13 artificial-lift
TRANSCRIPT
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Artificial Lift
Overview of Methods, Equipment and Operation
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.
Pe initial
PRESSUREPwh
DE
PT
H
Well pressure gradient
Inflow Performance
Pwf initial
Pe actual
Pwf actual
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Gas Lift
Principle
Equipment
Types
Operation
Troubleshooting & Control
Advantages & disadvantages
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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.
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Gaslift Equipment
Gasline
Surface casing
Production casing
Tubing
Packer
Flowline
Side pocket mandrel
Bellows Section
Pilot Section
Gaslift valve
Gaslift completion
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Bellows
Pilot
Gaslift Valves
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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.
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Continuous Gaslift
Gasline
Flowline
Unloading valve
Operating valveTubing
Packer
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PrOPENING PRESSURE
.
Val. 1
Val. 2
Val. 3
A
B
C
Pwh
DE
PT
H
Gaslift Valve Operation
VIDEO
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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
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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
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Gas Injection Rate
DOWNSTREAM PRESSURE (PSI)
SUB-CRITICAL
FLOW
PCASING
PTUBING = 55%
ORIFICE FLOW
GA
S I
NJ
EC
TIO
N R
AT
E (
MM
SC
F/D
)
Gas passage through the orifice valve
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LIQUID PRODUCTION RATE (QL)
WE
LL
FL
OW
ING
PR
ES
SU
RE
(P
wf)
Well inflow
Pr
TA
SA
DE
PR
OD
UC
CIO
N (
QL)
GAS INJECTION RATE(Qgi)
Optimum Economical
Maximum Production
Gaslift injection
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Intermittent Gaslift
Gasline
Flowline
Unloading valve
Operating valveTubing
Packer
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Gasline
Flowline
Unloading valve
Operating valve
Tubing
Packer
Plungerlift
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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
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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
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Surface Gaslift Control
GASLIFT MANIFOLDManual Flow Control Valve
Actuated Flow Control Valve
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Surface Gaslift Control
INDIRECT METERING OF GAS FLOW TO THE WELL
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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
Surface Gaslift Control
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Surface Gaslift Control
CONTINUOUS FLOWINTERMITTENT FLOW
CASING PRESSURE
WELLHEAD PRESSURE
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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
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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
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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
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Types of Artificial Lift Pumping Methods
RP HP PCP ESP
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Principle
Equipment
Operation
Troubleshooting & Control
Advantages and disadvantages
Mechanical Pumping (Sucker Rod Pumps)
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27
Mechanical Pumping (Sucker Rod Pumps)
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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
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Standing valve
Riding valvePiston
Casing
Tubing
Rod string
Carrier Bar
Counter weight
Crank arm
Gearbox
Head
Elevator
Polished rod
Stuffing Box
Flow line
Gsa line
Sucker Rod Pumping
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BARREL
RODS
PISTON
SETTING
BALLS
RIDING
VALVE
FLUID
Sucker Rod Pumping Equipment
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Rod Pumping Troubleshooting and Control
31
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DISPLACEMENT
LO
AD
UPWARDS STROKE
DOWNWARDS
STROKE
NORMAL FUNCTIONING
ROD
PISTON
STANDIN
G VALVE
FLUID
DOWNWARD MOVEMENT UPWARD MOVEMENT
RIDING
VALVE
FLUIDBARREL
Rod Pumping Troubleshooting and Control
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Rod Pumping Troubleshooting and Control
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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
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Rod Pumping Typical Problems
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
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Rod Pumping Typical Problems
Displacement
Load
Load
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.
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Electric Submersible Pumps (ESP)
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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
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Pwh
PUMP
Pwh
Pwf Pr
Pdn
Pup
ΔP
gas
Pwf
PdnPup
Pressure
De
pth
Pup = Suction pressure of pump
Pdn = Unloading pressure of pump
ESP System Functioning
Pr
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LIQUID PRODUCTION RATE, QL
WE
LL
FL
OW
ING
PR
ES
SU
RE
(P
wf)
00
ΔP ΔP
Unloading pressure, Pdn
Suction Pressure, Pup
ESP System Functioning
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ESP System Components
Electrical transformer
Well
headFlare
box
Switch board
Tubing
Drainage valve
Retention valve
Unloading head
Pump
Intake
Protector
Power cable
Motor
Motor base
Casing
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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.
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ESP Downhole System Components
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).
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Compliant Mounted Zirconia Radial Bearings
Head and Base Bearing
Stage Bearing
ESP Downhole System Components
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ESP Downhole System Components
Typical fluid flow path in a
"mixed flow" stage.
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ESP Downhole System Components
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.
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ESP Downhole System Components
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:
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ESP Downhole System Components
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
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ESP Downhole System Components
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
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ESP Downhole System Components
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.
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ESP Downhole System Components
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.
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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
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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.
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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
unit.
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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
10%
20%
30%
40%
50%
60%
B.E.P.Q = 2581H = 46.75P = 1.31E = 68.09
10
20
30
40
50
60
0.50
1.00
1.50
2.00
2.50
3.00
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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)
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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
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Opportunity of application:
• Deep wells that requires hightorque
• Horizontal and highly deviatedwells
• Rotating gas separator
Downhole Motor PCP
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0
50
100
150
200
250
300
350
400
450
500
0 1000 2000 3000 4000 5000
HEAD (FT. WATER)
CA
PA
CIT
Y (
BF
PD
)
0
2
4
6
8
10
12
14
16
18
HO
RS
EP
OW
ER
(H
P)
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