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Artificial lift technology
- 1. ARTIFICIAL LIFT TECHNOLOGYARTIFICIAL LIFT TECHNOLOGY
- 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
- 9. Gas Lift ESP’s PC Pumps Hydraulic Pumps Beam pump ARTIFICIAL LIFT METHODS
- 10. Artificial-lift in Assam Asset
- 11. Reciprocating Rod Lift Systems Pumping Units Motors & Controls Continuous & Threaded Sucker Rods Rod Pumps &Accessories Pumping Unit Services
- 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
- 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
- 25. Plunger Lift Systems Lubricators Plungers Bumper Springs Controllers Accessories
- 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
- 29. Hydraulic Lift Systems Surface Hydraulic Equipment Jet Pumps
- 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
- 33. Electric Submersible Pumping Systems Wellhead Equipment Power Cables Pumps & Motors Variable Speed Drives Gas Separators
- 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
- 37. Wellsite Optimization Equipment Remote Communication Packages Data Gathering Systems
- 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.
- 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.
- 41. Project ScopeProject Scope1.1. General Field Requirements Data Collection Data Confirmation
- 42. Project ScopeProject Scope1.1. Well Information Production & Fluid Information Desired Production Rate System Details Data Collection/Confirmation
- 43. Easy Eliminations More Detailed Reviews Applicable Systems Elimination ProcessElimination Process2.2. Selection Process
- 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.
- 46. SPE 59026 Elimination ProcessElimination Process2.2.
- 47. 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 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 Gas LiftESP Hydraulic Jet Pump BarrelsperDay Lift Depth Elimination ProcessElimination Process2.2.
- 48. 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000 16,000 Recip. Hydraulic Recip. Rod Pump PC Pumps Plunger Lift BarrelsperDay Lift Depth Lower Volume Reciprocating Hydraulic Pumps, PC Pumps, Rod Pumps & Plunger Lift 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.