Gas Well Deliquification
Solutions to Gas Well Liquid Loading Problems
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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.
Key Features
* Only book on market to offer a turnkey solution to the problem of liquid interference in gas wells
* Contains descriptions of the various methods of de-watering gas wells, as well as comparing the various methods with a view to explaining the suitability of each under particular circumstances
* Introduces material as practical information that can be immediately applied, rather than a theoretical treatment.
* Contains descriptions of the various methods of de-watering gas wells, as well as comparing the various methods with a view to explaining the suitability of each under particular circumstances
* Introduces material as practical information that can be immediately applied, rather than a theoretical treatment.
Readership
Operating engineers and reservoir engineers, consulting engineers, service companies that supply equipment for gas wells, academic market
Table of Contents
- 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
7.5.1.1 Load factor
7.5.2 Kickoff
7.5.3 Cycle adjustment
7.5.4 Stabilization period
7.5.5 Optimization
7.5.5.1 Oil well optimization
7.5.5.2 Gas well optimization
7.5.5.3 Optimizing cycle time
7.5.6 Monitoring
7.6 Problem Analysis
7.6.1 Motor Valve
7.6.1.1 Valve leaks
7.6.1.2 Valve won't open
7.6.1.3 Valve won't close
7.6.2 Controller
7.4.2.1 Electronics
7.4.2.2 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
7.6.8.1 Plunger won't fall
7.6.8.2 Plunger won't surface
7.6.8.3 Plunger travel too slow
7.6.8.4 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
8.4.3.1 Nonionic surfactants
8.4.3.2 Anionic surfactants
8.4.3.3 Cationic surfactants
8.4.3.4 Foaming agents for hydrocarbons
8.4.4 Foaming with brine/condensate mixtures
8.4.4.1 Effect of condensate (aromatic) fraction
8.4.4.2 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
8.5.3.1 Batch treatment
8.5.3.2 Continuous treatment
8.5.4 Determining surface surfactant concentration
8.5.6 Chemical treatment problems
8.5.6.1 Emulsion problems
8.5.6.2 Foam carryover
8.6 Summary
8.7 References
Chapter 9: Hydraulic Pumps
9.1 Introduction
9.2 Advantages and Disadvantages
9.3 The 1 ¼" 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", or limited-entry gas separator
10.4.3 Collar sized separator
10.5 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 valve
10.6 Inject Liquids below a Packer
10.7 Other Problems Indicated By the Shape of the Pump Card
10.8. Summary
10.9 References
Chapter 11: Gas Lift
11.1 Introduction
11.2 Continuous Gas Lift
11.2.1 Basic principles of continuous gas lift
11.3 Intermittent Gas Lift
11.4 Gas Lift System Components
11.5 Continuous Gas Lift Design Objectives
11.6 Gas Lift Valves
11.6.1 Orifice valves
11.6 2 Injection pressure operated (IPO) valves
11.6.3 Production pressure operated (PPO) valves
11.7 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 circulation
11.8 Gas Lift without Gas Lift Valves
11.9 Summary
11.10 References
Chapter 12: Electrical Submersible Pumps
12.1 Introduction
12.2 The ESP System
12.3 What Is A "Gassy" Well?
12.4 Completions and Separators
12.5 Injection of Produced Water
12.6 Summary
12.7 References
Chapter 13: Progressive Cavity Pumps
13.1 Introduction
13.2 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 PCP
13.4 Ancillary Equipment
13.4.1 Flow detection devices
13.4.1.1 Flow meters
13.4.1.2 Differential pressure switches
13.4.1.3 Thermal dispersion devices
13.4.2 Rod guides
13.4.3 Gas separators
13.4.4 Tubing anchor/catcher
13.5 Trouble Shooting PCP Systems
13.6 Summary
13.7 References
Chapter 14: Other Methods to Attack Liquid Loading Problems
14.1 Introduction
14.2 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 Annulus
14.3 Cycling
14.4 Tubing/Annulus Switching Control
14.5 Tubing Flow Control
14.6 Tubing Collar Inserts for Producing Below Critical Velocity
14.7 Summary
14.8 References
Appendix A: Development of Critical Velocity Equations
A.1 Introduction
A.2 Equation Simplification
A.3 Turner Equations
A.4 Coleman et al. Equations
A.5 References
Appendix B: Development of Plunger Lift Equations
B.1 Introduction
B.2 Minimum Casing Pressure
B.3 Maximum Casing Pressure
B.4 Summary
B.5 References
Appendix C: Gas Fundamentals
C.1 Introduction
C.2 Phase Diagram
C3 Gas Apparent Molecular Weight and Specific Gravity
C.4 Gas Law
C.5 Z Factor
C.6 Gas Formation Volume Factor
C.7 Pressure Increase in Static Column of Gas
C.8 Calculate the Pressure Drop in Flowing Dry Gas Well: Cullender and Smith Method
C.9 Pressure Drop in a Gas Well Producing Liquids
C.10 Gas Well Deliverability Expressions
C.10.1 Backpressure equation
C.10.2 Darcy equation
C.11 References
Product details
- No. of pages: 314
- Language: English
- Copyright: © Gulf Professional Publishing 2003
- Published: July 21, 2003
- Imprint: Gulf Professional Publishing
- eBook ISBN: 9780080477985
About the Authors
James Lea
James F. Lea, Jr. is currently an independent consultant for both academic and corporate facilities aiding in production projects and teaching seminars. He was previously the Chair of the petroleum engineering department of Texas Tech University, where he taught since 1999. Previous to his teaching experience, Dr. Lea worked in the industry for 20 years for Amoco as a special research associate and team leader of the optimization and production group. He taught at the University of Arkansas from 1975 to 1978, and before that he worked as a senior research engineer at the famed Sun Oil Company in Richardson, Texas. Dr. Lea holds 8 patents, has co-authored 2 books, and was awarded the SPE Lifetime Achievement Award as a "Legend of Artificial Lift". Dr. Lea earned a BSME and MSME from the University of Arkansas and a PhD from Southern Methodist University. He is a member of the Society of Petroleum Engieers and ASME.
Affiliations and Expertise
Independent Consultant, PLTech LLC, Texas, USA
Henry Nickens
Affiliations and Expertise
BP, TX, USA
Mike Wells
Urgentiste, Professeur et consultant, Division of Emergency Medicine, University of Witwatersrand, et Netcare Union Hospital Emergency Department, Johannesbourg, Afrique du Sud
Affiliations and Expertise
Professor and Chairman, Department of Pathology, University of Sheffield, Sheffield, UK
PLUERE Inc., CO, USA
Specialist Emergency Physician, Lecturer and Consultant, Director of Emergency Ultrasound Training, Division of Emergency Medicine, Faculty of Health, University of Witwatersrand, Johannesburg, South Africa; Netcare Union Hospital Emergency Department, Johannesburg, South Africa
Ratings and Reviews
Latest reviews
(Total rating for all reviews)
Anonymous Thu Nov 01 2018
Great Book!
This book is very educational; I learned a lot about the de-watering process! Nevermind that I didn't read it, but I'm sure if I did, it wouldn't be too hard of a read. Easy to get through, too! Great job!