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Major forms of Artificial Lift

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PRODUCED FLOWRATE

WELL OUTFLOWRELATIONSHIP

WELL INFLOW (IPR)

SURFACE PRESSUREAt Wellhead

Pwf

WELL FACE PRESSURE

Reservoir Pressure- Pr

Available Available Available Available Available Available Available Available PwfPwfPwfPwfPwfPwfPwfPwf as function of the flowrateas function of the flowrateas function of the flowrateas function of the flowrateas function of the flowrateas function of the flowrateas function of the flowrateas function of the flowrate

Required Po to produce desired rateRequired Po to produce desired rateRequired Po to produce desired rateRequired Po to produce desired rateRequired Po to produce desired rateRequired Po to produce desired rateRequired Po to produce desired rateRequired Po to produce desired rate

Po

If Po < Pwf, the well will flow naturally

(~6% of wells by number)

If Po Pwf, the well will require Artificial Lift

(~94% of wells worldwide)

INFLOW AND OUTFLOW PERFORMANCE

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INFLOW PREFORMANCE RELATIONSHIPS

Straight Line (PI):Pwf = Pr Q / PI

Vogel Relationship:

Qo/Qomax = 1 0.2 (Pwf/Pr) 0.8 (Pwf/Pr)2Pwf = flowing bottom hole pressure at sandface (psia)

Pr = average reservoir pressure (shut in BHP psi)

Q = oil flow rate (BPD)

Qo = flow rate (BPD)

Qomax = maximum flow rate (Vogel or combination),

PI = Productivity Index BPD/psi.

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Straight line vs. Vogel Graphically

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OUTFLOW PERFORMANCE RELATIONSHIP

Po = Ph + Pfr + Pwh

Where, Ph = Hydrostatic pressure

Pfr = Pressure drop due to friction losses

Pwh = Wellhead Pressure (surface pressures)

Several correlations have been developed to better model mixed flow considering different factors such as flow-regime, water cut, viscosity, well inclination, roughness, holdup, etc.

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Pressure to Head Conversion

To convert pressure to head:

Fresh water gradient = 0.433 psi/ft

Head (in feet )= Pressure (psi) / (SG*0.433)

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The concept of Artificial Lift

Artificial Lift is needed when reservoir pressures do not sustain acceptable flow rates orororor there is no fluid flow at all.

Lift process transfers energy downholetransfers energy downholetransfers energy downholetransfers energy downholeor decreases decreases decreases decreases fluid density in the wellborefluid density in the wellborefluid density in the wellborefluid density in the wellboreto reduce hydrostatic pressure on formations.

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ARTIFICIAL LIFT METHODS -OVERVIEW

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Gas Lift (SLB)Gas Lift (SLB)Gas Lift (SLB)Gas Lift (SLB)

ESPs (SLB)ESPs (SLB)ESPs (SLB)ESPs (SLB)

DuraLiftDuraLiftDuraLiftDuraLiftPC Pumps (SLB)PC Pumps (SLB)PC Pumps (SLB)PC Pumps (SLB)

HydroLiftHydroLiftHydroLiftHydroLiftHydraulic Pumps (SLB)Hydraulic Pumps (SLB)Hydraulic Pumps (SLB)Hydraulic Pumps (SLB)

Beam pump (not SLB)Beam pump (not SLB)Beam pump (not SLB)Beam pump (not SLB)

ARTIFICIAL LIFT METHODS

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AL Methods Applicability not one size fits all

Condition Rod Pumps Hydraulic Pumps PCPs GL ESPsScale fair fair/poor fair fair poorSand fair very good/poor* good very good fairParaffin poor fair good poor goodCorrossion good fair fair fair fairHigh GOR poor fair fair very good fairDeviation poor very good fair/good very good goodRate poor fair fair very good goodDepth fair very good fair good fairFlexibility very good very good good very goodgood (with VSD)Temperature very good good poor good fair

Applicability of AL Methods

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Artificial Lift Market 94% of Wells are on AL

World: 845,000 wellsWorld: 845,000 wells

Canada Canada 48,20048,200

US US 541,000541,000

Argentina Argentina 13,80013,800

Russia Russia 121,000121,000

Indonesia 9,500Indonesia 9,500Venezuela Venezuela

15,00015,000

Brazil Brazil 7,4007,400Peru Peru

4,6004,600

Egypt Egypt 1,2001,200 Oman Oman

2,6002,600

China China 76,00076,000

India India 3,0003,000

Australia Australia 1,3001,300

North Sea North Sea 600600

W.Europe W.Europe 9,0009,000

Libya Libya 1,7601,760

RevenueSpears 2004

MM$Rod Pumps 717Electric Submersible Pumps 1725PCPs 369Gas Lift 130Hydraulic Pumping 30Others 320

