Surface Process, Transportation, and Storage

Front Cover
Surface Process, Transportation, and Storage
Copyright Page
Contents
List of contributors
1 Chemical scavenging of hydrogen sulfide and mercaptans
	1.1 Introduction
	1.2 Hydrogen sulfide and mercaptan measurement
	1.3 Hydrogen sulfide and mercaptan partitioning in oil, water, and gas
	1.4 Chemical scavengers
		1.4.1 Solid scavengers
		1.4.2 Oxidizing chemicals
		1.4.3 Aldehydes
		1.4.4 Formaldehyde reaction products
		1.4.5 High valence metal compounds
		1.4.6 Aqueous alkaline solutions
		1.4.7 Hydrogen fluoride
		1.4.8 Novel hydrogen sulfide scavengers from biological sources
	1.5 Physical chemistry of scavengers
		1.5.1 Scavenging kinetics
		1.5.2 Scavenger thermodynamics
	1.6 Laboratory testing of hydrogen sulfide and mercaptan scavengers
		1.6.1 ASTM D5705 test methodology with modifications
		1.6.2 Laboratory assessment of hydrogen sulfide and mercaptan scavengers in towers
		1.6.3 Continuous gas flow apparatus
	1.7 Hydrogen sulfide and mercaptan scavenging process
		1.7.1 In-line injection
		1.7.2 Gas lift injection
		1.7.3 Capillary injection
		1.7.4 Contact towers
		1.7.5 Storage tanks
		1.7.6 Rail cars
		1.7.7 Scavengers in acidizing treatment
	1.8 Case studies
		1.8.1 Optimization of South Texas system
		1.8.2 Optimization of scavenging cost from joint industry program
		1.8.3 Scavenger automation at sour gas processing facility
		1.8.4 Development of sour reservoir in giant field in Kuwait
		1.8.5 Development of sour gas field in the Netherlands using scavenger with scale inhibitor
		1.8.6 Scavenging dry gas pipeline in Western Oklahoma
		1.8.7 Scavenging in coiled tubing drilling operations in Saudi Arabia
		1.8.8 Reduction of sulfur oxide content of flare gas
		1.8.9 Capillary string downhole injection in South Texas
		1.8.10 Fixed bed hydrogen sulfide removal in the North Sea
	1.9 Challenges associated with scavenging treatment
		1.9.1 Reaction products
		1.9.2 Induced scaling problems
		1.9.3 Corrosion issues
		1.9.4 Formation damage
		1.9.5 Emulsion problems in oil and water separation
		1.9.6 Overconsumption of scavenger
	1.10 New developments
		1.10.1 Safe operation
		1.10.2 Digital transformation
		1.10.3 Environmentally friendly products
	1.11 Summary and conclusions
	Nomenclature
	References
2 Natural gas sweetening
	2.1 Introduction
	2.2 Gas conditioning to satisfy sales gas quality
	2.3 Natural gas sweetening methods
	2.4 Chemical absorption
		2.4.1 Chemical reactions between H2S and CO2 and amine
		2.4.2 Amine process overview
		2.4.3 Design best practices
			2.4.3.1 Process unit design
			2.4.3.2 Main operation issues
	2.5 Physical absorption
		2.5.1 Propylene carbonate process
		2.5.2 Dimethyl ether of polyethylene glycol (DEPG or DMEPEG) solvents
		2.5.3 N-Methyl-2-pyrrolidone
		2.5.4 Refrigerated methyl alcohol (methanol)
		2.5.5 Combined physical and chemical absorption
	2.6 Adsorption
	2.7 Permeation or membrane based technologies
		2.7.1 Principle
		2.7.2 Polymeric membrane type
		2.7.3 Membrane module types
		2.7.4 Gas pretreatment
	2.8 Sulfur recovery
		2.8.1 Thermal section
		2.8.2 Catalytic section
		2.8.3 Major equipment
		2.8.4 Quality of the acid gas
		2.8.5 Reduction absorption tail gas treatment
	2.9 Emerging approaches for treating highly sour gas
		2.9.1 Cryogenic distillation
		2.9.2 Membranes for high H2S
	2.10 CO2 capture technology at gas plant
		2.10.1 CO2 capture from flue gas
		2.10.2 CO2 captured from the acid gas stream
			2.10.2.1 CO2 capture upstream of SRU
			2.10.2.2 CO2 capture downstream sulfur recovery plant
	2.11 Final remarks
	Nomenclature
	References
3 Emulsion separation
	3.1 Introduction
	3.2 Emulsion formation
	3.3 Emulsion stabilization
