Major forms of Artificial Lift

PRODUCED FLOWRATE

WELL OUTFLOWRELATIONSHIP

WELL INFLOW (IPR)

SURFACE PRESSUREAt Wellhead

Pwf

WELL FACE PRESSURE

Reservoir Pressure- Pr

Available Pwf as function of the flowrate

Required 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

The concept of Artificial Lift• 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.

Gas Lift (SLB)

ESP’s (SLB)

DuraLiftPC Pumps

HydroLiftHydraulic Pumps

Beam pump

MAIN ARTIFICIAL LIFT METHODS

Artificial Lift Market 94% of Wells are on AL

World: 890,000 wells

Canada 48,200

US 541,000

Argentina 13,800

Russia 121,000

Indonesia 9,500

Venezuela 15,000

Brazil 7,400Peru

4,600

Egypt 1,200 Oman

2,600

China 76,000

India 3,000

Australia 1,300

North Sea 600

W.Europe 9,000

Libya 1,760

RevenueSpears 2004

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

Total Expenditures 3291

WellsSpears 2004

% WW Wells WWRod Pumps 79% 669,716Electric Submersible Pumps 12% 98,065PCP's 4% 30,144Gas Lift 3% 26,892Hydraulic Pumping <1% 5,000Others 2% 14,856

Total Systems 100% 844,673

Ft./Lift12,00011,00010,000

9,0008,0007,0006,0005,0004,0003,0002,0001,000

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 Pumps PC Pumps Hydraulic Lift Submersible Pump Gas Lift

ARTIFICIAL LIFT – Application Ranges

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

Syst

em E

ffici

ency

(%)

ARTIFICIAL LIFT – System Efficiency; includes all mechanical

losses

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

AL Methods Applicability – not ‘one size fits all’

Condition Rod Pumps Hydraulic PumpsPCP's Gas Lift ESP'sScale 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 good good (with VSD)

Temperature very good very good poor good fair/good*Efficiency good poor/very good* very good*fair good

Reciprocating Displacement Rod Pumps

Transfer 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.

Rod Pumping SystemWalking Beam

Pitman Arm

Saddle Bearing

Horsehead

Bridle

Hanger

Ladder

Wrist Pin

Crank ArmCounterweight

Prime MoverBrake

Lever

Base

Samson Post

Equalizer Bearing

Brake Cable

Polished RodStuffing Box Seal

Flow Line

Flow TeeRod String

Downhole Pump

Production Tubing

Production Casing

Drawings Courtesy of Lufkin Industries, Inc. Lufkin, Texas

Types of Pumping Units

Mark II

Low Profile Air Balanced

Beam Balanced

Drawings Courtesy of Lufkin Industries, Inc. Lufkin, Texas

How a Downhole Pump Works

Ball & seat

Seating nipple

Standing valve closed

Barrel

Traveling valve open

Plunger Moving Down

Tubing

Cage

Plunger Moving Up

How can we change the flow rate ?

• Change the pump stroke length– Typical range 54 – 306 inches

• Change the number of strokes– Typical range 5 –15 spm

Downhole Pumps

• Insert Pump - fits inside the production tubing and is seated in nipple in the tubing.

• Tubing Pump - is an integral part of the production tubing string.

Insert Pumps

• Pump is run inside the tubing attached to sucker rods

• Pump size is limited by tubing size

• Lower flow rates than tubing pump

• Easily removed for repair

Insert Pump

Ball & seat

Seating nipple

Standing valve

Barrel

Traveling valve

Plunger

Tubing

Cage

Tubing Pumps

• Integral part of production tubing string

• Cannot be removed without removing production tubing

• Permits larger pump sizes

• Used where higher flow rates are needed

Tubing Pump

Ball & seat

Standingvalve

Barrel

Travelingvalve

Plunger

Tubing

Cage

Connectionw/tubing

Prime Mover HorsePower -estimations

• Hydraulic Horsepower = power required to lift a given volume of fluid vertically in a given period of time

= 7.36 x 10-6 x Q x G x L

where Q = rate b/d (efficiency corrected), G= SG of fluid,L = net lift in feet

• Frictional Horsepower

= 6.31 x 10-7 x W x S x N

Where W=weight of rods in lb, S=stroke length,N=SPM

• Polished Rod Horsepower (PRHP)= sum (hydraulic, frictional)

• Prime mover HP = PRHP x CLF / surface efficiency

where CLF = cyclic load factor dependent on model of motor typical range 1.1 to 2.0

Sonolog Fluid Level Survey

Sound reflection

Tubing collars

Fluid level

Sonolog

Charge ignited

Fluid level

Beam 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

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.

