The document discusses various artificial lift technologies used in oil production, including reciprocating rod lift systems, progressing cavity pumps, gas lift systems, plunger lift systems, hydraulic lift systems, and electric submersible pumps. It provides details on the advantages and limitations of each system, as well as parameters for determining appropriate applications, such as operating depth, volume, temperature, and wellbore characteristics. Selection of the optimal artificial lift method involves a systematic evaluation process to maximize return on investment.
2. 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.
3. Oil Field Production Phases
In the secondary recovery phase, water or gas is
injected to displace oil, making it much easier to
drive it to a production well bore.
This technique generally results in the recovery
of 20 to 40 percent of the original oil in place.
4. 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.
5. 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.
6. 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 surface
ii) Need to supplement the natural reservoir
drive in boosting fluids out of the wellbore.
7. 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
8. Selection Parameters
Well Completion & profile
Geographical & Environmental conditions
Reservoir characteristics
Reservoir pressure & Well productivity
Characteristics of fluids
Surface Constraints
Services available
Economic considerations
Operating ease
11. Reciprocating Rod Lift Systems
Pumping Units
Motors & Controls
Continuous & Threaded
Sucker Rods
Rod Pumps &Accessories
Pumping Unit Services
12.
13. Reciprocating Rod Lift
System Advantages
High 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 Rod
Tubing Anchor/
Catcher
Sucker Rod
Pump
Assembly
14. 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 Lift
System Limitations
Sucker Rod
Tubing Anchor/
Catcher
Sucker Rod
Pump
Assembly
15. Rod Lift System Application Considerations
Typical Range Maximum*
Operating
Depth 100 - 11,000’ TVD 16,000’ TVD
Operating
Volume 5 - 1500 BPD 5000 BPD
Operating
Temperature 100° - 350° F 550° F
Wellbore 0 - 20° Landed 0 - 90° Landed
Deviation Pump Pump -
<15°/100’
Build Angle
Corrosion Handling Good to Excellent
w/ Upgraded Materials
Gas Handling Fair to Good
Solids Handling Fair to Good
Fluid Gravity >8° API
Servicing Work over or Pulling Rig
Prime Mover Type Gas or Electric
Offshore Application Limited
System Efficiency 45%-60%
*Special
Analysis
Required
Sucker Rod
Tubing Anchor/
Catcher
Sucker Rod
Pump
Assembly
16. Progressing Cavity Pumping Systems
Wellhead Surface Drives
Continuous & Threaded Sucker Rods
Subsurface PC Pumps & Accessories
17. Stator
Vertical
Electric Wellhead
Drive
Casing
Production Tubing
Sucker Rod
Sucker Rod Coupling
Tubing Collar
Rotor
Tubing Collar
Tag Bar Sub
Progressing Cavity
Pumping System
Advantages
Low 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
18. 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 LimitationsVertical
Electric Wellhead
Drive
Casing
Production Tubing
Sucker Rod
Sucker Rod Coupling
Tubing Collar
Stator
Rotor
Tubing Collar
Tag Bar Sub
19. Progressing Cavity System Application
ConsiderationsTypical Range Maximum*
Operating
Depth 2,000 --4,500’ TVD 6,000’ TVD
Operating
Volume 5 - 2,200 BPD 4,500 BPD
Operating
Temperature 75 -150° F 250° F
Wellbore N/A 0 - 90° Landed
Deviation 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
Vertical
Electric Wellhead
Drive
Casing
Production Tubing
Sucker Rod
Sucker Rod Coupling
Tubing Collar
Stator
Rotor
Tubing Collar
Tag Bar Sub
20. Gas Lift Systems
Gas Lift Valves
Mandrels
Latches
Kick over Tools
Surface Controls
Coiled-Tubing
Gas Lift Equipment
Pack-Off Equipment
21.