Total Expenditures 3291

WellsSpears 2004

% WW Wells WWRod Pumps 79% 669,716Electric Submersible Pumps 12% 98,065PCPs 4% 30,144Gas Lift 3% 26,892Hydraulic Pumping

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Ft./Lift12,000

11,000

10,000

9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 20,000 30,000 40,000 50,000 BPD

Typical Artificial Lift Application Range

Rod PumpsRod PumpsRod PumpsRod Pumps PC PumpsPC PumpsPC PumpsPC Pumps Hydraulic LiftHydraulic LiftHydraulic LiftHydraulic Lift Submersible PumpSubmersible PumpSubmersible PumpSubmersible Pump Gas LiftGas LiftGas LiftGas Lift

ARTIFICIAL LIFT Application Ranges

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0

10

20

30

40

50

60

70

80

90

100

PCP Hydraulic PistonPumps

Beam Pump ESP Hydraulic JetPump

Gas Lift(Continuous)

Gas Lift(Intermittent)

Artificial Lift Type

Ove

rall

Sys

tem

Effi

cien

cy (

%)

ARTIFICIAL LIFT System Efficiency; includes all mechanical losses

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Artificial Lift Selection

Making artificial lift decisions is primarily a process of choosing the lift method most applicable to expected surface, reservoir, fluid and operational conditions

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AL Methods Applicability not one size fits all

ConditionConditionConditionCondition Rod PumpsRod PumpsRod PumpsRod PumpsHydraulic PumpsHydraulic PumpsHydraulic PumpsHydraulic PumpsPCPs PCPs PCPs PCPs Gas LiftGas LiftGas LiftGas Lift ESPsESPsESPsESPsScale fair fair/good* fair good poorSand fair very good/poor* good very good fairParaffin poor fair/good* good poor goodCorrossion good fair fair fair fairHigh GOR poor fair fair excellent fair/good*Deviation poor excellent poor/good very good goodRate poor good fair very good goodDepth fair very good fair good goodFlexibility very good very good good very goodgood (with VSD)Temperature very good very good poor good fair/good*Efficiency good poor/very good*very good*fair fair

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Reciprocating Displacement Rod Pumps

Transfer of mechanical energyTransfer of mechanical energyTransfer of mechanical energyTransfer of mechanical energy from surface via rod string to downhole pump

Rod Pumps combine a cylinder (barrel) and piston (plunger) with valves to transfer well fluids into the tubing and lift the fluid to the surface.

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Rod PumpsAdvantages: Most widely used AL method

Best understood by field personnel

Usually the cheapest (where suitable)

Low intervention cost

Remote locations without electricity

Readily accommodates volume changes

Reliable diagnostic tools available

Can often pump below perforations

Disadvantages: Restricted flow and depth

Susceptible to free gas

Frequent maintenance

Deviated wellbores are difficult (rod and tubing wear)

Reduced tubing bore

Susceptible to corrosion

Potential wellhead leaks

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Progressing Cavity Displacement Pumps

Progressing cavity pumps are based on rotary fluid displacement. This spiral system consists of a rotor turning inside a stationary stator.

MechanicaMechanicaMechanicaMechanical energy transferenergy transferenergy transferenergy transfer via rotationrotationrotationrotationsucker rods (top drive) orororor electricityelectricityelectricityelectricity(bottom drive).

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PC Pumps Applications

Heavy & viscous oils.

Production of solids-laden fluids.

Medium to sweet crude.

Coal bed methane / gas well de-watering.

Urban areas.

Agricultural areas. Lower surface footprint than Beam PumpsLower surface footprint than Beam PumpsLower surface footprint than Beam PumpsLower surface footprint than Beam Pumps

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Progressing Cavity PumpsAdvantages

Simple two piece design.

Excellent for viscous crude

Resistant to abrasives and solids

Non-pulsating. Does not gas lock or emulsify fluid.