Mechanical energy transfer via rotation sucker rods (top drive) orelectricity (bottom drive).

Introduction to PC PumpsHistory

• Invented by Rene Moineau in 1932.

• Initial uses in industrial pumping applications.

• Used as power sections for directional drilling since mid 1950’s.

• First artificial lift applications in early 1980’s.

THEORECTICAL PC PUMP LIMITS90% Volumetric Efficiency

0500

100015002000250030003500400045005000

0 500 1000 1500 2000 2500 3000 3500 4000 4500DISPLACEMENT @ 425 RPM (BFPD)

PRES

SUR

E (P

SI)

6.875"Dia5.25" Dia4.2" Dia.

Application Range

Characteristics

• Interference fit between the rotor and stator creates a series of isolated cavities

• Rotation of the rotor causes the cavities to move or “progress” from one end of the pump to the other

• Non Pulsating• Pump Generates Pressure Required To

Move Constant Volume• Flow is a function of RPM

Flow Characteristics

PCP Description

E 4E

D

P

D

P = Stator Pitch length

D = Minor Diameter of StatorMajor Diameter of Stator

• The geometry of the helical gear formed by the rotor and the stator is fully defined by the following parameters:– the diameter of the Rotor = D– eccentricity = E – pitch length of the Stator = P

• The minimum length required for the pump to create effective pumping action is the pitch length. This is the length of one seal line.

Pumping Principle

• Each full turn of the Rotor produces two cavities of fluid.

• Pump displacement = Volume produced for each turn of the rotorPD = C *D*E*P

C = Constant (SI: 5.76x10-6, Imperial: 5.94x10-1)• At zero head, the flow rate is directionally

proportional to the rotational speed N:Q = PD*N (remember to account for Bo)

Pumping Principle

• Manufacturers rate the pressure capability of a pump as a function of the number of pump stages. Pressure capability is determined by the number of stator pitches

• One stage is defined as the pump length required to offset 100 psi of differential pressure.

Stages

Stator Pitch

Rotor Pitch1 Stage = 1.5 Stator Pitches

(or 3 Rotor Pitches)

• Lifting capacity is typically referred to in feet of water, rather than stages.– 1 stage = approx. 100 psi– 1 stage = approx. 231 ft of lift– 1 stage = approx. 70 meters of lift– 1 stage = approx. 690 Kpa

• An 18 stage pump (1800 psi) is commonly referred to as a 4000 ft (1200 meter) pump.

Progressing Cavity Pump BasicsStage Ratings

PCP performance

• Positive displacement pump theoretically not affected by pressure across the pump

• But with higher pressure differential the seal between cavities is not adequate and slippage of pumped fluid results

• Pump efficiency is a function of – the “fit” between rotor and stator– Viscosity of the fluid

Efficiency, Pressure and Slip

S40G65

0

10

20

30

40

50

60

70

0 1000 2000 3000 4000 5000 6000 7000

Feet of Lift

(BFP

D)

20% Slip @ rated Pressure

So for a head of 4000 feet the production is 52 bfpd

• The horsepower requirements for a PC pump can be broken down into two categories:– Hydraulic: Work to lift fluid to the surface, directly

proportional to pressure and speed.

– Frictional: Work to overcome losses in the pump due to rotor/stator compression fit and speed.

• One of the reasons PC Pumps are such an efficient artificial lift method is because the frictional horsepower is very low.

Progressing Cavity Pump BasicsHorsepower Requirements

Progressing Cavity Pump BasicsHorsepower Requirements

HHOORRSSEEPPOOWWEERR

VVOOLLUUMMEE

DEPTH IN FEETDEPTH IN FEET

25002500

20002000

15001500

10001000

500500

0000 3000300015001500 250025002000200010001000500500

00

1010

2020

3030

4040

5050

6060

7070

• The Elastomer Reacts with its Environment– Temperature changes cause large dimensional

changes– CO2 and aromatic compounds cause swelling and

softening– Sulfur causes hardening and embrittlement

• These Factors are Considered When Designing a Pumping System

Elastomer Characteristics

ElastomersSelection Guide

CompoundMax Temp

Deg. FMax API

Max H2S

Physical Properties

Abrasion Resistance

Aromatic Resistance

Standard Nitrile 180 20 2% Excellent Acceptable LowSoft Nitrile 180 20 2% Excellent Superior LowSuper-saturated Nitrile 200 38 2% Good Poor GoodHNBR 225 25 4% Excellent Fair FairEnhanced HNBR 250 38 6% Excellent Poor Good

• Cause: Production Flow Line Valve Closed / Plugged Pump

• Result: Over Pressure

Failure Modes – High Pressure

Failure Modes – Abrasion

• Identification:– Roughened, worn or scuffed surfaces usually

on the minor diameter of the stator.• Cause:

– Due to normal wear and abrasion. Influenced by quantity and abrasiveness of fluid solids content, pump speed, elastomer type.

