13 artificial-lift

Artificial Lift

Overview of Methods, Equipment and Operation

Pe initial

PRESSUREPwh

Well pressure gradient

Inflow Performance

Pwf initial

Pe actual

Pwf actual

Gas Lift

Principle

Equipment

Operation

Troubleshooting & Control

Advantages & disadvantages

GAS INJECTION

PRODUCED FLUIDSURFACE PRESSURE

SANDFACE

PRESSURE

RESERVOIR

PRESSURE

Gas Lift

Injection of gas in the annulus

to decrease the hydrostatic

head below bottom hole

flowing pressure and allow

the well to flow.

Gaslift Equipment

Gasline

Surface casing

Production casing

Tubing

Packer

Flowline

Side pocket mandrel

Bellows Section

Pilot Section

Gaslift valve

Gaslift completion

Bellows

Gaslift Valves

Types of Gas Lift

CONTINUOUS FLOW GAS LIFT Steady State Flow;

mechanisms are lowering density, expanding gas and

pushing to surface. P & T remain constant at process plant.

INTERMITTENT GAS LIFT Batch Production; for low

productivity wells; process problems.

Continuous Gaslift

Gasline

Flowline

Unloading valve

Operating valveTubing

Packer

PrOPENING PRESSURE

Val. 1

Val. 2

Val. 3

Gaslift Valve Operation

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

Operating 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

Gas Injection Rate

DOWNSTREAM PRESSURE (PSI)

SUB-CRITICAL

PCASING

PTUBING = 55%

ORIFICE FLOW

Gas passage through the orifice valve

LIQUID PRODUCTION RATE (QL)

Well inflow

GAS INJECTION RATE(Qgi)

Optimum Economical

Maximum Production

Gaslift injection

Intermittent Gaslift

Gasline

Flowline

Unloading valve

Operating valveTubing

Packer

Gasline

Flowline

Unloading valve

Operating valve

Tubing

Packer

Plungerlift

Typical Range Maximum

• Depth (feet) 2.000 – 10.000 15.000

• Production (BPD) 100 – 10.000 20.000

• Temperature (°F) 100 – 250 N/D

Typical Operating Conditions

Gaslift Well

3-PHASE FLOWS

RICH GAS

DRY GAS

CRUDE OIL

DRY GAS

MANIFOLD

GAS PLANT

FLOW STATION

GASLIFT

MANIFOLD

Surface Gaslift Control

GASLIFT MANIFOLDManual Flow Control Valve

Actuated Flow Control Valve

INDIRECT METERING OF GAS FLOW TO THE WELL

Connected to the

production casing valve

to record casing-tubing

annulus pressure.

Connected between the left

wing valve and the choke

box, to record WHP

CONTINUOUS FLOWINTERMITTENT FLOW

CASING PRESSURE

WELLHEAD PRESSURE

Advantages of Gas Lift

Low initial downhole equipment costs

Low operational and maintenance cost

Simplified well completions

Flexibility - can handle rates from 10 to 50,000 bpd

Can best handle sand / gas / well deviation

Intervention relatively less expensive

Disadvantages of Gas Lift

Must have a source of gas

– Imported from other fields

– Produced gas - may result in start up problems

Possible high installation cost

– Top sides modifications to existing platforms

– Compressor installation

Limited by available reservoir pressure and bottom hole

flowing pressure

Efficiency decreases while BW&S increases

Summary of Gaslift Requirements

Maximize oil production

Minimize well intervention (especially in subsea wells)

Maximize design flexibility without compromising production

Maximize depth of injection

Well stability

Uncertainties in reservoir performance

Range of reservoir pressures over well life

Range of watercuts over well life

Range of gas injection rates

Valve port sizing and gas passage pressure drops in system

Valve performance

Types of Artificial Lift Pumping Methods

RP HP PCP ESP

Principle

Equipment

Operation

Troubleshooting & Control

Advantages and disadvantages

Mechanical Pumping (Sucker Rod Pumps)

Mechanical Pumps

The first Artificial Lift method to be used and still very popular

Simple combination of a cylinder, a piston, intake valve and discharge valve

Strokes from a few inches to less than 3,000 bopd

Suitable for viscous oils (+400 cp)

Main problems:

