Gas well deliquification : solution to gas well liquid loading problems

목차 (Table of Contents)

• CONTENTS
• Preface = xiii
• 1 Introduction = 1
• 1.1 Introduction = 1
• 1.2 Multiphase Flow In A Gas Well = 2
• 1.3 What Is Liquid Loading? = 4
• 1.4 Problems Caused By Liquid Loading = 5
• 1.5 Deliquefying Techniques = 6
• 1.6 Source of Liquids In A Producing Gas Well = 8
• 1.6.1 Water Coning = 8
• 1.6.2 Aquifer Water = 8
• 1.6.3 Water Produced from Another Zone = 8
• 1.6.4 Free Formation Water = 9
• 1.6.5 Water of Condensation = 9
• 1.6.6 Hydrocarbon Condensates = 9
• References = 11
• 2 Recognizing Symptoms of Liquid Loading in Gas Wells = 13
• 2.1 Introduction = 13
• 2.2 Presence of Orifice Pressure Spikes = 14
• 2.3 Decline Curve Analysis = 14
• 2.4 Drop in Tubing Pressure with Rise in Casing Pressure = 15
• 2.5 Pressure Survey Showing Tubing Liquid Level = 18
• 2.6 Well Performance Monitoring = 21
• 2.7 Annulus Heading = 21
• 2.7.1 Heading Cycle without Packer = 21
• 2.7.2 Heading Cycle Controls = 23
• 2.8 Liquid Production Ceases = 25
• 2.9 Summary = 25
• References = 26
• 3 Critical Velocity = 27
• 3.1 Introduction = 27
• 3.2 Critical Flow Concepts = 27
• 3.2.1 Turner Droplet Model = 27
• 3.2.2 Critical Rate = 30
• 3.2.3 Critical Tubing Diameter = 31
• 3.2.4 Critical Rate for Low Pressure Wells-Coleman Model = 31
• 3.2.5 Critical Flow Nomographs = 34
• 3.3 Critical Velocity at Depth = 38
• 3.4 Critical Velocity in Horizontal Well Flow = 40
• References = 41
• 4 Systems Nodal Analysis = 43
• 4.1 Introduction = 43
• 4.2 Tubing Performance Curve = 45
• 4.3 Reservoir Inflow Performance Relationship(IPR) = 46
• 4.3.1 Gas Well Backpressure Equation = 47
• 4.3.2 Future IPR Curve with Backpressure Equation = 49
• 4.4 Intersections of the Tubing Curve and the Deliverability Curve = 49
• 4.5 Tubing Stability and Flowpoint = 52
• 4.6 Tight Gas Reservoirs = 53
• 4.7 Nodal Example-Tubing Size = 54
• 4.8 Nodal Example-Surface Pressure Effects : Use Compression to Lower Surface Pressure = 55
• 4.9 Summary Nodal Example of Developing IPR from Test Date with Tubing Performance = 56
• 4.10 Summary = 60
• References = 60
• 5 Sizing Tubing = 61
• 5.1 Introduction = 61
• 5.2 Advantages and Disadvantages of Smaller Tubing = 61
• 5.3 Concepts Required to Size Smaller Tubing = 62
• 5.3.1 Critical Rate at Surface Conditions = 65
• 5.3.2 Critical Rate at Bottomhole Conditions = 65
• 5.3.3 Summary of Tubing Design Concepts = 66
• 5.4 Sizing Tubing without IPR Information = 67
• 5.5 Field Example No. 1 - Results of Tubing Changeout = 69
• 5.6 Field Example No. 2 - Results of Tubing Changeout = 69
• 5.7 Pre- and Post-Evaluation = 71
• 5.8 Where to Set the Tubing = 72
• 5.9 Hanging Off Smaller Tubing from the Current Tubing = 74
• 5.10 Summary = 76
• References = 76
• 6 Compression = 79
• 6.1 Introduction = 79
• 6.2 Nodal Example = 80
• 6.3 Compression with a Tight Gas Reservoir = 81
• 6.4 Compression with Plunger Lift Systems = 82
• 6.5 Compression with Beam Pumping Systems = 84
• 6.6 Compression with Electric Submersible Systems = 85
• 6.7 Types of Compressors = 85
• 6.7.1 Rotary Lobe Compressor = 86
• 6.7.2 Re-Injected Rotary Lobe Compressor = 86
• 6.7.3 Rotary Vane Compressor = 86
• 6.7.4 Liquid Ring Compressor = 87
