Artificial lift technology
Transcript of Artificial lift technology
ARTIFICIAL LIFT TECHNOLOGYARTIFICIAL LIFT TECHNOLOGY
Oil Field Production Phases
The production of crude oil in oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary recovery.
During primary recovery, the natural pressure of the reservoir, combined with pumping equipment, brings oil to the surface. Primary recovery is the easiest and cheapest way to extract oil from the ground. But this method of production typically produces only about 10 percent of a reservoir's original oil in place reserve.
Oil Field Production Phases
In the secondary recovery phase, water or gas is injected to displace oil, making it much easier todrive it to a production well bore.This technique generally results in the recovery of 20 to 40 percent of the original oil in place.
Oil Field Production Phases
When companies talk about enhanced oil recovery, they're really referring to the tertiary recovery phase. Tertiary recovery involves injecting other gases, such as carbon dioxide, to stimulate the flow of the oil and to produce remaining fluids that were not extracted during primary or secondary recovery phases.
Oil Field Production Phases
These methods are not used routinely because they are expensive. When the price of oil increases, there is greater incentive to use them and thus increase, to some degree, the proven reserves of oil.
The amount of oil that is recoverable is determined by a number of factors including the permeability of the rocks, the strength of natural drives (the gas present, pressure from adjacent water or gravity), and the viscosity of the oil.
Producing The Well
Because oil, gas and water in underground are under a lot of pressure at first, these fluids flow up a wellbore all by themselves, much like a soft drink that has been shaken up. When oil and gas are produced this way, it is called primary recovery.
Artificial lift is installed in wells that: i) Do not have sufficient reservoir pressure to raise fluids to surfaceii) Need to supplement the natural reservoir drive in boosting fluids out of the wellbore.
MODES OF ARTIFICIAL LIFT
Reciprocating Rod Lift Systems
Progressing Cavity Pumping Systems
Hydraulic Lift Systems
Gas Lift Systems
Plunger Lift Systems
Electric Submersible Pumping Systems
Selection ParametersWell Completion & profile
Geographical & Environmental conditions
Reservoir characteristics
Reservoir pressure & Well productivity
Characteristics of fluids
Surface Constraints
Services available
Economic considerations
Operating ease
Gas Lift
ESP’s
PC PumpsHydraulic
PumpsBeam pump
ARTIFICIAL LIFT METHODS
Artificial-lift in Assam Asset
Reciprocating Rod Lift Systems
Pumping Units
Motors & Controls
Continuous & Threaded
Sucker Rods
Rod Pumps &Accessories
Pumping Unit Services
Reciprocating Rod LiftSystem AdvantagesHigh System Efficiency
Optimization Controls Available
Economical to Repair and Service
Positive Displacement/Strong
Drawdown
Upgraded Materials Reduce
Corrosion Concerns
Flexibility - Adjust Production
Through Stroke Length and Speed
High Salvage Value for Surface &
Downhole Equipment
Sucker RodTubing Anchor/Catcher
Sucker RodPumpAssembly
Potential for Tubing and Rod Wear
Gas-Oil Ratios
Most Systems Limited to Ability of
Rods to Handle Loads ( Volume Decreases As Depth Increases)
Environmental and Aesthetic
Concerns
Reciprocating Rod LiftSystem Limitations
Sucker RodTubing Anchor/Catcher
Sucker RodPumpAssembly
Rod Lift System Application Considerations