– low intake pressure

– high discharge pressure

– sand

– corrosion

– scales and deposits

– handling of gases and condensed vapors

Standing valve

Riding valvePiston

Casing

Tubing

Rod string

Carrier Bar

Counter weight

Crank arm

Gearbox

Elevator

Polished rod

Stuffing Box

Flow line

Gsa line

Sucker Rod Pumping

BARREL

PISTON

SETTING

RIDING

Sucker Rod Pumping Equipment

Rod Pumping Troubleshooting and Control

DISPLACEMENT

UPWARDS STROKE

DOWNWARDS

STROKE

NORMAL FUNCTIONING

PISTON

STANDIN

G VALVE

DOWNWARD MOVEMENT UPWARD MOVEMENT

RIDING

FLUIDBARREL

Rod Pumping Typical Problems

Displacement

Excessive Pumping Speed Restriction in the Well

When a well is pumped at an

inadequate high speed in the beam’s

motor, it is observed in the chart that

the load decreases when beginning

the upwards piston stroke and

happens a closing in form of circle at

the end of this piston stroke.

Restrictions most of the cases reduce

the volume of fluid entering to the well

and causes in the chart an increasing

upwards load during the piston

stroke, but with excessive

displacement, which indicates little

work of the pump.

Displacement

The fluid blow happens when the

barrel of the pump does not fill

completely during the piston stroke

upwards and it is characterized by

a fast unloading at the end of the

downwards piston stroke.

The gas blow happens when the

pump fills partially with gas,

showing a chart’s shape very

similar to the one of the liquid lock,

but the unloading at the end of the

downwards piston stroke is less

pronounced.

Liquid Blow on the Pump Gas Blow on the Pump

Displacement

Gas Blockade Full DrainedWhen the pump fills almost totally

with gas it is called gas blockade

and the chart is recognized

because the load decreases during

the upwards piston stroke and

shows very little work of the pump.

If there is no entrance of fluid to

the pump it generates a chart that

shows very few loads with normal

displacement, but without work of

the pump.

Electric Submersible Pumps (ESP)

Historical Perspective

1927 - El Dorado Kansas First

ESP Installation

Early 1930s - First Horizontal

Pumping Unit

1960s - First Variable Speed

Applications

1980s - First ESP Performance

Models

1990s First Subsea Completed

Applications

Pwf Pr

PdnPup

Pressure

Pup = Suction pressure of pump

Pdn = Unloading pressure of pump

ESP System Functioning

LIQUID PRODUCTION RATE, QL

ΔP ΔP

Unloading pressure, Pdn

Suction Pressure, Pup

ESP System Functioning

ESP System Components

Electrical transformer

headFlare

Switch board

Tubing

Drainage valve

Retention valve

Unloading head

Intake

Protector

Power cable

Motor base

Casing

ESP Downhole System Components

In wells of high GOR a rotary gasseparator removes the free gas fromthe produced fluid through thecasing-tubing annulus, the separatorprevents problems with gas blow andcavitations, increasing the life of theequipment.

The motors are bipolar, three-phaseand come full with a very refinedmineral oil to provide dielectricresistance, lubrication for seals andthermal conductivity.

The pumps are centrifugal ofseveral stages. Each stage consistsof a revolving impeller and a fixeddiffuser. The used materials are ofspecial metallurgy for optimaloperation in corrosive and/orabrasive environments.

Each "stage" consists of an

impeller and a diffuser. The

impeller takes the fluid and

imparts kinetic energy to it. The

diffuser converts this kinetic

energy into potential energy

(head).

Compliant Mounted Zirconia Radial Bearings

Head and Base Bearing

Stage Bearing

Typical fluid flow path in a

"mixed flow" stage.

The next part of the system is the submergible motor. The motor

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

PHASE 2PHASE 3

PHASE 1

The three power phases are "Wye" connected within the motor

itself to establish a "neutral" point.

Because of the way the stator is

wound, the three phase power

establishes a two pole magnetic

field within the stator.

The motor is called a squirrel

cage because this is what the

rotor looks like:

The next major component of the ESP system is

the "Protector". The Protector is placed between

the pump and connects the motor shaft to the

pump shaft.

The Protector also houses the pump's upthrust

and downthrust bearings and provides for

pressure equalization between the outside of the

motor and the inside.