Oil Gravities from 5 to 42 API

Fairly flexible application method

Efficient power usage

Disadvantages

Sensitive to overpressure

Sensitive to pump off

Restricted flow rate (< 5000 bpd)

Restricted setting depths (< 6500 ft)

Limited operating temp (< 250 F absolute max)

Not compatible with some chemicals, H2S and high API Gravity Oils

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Gas LiftGas Lift uses additional high pressure gas to supplement formation gas. Produced fluids are lifted by rrrreeeedddduuuucccciiiinnnngggg fluid densityfluid densityfluid densityfluid density in wellbore to lighted the hydrostatic column, or back pressure, load on formations.

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Gas Lift as an Artificial Lift Method

Gas lift injection decreases fluid average density, thus the hydrostatic load on formations is reduced so that available reservoir energy can cause inflow, and commercial hydrocarbon volumes can be boosted or displaced to the surface.

By injecting relatively high pressure gas from the surface to a predetermined depth in the wellbore, the average specific gravity of the fluid decreaseswhich causes a drop in the well face pressure (Pwf) generating additional draw-down which according to Darcys Law- turns on increased fluid production.

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INFLOWINFLOWINFLOWINFLOW

GL Typical System

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Gas Lift

AdvantagesAdvantagesAdvantagesAdvantages

Fairly low operational cost

Flexibility - can change rates by

adjusting injection rates and/or

pressures. Also, easy to change gas lift

valves without pulling tubing

High volume lift method 35,000 bpd

typical

Very good for sand / deviated wells

DisadvantagesDisadvantagesDisadvantagesDisadvantages Must have a source of gas

If gas is corrosive it will require treatment

Possible high installation costs

Top sides modifications to existing

platforms

Compressor installation & maintenance

Limited by available reservoir pressure

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Hydraulic-Lift Pumping SystemsHydraulic systems transfer energytransfer energytransfer energytransfer energydownhole by pressurizing special power fluidpower fluidpower fluidpower fluid, usually water or a light refined oil or pumped through well tubing or annulus to a subsurface pump, which transmits the potential energy to produced fluids. Common pumps consist of jets (venturi and orifice nozzles), reciprocating pistons, or less widely used rotating turbines.

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Advantages of Jet Pumping

No moving parts, can tolerate solids & deviated wellbores

No rig required to replace pump (due to wear or productivity changes)

Simplifies completions significantly

Chemicals can be injected with power fluid

No rig required to change zones (tandem well)

Low capital cost per unit production

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Disadvantages of Jet Pumps

Low system mechanical efficiencies (30%)

High fuel/energy running costs

High surface maintenance costs if using piston power fluid pumps

Industry not familiar with system due to past monopoly supply & poor marketing/product knowledge

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Hydraulic Piston Pumps

Offered as an alternative to jet pumps Higher efficiencies (up to 95%)

Reciprocating piston to lift product to surface

Hydraulically retrievable

Similar flexibility in design and application

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Ideal Hydraulic Pumping System

RedaHPSRedaHPSRedaHPSRedaHPS + Surface System + Downhole Equipment = A Complete + Surface System + Downhole Equipment = A Complete + Surface System + Downhole Equipment = A Complete + Surface System + Downhole Equipment = A Complete SystemSystemSystemSystem

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Multi-well Installation Driven by RedaHPS

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Portable Testing Units

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Principles of Operation

Jet pumps can be used as an alternate to Piston pumps They can fit interchangeably into BHAs

Shorter BHAs can be used Jet pump assemblies can be shorter and higher flow

Referred to as far back as 1852

First patents for oil wells usage in 1930

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Jet Pump Overview

Pumping action achieved with energy transfer

High pressure fluid passed through the nozzle Potential energy (pressure) is converted to kinetic energy in

form of high velocity jet stream

Well fluids intermix at the exit (in throat) Momentum entrains well fluid

Mixture passes through expanding area (diffuser) slows down the liquid

Pressure of the mixture must be sufficient to reach the surface

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Pressure Head

Velocity Head

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Nozzle and Throat Sections

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Jet Pump Overview Contd

No moving parts

Flow passages can use exotic materials for: Heavy oils, paraffin, gas, sand and corrosives

Reservoir needs relatively strong drive 100 psi / 1000 ft as a guideline

Has to be sufficient tubular space in well To avoid excessive friction loss

Offer ruggedness, reliability and volume

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Jet Pump Overview Contd

Guidelines: PF pressure 2000 4000 psi (5000 psi max)