22. Gas Lift
System 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
Hydrocarbons
Out
Injection
Gas In
Side Pocket
Mandrel with
Gas Lift Valve
Completion
Fluid
Side Pocket
Mandrel with
Gas Lift Valve
Single Production
Packer
Side Pocket
Mandrel with
Gas Lift Valve
23. Needs High-Pressure Gas Well or Compressor
One Well Leases May Be Uneconomical
Fluid Viscosity
Bottom hole Pressure
High Back-Pressure
Gas Lift
System LimitationsProduced
Hydrocarbons
Out
Injection
Gas In
Side Pocket
Mandrel with
Gas Lift Valve
Completion
Fluid
Side Pocket
Mandrel with
Gas Lift Valve
Single Production
Packer
Side Pocket
Mandrel with
Gas Lift Valve
24. Gas Lift System Application Considerations
Typical Range Maximum*
Operating
Depth 5,000 -10,000’ TVD 15,000’ TVD
Operating
Volume 100 - 10,000 BPD 30,000 BPD
Operating
Temperature 100 - 250° F 400° F
Wellbore 0- 50° 70°
Deviation Short to
Medium
Radius
Corrosion Handling Good to Excellent with
Upgraded Materials
Gas Handling Excellent
Solids Handling Good
Fluid Gravity Best in >15° API
Servicing Wireline or Work over Rig
Prime Mover Type Compressor
Offshore Application Excellent
System Efficiency 10% - 30%
*Special
Analysis
Required
Produced
Hydrocarbons
Out
Injection
Gas In
Side Pocket
Mandrel with
Gas Lift Valve
Completion
Fluid
Side Pocket
Mandrel with
Gas Lift Valve
Single
Production
Packer
Side Pocket
Mandrel with
Gas Lift Valve
26. Plunger Lift
System Advantages
Requires No Outside Energy Source -
Uses Well’s Energy to Lift
Dewatering Gas Wells
Rig Not Required for Installation
Easy Maintenance
Keeps Well Cleaned of Paraffin Deposits
Low Cost Artificial Lift Method
Handles Gassy Wells
Good in Deviated Wells
Can Produce Well to Depletion
Lubricator
Catcher
Orifice Control
Valves
Solar Panel
Controller
Motor Valve
Dual “T” Pad
Plunger
Bumper
Spring
27. Specific GLR’s to Drive System
Low Volume Potential (200 BPD)
Solids
Requires Surveillance to Optimize
Plunger Lift
System Limitations
Lubricator
Catcher
Orifice Control
Valves
Solar Panel
Controller
Motor Valve
Dual “T” Pad
Plunger
Bumper
Spring
28. Plunger Lift System Application
Considerations
Typical Range Maximum*
Operating
Depth 8,000’ TVD 19,000’ TVD
Operating
Volume 1-5 BPD 200 BPD
Operating
Temperature 120° F 500° F
Wellbore 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 Control
Valves
Solar Panel
Controller
Motor Valve
Dual “T” Pad
Plunger
Bumper
Spring
Lubricator
Catcher
30. Hydraulic Jet Lift System
Advantages
No Moving Parts
High Volume Capability
“Free” Pump
Deviated Wells
Multi-Well Production from
Single Surface Package
Low Pump Maintenance
Production
Casing
High Pressure
Power Fluid
Packer Nose
Bottom Hole
Assembly
Piston or Jet
“Free Pump”
Standing Valve
Surface Power
Fluid Package
31. Producing Rate Relative to Bottomhole Pressure
Some Require Specific Bottomhole Assemblies
Lower Horsepower Efficiency
High-Pressure Surface Line Requirements
Hydraulic Jet Lift System
Limitations
Production
Casing
High Pressure
Power Fluid
Packer Nose
Bottom Hole
Assembly
Piston or Jet
“Free Pump”
Standing Valve
Surface Power
Fluid Package
32. Hydraulic Jet Lift Application Considerations
Typical Range Maximum*
Operating
Depth 5,000 - 10,000’ TVD 15,000’ TVD
Operating
Volume 300 - 1,000 BPD >15,000 BPD
Operating
Temperature 100° - 250° F 500° F
Wellbore 0 - 20° 0 - 90° Pump
Deviation 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 Power
Fluid Package
Production
Casing
High Pressure
Power Fluid
Packer Nose
Bottom Hole
Assembly
Piston or Jet
“Free Pump”
Standing Valve
34. Electric Submersible
Pumping System
Advantages
High 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
Production
Tubing
Produced
Hydrocarbons Out
Flat Cable
Extension
35. 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 Submersible
Pumping System
Limitations
Vent Box
Motor Control
Pump
Seal Section
Motor
Production
Tubing
Produced
Hydrocarbons Out
Flat Cable
Extension
36. Electric Submersible Systems Application
Considerations
Typical Range Maximum*
Operating
Depth 1,000’ - 10,000’ TVD 15,000’ TVD
Operating
Volume 200 - 20,000 BPD 30,000 BPD
Operating
Temperature 100° - 275° F 400° F
Wellbore 10° 0 - 90° Pump
Deviation Placement -
<10° Build
Angle
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
Production
Tubing
Produced
Hydrocarbons Out
Flat Cable
Extension
38. 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 final
solution is one that provides the
highest return on your investment.