Typical Range Maximum*OperatingDepth 100 - 11,000’ TVD 16,000’ TVDOperatingVolume 5 - 1500 BPD 5000 BPDOperatingTemperature 100° - 350° F 550° FWellbore 0 - 20° Landed 0 - 90° LandedDeviation Pump Pump -
<15°/100’Build Angle
Corrosion Handling Good to Excellent w/ Upgraded Materials
Gas Handling Fair to GoodSolids Handling Fair to GoodFluid Gravity >8° APIServicing Work over or Pulling RigPrime Mover Type Gas or ElectricOffshore Application LimitedSystem Efficiency 45%-60%
*Special Analysis Required
Sucker Rod
Tubing Anchor/Catcher
Sucker RodPump
Assembly
Progressing Cavity Pumping Systems
Wellhead Surface Drives
Continuous & Threaded Sucker Rods
Subsurface PC Pumps & Accessories
Stator
VerticalElectric Wellhead
Drive
Casing
Production Tubing
Sucker Rod
Sucker Rod Coupling
Tubing Collar
Rotor
Tubing Collar
Tag Bar Sub
Progressing Cavity Pumping System
AdvantagesLow Capital Cost
Low Surface Profile for Visual & Height
Sensitive Areas
High System Efficiency
Simple Installation, Quiet Operation
Pumps Oils and Waters with Solids
Low Power Consumption
Portable Surface Equipment
Low Maintenance Costs
Use In Horizontal/Directional Wells
Limited Depth Capability
Temperature
Sensitivity to Produced Fluids
Low Volumetric Efficiencies in
High-Gas Environments
Potential for Tubing and Rod
Coupling Wear
Requires Constant Fluid Level above
Pump
Progressing Cavity Pumping System Limitations
VerticalElectric Wellhead
Drive
Casing
Production Tubing
Sucker Rod
Sucker Rod Coupling
Tubing Collar
StatorRotor
Tubing Collar
Tag Bar Sub
Progressing Cavity System Application Considerations
Typical Range Maximum*OperatingDepth 2,000 --4,500’ TVD 6,000’ TVDOperatingVolume 5 - 2,200 BPD 4,500 BPDOperatingTemperature 75 -150° F 250° FWellbore N/A 0 - 90° LandedDeviation Pump -
<15°/100’Build Angle
Corrosion Handling Fair
Gas Handling Good
Solids Handling Excellent
Fluid Gravity <35° API
Servicing Workover or Pulling Rig
Prime Mover Type Gas or Electric
Offshore Application Good (ES/PCP)
System Efficiency 40%-70%*Special Analysis Required
VerticalElectric Wellhead
Drive
Casing
Production Tubing
Sucker Rod
Sucker Rod Coupling
Tubing Collar
StatorRotor
Tubing Collar
Tag Bar Sub
Gas Lift Systems
Gas Lift Valves
Mandrels
Latches
Kick over Tools
Surface Controls
Coiled-Tubing
Gas Lift Equipment
Pack-Off Equipment
Gas LiftSystem Advantages
High Degree of Flexibility and Design Rates
Wireline Retrievable
Handles Sandy Conditions Well
Allows For Full Bore Tubing Drift
Surface Wellhead Equipment Requires Minimal Space
Multi-Well Production From Single Compressor
Multiple or Slim hole Completion
Produced HydrocarbonsOut
InjectionGas In
Side PocketMandrel withGas Lift Valve
CompletionFluid
Side PocketMandrel withGas Lift Valve
Single ProductionPacker
Side PocketMandrel withGas Lift Valve
Needs High-Pressure Gas Well or Compressor
One Well Leases May Be Uneconomical
Fluid Viscosity
Bottom hole Pressure
High Back-Pressure
Gas LiftSystem LimitationsProduced
HydrocarbonsOut
InjectionGas In
Side PocketMandrel withGas Lift Valve
CompletionFluid
Side PocketMandrel withGas Lift Valve
Single ProductionPacker
Side PocketMandrel withGas Lift Valve
Gas Lift System Application Considerations
Typical Range Maximum*OperatingDepth 5,000 -10,000’ TVD 15,000’ TVDOperatingVolume 100 - 10,000 BPD 30,000 BPDOperatingTemperature 100 - 250° F 400° FWellbore 0- 50° 70°Deviation Short to
MediumRadius
Corrosion Handling Good to Excellent withUpgraded Materials