Maximum well depths 3000 12,000 ft Higher lifts = higher pressure

Production capacities from 50 10,000 bpd

Abrasion resistant nozzles in ceramic, SS or Tungsten Carbide

Total length of jet pump section can be ~1.5 ft

Gas can lead to reduced return flowing gradient = less HP

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Performance - Nozzle to Throat Area

Ranges from 20 60% ratio

Different N to T combinations provide range of lift capacity

Selection defines defines: Effectiveness of power fluid injected

Power fluid to lift

Input horsepower

Higher lift = more pressure = more efficiency (up to 5000 psi max)

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Area Ratio

Fad= An/AtFad= An/AtFad= An/AtFad= An/At

Where:Fad= dimensionless area ratioAn= area of nozzle, sq. in.At= area of throat, sq. in.

E.G. Large throat to nozzle ratios have higher flow capacities

OBJECTIVE IS TO MINIMIZE HP TO MAXIMIZE EFFICIENCY

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N/T Characteristics Examples

High head, low flow pump

When nozzle is 60% of the area of the throat

LESS flow area around nozzle for well fluids to enter

Low production rate capacity compared to power fluid rate

Deep wells with high lift may need this configuration

Low head, high flow pump

When nozzle is 20% of the area of the throat

MORE flow area around the nozzle for well fluids to enter

High production rate capacity compared to power fluid rate

Higher injection pressures required to meet defined lift

Shallow wells with low lift

Velocities are typically 200 - 300 fps in throat area!

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Equipment Selection Balancing the Following:

Jet pump components Nozzle too small

Will only circulate PF

PF pressure could be too high for required lift

If the throat area is too small = cavitation Defining minimum annular area is a key part of the design

Power fluid supplied Goal = minimal HP and maximum production

Friction considerations Goal = keep losses to a minimum for application

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Jet Pump Application RangeJet Pump Application RangeJet Pump Application RangeJet Pump Application RangeTubing Tubing Tubing Tubing Max LiftMax LiftMax LiftMax Lift

SizeSizeSizeSize Max Production (B/D)Max Production (B/D)Max Production (B/D)Max Production (B/D) Capacity (Ft.)Capacity (Ft.)Capacity (Ft.)Capacity (Ft.)

1-1/4 1,000 B/D 10,000 Ft.2-3/8 2,500 B/D 15,000 Ft.2-7/8 8,000 B/D 15,000 Ft.3-1/2 10,000 B/D 15,000 Ft.

Advantages of Hydraulic Jet PumpsAdvantages of Hydraulic Jet PumpsAdvantages of Hydraulic Jet PumpsAdvantages of Hydraulic Jet Pumps Reverse flow retrievable Flexible production capacity

Deviated & crooked wells Deep wells

Multiple wells Offshore platforms

Remote & urban locations Environmentally friendly

Multiple zones Economical

Unitized & transportable Complex well completions

Low Profile Field repairable

No-moving parts Sand & solids

Gas & water Paraffin & heavy oil

Corrosive fluids DST, well cleaning & testing

Low maintenance

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Piston PumpsPiston PumpsPiston PumpsPiston Pumps

Free Piston Pump Application RangeFree Piston Pump Application RangeFree Piston Pump Application RangeFree Piston Pump Application Range

Tubing Tubing Tubing Tubing Max Production (B/D)Max Production (B/D)Max Production (B/D)Max Production (B/D) Max LiftMax LiftMax LiftMax LiftSizeSizeSizeSize at Depthat Depthat Depthat Depth Capacity (B/D)Capacity (B/D)Capacity (B/D)Capacity (B/D)

2-3/8 1317 B/D at 8700 ft. 18,000 Ft.2-7/8 2400 B/D at 8700 ft. 18,000 Ft.3-1/2 4007 B/D at 8700 ft. 18,000 Ft.4 5005 B/D at 5005 ft. 18,000 Ft.

Advantages of Piston PumpsAdvantages of Piston PumpsAdvantages of Piston PumpsAdvantages of Piston Pumps Hydraulic retrievable Flexible production capacity Deviated & crooked wells

Deep wells Multiple wells Offshore platforms

Remote & urban locations Environmentally friendly Multiple zones

Economical Unitized & transportable Complex well completions

Low profile High Efficiency (95%) Low fluid levels

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Typical Hydraulic System

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Open Power Fluid System

Power fluid is produced

Casing free installation

Simplest design

Most economical design

Ideal for chemical treatment

Allows circulation of heated fluids

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Closed Power Fluid System

Minimize power fluid treatment

Excellent in abrasive, corrosive, and viscous fluids

Excellent in offshore and urban applications

Higher initial capital expense

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Piston Pump

Same reciprocating action as rod pump

Ideal for low flow rates

Low intake pressure

Higher efficiency

Maximum drawdown

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Standard Wellhead and Downhole Pump

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Electric Submersible Centrifugal Pump SystemsElectric submersible systems use multiple pump stages mounted in series within a housing, mated closely to submersible electric motor on the end of tubing and connected to surface controls and electric power by an armor protected cable.

