Gas well deliquification / James F. Lea, Jr., Lynn Rowlan.

Format:

Book

Author/Creator:

Lea, James F., Jr., author.

Rowlan, Lynn, author.

Language:

English

Subjects (All):

Gas wells.

Physical Description:

1 online resource (494 pages)

Edition:

Third edition.

Place of Publication:

Cambridge, Massachusetts ; Oxford, England : Gulf Professional Publishing, 2019.

Summary:

Gas Well Deliquification, Third Edition, expands upon previous experiences and applies today's more applicable options and technology. Updated to include more information on automation, nodal analysis, and horizontal gas well operations, this new edition provides engineers with key information in one central location. Multiple contributors from today's operators offer their own learned experiences, critical equipment, and rules of thumb for practicality. Covering the entire lifecycle of the well, this book will be an ideal reference for engineers who need to know the right solutions regarding a well's decline curve in their work to continuously optimize assets.- Teaches users how to understand the latest methods of deliquifying gas wells, from nodal analysis, to various forms of artificial lift- Provides an up-to-date reference on automation techniques for today's operations, including horizontal wells- Presents various perspectives contributed from multiple sources, allowing readers to select the best method for a well's lifecycle

Contents:

Front Cover

Gas Well Deliquification

Copyright Page

Contents

1 Introduction

1.1 Introduction

1.2 Multiphase flow in a gas well

1.3 Liquid loading

1.4 Deliquification techniques

1.5 Most used systems for deliquification

Reference

Further reading

2 Recognizing symptoms of liquid loading in gas wells

2.1 Introduction

2.2 Predictive indications of liquid loading

2.2.1 Predict or verify liquid loading using critical velocity correlations, Nodal Analysis, and multiphase flow regimes

Critical velocity

Use of Nodal Analysis to predict if flow is above/below critical

Multiphase flow regimes

2.3 Field symptoms of liquid loading

2.3.1 Increase in difference between surface values of casing and tubing pressures

2.3.2 Pressure survey showing liquid level

2.3.3 Appearance of slug flow at surface of well

2.3.4 Acoustic fluid level measurements in gas wells (Echometer)

A Type 1 well

A Type 2 well

A Type 3 well

2.3.5 Determining well performance from a fluid shot

2.4 Summary

3 Critical velocity

3.1 Introduction

3.2 Critical flow concepts

3.2.1 Turner droplet model

3.3 Critical velocity at depth

3.4 Critical velocity with deviation

References

4 Nodal Analysis

4.1 Introduction

4.2 Nodal example showing liquid loading and solutions

4.2.1 Liquid-loaded well

4.2.2 Solutions to the loading situation

Smaller tubing as solution

Compression as a solution

Using chokes as solution

Inject gas to stabilize

Use foam to stabilize

Plunger to unload

Pumped-off pumping well to unload- Use of pumps to lift the liquids

4.3 Summary

5 Compression

5.1 Introduction

5.2 Compression horsepower and critical velocity

5.3 Systems Nodal Analysis and compression.

5.4 The effect of permeability on compression

5.5 Pressure drop in compression suction

5.6 Wellhead versus centralized compression

5.7 Developing a compression strategy using Integrated Production Modeling

5.8 Downstream gathering and compression's effect on uplift from deliquifying individual gas wells

5.9 Compression alone as a form of artificial lift

5.10 Compression with foamers

5.11 Compression and gas lift

5.12 Compression with plunger lift systems

5.13 Compression with beam pumping systems

5.14 Compression with electric submersible pump systems

5.15 Types of compressors

5.15.1 Liquid injected rotary screw compressor

5.15.2 Reciprocating compressor

5.16 Gas jet compressors or ejectors

5.17 Other compressors

5.18 Centrifugal compressors

5.19 Natural gas engine versus electric compressor drivers

5.20 Optimizing compressor operations

5.21 Unconventional wells

5.22 Summary

6 Plunger lift

6.1 Introduction

6.2 Plunger cycles

6.2.1 The continuous plunger cycle

6.2.2 The conventional plunger cycle

6.2.3 When to use the continuous/conventional plunger cycle

6.2.4 Additional plunger types

6.3 Plunger lift feasibility

6.3.1 Gas/liquid ratio rule of thumb

6.3.2 Feasibility charts

6.3.3 Maximum liquid production with plunger lift

Plunger lift with packer installed

Plunger lift nodal analysis

6.4 Plunger system line-out procedure

6.4.1 Considerations before kickoff

Load factor

Kickoff

Cycle adjustment

Stabilization period

6.5 Optimization

6.5.1 Oil well optimization

6.5.2 Gas well optimization

6.5.3 Optimizing cycle time

6.6 Monitoring and troubleshooting

6.6.1 Decline curve

6.6.2 Supervisory control and data acquisition data

6.6.3 Some common monitoring rules.

6.6.4 Tracking plunger fall and rise velocities in well

Plunger fall velocity

Methods to determine plunger fall velocity

Plunger rise velocity in well