systematic evaluations to ensure the final
solution is one that provides the
highest return on your investment.
39.
40. 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.
44. Operating
Depth
Operating
Volume (Typical)
Operating
Temperature
Corrosion
Handling
Gas
Handling
Solids
Handling
Fluid
Gravity
Servicing
Prime Mover
Offshore
Application
Overall System
Efficiency
Rod Lift Progressing
Cavity
Gas Lift Plunger
Lift
Hydraulic
Piston
Hydraulic
Jet
100’ -
16,000’ TVD
5 - 5000
BPD
100° -
550° F
Good to
Excellent
Fair to
Good
Fair to
Good
>8° API
Work over or
Pulling 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 Rig
Gas or
Electric
Good
40% - 70%
7,500’ -
17,000’ TVD
50 - 4,000
BPD
100° -
500° F
Good
Fair
Poor
>8° API
Hydraulic or
Wireline
Multicylinder
or Electric
Good
45% - 55%
5,000’ -
15,000’ TVD
300 - >15,000
BPD
100° -
500° F
Excellent
Good
Good
>8° API
Hydraulic or
Wireline
Multicylinder
or Electric
Excellent
10% - 30%
5,000’ -
15,000’ TVD
200 - 30,000
BPD
100° -
400° F
Excellent
Good
>15° API
Wireline or
Work over
Rig
Compressor
Excellent
10% - 30%
8,000’ -
19,000’ TVD
1 - 5 BPD
120° -
500º F
Excellent
Excellent
Poor to
Fair
Wellhead
Catcher or Wireline
Wells’ Natural
Energy
N/A
N/A
GLR Required -
300 SCF/BBL/
1000’ Depth
Electric
Motor
100° -
400° F
Good
Poor to
Fair
Poor
to Fair
>10° API
Workover or
Pulling Rig
Excellent
35% - 60%
1,000’-
15,000’ TVD
200 - 30,000
BPD
Good to
Excellent
Electric
Submersible
Elimination ProcessElimination Process2.2.
45. 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.
49. 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
50. Proposal for Viable Forms of Lift
Economic Evaluation Model
- Capital Expenditure
- Operating Expenses
- Comprehensive Analysis
What Equipment is Available?
Selection Process
Final SelectionFinal Selection4.4.
51. Final SelectionFinal Selection4.4.
Cost Category
Rod
Lift
“CAPEX”
Installation Cost
Energy Cost Per
Month
Failure Frequency
Equipment Repair
$/Failure
Well Service Cost
$/Failure
PCP
Plunger
Lift
Gas
Lift
Hydr.
Piston
Hydr.
Jet
ESP
“OPEX” Annual
Total $
CAPEX / OPEX SUMMARY*CAPEX / OPEX SUMMARY*
52. Did System Meet Expectations?
Continuous Process of Evaluation
and Follow-Up on Failure Rates,
Confirm Costs, etc.
Follow-Up AnalysisFollow-Up Analysis5.5.