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
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