	3.4 Theory of emulsion separation
		3.4.1 Settling velocity of droplets
		3.4.2 Coalescence rates
		3.4.3 Semi-empirical approaches
	3.5 Emulsion separation techniques
	3.6 Thermal demulsification
		3.6.1 Effect of heating on emulsion properties
		3.6.2 Heater technology
		3.6.3 Case studies
	3.7 Mechanical internals
		3.7.1 Separator vessels
		3.7.2 Perforated baffles
		3.7.3 Plate packs
		3.7.4 Pipe separators
		3.7.5 Case studies
	3.8 Chemical demulsification
		3.8.1 Effect of demulsifier on separation rates
		3.8.2 Mechanisms of demulsifier action
		3.8.3 Demulsifier formulation
		3.8.4 Case studies
	3.9 Electrostatic demulsification
		3.9.1 Droplet migration in electric fields
		3.9.2 Droplet collisions in electric fields
		3.9.3 Effect of electric field properties on droplet coalescence
		3.9.4 Electrocoalescer technology
		3.9.5 Case studies
	3.10 Concluding remarks
	Nomenclature
	References
4 Foam control
	4.1 Introduction and overview
		4.1.1 Foam basics
		4.1.2 Oil-based versus water-based foams
		4.1.3 Antifoaming versus defoaming
		4.1.4 Antifoaming versus deaeration
		4.1.5 Solid-stabilized foams
		4.1.6 Overview of foam stabilizer and antifoam chemistries
	4.2 Oil-based foams
		4.2.1 Defoaming versus demulsification
		4.2.2 Nonaqueous foaming
			4.2.2.1 Presence of surfactants
				4.2.2.1.1 Modified hydrocarbon-type surfactants
				4.2.2.1.2 PDMS and organomodified silicones
				4.2.2.1.3 Fluorocarbons
			4.2.2.2 Multiphase condensed media
		4.2.3 Nonaqueous foams of crude oil
			4.2.3.1 Factors determining crude oil foaming
				4.2.3.1.1 Volume and properties of the dissolved gas
				4.2.3.1.2 Crude oil composition
				4.2.3.1.3 Liquid-gas interfacial properties
				4.2.3.1.4 Presence of other (solid) phases and water
				4.2.3.1.5 Viscosity
			4.2.3.2 Testing methods
			4.2.3.3 Crude oil foaming field case histories
			4.2.3.4 Crude oil lift
		4.2.4 Chemistry of antifoams for oil-based foams
			4.2.4.1 Silicones (siloxanes)
				4.2.4.1.1 Polydimethylsiloxane
					PDMS synthesis
					Physical properties of PDMS
					Small PDMS molecules and cyclic siloxanes
				4.2.4.1.2 Organomodified silicones
					Silicone polyether copolymers
					Use of organomodified silicones as antifoams
				4.2.4.1.3 Fluorosilicones
					Properties of fluorosilicones
					Use of fluorosilicones as antifoams
			4.2.4.2 Nonsilicone antifoams for oil-based foams
	4.3 Water-based foams
		4.3.1 Chemistry of antifoams for water-based foams
			4.3.1.1 Silicones, silica-filled polydimethylsiloxane
				4.3.1.1.1 PDMS as antifoam for aqueous liquids
				4.3.1.1.2 Mixed (oil+solid) antifoams
			4.3.1.2 Nonsilicone antifoams
			4.3.1.3 Antifoam formulations
		4.3.2 Water-based applications
			4.3.2.1 Aqueous foams in produced water and seawater injection systems
			4.3.2.2 Field examples of injection water system foaming
			4.3.2.3 Cementing
				4.3.2.3.1 Testing cement slurry antifoams
				4.3.2.3.2 Chemistry of cement slurry antifoams
			4.3.2.4 Drilling and completion
			4.3.2.5 Gas dehydration
			4.3.2.6 Gas sweetening
				4.3.2.6.1 Foaming problems in amine units
				4.3.2.6.2 Use of antifoams in amine units
			4.3.2.7 Water reinjection
			4.3.2.8 Steam regeneration
			4.3.2.9 Foam assisted lift
	4.4 Mechanical defoaming
	4.5 Defoaming by chemical reaction
	4.6 Mechanisms of antifoaming action
		4.6.1 Antifoaming of nonaqueous foams
			4.6.1.1 Thermodynamic coefficients
			4.6.1.2 Mechanism of nonaqueous antifoaming
		4.6.2 Antifoaming of aqueous foams
			4.6.2.1 The pseudoemulsion film
			4.6.2.2 Effect of hydrophobic solids and penetration depth
			4.6.2.3 Rate of antifoaming and location of oil drops inside the foam
			4.6.2.4 Bridging
			4.6.2.5 Antifoam deactivation (durability)