• Remedy– Reduce particle velocity through the pump,

running pump at lower speeds, and by adding more stages to the pump.

Failure Modes – Chemical Attack

• Identification:– Signs of chemical attack or fluid incompatibility

include elastomer swelling, softening or blistering

– Results in a loss in pump efficiency and an increase in the torque to turn the pump.

• Cause:– Light end hydrocarbons and aromatics result in

an increase in volume of the elastomer and softening of the surface.

• Remedy– Proper elastomer selection.– Pump sizing practices.

Failure Modes – High Temperature

• Identification:– Surface of the elastomer will be hard, brittle and

extensively cracked.• Cause:

– High temperatures result in an increased rate of oxidation causing loss of tensile strength and increase of hardness of elastomer.

– High temps result from pump being run dry or high operating temperature.

• Remedy– Monitor fluid levels and adjust pump speed.– Select proper elastomer for operating

temperature.

Failure Modes - Rotor Failures

• Abrasive wear along seal lines.• Fluid incompatibility.

Rare Occurrence

Rod design

• Consider– Weight of rod and rotor– Maximum stress in rod (torque and load)– Yield strength– Environment– Fatigue loading

• Provides safe controlled release of the stored energy in rod string– Backspin energy components include:

• Elastic rod string energy• Fluid level equalization

Drivehead Design

Standard PC Pump - Topdrive

• Down-hole pump components:– Rotor.– Stator.

• Sucker rod string.• Surface drive head.• Accessories:

– Torque anchor.– Rod protectors / centralizers.– Etc.

Top Drive System Design

• Has to:– Suspend rod & carry axial loads

– Deliver torque to rod

– Rotate rod

– Prevent backspin

– Prevent escape of fluid

• Typical HP range = 10 – 100 HP

• HP = 1.904 x 10-2 x Rod torque (ft.lbs) x N (rpm)/ Drive efficiency

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 Pumps

ProgressingCavity Pump

Tubing

Casing

Intake

Gear Box &Flex Drive

Protector

Motor

Perforations

Alternative PC Pump – BottomDrive*

• Down-hole pump components:– Rotor.– Stator.

• Intake.• Gearbox.• Protector.• Motor.• Cable.

• FCE• VSD• Junction Box• Transformer• Rotor Adapter• Stator Adapter

*mark of Schlumberger

Motor

Protector

GearboxIntake

StatorRotorCable

FCE

PC PumpsApplication

• Top Drive– Target wells with minimal deviation– Low volume – Shallow pump setting depth

• Bottom Drive– Target wells

• Severe dogleg• Horizontal• Higher Rate• Deeper• Environmentally Sensitive

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 (< 8000 ft)

• Limited operating temp (normally < 250 F)

• Not compatible with some chemicals, H2S 6%, CO2 30% Aromatics 12% and high API Gravity Oils