Gas Handling ExcellentSolids Handling GoodFluid Gravity Best in >15° APIServicing Wireline or Work over RigPrime Mover Type CompressorOffshore Application ExcellentSystem Efficiency 10% - 30%
*Special Analysis Required
Produced HydrocarbonsOut
InjectionGas In
Side PocketMandrel withGas Lift Valve
CompletionFluid
Side PocketMandrel withGas Lift Valve
SingleProduction Packer
Side PocketMandrel withGas Lift Valve
Plunger Lift Systems
Lubricators
Plungers
Bumper Springs
Controllers
Accessories
Plunger LiftSystem Advantages
Requires No Outside Energy Source -Uses Well’s Energy to LiftDewatering Gas WellsRig Not Required for InstallationEasy MaintenanceKeeps Well Cleaned of Paraffin DepositsLow Cost Artificial Lift MethodHandles Gassy WellsGood in Deviated WellsCan Produce Well to Depletion
LubricatorCatcher
Orifice ControlValves
Solar Panel
Controller
Motor Valve
Dual “T” PadPlunger
BumperSpring
Specific GLR’s to Drive System
Low Volume Potential (200 BPD)
Solids
Requires Surveillance to Optimize
Plunger LiftSystem Limitations
LubricatorCatcher
Orifice ControlValves
Solar PanelController
Motor Valve
Dual “T” PadPlunger
BumperSpring
Plunger Lift System Application Considerations
Typical Range Maximum*OperatingDepth 8,000’ TVD 19,000’ TVDOperatingVolume 1-5 BPD 200 BPDOperatingTemperature 120° F 500° FWellbore N/A 80°Deviation
Corrosion Handling Excellent
Gas Handling Excellent
Solids Handling Poor to Fair
GLR Required 300 SCF/BBL/1000’ Depth
Servicing Wellhead Catcher or Wireline
Prime Mover Type Well’s Natural Energy
Offshore Application N/A at this time
System Efficiency N/A*Special Analysis Required
Orifice ControlValves
Solar PanelController
Motor Valve
Dual “T” PadPlunger
BumperSpring
LubricatorCatcher
Hydraulic Lift Systems
Surface Hydraulic Equipment
Jet Pumps
Hydraulic Jet Lift System Advantages
No Moving Parts
High Volume Capability
“Free” Pump
Deviated Wells
Multi-Well Production fromSingle Surface Package
Low Pump Maintenance
ProductionCasing
High PressurePower FluidPacker Nose
Bottom HoleAssembly
Piston or Jet“Free Pump”
Standing Valve
Surface PowerFluid Package
Producing Rate Relative to Bottomhole Pressure
Some Require Specific Bottomhole Assemblies
Lower Horsepower Efficiency
High-Pressure Surface Line Requirements
Hydraulic Jet Lift System Limitations
ProductionCasing
High PressurePower FluidPacker Nose
Bottom HoleAssembly
Piston or Jet“Free Pump”
Standing Valve
Surface PowerFluid Package
Hydraulic Jet Lift Application Considerations
Typical Range Maximum*OperatingDepth 5,000 - 10,000’ TVD 15,000’ TVDOperatingVolume 300 - 1,000 BPD >15,000 BPDOperatingTemperature 100° - 250° F 500° FWellbore 0 - 20° 0 - 90° PumpDeviation Hole Angle Placement -
<24°/100’ Build Angle
Corrosion Handling Excellent
Gas Handling Good
Solids Handling Good
Fluid Gravity >8° API
Servicing Hydraulic or Wireline
Prime Mover Type Multi-Cylinder or Electric
Offshore Application Excellent
System Efficiency 10%-30%*Special Analysis Required
Surface PowerFluid Package
ProductionCasing
High PressurePower FluidPacker Nose
Bottom HoleAssembly
Piston or Jet“Free Pump”
Standing Valve
Electric SubmersiblePumping Systems
Wellhead Equipment
Power Cables
Pumps & Motors
Variable Speed Drives
Gas Separators
Electric SubmersiblePumping System
AdvantagesHigh Volume and Depth Capability
High Efficiency Over 1,000 BPD
Low Maintenance
Minor Surface Equipment Needs
Good in Deviated Wells
Adaptable in Casings > 4-1/2”
Use for Well Testing
Vent Box
Motor Control
Pump
Seal Section
