Business & Economics

Publications » Engineering » General

Gas Well Deliquification

Price £48.99

temporarily out of stock

Gas Well Deliquification

James Lea, Henry Nickens, Mike Wells

ISBN 0750677244
Pages 314

No other book on the market offers such a turnkey solution to the problem of liquid interference in gas wells. Gas Well Deliquification contains not only descriptions of the various methods of de-watering gas wells, but also compares the various methods with a view toward explaining the suitability of each under particular circumstances. The material is presented as practical information that can be immediately applied, rather than a theoretical treatment. And, includes useful historical methods, but focuses on the latest techniques for de-watering gas wells.

Table of Contents: Chapter 1: Introduction 1.1 Introduction 1.2 Multiphase Flow In A Gas Well 1.3 What Is Liquid Loading? 1.4 Problems Caused By Liquid Loading 1.5 De-Liquefying Techniques Presented 1.6 Source Of Liquids In A Producing Gas Well 1.6.1 Water coning 1.6.2 Aquifer water 1.6.3 Water produced from another zone 1.6.4 Free formation water 1.6.5 Water of condensation 1.6.6 Hydrocarbon condensates 1.7 References Chapter 2: Recognize Symptoms of Liquid Loading in Gas Wells 1.2 Introduction 2.2 Presence of Orifice Pressure Spikes 2.3 Decline Curve Analysis 2.4 Drop In Tubing Pressure with Rise in Casing Pressure 2.5 Pressure Survey Showing Liquid Level 2.6 Well Performance Monitoring 2.7 Annulus Heading 2.7.1 Heading cycle without packer 2.7.2 Heading cycle with controller 2.8 Liquid Production Ceases 2.9 Summary 2.10 References Chapter 3: Critical Velocity 3.1 Introduction 3.2 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 nomographs 3.3 Critical velocity at depth 3.4 Critical velocity in horizontal well flow 3.5 References Chapter 4: Systems Nodal Analysis 4.1 Introduction 4.2 Tubing Performance Curve 4.3 Reservoir Inflow Performance Relationship (IPR) 4.3.1 Gas well backpressure equation 4.3.2 Future IPR curve with backpressure equation 4.4 Intersections of the Tubing Curve and the Deliverability Curve 4.5 Tubing Stability and Flowpoint 4.6 Tight Gas Reservoirs 4.7 Nodal Example-Tubing Size 4.8 Nodal Example-Surface Pressure Effects: Use Compression to Lower Surface Pressure 4.9 Summary Nodal Example of Developing IPR from Test Data with Tubing Performance 4.10 Summary Chapter 5: Sizing Tubing 5.1 Introduction 5.2 Advantages/Disadvantages of Smaller Tubing 5.3 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 concepts 5.4 Sizing Tubing without IPR Information 5.5 Field Examples #1-Results Of Tubing Chang-Out 5.6 Field Examples #2-Results of Tubing Change-Out 5.7 Pre/Post Evaluation 5.8 Where to Set the Tubing 5.9 Hanging off Smaller Tubing from the Current Tubing 5.10 Summary 5.11 References Chapter 6: Compression 6.1 Introduction 6.2 Nodal Example 6.3 Compression with a Tight Gas Reservoir 6.4 Compression with Plunger Lift Systems 6.5 Compression with Beam Pumping Wells 6.6 Compression with ESP Systems 6.7 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 compressor 6.8 Gas Jet Compressors or Eductors 6.9 Summary 6.10 References Chapter 7: Plunger Lift 7.1 Introduction 7.2 Plunger 7.3 Plunger Cycle 7.4 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 Analysis 7.5 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 Monitoring 7.6 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 frequently 7.7 New Plunger Concept 7.8 Casing Plunger for Weak Wells 7.9 Plunger with Side String: Low Pressure Well Production 7.10 Plunger Summary 7.11 References Chapter 8: Use Of Foam to De-Liquefy Gas Wells 8.1 Introduction 8.2 Liquid Removal Process 8.2.1 Surface de-foaming 8.3 Foam Selection 8.4 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 brine 8.5 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 carryover 8.6 Summary 8.7 References Chapter 9: Hydraulic Pumps 9.1 Introduction 9.2 Advantages and Disadvantages 9.3 The 1 Jet Pump 9.4 System Comparative Costs 9.5 Hydraulic Pump Case Histories 9.6 Summary 9.7 References Chapter 10: Use of Beam Pumps to De-Liquefy Gas Wells 10.1 Introduction 10.2 Basics of Beam Pump Operation 10.3 Pump-Off Control 10.3.1 Design rate with pump-off control 10.3.2 Use of surface indications for pump-off control 10.4 Gas Separation to Keep Gas Out Of the Pump 10.4.1 Set pump below the perforations 10.4.2 'Poor-boy'