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

APPLICATIONS OF GAS LIFT

• TO ENABLE WELLS THAT WILL NOT FLOW NATURALLY TO PRODUCE

• TO INCREASE PRODUCTION RATES IN FLOWING WELLS

• TO UNLOAD A WELL THAT WILL LATER FLOW NATURALLY

• TO REMOVE OR UNLOAD FLUID IN GAS WELLS

• TO BACK FLOW SALT WATER DISPOSAL WELLS

• TO LIFT AQUIFER WELLS

• CAN BE INTERMITTENT OR CONTINUOUS

INJECTION GASCHOKE CLOSED

TO SEPARATOR/STOCK TANK

TOP VALVE OPEN

SECOND VALVEOPEN

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

SIBHPTUBING PRESSURECASING PRESSURE

30001000 5000 6000 7000

INJECTION GASCHOKE OPEN

TO SEPARATOR/STOCK TANK

TOP VALVE OPEN

SECOND VALVEOPEN

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

SIBHPTUBING PRESSURECASING PRESSURE

30001000 5000 6000 7000

INJECTION GASCHOKE OPEN

TO SEPARATOR/STOCK TANK

TOP VALVE OPEN

SECOND VALVEOPEN

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

SIBHPTUBING PRESSURECASING PRESSURE

30001000 5000 6000 7000

INJECTION GASCHOKE OPEN

TO SEPARATOR/STOCK TANK

TOP VALVE OPEN

SECOND VALVEOPEN

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

TUBING PRESSURECASING PRESSURE

30001000 5000

DRAWDOWN

6000 7000

FBHP SIBHP

INJECTION GASCHOKE OPEN

TO SEPARATOR/STOCK TANK

TOP VALVE CLOSED

SECOND VALVEOPEN

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

TUBING PRESSURECASING PRESSURE

30001000 5000

DRAWDOWN

6000 7000

FBHP SIBHP

INJECTION GASCHOKE OPEN

TO SEPARATOR/STOCK TANK

TOP VALVE CLOSED

SECOND VALVEOPEN

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

TUBING PRESSURECASING PRESSURE

30001000 5000

DRAWDOWN

6000 7000

FBHP SIBHP

INJECTION GASCHOKE OPEN

TO SEPARATOR/STOCK TANK

TOP VALVE CLOSED

SECOND VALVECLOSED

THIRD VALVEOPEN

FOURTH VALVEOPEN

0

2000

6000

8000

10000

12000

14000

4000

2000 4000

PRESSURE PSI

DEP

TH F

TTV

D

TUBING PRESSURECASING PRESSURE

30001000 5000

DRAWDOWN

6000 7000

FBHP SIBHP

FIGURE 3-8: Example of the Unloading SequenceCasing Operated Valves and Choke Control of Injection Gas

0

200

400

600

800

1000

1200

1400

1600

1800

2000

12:00 AM 03:00 AM 06:00 AM 09:00 AM 12:00 PM 03:00 PM 06:00 PMTime

Pres

sure

psi

PRESSURE CASING PRESSURE TUBING

3 basic types of gas lift valve, each available in 1” & 1-1/2” sizes:

Dummy valves Orifice valvesUnloading valves

• Square edged• Venturi (nova)

• Injection pressure (casing) operated valves

• production pressure (fluid) operated valves

• Throttling/proportional response valves

GAS LIFT VALVE MECHANICS

UNLOADING GAS LIFT VALVE

• Normally required during unloading phase only

• Open only when annulus and tubing pressures are high enough to overcome valve set pressure

• Valve closes after transfer to next station

• May be spring or nitrogen charged

Pressure Regulator

Diaphragm/Atmospheric Bellows

Spring

Stem

Stem Tip

Port

DownstreamUpstream

Spring Operated Gas Lift Valve

Upstream/Casing

Downstream/Tubing

VALVE OPENING & CLOSING PRESSURESF = P X A

Pc1

Pd

Pt

WHEN THE VALVE IS CLOSEDTO OPEN IT…..Pd x Ab= Pc1 (Ab - Ap) + Pt Ap Pd

Pc2

WHEN THE VALVE IS OPENTO CLOSE IT…..Pd x Ab = Pc2 (Ab)

GAS LIFT VALVES CLOSE IN SEQUENCE0

2000

6000

8000

10000

12000

14000

4000

1000 2000

DEP

TH F

TTV

D

TUBING PRESSURECASING PRESSURE

1500500 2500

DRAWDOWN

3000 3500

FBHP SIBHP

NORMAL GAS LIFT VALVE• Bellows

• Check valve

• Stem travel

• Metallurgy

• Elastomers

• Max fluid rate

ORIFICE GAS LIFT VALVE

• Typically an ‘orifice’ type Gas lift valve

• always open - allows gas across Passage whenever correct differential exists

• Gas injection controlled by size and differential across replaceable choke

• Back-check prevents reverse flow of well fluids from the production conduit

ORIFICE VALVES

THERE ARE 2 TYPES OF ORIFICE VALVES:

• SQUARED EDGED ORIFICE

• VENTURI (NOVA)

OPERATING PRINCIPLE OF THE VENTURI

00

2020

4040

6060

8080

100100

120120

140140

160160

180180

200200

0 0 100 100 200 200 300 300 400 400 500 500 600 600

Tubing PressureTubing PressureTubing Pressure

Flow

Rat

e (M

CF/

d)Fl

ow R

ate

(MC

F/d)

The Square-edged orifice performance curve

CHARACTERISTICS OF A SQUARE-EDGED ORIFICE

• Large sub-critical flow regime

• Gas passage dependent on downstream pressure until 40 - 50% pressure lost

• Poor pressure recovery = large pressure drop & large energy loss

NOVA VALVENOVA VALVE

PRESSURE (PSI)

SUB-CRITICAL FLOW

PCASING

PTUBING = 90%PTUBING = 55%

CRITICAL FLOW

CRITICAL FLOW

GA

S IN

JEC

TIO

N R

ATE

(MM

SCF/

D)

NOVA VALVENOVA VALVE

INFLOW

GL Typical System

Gas Lift

Advantages• 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

Disadvantages• 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

Hydraulic-Lift Pumping SystemsHydraulic systems transfer energy downhole by pressurizing special power 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.

