Macam-Macam Artificial Lift

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.


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.


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.


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


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


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


Single ProductionPacker


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


CompletionFluid


Single ProductionPacker


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%


Produced HydrocarbonsOut

InjectionGas In


CompletionFluid


SingleProduction Packer


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


Solar PanelController

Motor Valve


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


Solar PanelController

Motor Valve


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


Bottom HoleAssembly


Standing Valve


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


ProductionCasing


Bottom HoleAssembly


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


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%


Vent Box

Motor Control

Pump

Seal Section

Motor

ProductionTubing


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.


General Field Requirements

Data Collection

Data Confirmation


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


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


SPE 59026


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


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


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.

Documents

Macam-Macam Artificial Lift