Gas Well Deliquification

Solutions to Gas Well Liquid Loading Problems


  • James Lea, Chair of Petroleum Engineering Department, Texas Tech University
  • Henry Nickens, BP, TX, USA
  • Mike Wells, PLUERE Inc., CO, USA


Operating engineers and reservoir engineers, consulting engineers, service companies that supply equipment for gas wells, academic market


Book information

  • Published: July 2003
  • ISBN: 978-0-7506-7724-0


"...the only book in the market that offers a turnkey solution to the problem of liquid interference in gas wells.¿It is a useful book for every engineer, scientist, and researcher who has ever faced the challenge of investigating gas well production and optimization. I will recommend that if you work in the artificial lift, gas field and well optimization area, you have this practical reference available." Saeid Mokhatab Chairman of Natural Gas Engineering Editorial Advisory Board Gas Well Deliquification by Professor James F. Lea, et al., introduces the subject of liquid loading problems and discusses how to distinguish them from other possible well problems. The book covers the methods of solving the problems, how to apply the various solutions, and the advantages and disadvantages of each. It describes various methods of dewatering gas wells, comparing them and explaining the suitability of each under particular circumstances. The material is presented as practical information that can be immediately applied, rather than simply theory. Useful historical methods are discribed, but the focus is on the latest techniques. Solutions range from simple application of smaller ID tubing to complex artificial-lift methods.-World Oil, February 2007