Unloading head

Intake w/ or wo/

Gas Separator

Protector

Motor base

Prevents Wellbore Fluids Entering

Balances Pressure Between Motor &

Annulus

Carries Thrust Load of Pump

Shaft bushing

Labyrinth Chamber

Shaft Seals

Thrust Bearing

Filter Screen

Shedder

Elastomer Bag

Protector

Between the Protector and the pump is the

pump intake section. This can be either a

standard ported intake or, as shown here,

a centrifugal gas separator to eliminate

free gas from the pumped fluid allowing it

to be produced up the annulus.

Another component of the ESP system is the power cable.

This particular cable shows an optional chemical injection line

which can be incorporated within the cable itself.

OPERATING CONDITIONS:

Typical Range Maximum

• Depth (feet) 1,000 – 10,000 15,000

• Production (BPD) 100 – 20,000 90,000

• Temperature (°F) 100 – 275 400

ADVANTAGES:

• High temperature resistant

• Highly efficient

• Positive displacement

• High liquid rates

DISADVANTAGES:

• High efficiency

• Affected by high GOR

• Little resistant to solids and sand

ESP Operation

The Basic ESP System

Equipment diameters from 3.38” -

(A) series to 11.25” - (P) series

Casing Sizes - 4 1/2” to 13 5/8”

Variable Speed Available

Metallurgies to Suit Applications.

ESP Downhole System Operation

A centrifugal pump produces "constant head". This means that,regardless of the fluid being pumped, it will be lifted to the same height asany other fluid for the same flow rate.

Propane Water Oil

Head: The height

to which the pump

will "lift" the fluid

Curves for centrifugal pumps

are normally shown as flow

versus head in feet, meters,

or some other consistent

ESP Downhole System Operation

From this curves we can determine the head produced, brake horsepower required and hydraulic efficiency at any flow rate.

REDARev. B

SN2600 60 HZ / 3500 RPMPump Performance Curve538 Series - 1 Stage(s) - Sp. Gr. 1.00

Optimum Operating RangeNominal Housing DiameterShaft DiameterShaft Cross Sectional AreaMinimum Casing Size

1600 - 32005.38

0.8750.6017.000

bpd inches inches in2 inches

Shaft Brake Horsepower Limit:

Housing Burst Pressure Limit:

StandardHigh StrengthStandardButtressWelded

256410N/A

60006000

Hp Hp psi psi psi

05001,0001,5002,0002,5003,0003,5004,000

REDARev. B

SN2600 60 HZ / 3500 RPMPump Performance Curve538 Series - 1 Stage(s) - Sp. Gr. 1.00

Optimum Operating RangeNominal Housing DiameterShaft DiameterShaft Cross Sectional AreaMinimum Casing Size

1600 - 32005.38

0.8750.6017.000

bpd inches inches in2 inches

Shaft Brake Horsepower Limit:

Housing Burst Pressure Limit:

StandardHigh StrengthStandardButtressWelded

256410N/A

60006000

Hp Hp psi psi psi

EffHpFeet

Capacity - Barrels per Day

B.E.P.Q = 2581H = 46.75P = 1.31E = 68.09

OPERATION CONDITIONS:

Typical Range Máximum

• Depth (feet) 2.000 – 4.500 6.000

• Volume (BPD) 5 – 2.200 4.500

• Temperature (°F) 75 – 150 225

ADVANTAGES:

• Low investment, operating and maintenence

• High efficiency

• Positive displacement

• Small size surface equipment

DISADVANTAGES:

• Medium to low resistance to high temperatures

• Low resistance to solids

• Incompatibility elastomers - fluid

Progressive Cavity Pumps (PCP)

Positive displacement pump without

valves

Delivers a consistent flow

Stator being stationary attached to

the tubing string

Rotor rotates driven from the surface

through the rod string and the stator

is attached to the tubing string

The rotor is a single threaded helix

and the stator is an elastomer lined

double threaded helical cavity.

The Progressive Cavity Pump

Opportunity of application:

• Deep wells that requires hightorque

• Horizontal and highly deviatedwells

• Rotating gas separator

Downhole Motor PCP

0 1000 2000 3000 4000 5000

HEAD (FT. WATER)

500 RPM

400 RPM

300 RPM

200 RPM

100 RPM

500 RPM

400 RPM

300 RPM

200 RPM

100 RPM

TYPICAL PERFORMANCE OF A PROGRESSIVE CAVITY PUMP

The Progressive Cavity Pump

13 artificial-lift

operating gas lift valve

unloading gas lift valve

orifice type gas lift

orifice valve

pressure valve closes

surface gaslift control

bellows pilot gaslift

reverse flow

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