دانلود کتاب Gas Well Deliquification

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Gas Well Deliquification
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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
Further reading
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
Further reading
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
Further reading
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
References
Further reading
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
References
Further reading
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
Further reading
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
References
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
Further reading
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
References
Further reading
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
References
Further reading
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
12.5.6 Pump performance curve, mixed and radial flow stages
12.5.7 Pump performance curve, helico-axial stage
12.5.8 Pump performance curve changes with changes in impeller RPM
12.5.9 Pump stage thrust
12.5.10 Floater pump construction
12.5.11 Compression pump construction
12.5.12 Abrasion resistant modular construction
12.5.13 Designing a pump for gas handling
Tapered pump design
Tapered pump including the helico-axial stage (gas handler) design
12.6 Summary
12.6.1 ESP motors
12.6.2 ESP seals
12.6.3 ESP intakes
12.6.4 ESP pumps
References
13 Coal bed methane (CBM) and shale
13.1 Introduction
13.1.1 History
13.1.2 Economic impact
13.2 Organic reservoirs
13.2.1 Reservoir characteristics
13.2.2 Flow within an organic reservoir
13.2.3 Adsorption site contamination
13.2.4 Coal mechanical strength
13.3 Organic reservoir production
13.3.1 Deliquification plan
Initial deliquification
Mid-life deliquification
Late-life deliquification
13.3.2 Wellsite and gathering plan
Initial system layout
Water strategy
13.4 Pressure targets with time
13.4.1 Wellbore
13.4.2 Flow lines
13.4.3 Separation
13.4.4 Compression
13.4.5 Deliquification
References
14 Production automation
14.1 Introduction
14.2 Brief history
14.2.1 Wellsite intelligence
14.2.2 Desktop intelligence
14.2.3 Communications
14.2.4 System architecture
14.3 Automation equipment
14.3.1 Instrumentation
14.3.2 Electronic flow measurement
System description
Algorithms
Sampling frequency
Data availability
Audit and reporting requirements
Equipment installation
Equipment calibration/verification
Security
14.3.3 Controls
Automatically controlled valves and accessories
Fluid-controlled valves
Electrically controlled valves
Production safety controls
Motor controllers
Switchboards
Variable frequency drives
14.3.4 Remote terminal units and programmable logic controllers
Remote terminal units
Programmable logic controllers
14.3.5 Host systems
General automation systems
Equipment-specific systems
Home-grown systems
Generic oil and gas systems
14.3.6 Communications
Instrument to remote terminal unit
Remote terminal unit to host
Host to users
Host to computer systems
Computer systems to users
14.3.7 Database
Overview
Database models and schema
Storage
Indexing
Real-time databases
FIFO
Historians
14.3.8 Other
14.4 General applications
14.4.1 User interface
14.4.2 Scanning
14.4.3 Alarming
Class I alarms
Class II alarms
Class III alarms
14.4.4 Reporting
Current reports
Daily reports
Historical reports
Special reports
Unique application reports
14.4.5 Trending and plotting
14.4.6 Displays
Unique
Generic
Static
Dynamic
Interactive
14.4.7 Data historians
14.5 Unique applications for gas well deliquification and oil well production
14.5.1 Plunger lift
Measurements
Control
Unique hardware
Unique software
On pressure limit control
Off pressure limit control
Specialized alarms
Surveillance
Analysis
Design
Optimization
Safety
14.5.2 Sucker rod pumping
Measurements
Control
Unique hardware
Unique software
Specialized alarms
Surveillance
Analysis
Design
Optimization
Use of sucker rod pumping on highly deviated or horizontal wells
14.5.3 Progressive cavity pumping
Measurements
Control
Unique hardware
Unique software
Specialized alarms
Surveillance
Analysis
Design and optimization
14.5.4 Electrical submersible pumping
Measurements
Control
Start, stop, and safety shutdown
Control of wells with FSDs
Control of wells with VSDs
Control of wells on start-up
Unique hardware
Unique software
Specialized alarms
Surveillance
Analysis
Design and optimization
14.5.5 Hydraulic pumping
Surveillance
Control
14.5.6 Chemical injection
Surveillance
Control
14.5.7 Gas-lift
Measurements
Control
Unique hardware
Unique software
Specialized alarms
Surveillance
Analysis
Design
Use of gas-lift in horizontal wells
Dual gas-lift
Optimization
14.5.8 Wellhead compression
Surveillance
Control
14.5.9 Heaters
Surveillance
Control
14.5.10 Cycling
Surveillance
Control
14.5.11 Production allocation
14.5.12 Other unique applications
14.6 Automation issues
14.6.1 Typical benefits
Tangible benefits
Intangible benefits
14.6.2 Potential problem areas
Automation system design
Instrumentation selection
Automation hardware and software selection
Environmental protection
Communications
Project team
Integration into the organization
14.6.3 Justification
The impact of time
Acceleration versus increased recovery
The role of “pilot” tests
14.6.4 Capital expenditure
14.6.5 Operational expense
14.6.6 Design
People
Process
Technology
14.6.7 Installation
14.6.8 Security
Field devices
Host systems
14.6.9 Staffing
Steering committee
Automation team
Surveillance team
14.6.10 Training
Aware
Knowledgeable
Skilled
14.6.11 Commercial versus “in-house”
14.7 Case histories
14.7.1 Success stories
Rod pump controllers
Plunger lift automation
Host system/workflow management
14.7.2 Failures
Beam pump optimization
Progressing cavity pump optimization
Gas-lift automation
14.7.3 Systems that have not reached their potential
14.8 Summary
Further reading
Section 14.2
Section 14.3.1
Section 14.3.2
Section 14.3.3
Section 14.3.6
Section 14.3.7
Section 14.3.8
Section 14.4.1
Section 14.4.3
Section 14.4.5
Section 14.4.6
Section 14.4.7
Section 14.5.1
Section 14.5.2
Section 14.5.3
Section 14.5.4
Section 14.5.5
Section 14.5.7
Section 14.5.9
Section 14.6.6
Section 14.6.9
Section 14.6.10
Appendix A Development of critical velocity equations
A.1 Introduction
A.1.1 Physical model
A.2 Equation simplification
A.3 Turner equations
A.4 Coleman et al. equations
References
Appendix B Nodal concepts and stability concerns*
B.1 Introduction
B.2 Tubing performance curve
B.3 Reservoir inflow performance relationship
B.3.1 Gas well inflow performance relationship equations
B.3.2 Future inflow performance relationship curves
B.4 Intersections of the tubing curve and the deliverability curve
B.5 Tubing stability and flowpoint
B.6 Tight gas reservoirs
B.7 Nodal example—tubing size
B.8 Summary
References
Appendix C Plunger troubleshooting procedures*
C.1 Motor valve
C.1.1 Valve leaks
C.1.2 Internal leaks
C.1.3 Valve will not open
C.1.4 Valve will not close
C.2 Controller
C.2.1 Electronics
C.2.2 Pneumatics
C.3 Arrival transducer
C.4 Wellhead leaks
C.5 Catcher not functioning
C.6 Pressure sensor not functioning
C.7 Control gas to stay on measurement chart
C.8 Plunger operations
C.8.1 Plunger will not fall
C.8.2 Plunger will not surface
C.8.3 Plunger travels too slow
C.8.4 Plunger travels too fast
C.8.5 Head gas bleeding off too slowly
C.8.6 Head gas creating surface equipment problems
C.8.7 Low production
C.8.8 Well loads up frequently
Reference
Appendix D Gas lift terminology
Index
Back Cover