Natural Gas Hydrates: A Guide for Engineers

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Natural Gas Hydrates: A Guide for Engineers
Copyright
Dedication
Preface to the fourth edition
Preface to the third edition
Preface to the second edition
Preface to the first edition
Acknowledgments
1 - Introduction
	1.1 What is water?
	1.2 Natural gas
		1.2.1 Sales gas
		1.2.2 Hydrates
	1.3 The water molecule
		1.3.1 The normal boiling point of water
		1.3.2 Enthalpy of vaporization
		1.3.3 Expansion upon freezing
		1.3.4 The shape of the water molecule and the hydrogen bond
	1.4 Hydrates
		1.4.1 Temperature and pressure
	1.5 Water and natural gas
		1.5.1 Free-water
	1.6 Heavy water
	1.7 The hydrate toolbox
	1.8 Additional reading
	1.9 Units
	1.10 Quantifying error
	References
	Bibliography
2 - Hydrate types and formers
	2.1 Type I hydrates
		2.1.1 Type I formers
	2.2 Type II hydrates
		2.2.1 Type II formers
	2.3 Type H hydrates
		2.3.1 Type H formers
	2.4 The size of the guest molecule
		2.4.1 n-Butane
	2.5 Other hydrocarbons
	2.6 Cyclopropane
	2.7 2-Butene
	2.8 Mercaptans
		2.8.1 Methyl mercaptan
		2.8.2 Others
	2.9 Hydrogen and helium
	2.10 Chemical properties of potential guests
	2.11 Liquid hydrate formers
	2.12 Hydrate forming conditions
		2.12.1 Pressure-temperature
		2.12.2 Composition
		2.12.3 Caution
		2.12.4 Nitrogen
		2.12.5 Ethylene
		2.12.6 Propylene
		2.12.7 Methyl mercaptan
	2.13 V+LA+H correlations
		2.13.1 Ethylene
	2.14 LA+LN+H correlations
	2.15 Quadruple points
		2.15.1 Cyclopropane
	2.16 Other hydrate formers
		2.16.1 Freons
		2.16.2 Halogens
		2.16.3 Noble gases
		2.16.4 Air
		2.16.5 Others
	2.17 Hydrate formation at 0°C
	2.18 Mixtures
		2.18.1 Mixtures of the same type
		2.18.2 Type I plus Type II
		2.18.3 Azeotropy
		2.18.4 Mixtures with nonformers
		2.18.5 Petroleum
	References
	Appendix 2A Water Content of the Fluid in Equilibrium with Hydrate for Pure Components
3 - Hand calculation methods
	3.1 The gas gravity method
		3.1.1 Verifying the approach
			3.1.1.1 Molar mass
			3.1.1.2 Boiling point
			3.1.1.3 Density
			3.1.1.4 Discussion
	3.2 The K-Factor method
		3.2.1 Calculation algorithms
			3.2.1.1 Flash
			3.2.1.2 Incipient solid formation
		3.2.2 Liquid hydrocarbons
		3.2.3 Computerization
		3.2.4 Comments on the accuracy of the K-Factor method
			3.2.4.1 Ethylene
			3.2.4.2 Mann et al.
	3.3 Baillie-Wichert method
	3.4 Other correlations
		3.4.1 Makogon
		3.4.2 Kobayashi et al.
		3.4.3 Motiee
		3.4.4 Østergaard et al.
		3.4.5 Towler and Mokhatab
	3.5 Comments on all of these methods
		3.5.1 Water
		3.5.2 Nonformers
		3.5.3 Isobutane vs. n-Butane
		3.5.4 Quick comparison
			3.5.4.1 Mei et al. (1998)
			3.5.4.2 Fan and Guo (1999)
			3.5.4.3 Ng and Robinson (1976)
		3.5.5 Sour natural gas
			3.5.5.1 Ward et al. (2015)
	3.6 Local models
		3.6.1 Wilcox et al. (1941)
		3.6.2 Composition
			3.6.2.1 Sun et al.
	References
	Appendix Katz K-factor Charts
4.- Computer methods
	4.1 Phase equilibrium
	4.2 Hydrate models
		4.2.1 van der Waals and Platteeuw
		4.2.2 Parrish and Prausnitz
		4.2.3 Ng and Robinson
		4.2.4 Summary of models
		4.2.5 Type H
	4.3 Calculations
		4.3.1 Compositions
		4.3.2 Commercial software packages
			4.3.2.1 CSMHYD
			4.3.2.2 EQUI-PHASE Hydrate
			4.3.2.3 CSMGEM
			4.3.2.4 General purpose process simulation programs
	4.4 The accuracy of these programs
		4.4.1 Pure components
			4.4.1.1 Methane
	4.5 Ethane
		4.5.1 Carbon dioxide
			4.5.1.1 Hydrogen sulfide
		4.5.2 Mixtures
			4.5.2.1 Mei et al. (1998)
			4.5.2.2 Fan and Guo (1999)
			4.5.2.3 Ng and Robinson (1976)
			4.5.2.4 Wilcox et al. (1941)
			4.5.2.5 Tohidi et al. (1997)
			4.5.2.6 Type H predictions
		4.5.3 Sour gas
			4.5.3.1 Ward et al. (2015)
		4.5.4 Comment on natural gas
		4.5.5 Oil - Tohidi et al. (1997)
		4.5.6 Third party studies
	4.6 Dehydration
		4.6.1 Margin of error
	References
5.- Inhibiting hydrate formation with chemicals
	5.1 Freezing point depression
	5.2 The Hammerschmidt equation
	5.3 The Nielsen-Bucklin equation
	5.4 The Carroll method
	5.5 A chart
	5.6 Accuracy of the Carroll method
	5.7 Brine solutions
	5.8 McCain method
	5.9 Østergaard et al.