Motor
ProductionTubing
Produced Hydrocarbons Out
Flat CableExtension
Available Electric Power
Limited Adaptability to Major Changes in
Reservoir
Difficult to Repair In the Field
Free Gas and/or Abrasives
High Viscosity
Higher Pulling Costs
Electric SubmersiblePumping System
LimitationsVent Box
Motor Control
Pump
Seal Section
Motor
ProductionTubing
Produced Hydrocarbons Out
Flat CableExtension
Electric Submersible Systems Application Considerations
Typical Range Maximum*OperatingDepth 1,000’ - 10,000’ TVD 15,000’ TVDOperatingVolume 200 - 20,000 BPD 30,000 BPDOperatingTemperature 100° - 275° F 400° FWellbore 10° 0 - 90° PumpDeviation Placement -
<10° BuildAngle
Corrosion Handling Good
Gas Handling Poor to Fair
Solids Handling Poor to Fair
Fluid Gravity >10° API
Servicing Workover or Pulling Rig
Prime Mover Type Electric Motor
Offshore Application Excellent
System Efficiency 35%-60%
*Special Analysis Required
Vent Box
Motor Control
Pump
Seal Section
Motor
ProductionTubing
Produced Hydrocarbons Out
Flat CableExtension
Wellsite Optimization Equipment
Remote Communication
Packages
Data Gathering Systems
Lift System Selection – How to Approach
Do more than —merely offer every type of major lift system.merely offer every type of major lift system.
Provide —smart solutions for enhanced production.smart solutions for enhanced production.
This means—systematic evaluations to ensure the finalsolution is one that provides the highest return on your investment.
systematic evaluations to ensure the finalsolution is one that provides the highest return on your investment.
Artificial Lift Selection
Project ScopeProject Scope1.1.
Systems AnalysisSystems Analysis3.3.
Final SelectionFinal Selection4.4.
Follow-Up AnalysisFollow-Up Analysis5.5.
Elimination ProcessElimination Process2.2.
Project ScopeProject Scope1.1.
General Field Requirements
Data Collection
Data Confirmation
Project ScopeProject Scope1.1.
Well Information
Production & Fluid Information
Desired Production Rate
System Details
Data Collection/Confirmation
Easy Eliminations
More Detailed Reviews
Applicable Systems
Elimination ProcessElimination Process2.2.Selection Process
OperatingDepthOperatingVolume (Typical)OperatingTemperatureCorrosionHandlingGasHandlingSolidsHandlingFluidGravityServicing
Prime Mover
OffshoreApplicationOverall SystemEfficiency
Rod Lift Progressing Cavity
Gas Lift PlungerLift
HydraulicPiston
HydraulicJet
100’ -16,000’ TVD
5 - 5000BPD
100° -550° F
Good toExcellent
Fair toGood
Fair toGood
>8° API
Work over orPulling Rig
Gas or Electric
Limited
45% - 60%
2,000’ -6,000’ TVD
5 - 4,500 BPD
75°-250° F
Fair
Good
Excellent
<35° API
Work over or
Pulling RigGas or Electric
Good
40% - 70%
7,500’ -17,000’ TVD
50 - 4,000 BPD
100° -500° F
Good
Fair
Poor
>8° API
Hydraulic orWireline
Multicylinderor Electric
Good
45% - 55%
5,000’ -15,000’ TVD
300 - >15,000 BPD
100° -500° F
Excellent
Good
Good
>8° API
Hydraulic orWireline
Multicylinderor Electric
Excellent
10% - 30%
5,000’ -15,000’ TVD
200 - 30,000 BPD
100° -400° F
Excellent
Good
>15° API
Wireline orWork over
RigCompressor
Excellent
10% - 30%
8,000’ -19,000’ TVD
1 - 5 BPD
120° -500º F
Excellent
Excellent
Poor toFair
WellheadCatcher or Wireline
Wells’ Natural Energy
N/A
N/A
GLR Required -300 SCF/BBL/1000’ Depth
ElectricMotor
100° -400° F
Good
Poor to Fair
Poor to Fair
>10° API
Workover orPulling Rig
Excellent
35% - 60%
1,000’-15,000’ TVD
200 - 30,000 BPD
Good toExcellent
ElectricSubmersible
Elimination ProcessElimination Process2.2.
