13 artificial-lift

Copyright 2007, , All rights reserved
Artificial Lift
Overview of Methods, Equipment and Operation

.
Pe initial
PRESSUREPwh
DEPTH
Well pressure gradient
Inflow Performance
Pwf initial
Pe actual
Pwf actual

Gas Lift
Principle
Equipment
Types
Operation
Troubleshooting & Control
Advantages & disadvantages

Copyright 2007, , All rights reserved 4
GAS INJECTION
PRODUCED FLUIDSURFACE PRESSURE
SANDFACE
PRESSURE
BHFP
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
Pilot
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 valve
Tubing
Packer

Pr
OPENING PRESSURE
.
Val. 1
Val. 2
Val. 3
A
B
C
Pwh
DEPTH
Gaslift Valve Operation
VIDEO

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
FLOW
PCASING
PTUBING = 55%
ORIFICE FLOW
GASINJECTIONRATE(MMSCF/D)
Gas passage through the orifice valve

LIQUID PRODUCTION RATE (QL)
WELLFLOWINGPRESSURE(Pwf)
Well inflow
Pr
TASADEPRODUCCION(QL)
GAS INJECTION RATE(Qgi)
Optimum Economical
Maximum Production
Gaslift injection

Intermittent Gaslift
Gasline
Flowline
Unloading valve
Operating valve
Tubing
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
LNG
GAS
MANIFOLD
GAS PLANT
FLOW
STATION
WATER
GASLIFT
MANIFOLD
Surface Gaslift Control

GASLIFT MANIFOLD
Manual 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 FLOW
INTERMITTENT 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 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 valve
Piston
Casing
Tubing
Rod string
Carrier Bar
Counter weight
Crank arm
Gearbox
Head
Elevator
Polished rod
Stuffing Box
Flow line
Gsa line
Sucker Rod Pumping

BARREL
RODS
PISTON
SETTING
BALLS
RIDING
VALVE
FLUID
Sucker Rod Pumping Equipment

Rod Pumping Troubleshooting and Control
31

DISPLACEMENT
LOAD
UPWARDS STROKE
DOWNWARDS
STROKE
NORMAL FUNCTIONING
ROD
PISTON
STANDIN
G VALVE
FLUID
DOWNWARD MOVEMENT UPWARD MOVEMENT
RIDING
VALVE
FLUID BARREL

Rod Pumping Typical Problems
34
Displacement
Load
Excessive Pumping Speed Restriction in the Well
Load
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

Displacement
Load
Load
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
Load
Load
Displacement
Gas Blockade Full Drained
When 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

Pwh
PUMP
Pwh
Pwf Pr
Pdn
Pup
ΔP
gas
Pwf
PdnPup
Pressure
Depth
Pup = Suction pressure of pump
Pdn = Unloading pressure of pump
ESP System Functioning
Pr

LIQUID PRODUCTION RATE, QL
WELLFLOWINGPRESSURE(Pwf)
0
0
ΔP ΔP
Unloading pressure, Pdn
Suction Pressure, Pup
ESP System Functioning

ESP System Components
Electrical transformer
Well
head
Flare
box
Switch board
Tubing
Drainage valve
Retention valve
Unloading head
Pump
Intake
Protector
Power cable
Motor
Motor base
Casing

ESP Downhole System Components
In wells of high GOR a rotary gas
separator removes the free gas from
the produced fluid through the
casing-tubing annulus, the separator
prevents problems with gas blow and
cavitations, increasing the life of the
equipment.
The motors are bipolar, three-phase
and come full with a very refined
mineral oil to provide dielectric
resistance, lubrication for seals and
thermal conductivity.
The pumps are centrifugal of
several stages. Each stage consists
of a revolving impeller and a fixed
diffuser. The used materials are of
special metallurgy for optimal
operation in corrosive and/or
abrasive 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 2
PHASE 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
Pump
Intake w/ or wo/
Gas Separator
Protector
Motor
Motor base

 Prevents Wellbore Fluids Entering
Motor
 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 as
any 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
unit.

ESP Downhole System Operation
From this curves we can determine the head produced, brake
horsepower required and hydraulic efficiency at any flow rate.
R E D
R e v . B
S N 2 6 0 0 6P u m p P- S p . G r . 1 . 0 0
O p t i m u m O p
N o m i n a l H o u
S h a f t D i a m e
S h a f t C r o s s
M i n i m u m C a
6 0 0 - 3 2 0 0
5 . 3 8
0 . 8 7 5
0 . 6 0 1
7 . 0 0 0
b p d
i n c h e s
i n c h e s
i n 2
i n c h e s
S h a f t B r
H o u s i n g
S t a n d
H i g h S
S t a n d
B u t t r e
W e l d e
2 5 6
4 1 0
N / A
6 0 0 0
6 0 0 0
H p
H p
p s i
p s i
p s i
05 0 01 , 0 0 01 , 5 0 02 , 0 0 02 , 5 0 03 , 0 0 03 , 5 0 04 , 0 0 0
R E D
R e v . B
S N 2 6 0 0 6P u m p P- S p . G r . 1 . 0 0
O p t i m u m O p
N o m i n a l H o u
S h a f t D i a m e
S h a f t C r o s s
M i n i m u m C a
6 0 0 - 3 2 0 0
5 . 3 8
0 . 8 7 5
0 . 6 0 1
7 . 0 0 0
b p d
i n c h e s
i n c h e s
i n 2
i n c h e s
S h a f t B r
H o u s i n g
S t a n d
H i g h S
S t a n d
B u t t r e
W e l d e
2 5 6
4 1 0
N / A
6 0 0 0
6 0 0 0
H p
H p
p s i
p s i
p s i
EffHpFeet
ty - Barrels p
1 0 %
2 0 %
3 0 %
4 0 %
5 0 %
6 0 %
B
Q= 2 5
H= 4 6
P= 1 .
E= 6 8
1 0
2 0
3 0
4 0
5 0
6 0
0 . 5 0
1 . 0 0
1 . 5 0
2 . 0 0
2 . 5 0
3 . 0 0

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
costs
• 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 high
torque
• Horizontal and highly deviated
wells
• Rotating gas separator
Downhole Motor PCP

0
50
100
150
200
250
300
350
400
450
500
0 1000 2000 3000 4000 5000
HEAD (FT. WATER)
CAPACITY(BFPD)
0
2
4
6
8
10
12
14
16
18
HORSEPOWER(HP)
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

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