Measurement of rise velocity profiles

6.7 Controllers

6.8 Problem analysis

6.9 Operation with weak wells

6.9.1 Progressive/staged plunger system

6.9.2 Casing plunger for weak wells

6.9.3 Gas-assisted plunger

6.9.4 Plunger with side string: low-pressure well production

6.10 Summary

7 Hydraulic pumping

7.1 Introduction

7.2 Application to well deliquification-gas, coal bed methane, and frac fluid removal

7.3 Jet pumps

7.4 Piston pumps

7.5 Summary

8 Liquid unloading using chemicals for wells and pipelines

8.1 Introduction

8.2 Chemical effects aiding foam formation

8.2.1 Surface tension

8.2.2 Foam formation and foam density measurement

8.3 Flow regime modification and candidate identification

8.4 Application of surfactants in field systems

8.5 Surfactant application for increased ultimate recovery

8.6 Summary and conclusion

9 Progressing cavity pumps

9.1 Introduction

9.2 The progressing cavity pumping system

9.3 Water production

9.4 Gas production

9.5 Handling of sand/solids/fines

9.6 Critical flow velocity

9.7 Design and operational considerations

9.8 Implications of pump setting depth

9.8.1 Open-hole completion

9.8.2 Cased-hole completion

9.8.3 Presence of CO2 and its effects

9.9 Selection of progressing cavity pumps

9.10 Elastomer selection

10 Use of beam pumps to deliquefy gas wells

10.1 Introduction

10.1.1 The surface unit

10.1.2 Wellhead

10.1.3 Polish rods

10.1.4 Sucker rods and sinker rods

10.1.5 Sinker bars

10.1.6 Pumps

10.1.7 Pump-off controls.

10.2 Beam system components and basics of operations

10.2.1 Prime movers

10.2.2 Belts and sheaves

10.2.3 The gearbox

10.3 Design basics for SRP pumping

10.3.1 Example designs

10.3.2 Rod designs with dog leg severity present

10.3.3 Sinker bars

10.3.4 Design with pump-off control

Variable speed drive pump-off control

10.4 Handling gas through the pump

10.4.1 Gas lock or loss of valve action: summary

10.5 Gas separation

10.5.1 Principle of gas separation

Maximum liquid rate such that gas separation can be possible

Poor boy separator

10.5.2 Casing separator with dip tube: for use in horizontal wells

10.5.3 Compression ratio

10.5.4 Variable slippage pump to prevent gas lock

10.5.5 Pump compression with dual chambers

10.5.6 Pumps that open the traveling valve mechanically

10.5.7 Pumps to take the fluid load off the traveling valve

10.5.8 Gas Vent Pump to separate gas and prevent gas lock (Source: B. Williams, HF Pumps.)

10.6 Inject liquids below a packer

10.7 Summary

11 Gas lift

11.1 Introduction

11.2 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 valves

11.6.3 Production pressure operated valves

11.7 Gas lift completions

11.7.1 Conventional gas lift design

11.7.2 Chamber lift installations

11.7.3 Intermittent lift and/or gas-assisted plunger lift

11.7.4 Horizontal or unconventional wells

11.7.5 Examples of using gas lift to deliquefy gas wells

11.7.6 Horizontal unconventional well

11.8 Single-point/high-pressure gas lift4

11.9 Gas lift summary

12 Electrical submersible pumps

12.1 Introduction.

12.2 The electric submersible pump motor

12.2.1 Electric submersible pump induction and permanent magnet motor RPM

12.2.2 Electric submersible pump motor voltage variation effects

12.2.3 Defining electric submersible pump motor frame sizes

12.2.4 Electric submersible pump motor, or frame, winding temperature

12.2.5 Electric submersible pump motor insulation life

12.2.6 Applying the National Electrical Manufactures Association method to the electric submersible pump motor's class N in...

12.2.7 Electric submersible pump motor insulation life-sensitivities

12.3 Electric submersible pump seals

12.3.1 The labyrinth seal

12.3.2 Positive barrier or bag seal

12.3.3 Seal thrust bearing

12.3.4 Seal horsepower requirement

12.4 Electric submersible pump intakes

12.4.1 Standard intake

12.4.2 Determining the gas volume fraction

12.4.3 Estimating natural separation efficiency

12.4.4 Estimating the probability of stage head degradation

12.4.5 Avoiding the gas-intake below the production interval-motor shrouded intake

12.4.6 Avoiding the gas-intake below the production interval-recirculating system

12.4.7 Avoiding the gas-intake below the production interval-permanent magnet motor without cooling

12.4.8 Avoiding the gas-intake above the production interval-motor shrouded intake or pod with a tail pipe or dip tube

12.4.9 Avoiding the gas-intake above/below the production interval-encapsulated system

12.4.10 Avoiding the gas-intake above the production interval-pump shrouded intake-upside-down shroud

12.4.11 Removing the gas-gas separators-rotary gas separator

12.4.12 Removing the gas-gas separators-vortex gas separator

12.5 Electric submersible pumps

12.5.1 The pump stage

12.5.2 Pump radial flow stages

12.5.3 Pump mixed flow stages

12.5.4 Pump gas handler stage.

12.5.5 Pump gas handler helico-axial stage.

Notes:

Description based on print version record.

ISBN:

0-12-816216-3

0-12-815897-2