Table of Contents

Table of Contents:Chapter 1: Introduction1.1 Introduction1.2 Multiphase Flow In A Gas Well1.3 What Is Liquid Loading?1.4 Problems Caused By Liquid Loading1.5 De-Liquefying Techniques Presented1.6 Source Of Liquids In A Producing Gas Well1.6.1 Water coning1.6.2 Aquifer water1.6.3 Water produced from another zone1.6.4 Free formation water1.6.5 Water of condensation1.6.6 Hydrocarbon condensates1.7 ReferencesChapter 2: Recognize Symptoms of Liquid Loading in Gas Wells1.2 Introduction2.2 Presence of Orifice Pressure Spikes2.3 Decline Curve Analysis2.4 Drop In Tubing Pressure with Rise in Casing Pressure2.5 Pressure Survey Showing Liquid Level2.6 Well Performance Monitoring2.7 Annulus Heading 2.7.1 Heading cycle without packer 2.7.2 Heading cycle with controller2.8 Liquid Production Ceases2.9 Summary2.10 ReferencesChapter 3: Critical Velocity3.1 Introduction3.2 Critical Flow Concepts 3.2.1 Turner droplet model 3.2.2 Critical rate 3.2.3 Critical tubing diameter 3.2.4 Critical rate for low pressure wells-Coleman model 3.2.5 Critical flow nomographs3.3 Critical velocity at depth3.4 Critical velocity in horizontal well flow 3.5 ReferencesChapter 4: Systems Nodal Analysis4.1 Introduction4.2 Tubing Performance Curve4.3 Reservoir Inflow Performance Relationship (IPR) 4.3.1 Gas well backpressure equation 4.3.2 Future IPR curve with backpressure equation4.4 Intersections of the Tubing Curve and the Deliverability Curve4.5 Tubing Stability and Flowpoint4.6 Tight Gas Reservoirs4.7 Nodal Example-Tubing Size4.8 Nodal Example-Surface Pressure Effects: Use Compression to Lower Surface Pressure4.9 Summary Nodal Example of Developing IPR from Test Data with Tubing Performance4.10 SummaryChapter 5: Sizing Tubing5.1 Introduction5.2 Advantages/Disadvantages of Smaller Tubing5.3 Concepts Required To Size Smaller Tubing 5.3.1 Critical rate at surface conditions 5.3.2 Critical rate at bottomhole conditions 5.3.3 Summary of tubing design concepts5.4 Sizing Tubing without IPR Information5.5 Field Examples #1-Results Of Tubing Chang-Out5.6 Field Examples #2-Results of Tubing Change-Out5.7 Pre/Post Evaluation5.8 Where to Set the Tubing5.9 Hanging off Smaller Tubing from the Current Tubing5.10 Summary5.11 ReferencesChapter 6: Compression6.1 Introduction6.2 Nodal Example6.3 Compression with a Tight Gas Reservoir6.4 Compression with Plunger Lift Systems6.5 Compression with Beam Pumping Wells6.6 Compression with ESP Systems6.7 Types of Compressors 6.7.1 Rotary lobe compressor 6.7.2 Re-injected rotary lobe compressor 6.7.3 Rotary vane compressor 6.7.4 Liquid ring compressor 6.7.5 Liquid injected rotary screw compressor 6.7.6 Reciprocating compressor 6.7.7 Sliding vane compressor6.8 Gas Jet Compressors or Eductors6.9 Summary 6.10 ReferencesChapter 7: Plunger Lift7.1 Introduction7.2 Plunger7.3 Plunger Cycle7.4 Plunger Lift Feasibility 7.4.1 GLR rule of thumb 7.4.2 Feasibility charts 7.4.3 Maximum liquid production with plunger lift 7.4.4 Plunger lift with a packer installed 7.4.5 Plunger lift Nodal Analysis7.5 Plunger-Lift System Line-Out Procedure 7.5.1 Considerations before Kickoff Load factor 7.5.2 Kickoff 7.5.3 Cycle adjustment 7.5.4 Stabilization period 7.5.5 Optimization Oil well optimization Gas well optimization Optimizing cycle time 7.5.6 Monitoring7.6 Problem Analysis 7.6.1 Motor Valve Valve leaks Valve won't open Valve won't close 7.6.2 Controller Electronics Pneumatics 7.6.3 Arrival Transducer 7.6.4 Wellhead leaks 7.6.5 Catcher not functioning 7.6.6 Pressure sensor not functioning 7.6.7 Control gas to stay on measurement chart 7.6.8 Plunger operations Plunger won't fall Plunger won't surface Plunger travel too slow Plunger travel too fast 7.6.9 Head gas bleeding off too slowly 7.6.10 Head gas creating surface equipment problems 7.6.12 Well loads up frequently7.7 New Plunger Concept7.8 Casing Plunger for Weak Wells7.9 Plunger with Side String: Low Pressure Well Production7.10 Plunger Summary7.11 ReferencesChapter 8: Use Of Foam to De-Liquefy Gas Wells8.1 Introduction8.2 Liquid Removal Process 8.2.1 Surface de-foaming8.3 Foam Selection8.4 Foam Basics 8.4.1 Foam generation 8.4.2 Foam stability 8.4.3 Surfactant types Nonionic surfactants Anionic surfactants Cationic surfactants Foaming agents for hydrocarbons 8.4.4 Foaming with brine/condensate mixtures Effect of condensate (aromatic) fraction Effect of brine8.5 Operating Considerations 8.5.1 Surfactant selection 8.5.2 Bureau of Mines testing procedures 8.5.3 Unloading techniques and equipment Batch treatment Continuous treatment 8.5.4 Determining surface surfactant concentration 8.5.6 Chemical treatment problems Emulsion problems Foam carryover8.6 Summary8.7 References Chapter 9: Hydraulic Pumps9.1 Introduction9.2 Advantages and Disadvantages9.3 The 1 ¼" Jet Pump9.4 System Comparative Costs9.5 Hydraulic Pump Case Histories9.6 Summary9.7 ReferencesChapter 10: Use of Beam Pumps to De-Liquefy Gas Wells10.1 Introduction10.2 Basics of Beam Pump Operation10.3 Pump-Off Control 10.3.1 Design rate with pump-off control 10.3.2 Use of surface indications for pump-off control10.4 Gas Separation to Keep Gas Out Of the Pump 10.4.1 Set pump below the perforations 10.4.2 "Poor-boy", or limited-entry gas separator 10.4.3 Collar sized separator10.5 Handling Gas through the Pump 10.5.1 Compression ratio 10.5.2 Variable slippage pump to prevent gas lock 10.5.3 Pump compression with dual chambers 10.5.4 Pumps that open the traveling valve mechanically 10.5.5 Pumps to take the fluid load off the traveling valve10.6 Inject Liquids below a Packer10.7 Other Problems Indicated By the Shape of the Pump Card10.8. Summary10.9 References Chapter 11: Gas Lift11.1 Introduction11.2 Continuous Gas Lift 11.2.1 Basic principles of continuous gas lift11.3 Intermittent Gas Lift11.4 Gas Lift System Components11.5 Continuous Gas Lift Design Objectives11.6 Gas Lift Valves 11.6.1 Orifice valves 11.6 2 Injection pressure operated (IPO) valves 11.6.3 Production pressure operated (PPO) valves11.7 Gas Lift Completions 11.7.1 Conventional gas lift design 11.7.2 Chamber lift installations 11.7.3 Horizontal well installations 11.7.4 Coiled tubing gas lift completions 11.7.5 A gas pump concept 11.7.6 Gas circulation11.8 Gas Lift without Gas Lift Valves11.9 Summary11.10 ReferencesChapter 12: Electrical Submersible Pumps12.1 Introduction12.2 The ESP System12.3 What Is A "Gassy" Well?12.4 Completions and Separators12.5 Injection of Produced Water12.6 Summary12.7 ReferencesChapter 13: Progressive Cavity Pumps13.1 Introduction13.2 PCP System Selection 13.2.1 Rotor 13.2.2 Stator 13.2.3 Surface drive 13.3 Selection and Operational Factors 13.3.1 Important factors for sizing the system 13.3.2 Steps to size the PCP13.4 Ancillary Equipment 13.4.1 Flow detection devices Flow meters Differential pressure switches Thermal dispersion devices 13.4.2 Rod guides 13.4.3 Gas separators 13.4.4 Tubing anchor/catcher13.5 Trouble Shooting PCP Systems13.6 Summary13.7 ReferencesChapter 14: Other Methods to Attack Liquid Loading Problems14.1 Introduction14.2 Thermal Methods for Water of Condensation 14.2.1 Thermal lift 14.2.1 Thermal liner 14.2.3 Thermal Coating 14.2.4 With Packer Installed, Draw a Vacuum on the Annulus14.3 Cycling14.4 Tubing/Annulus Switching Control14.5 Tubing Flow Control14.6 Tubing Collar Inserts for Producing Below Critical Velocity14.7 Summary14.8 ReferencesAppendix A: Development of Critical Velocity EquationsA.1 IntroductionA.2 Equation SimplificationA.3 Turner EquationsA.4 Coleman et al. EquationsA.5 References Appendix B: Development of Plunger Lift EquationsB.1 IntroductionB.2 Minimum Casing PressureB.3 Maximum Casing PressureB.4 SummaryB.5 ReferencesAppendix C: Gas FundamentalsC.1 IntroductionC.2 Phase DiagramC3 Gas Apparent Molecular Weight and Specific GravityC.4 Gas LawC.5 Z FactorC.6 Gas Formation Volume FactorC.7 Pressure Increase in Static Column of GasC.8 Calculate the Pressure Drop in Flowing Dry Gas Well: Cullender and Smith MethodC.9 Pressure Drop in a Gas Well Producing LiquidsC.10 Gas Well Deliverability Expressions C.10.1 Backpressure equation C.10.2 Darcy equationC.11 References