Performance Comparison Characteristic SRP PCP ESP Gas Lift Jet
Rates Poor Fair Good Excellent Good Gas Production Fair Poor Poor Excellent Good Viscous Fluids Good Excellent Fair Fair Excellent Emulsions Good Excellent Fair Fair Excellent Solid Handling Fair Fair Poor Excellent Excellent Wax Mitigation Fair Fair Fair Good Excellent Corrosion Good Good Fair Good Excellent Reliability Excellent Good Varies Excellent Good Efficiency Good Good Fair Poor Poor Capital Costs Moderate Low Moderate Moderate Moderate Operating Costs Low Low High Low Moderate
Elimination ProcessElimination Process2.2.
SPE 59026
Elimination ProcessElimination Process2.2.
High Volume
Hydraulic Jet Pumps,
Electric Submersible
Pumping and Gas Lift
35,000
30,000
25,000
20,000
15,000
10,000
5,000
1,00
0
2,00
0
3,00
0
4,00
0
5,00
0
6,00
0
7,00
0
8,00
0
9,00
0
10,0
00
11,0
00
12,0
00
13,0
00
14,0
00
15,0
00
16,0
00
Gas LiftESP
Hydraulic Jet Pump
Bar
rels
per
Day
Lift Depth
Elimination ProcessElimination Process2.2.
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
1,00
0
2,00
0
3,00
0
4,00
0
5,00
0
6,00
0
7,00
0
8,00
0
9,00
0
10,0
00
11,0
00
12,0
00
13,0
00
14,0
00
15,0
00
16,0
00
Recip. Hydraulic
Recip. Rod Pump
PC Pumps
Plunger Lift
Bar
rels
per
Day
Lift Depth
Lower Volume
Reciprocating Hydraulic
Pumps,PC Pumps,
Rod Pumps & Plunger Lift
Elimination ProcessElimination Process2.2.
Systems AnalysisSystems AnalysisSystems Analysis3.3.Selection Process
ESP SubPUMP,PROPSER
Reciprocating Rod Lift Rod Star, NABLA,API Rod, Tamer
PCP C-Fer
Gas Lift PROSPER, PIPESIM,GLIDE
Hydraulic Jet 4.1, Super H &Pump Eval
Type Lift Programs
Proposal for Viable Forms of Lift
Economic Evaluation Model
- Capital Expenditure
- Operating Expenses
- Comprehensive Analysis
What Equipment is Available?
Selection ProcessFinal SelectionFinal Selection4.4.
Final SelectionFinal Selection4.4.
Cost CategoryRodLift
“CAPEX” Installation Cost
Energy Cost Per Month
Failure FrequencyEquipment Repair$/FailureWell Service Cost$/Failure
PCPPlunger
LiftGasLift
Hydr. Piston
Hydr. Jet ESP
“OPEX” Annual Total $
CAPEX / OPEX SUMMARY*CAPEX / OPEX SUMMARY*
Did System Meet Expectations?
Continuous Process of Evaluation
and Follow-Up on Failure Rates,
Confirm Costs, etc.
Follow-Up AnalysisFollow-Up Analysis5.5.