TransfersTransfersTransfersTransfers electricalelectricalelectricalelectrical energy energy energy energy that is converted to torque....

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ELECTRIC SUBMERSIBLE PUMPS

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ESP

The Electric Submersible Pumping (ESP) System transfers transfers transfers transfers electrical energy from the surface to a down hole motor that converts it into a mechanical force (torque). This rotational movement turns the pumps impellers and lifts the well fluids to the surface.

The ESP was introduced as a means of Artificial lift by REDA in the late 1920s.

There are a wide variety of pump sizes, capacities, motor horsepower, and voltage ranges for different applications

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The motor The motor The motor The motor is a three phase, squirrel cage, two pole induction design.

Its the heart of the system since it provides the torque required by the downhole pump.

ESP - Motor

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Motor - Components

The statorstatorstatorstator is composed of the the

housing material for a desired

diameter, the stator core, and the

stator windings (copper wirecopper wirecopper wirecopper wire) .

The housing material forms the cover

for the motor and is threaded at both

ends for head and base components.

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540 562

Stator Laminations

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Motor - Components

The rotorrotorrotorrotor is made up of rotor

laminations that are smaller in

diameter from the stator

laminations and these create

the iron core. Inside each slot

are copper barscopper barscopper barscopper bars with

supporting copper end rings.

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Rotor laminationswith copper bars

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Motors are available in a number of different Sizes, Voltages, and Horsepower ranges depending on the application

ESP - Motor Selection

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ESP Protector

The protector is located directly above the motor.

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ESP - Functions of the Protector

Couples the torque developed in the motor to the pump via the protector shaft.

Prevents entry of well fluid into the motor. Provides pressure equalization. Houses the bearing to carry the thrust

developed by the pump(s) and keeps it off of the motor.

Provides a reservoir for the thermal expansion of the motors oil

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In some applications, there may be gas produced along with the oil and water liquids.

If gas is present, then a gas separator can be installed and becomes the pumps intake. This assists in eliminating some of the gas that might be produced through the pump.

ESP Gas Separators

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The multistage centrifugal pump consists of numerous impellers and diffusers (application dependent) to provide the lift (pressure) required. The pump has a discharge head that the tubing screws into.

ESP Pump

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ESP - Pumps

A Centrifugal Pump is a machine that moves fluid by spinning it with a rotating impellerrotating impellerrotating impellerrotating impellerinside a stationary diffuserstationary diffuserstationary diffuserstationary diffuser that has a central inlet and a tangential outlet. The pressure (head)pressure (head)pressure (head)pressure (head) develops against the inside wall of the diffuser diffuser diffuser diffuser as the curved wall forces fluid to move in a circular path upwards and into the impeller and diffuser above.One impellerimpellerimpellerimpeller and diffuserdiffuserdiffuserdiffuser make one pump pump pump pump stagestagestagestage.

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0 2000010000 30000

20000

10000

0

Tot

al D

ynam

ic H

ead

-Fee

t

15000

5000

Flow Rate - BPD (60 Hz)

Maximum HeadMaximum HeadMaximum HeadMaximum Head----Capacity for PumpsCapacity for PumpsCapacity for PumpsCapacity for Pumps

5.5" Casing7" Casing

4.5" Casing

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ESPs operate at 3,500 rpm on a 60-cycle power supply or 2,900 rpm on a 50-cycle power supply.

Pump

Performance

Curves

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Electric power is transferred to the motor through an electrical cable banded to the tubing.

ESP - Power Cable And Motor Lead Extension

Power Cable Power Cable Power Cable Power Cable

MLE CableMLE CableMLE CableMLE Cable

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The electrical cable has been refined over the years to be used specifically for oilwell applications.

The size of the cable selected is based on amperage and voltage drop.

Bottom Hole Temp and fluid properties are critical for the selection of cable.