Two Types of Hydraulic Pumps

• Jet Pump• Piston Pump

Jet Pump - Principles of Operation

• Jet pumps can be used as an alternate to Piston pumps– They can fit interchangeably into BHA’s– Shorter BHA’s 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

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

Well in Flowing Condition through BHA with no Communication with Casing Annulus

Well no Longer Flowing Standing Valve Drop down Tubing until Seated

Pressure is exerted against the standing valve & gate is open

Pump is then Drop and placed in bottom hole assembly

Injected power fluid goes into nozzle converting to pressure head to a velocity stream, pressure is lower at the discharge of nozzle allowing pressure from formation to flow and mixed in with jet stream, allowing production & power fluid to circulate to surface

Bernoulli’s Equation of State

P+ vgh 2

2g + Constant

If pressure goes up, velocity….

If velocity goes up, pressure….

Pressure Head

Velocity Head

Power Fluid Mixture

Well Fluids

Jet Pump Overview Cont'd

• 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

Jet Pump Overview Cont'd

• 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

Nozzle and Throat Sections

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)

Area Ratio

Fad= 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

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!

Equipment Selection –Balancing the Following:

• Jet pump components– Nozzle too small

• Will only circulate PF• PF pressure could be too high for required lift

– 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

Jet Pump Application RangeTubing Size Max Production (B/D) 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 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

Standard Wellhead and Downhole Pump

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• Low capital cost per unit production

Disadvantages of Jet Pumps

• Low system mechanical efficiencies (5 to 30%)• High fuel/energy running costs• High GOR impacts performance• High surface maintenance costs if using piston

power fluid pumps• Cavitation can occur with high GOR

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

Piston Pump

• Same reciprocating action as rod pump

• Ideal for low flow rates

• Low intake pressure

• Higher efficiency

• Maximum drawdown

Piston PumpsFree Piston Pump Application Range

Tubing Max Production (B/D) Max HeadSize at Depth Capacity

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 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

Typical Hydraulic System

PD Pump Set Up

Optional Hydraulic Pumping System

HPS + Surface System

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.

Transfers electricalenergy that is converted to torque.

Electrical Submersible Pump• The Electric Submersible Pumping (ESP) System

transfers electrical energy from the surface to a down hole motor that converts it into a mechanical force (torque). This rotational movement turns the pump’s 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

REDA

Russian

Electrical

Dynamo

Artunoff

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

ESP - Pumps

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

0 2000010000 30000

20000

10000

0

Tota

l Dyn

amic

Hea

d -F

eet

15000

5000

Flow Rate - BPD (60 Hz)

Maximum Head-Capacity for Pumps

5.5" Casing7" Casing

4.5" Casing

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

PumpPerformanceCurves

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 pump’s intake. This assists in eliminating some of the gas that might be produced through the pump.

ESP Gas Separators

ESP Protector

The protector is located directly above the motor.

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

It’s the “heart” of the system since it provides the torque required by the downhole pump.

ESP - Motor

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

ESP - Motor Selection

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

ESP - Power Cable Motor Lead Extension

Power

Cable

MLE

Cable

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

•The conductor - electrical properties

•Insulation material - protects and covers the conductor

wire

•Barrier Jacket - protects and covers the insulation.

•Jacket Material - rubber compound designed for

temperature, chemical, and gas considerations.

•The exterior armor - the outer shield that holds it all

together

ESP – Power Cable Components

ESP - Surface Equipment

Transformers

VSD’s J-BoxesWellhead Connectors

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

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.

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

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.

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

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

VSD’s

Perforations.

Protector

Pump intakePump

1 joint Tubing

Check valveDrain valveCasing

MotorPothead

Motor flat cable

Primary cable

Production

WellheadJunction

box

Motorcontroller

Transformers

ESP ‘s Advantages• Good efficiency over the widest range of production rates• Can achieve high production rates• When VSD operated, can offer 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

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.

END of MODULE Two