	5.10 Comment on the simple methods
	5.11 Advanced calculation methods
	5.12 A word of caution
	5.13 Ammonia
	5.14 Acetone
	5.15 Inhibitor vaporization
	5.16 A more theoretical approach
	5.17 Inhibitor losses to the hydrocarbon liquid
		5.17.1 Methanol
		5.17.2 Glycol
	5.18 A comment on injection rates
	5.19 Inhibitor recovery
	5.20 Safety considerations
	5.21 Diluted methanol
	5.22 Price for inhibitor chemicals
	5.23 Low-dosage hydrate inhibitors
	5.24 Kinetic inhibitors
	5.25 Antiagglomerants
	5.26 KI vs. AA
	References
	Appendix 5A List of US patents related to low-dosage hydrate inhibitors
6 - Dehydration of natural gas
	6.1 Water content specification
	6.2 Glycol dehydration
		6.2.1 Liquid desiccants
			6.2.1.1 Glycols
		6.2.2 Process description
			6.2.2.1 Inlet separator
			6.2.2.2 The contactor
			6.2.2.3 The flash tank
			6.2.2.4 Lean-rich exchanger
			6.2.2.5 The regenerator
			6.2.2.6 Glycol pump
		6.2.3 Short-cut design method
			6.2.3.1 BTEX
			6.2.3.2 Software
		6.2.4 Approximate capital cost
	6.3 Mole sieves
		6.3.1 Process description
		6.3.2 Simplified modeling
	6.4 Refrigeration
		6.4.1 Process description
		6.4.2 Glycol injection
	References
7 - Combating hydrates using heat and pressure
	7.1 Plugs
		7.1.1 Plug formation
		7.1.2 Pipeline monitoring
	7.2 The use of heat
		7.2.1 Heat loss from a buried pipeline
		7.2.2 Fluid contribution
		7.2.3 Pipe contribution
		7.2.4 Soil contribution
		7.2.5 Overall
		7.2.6 Heat ttransferred
		7.2.7 Additional comments
		7.2.8 Line heater design
		7.2.9 Bath
		7.2.10 Tube bundle
		7.2.11 Fire tube
		7.2.12 Other considerations
		7.2.13 Heat transfer
		7.2.14 Two-phase heater transfer
	7.3 Depressurization
	7.4 Melting a plug with heat
	7.5 Hydrate plug location
		7.5.1 Buildings
	7.6 Capital costs
	7.7 Case studies
		7.7.1 Case 1
		7.7.2 Case 2
	References
	Appendix A: Output from pipe heat loss program for the examples in the text
8 - Physical properties of hydrates
	8.1 Molar mass
	8.2 Density
	8.3 Enthalpy of fusion
	8.4 Heat capacity
	8.5 Thermal conductivity
	8.6 Mechanical properties
	8.7 Volume of gas in hydrate
	8.8 Ice vs. hydrate
	References
9 - Phase diagrams
	9.1 Phase rule
	9.2 Comments about phases
	9.3 Single component systems
	9.4 Water
	9.5 Binary systems
	9.6 Constructing T-x and P-x diagrams
	9.7 Methane+water
	9.8 Free-water
	9.9 Carbon dioxide+water
	9.10 Hydrogen sulfide+water
	9.11 Propane+water
	9.12 Phase behavior below 0°C
	9.13 Methane+water
	9.14 Carbon dioxide+methane+water
	9.15 Multicomponent systems
	9.16 An acid-gas mixture
	9.17 A typical natural gas1
	References
10 - Water content of natural gas
	10.1 Dew point
	10.2 Equilibrium with liquid water
		10.2.1 Ideal model
		10.2.2 McKetta-Wehe chart
		10.2.3 Sharma-Campbell method
		10.2.4 Bukacek
		10.2.5 Ning et al.
		10.2.6 Maddox correction
		10.2.7 Robinson et al. charts
		10.2.8 Wichert correction
		10.2.9 AQUAlibrium
	10.3 Equilibrium with solids
		10.3.1 Ice
		10.3.2 Hydrate
		10.3.3 Methane
		10.3.4 Gas gravity
		10.3.5 Ethane
		10.3.6 Propane
		10.3.7 Carbon dioxide
	10.4 Local water content model
	Hydrate book Example 10.4: 100psi
	Hydrate book Example 10.4: 250psi
	Hydrate book Example 10.4: 500psi
	Hydrate book Example 10.4: 1000psi
	References
	Appendix 10A output from AQUAlibrium
11 - Additional topics
	11.1 Joule-Thomson expansion
		11.1.1 Theoretical treatment
		11.1.2 Ideal gas
		11.1.3 Real fluids
			11.1.3.1 Compressibility factor
			11.1.3.2 The Miller equation
	11.2 Hydrate formation in the reservoir during production
	11.3 Flow in the well
	11.4 Transportation
	11.5 Natural occurrence of hydrates
		11.5.1 Seabed
		11.5.2 Natural gas formations
			11.5.2.1 Messoyakha
			11.5.2.2 Mallik
		11.5.3 Outer space
	References
Index
	A
	B
	C
	D
	E
	F
	G
	H
	I
	J
	K
	L
	M
	N
	O
	P
	Q
	R
	S
	T
	U
	V
	W
	X
	Z
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