• 6.7.5 Liquid Injected Rotary Screw Compressor = 87
• 6.7.6 Reciprocating Compressor = 88
• 6.7.7 Sliding Vane Compressor = 89
• 6.8 Gas Jet Compressors or Eductors = 90
• 6.9 Summary = 92
• References = 93
• 7 Plunger Lift = 95
• 7.1 Introduction = 95
• 7.2 Plungers = 97
• 7.3 Plunger Cycle = 99
• 7.4 Plunger Lift Feasibility = 100
• 7.4.1 GLR Rule of Thumb = 101
• 7.4.2 Feasibility Charts = 102
• 7.4.3 Maximum Liquid Production with Plunger Lift = 105
• 7.4.4 Plunger Lift with Packer Installed = 106
• 7.4.5 Plunger Lift Nodal Analysis = 107
• 7.5 Plunger System Line-Out Procedure = 108
• 7.5.1 Considerations Before Kickoff = 109
• 7.5.2 Kickoff = 111
• 7.5.3 Cycle Adjustment = 112
• 7.5.4 Stabilization Period = 113
• 7.5.5 Optimization = 113
• 7.5.6 Monitoring = 115
• 7.6 Problem Analysis = 116
• 7.6.1 Motor Valve = 118
• 7.6.2 Controller = 121
• 7.6.3 Arrival Transducer = 123
• 7.6.4 Wellhead Leaks = 124
• 7.6.5 Catcher Not Functioning = 124
• 7.6.6 Pressure Sensor Not Functioning = 125
• 7.6.7 Control Gas to Stay on Measurement Chart = 126
• 7.6.8 Plunger Operations = 126
• 7.6.9 Head Gas Bleeding Off Too Slowly = 133
• 7.6.10 Head Gas Creating Surface Equipment Problems = 134
• 7.6.11 Low Production = 135
• 7.6.12 Well Loads up Frequently = 135
• 7.7 New Plunger Concept = 136
• 7.8 Operation with Weak Wells = 138
• 7.8.1 Casing Plunger for Weak Wells = 138
• 7.8.2 Plunger with Side String : Low Pressure Well Production = 142
• 7.9 Plunger Summary = 144
• References = 144
• 8 Use of Foam to Deliquefy Gas Wells = 147
• 8.1 Introduction = 147
• 8.2 Liquid Removal Process = 148
• 8.2.1 Surface De-Foaming = 150
• 8.3 Foam Selection = 150
• 8.4 Foam Basics = 153
• 8.4.1 Foam Generation = 153
• 8.4.2 Foam Stability = 153
• 8.4.3 Surfactant Types = 155
• 8.4.4 Foaming with Brine／Condensate Mixtures = 158
• 8.5 Operating Considerations = 163
• 8.5.1 Surfactant Selection = 163
• 8.5.2 Bureau of Mines Testing Procedures = 163
• 8.5.3 Unloading Techniques and Equipment = 166
• 8.5.4 Determining Surface Surfactant Concentration = 169
• 8.5.5 Instrumentation = 173
• 8.5.6 Chemical Treatment Problems = 173
• 8.6 Summary = 174
• References = 175
• 9 Hydraulic Pumps = 177
• 9.1 Introduction = 177
• 9.2 Advantages and Disadvantages = 182
• 9.3 The 1 1／4-Inch Jet Pump = 185
• 9.4 System Comparative Costs = 188
• 9.5 Hydraulic Pump Case Histories = 188
• 9.6 Summary = 189
• References = 189
• 10 Use of Beam Pumps to Deliquefy Gas Wells = 191
• 10.1 Introduction = 191
• 10.2 Basics of Beam Pump Operation = 193
• 10.3 Pump-Off Control = 195
• 10.3.1 Design Rate with Pump-Off Control = 196
• 10.3.2 Use of Surface Indications for Pump-Off Control = 197
• 10.4 Gas Separation to Keep Gas Out of the Pump = 199
• 10.4.1 Set Pump Below the Perforations = 200
• 10.4.2 "Poor-Boy" or Limited-Entry Gas Separator = 201
• 10.4.3 Collar-Sized Separator = 202
• 10.5 Handling Gas through the Pump = 203
• 10.5.1 Compression Ratio = 204
• 10.5.2 Variable Slippage Pump to Prevent Gas-Lock = 206
• 10.5.3 Pump Compression with Dual Chambers = 206
• 10.5.4 Pumps that Open the Traveling Valve Mechanically = 206
• 10.5.5 Pumps to Take the Fluid Load Off the Traveling Valve = 206
• 10.6 Inject Liquids Below a Packer = 207
