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www.eclipsepetrotech.com
SPE European Artificial Lift Forum 2008Artificial Lift Selection for Waxy Crude Production
Authors : Dale Chenery, Murat Kece, and
Rosaura Heath
Date : 27/02/2008
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Introduction
Topics
• Field and Reservoir
• Flow Assurance Challenges
• Artificial Lift Selection
• Conclusions
• Future Plans
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Project Location and Topography
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Structure Map on Z4 Unit
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General Reservoir Characteristics
• High porosity & permeability sands
• PI’s (from DST’s) of 18 – 27 m3/bar (8 – 12 bpd/psi)
• Porosity 24 – 30 %
• Shallow depth
• Less than 1000 m tvd (3200 ft tvd)
• Low reservoir energy
• No aquifer or gas cap detected
• GOR 35 – 45 m3/m3 (200 – 250 SCF/STB)
• Initial rates of 190 m3/day (1200bpd), but rapidly declining
• Initial Reservoir Pressure 75 – 90 bar (1100 - 1300 psi)
• Static Reservoir Temperature 53 - 60 OC (112 - 140OF)
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Oil Characteristics
• API Gravity 31 – 38 O
• Wax 35 weight %
• Resins 13 weight %
• Asphaltenes 0.15 weight %
• Upper Pour Point 39.0 OC
• Lower Pour Point 36.0 OC
• Wax Appearance Temperature 61.0 OC (First Appearance)
53.0 OC (Bulk Crystallisation)
• Wax Dissolution Temperature 59.0 OC (Commencement)
64.0 OC (Complete)
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Oil Viscosity
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Comparison with Other Waxy Crudes
Waxy Crude Database(Viscosity)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0 10 20 30 40 50 60 70 80
Temperature (OC)
Vis
co
sit
y (
cp
)
NZ India Vietnam E Africa China This Study
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Wax Deposition
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Emulsion Tendencies at 60 OC
10
100
1000
0.1 1.0 10.0 100.0Shear Rate (sec-1)
Vis
cosity (cp)
M-01 20% M-01 40% M-03 20%M-03 40% M-04 20% M-04 40%
Points = Measured
Lines = Fit
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Sucker Rod Pump (SRP)
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Jet Pump
1. Nozzle to convert
pressure to velocity
2. Intake to direct
produced fluids into jet
3. Throat where power
fluid and produced fluid
mix
4. Diffuser where velocity
is converted back to
pressure
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Progressive Cavity Pump (PCP)
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Hydraulic Submersible Pump
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Artificial Lift Challenges
• Flow Assurance Issues.
• Potential sand production due to shallow,
relatively weak rock
• High wax content in crude
• High pour point temperature
• Emulsions
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Artificial Lift Ranking Matrix
FairExcellentFair/GoodFair/GoodWorkover/Interventions
PoorPoorGood/ExcellentExcellentPower Requirements
Fair/Poor: typically designed for flow rates >1200 bpd
Fair: > 200 B/D from 4000ft.Excellent for <100 B/D
shallow wells that do not pump off
Excellent: most commonly used methods for wells producing < 100 B/D.
Low Volume Lift Capabilities
ExcellentGoodPoor/FairPoor / FairHigh Volume Lift Capabilities
Poor/FairPoorGoodGoodEmulsification
FairGood/excellentExcellentGoodHigh Viscosity Fluid Handling Capabilities
ExcellentExcellentFairExcellentTemperature Limitation
FairFairExcellentFairSolids/Sand Handling Ability
Good/ExcellentGood/excellentFairFair/goodParaffin Handling Capability
FairFairGoodGoodCorrosion/Scale Handling Ability
HSPJPPCPSRPAttribute
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Hydraulic Submersible Pumps
• HSP’s were eliminated due to:
• Currently recommended only for high flow rates (above 1200 bpd).
• Limited oilfield implementation.
• But also have the limitations of:
• The high cost and complexity of the surface equipment required for
cleaning, conditioning and pressurising the power fluid.
• The high cost and added complexity of the equipment required for surface
separation of the return fluids.
• The generation of stable emulsions due to the mixing of the power fluid
and produced oil.
• High power requirements
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Normalised CAPEX and OPEX Comparison
• High level comparison based on UK Prices
• Normalized to lowest cost in each category
• Jet Pump costs are a direct result of surface pumping equipment,
heated water for power fluid, and high pressure pipe lines.
Lift Capex OpexMethod $/bbl
PCP 1.00 1.00
SRP 2.54 1.26JP 5.11 4.18
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Jet Pumps
• Jet pumps were not recommended due to:
• The high cost and complexity of the surface equipment required for
cleaning, conditioning and pressurizing the power fluid.
• The high cost and added complexity of the equipment required for surface
separation of the return fluids.
• Limited solids handling capability due to erosion in the jet impingement
area.
• The generation of stable emulsions due to the mixing of the power fluid
and produced oil at high shear rates.
• Low efficiency (high power requirements)
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Sucker Rod Pumps
• Sucker Rods pumps were not recommended due to:
• High profile surface unit in wildlife refuge.
• Limited rate capacity without using large unit.
• Limited sand handling capability.
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Progressive Cavity Pumps
• PCP’s were recommended as the artificial lift method due to:
• Operational flexibility.
• High tolerance to solids.
• Low shear through pump.
• Simple and reliable.
• Lowest Capex and Opex.
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Heat Tracing System
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Tubing Heat Up Curves
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Conclusions
• No “One Best” artificial lift system
• Hydraulic pumps, due to heated power fluids, provide the best
flow assurance, but:
• Introduce emulsion, and fluid handling problems
• Poor efficiency means high energy costs
• PCP’s offer most flexible and lowest cost solution
• Require heat tracing for flow assurance
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Future Plans
• Possible trial of Hollow Tubing Rods as they will allow
circulation and simplify down hole chemical injection
• Perform Sand Influx Tests
• Wax Studies
• Pour point depressants and/or diluents
• Demulsifier testing
• Development of life cycle intervention / reservoir management
strategy and plan