 0 - 90°
Pump
Deviation
Placement -
<10° Build
Angle
Corrosion Handling : Good
Gas Handling : Fair
Solids Handling : Fair
Fluid Gravity : >10° API
Servicing : Work over or Pulling Rig
Prime Mover Type : Electric Motor
Offshore Application : Excellent
System Efficiency : 35%-60%

6. • High Volume and Depth
Capability
• High Efficiency Over 1,000 BPD
• Low Maintenance
• Minor Surface Equipment Needs
• Good in Deviated Wells
• Adaptable to All Wells With 4-
1/2” Casing and Larger
• Use for Well Testing

7.  Available Electric Power
 Limited Adaptability to
Major Changes in Reservoir
 Difficult to Repair In the
Field
 Free Gas and/or Abrasives
 High Viscosity
 Higher Pulling Costs

8.  Surface Control Board (SB) or
Variable Speed Controller
(VSD)
 Vented Junction Box
 Wellhead

9.  Attached to top of casing
 Holds production tubing that
holds the submersible system in
the casing annulus.
 Allows power cable to pass
through and into the well
 Tight seal around the cable
preventing production fluids from
leaking out of the well
 Allows produced hydrocarbons to
pass from the production tubing to
the surface flow line.

10.  Electric motor
 Seal section
 Gas separator: Not Shown
 Centrifugal pump
 Motor extension lead
 Down hole Power Cable

11. A two-pole three-phase induction motor
that rotates an internal shaft.
• Nominal speeds - 3450 rpm / 60 hertz or
2916 rpm / 50 hertz
• Filled with a light mineral oil that is
required for lubrication and cooling
During operation the oil in the motor heats up
and expands. The excess oil travels from the
motor up and into the seal section. When the
system is idle the oil cools, condenses, and is
drawn down from the seal back into the motor.
REMINDER : Motor must be completely
filled with oil at all times.

12. • Connected above the motor
• Motor shaft and seal shaft
connected via a coupler.
• Acts as oil reservoir for motor
• Contains a thrust module that
absorbs thrust generated by the
shafts of the gas separator
and pump.

13. Power cable transmits
electrical current from the
surface to the down hole
system.
 Begins at the transformers
 Passes through the surface
controller, junction box and
wellhead
 Attached to the production
tubing and run the entire
length of the well into motor.

14. Separates and removes free gas from the
hydrocarbons. Gases are discharged through a
series of passages/ports into the annulus.
• Assembled between the seal section and
centrifugal pump
• Separator shaft is connected to the seal shaft
below and the centrifugal pump shaft above.
• All connections use couplings.

16. The pressure increase is usually expressed as
pumping head, the equivalent height of fresh water
that the pressure differential can support.

18. - Free gas in oil
- Temperature at depth
- Viscosity of oil
- Sand content fluid
- Paraffin content of fluid

19. -P.I of well
-Casing and tubing sizes
-Static liquid level

20. THE FOLLOWING PROCEDURES CAN BE USED
FOR SELECTING AN ESP:
(1) Starting from well IPR, determine a desirable
liquid production rate QLd. Then select a pump size
from manufacturer’s specification that has a minimum
delivering flow rate QLp, i.e., QLp > QLd.
(2) From the IPR, determine the flowing bottom home
pressure Pwf at the pump-delivering flow rate QLp, not
the QLd.

21. (3) Assuming zero casing pressure and neglecting
gas weight in the annulus, calculate the
minimum pump depth by
Where
Dpump = minimum pump depth, ft
D = depth of production interval, ft
Pwf = flowing bottom hole pressure, psia
Psuction = required suction pressure of pump, 150 –300 psi
γL = specific gravity of production fluid, 1.0 for fresh water.

22. (4) Determine the required pump discharge
pressure based on wellhead pressure, tubing
size, flow rate qLp, and fluid properties. This can be
carried out quickly using the computer spreadsheet
HagedornBrownCorrelation.xls.
(5) Calculate the required pump pressure differential
and then required
pumping
head by Eq(3-1).

23. (6) From manufacturer’s pump characteristic
curve, read pump head or head per stage. Then
calculate required number of stages.
(7) Determine the total power required for the
pump by multiplying the power per stage by
the number of stages.

24. A 10,000-ft-deep well produces 32°API oil
with GOR 50 scf/stb and zero water cut
through a 3-in. (2.992 in. I.D.) tubing in a 7-
in. casing The oil has a formation volume
factor of 1.25 and average viscosity of 5 cp.
Gas specific gravity is 0.7. The surface and
bottom hole temperatures are 70°F and
170°F, respectively.