• 10.7 Other Problems Indicated by the Shape of the Pump Card = 209
• 10.8 Summary = 213
• References = 214
• 11 Gas Lift = 215
• 11.1 Introduction = 215
• 11.2 Continuous Gas Lift = 217
• 11.2.1 Basic Principles of Continuous Gas Lift = 217
• 11.3 Intermittent Gas Lift = 217
• 11.4 Gas Lift System Components = 218
• 11.5 Continuous Gas Lift Design Objectives = 220
• 11.6 Gas Lift Valves = 221
• 11.6.1 Orifice Valves = 222
• 11.6.2 IPO Valves = 222
• 11.6.3 PPO Valves = 223
• 11.7 Gas Lift Completions = 224
• 11.7.1 Conventional Gas Lift Design = 224
• 11.7.2 Chamber Lift Installations = 227
• 11.7.3 Horizontal Well Installations = 229
• 11.7.4 Coiled Tubing Gas Lift Completions = 231
• 11.7.5 Gas Pump Concept = 234
• 11.7.6 Gas Circulation = 235
• 11.8 Gas Lift without Gas Lift Valves = 235
• 11.9 Summary = 236
• References = 237
• 12 Electric Submersible Pumps = 239
• 12.1 Introduction = 239
• 12.2 ESP System = 240
• 12.3 What Is A "Gassy" Well? = 243
• 12.4 Completions and Separators = 245
• 12.5 Injection of Produced Water = 248
• 12.6 Summary = 248
• References = 250
• 13 Progressive Cavity Pumps = 251
• 13.1 Introduction = 251
• 13.2 PCP System Selection = 253
• 13.2.1 Rotor = 253
• 13.2.2 Stator = 254
• 13.2.3 Surface Drive = 257
• 13.3 Selection and Operational Factors = 257
• 13.3.1 Important Factors for Sizing the System = 257
• 13.3.2 Steps to Size the PCP = 259
• 13.4 Ancillary Equipment = 263
• 13.4.1 Flow Detection Devices = 264
• 13.4.2 Rod Guides = 265
• 13.4.3 Gas Separators = 265
• 13.4.4 Tubing Anchor／Catcher = 266
• 13.5 Troubleshooting PCP Systems = 266
• 13.6 Summary = 268
• References = 268
• 14 Other Methods to Attach Liquid-Loading Problems = 271
• 14.1 Introduction = 271
• 14.2 Thermal Methods for Water of Condensation = 271
• 14.2.1 Thermal Lift = 273
• 14.2.2 Thermal Liner = 276
• 14.2.3 Thermal Coatings／Liners = 277
• 14.2.4 With Packer Installed, Draw a Vacuum on the Annulus = 278
• 14.3 Cycling = 278
• 14.4 Tubing／Annulus Switching Control = 279
• 14.5 Tubing Flow Control = 280
• 14.6 Tubing Collar Inserts for Producing Below Critical Velocity = 281
• 14.7 Summary = 282
• References = 282
• Appendix A : Development of Critical Velocity Equations = 283
• A.1 Introduction = 283
• A.1.1 Physical Model = 283
• A.2 Equation Simplification = 286
• A.3 Turner Equations = 287
• A.4 Coleman Equations = 287
• References = 288
• Appendix B : Development of Plunger Lift Equations = 289
• B.1 Introduction = 289
• B.2 Minimum Casing Pressure = 289
• B.3 Maximum Casing Pressure = 291
• B.4 Summary = 291
• Reference = 292
• Appendix C : Gas Fundamentals = 293
• C.1 Introduction = 293
• C.2 Phase Diagram = 293
• C.3 Gas Apparent Molecular Weight and Specific Gravity = 293
• C.4 Gas Law = 295
• C.5 Z Factor = 296
• C.6 Gas Formation Volume Factor = 298
• C.7 Pressure Increase in Static Column of Gas = 299
• C.8 Calculate the Pressure Drop in Flowing Dry Gas Well : Cullender and Smith Method = 300
• C.9 Pressure Drop in a Gas Well Producing Liquids = 302
• C.9.1 Calculated Result with Dry Gas and Gas with Liquids = 303
• C.10 Gas Well Deliverability Expressions = 303
• C.10.1 Backpressure Equation = 303
• C.10.2 Darcy Equation = 305
• References = 307
• Index = 309