Power Cable consists of three copper conductor wires extending from the top of the motor flat cable lead to the wellhead.

ESP - Power Cable

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The conductorThe conductorThe conductorThe conductor---- electrical propertieselectrical propertieselectrical propertieselectrical properties

Insulation materialInsulation materialInsulation materialInsulation material---- protects and covers the conductor wireprotects and covers the conductor wireprotects and covers the conductor wireprotects and covers the conductor wire

Barrier JacketBarrier JacketBarrier JacketBarrier Jacket---- protects and covers the insulation.protects and covers the insulation.protects and covers the insulation.protects and covers the insulation.

Jacket MaterialJacket MaterialJacket MaterialJacket Material---- rubber compound designed for temperature, rubber compound designed for temperature, rubber compound designed for temperature, rubber compound designed for temperature,

chemical, and gas considerations.chemical, and gas considerations.chemical, and gas considerations.chemical, and gas considerations.

The exterior armorThe exterior armorThe exterior armorThe exterior armor---- the outer shield that holds it all togetherthe outer shield that holds it all togetherthe outer shield that holds it all togetherthe outer shield that holds it all together

ESP Power Cable Components

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ESP - Surface Equipment

TransformersTransformersTransformersTransformers

VSDsVSDsVSDsVSDs JJJJ----BoxesBoxesBoxesBoxesWellhead ConnectorsWellhead ConnectorsWellhead ConnectorsWellhead Connectors

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The Wellhead is the device that is installed at the surface on the wellbore casing.

Purposes: to support the tubing string, cable & ESP and contain high pressures conditions often present within the casing.

Special wellheads are required to allow for cable and/or connector passage.

ESP - Surface Equipment

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Electrical transformers are required to deliver the correct voltages at the motor terminals.

- Step-down transformers:- Step-up transformers:

Transformers can be either single phase or three phase.

ESP - Surface Equipment

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Perforations.Perforations.

ProtectorProtector

Pump intakePump intake

PumpPump

1 joint Tubing1 joint Tubing

Check valveCheck valveDrain valveDrain valveCasingCasing

MotorMotorPotheadPothead

Motor flat cableMotor flat cable

Primary cablePrimary cable

ProductionProduction

WellheadWellheadJunctionJunction

boxbox

MotorMotorcontrollercontroller

TransformersTransformers

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ESP J BoxA Junction box or vent box:

Provides a connection point for the surface cable from the motor control panel or VSD to the power cable in the wellbore.

Allows for any gas to vent that may have migrated through to the power cable.

Provides easy/safe accessible test point for electrically checking downhole equipment.

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ESP Switchboards

The switchboard is used to energize the motor

It contains a motor controller which monitors running parameters and provides protection to the system.

The controller also provides the capability to monitor the REDA Production system with the use of a recording instrument.

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The variable speed controller allows for flexibilityflexibilityflexibilityflexibility of the downhole system for flow control capabilities.

It provides a constant ratio of between voltage and frequency for proper operation.

VSDs

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ESP s Advantages

Can achieve high production rates When VSD operated, can offer flexibility flexibility flexibility flexibility to accommodate changing

conditions in time (PI, water cut, Pwf, Pr, etc.) Can be used at low bottom hole pressures. Can operate reliably in deviated and offshore wells. Can sometimes operate below perforations.

Can operate under conditions such as higher bottom hole temperate with the use of alternative materials.

Can be utilized to test wells by using a portable VSD

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ESP s Disadvantages

A pulling unit is required to retrieve the failed ESP, regardless of failed component.-expensive intervention costs.

High temperatures affect cable and motor insulation. High dog leg severities are a problem. Available electrical power for required horsepower. Use of Switchboards (constant speed) limits the flexibility of

production rates. Higher gas content can limit system capabilities. High solids may cause rapid wear and premature failure.

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Electric submersible systems use multiple pump stages mounted in series within a housing, mated closely to submersible electric motor on the end of tubing and connected to surface controls and electric power by an armor protected cable.

ESP - Summary

Wide performance range and versatility (VSD only)(VSD only)(VSD only)(VSD only)

Can operate in deviated wells and off shore

Most efficient and economical lift method on a cost-

per-barrel basis

Tubing must be pulled to change or repair the

downhole components

Depth and Gas Oil Ratio restrict capacity and

operating efficiency

Large volumes of gas can lock up the pump

Schlum

berger Private

Schlum

berger Private

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