			4.6.2.6 Practical aspects: effects of antifoam viscosity, drop size, and mixing
			4.6.2.7 Cloud point antifoams
		4.6.3 Breaking solid stabilized foams
	4.7 Concluding remarks
	Nomenclature
	References
5 Polymeric drag reduction in pipelines
	5.1 Drag-reducing agent history
	5.2 Basic pipeline hydraulics tutorial
		5.2.1 Reynolds number
		5.2.2 Laminar flow
		5.2.3 Turbulent flow
		5.2.4 Pressure drop
		5.2.5 Static head
		5.2.6 Friction pressure
		5.2.7 Gradient
		5.2.8 Profile
		5.2.9 Pipeline pumps
		5.2.10 Operating point
		5.2.11 Calculating drag reduction performance in a pipeline system
	5.3 Drag-reducing agent chemistry
	5.4 Drag reduction mechanism
		5.4.1 Misconceptions
	5.5 Application to the pipeline—drag-reducing agent theory
		5.5.1 Applications in oil/water or multiphase pipelines
	5.6 Utilization of drag-reducing agent in pipeline operations
		5.6.1 Example cases for utilization in pipelines
			5.6.1.1 Multi-station pipeline de-rated in the middle segment
			5.6.1.2 The production rate exceeds the design capacity
			5.6.1.3 Pump station bypass
			5.6.1.4 New pipeline design
	5.7 Conclusion
	Nomenclature
	References
6 Natural gas storage by adsorption
	6.1 Introduction
	6.2 Fundamentals of adsorption
		6.2.1 Definition
		6.2.2 Adsorption forces
		6.2.3 Adsorption separation and storage mechanism
		6.2.4 Adsorption processes
	6.3 Industrial adsorbents
		6.3.1 Adsorbent selection
		6.3.2 Silica gel
		6.3.3 Activated alumina
		6.3.4 Zeolites
		6.3.5 Activated carbons
		6.3.6 Potential novel industrial adsorbents
		6.3.7 Summary of natural gas storage adsorbents
	6.4 Case study: screening activated carbon for natural gas storage
		6.4.1 Experimental
		6.4.2 Method of determining the amount of methane adsorbed
		6.4.3 Experimental results
		6.4.4 Empirical modeling with adsorption potential theory
		6.4.5 Isosteric heat of adsorption modeling
	6.5 Heat management modeling
		6.5.1 Mathematical modeling
		6.5.2 Performance analysis through thermal simulation
	6.6 Summary
	Nomenclature
	References
7 Crude oil storage
	7.1 Introduction
	7.2 Types of storage
		7.2.1 Storage tank
		7.2.2 Concrete gravity-based structures
		7.2.3 Floating tanks
		7.2.4 Underground caverns
	7.3 Chemistry-related issues and solutions
		7.3.1 Corrosion
			7.3.1.1 Bottom plate corrosion
			7.3.1.2 Internal tank roof corrosion
			7.3.1.3 Tank external corrosion
			7.3.1.4 Tank corrosion monitoring
		7.3.2 Bacteria
			7.3.2.1 Biocide treatment
			7.3.2.2 Nonchemical treatment
		7.3.3 Emulsion
			7.3.3.1 Heating
			7.3.3.2 Demulsifier chemicals
			7.3.3.3 Physical treatment
		7.3.4 Carboxylate soaps
		7.3.5 Paraffin and asphaltene
			7.3.5.1 Thermal, mechanical and chemical methods
			7.3.5.2 Remediation methods
			7.3.5.3 Selection of treatment method
		7.3.6 Inorganic solids
			7.3.6.1 Mineral scales
			7.3.6.2 Removal of inorganic solids
	7.4 Summary
	Nomenclature
	References
8 Geologic carbon storage: key components
	8.1 Introduction
	8.2 Geologic carbon storage classifications, definitions, types
		8.2.1 Definitions
		8.2.2 Geologic carbon storage types
	8.3 Key components of geologic carbon storage projects
	8.4 Surface components: capture, conditioning, and transport
		8.4.1 Capture
		8.4.2 Conditioning
		8.4.3 Transport
	8.5 Subsurface components: exploration and reservoir
		8.5.1 Exploration and screening
		8.5.2 Storage capacity
		8.5.3 Injectivity
		8.5.4 Containment
	8.6 Risk assessment, monitoring, and validation
	8.7 Monitoring and validation
	8.8 Regulations and certification
	8.9 Economics
	8.10 Outlook
	Nomenclature
	References
9 Carbonate geochemistry and its role in geologic carbon storage
	9.1 Introduction
	9.2 Review of subsurface carbon dioxide trapping mechanisms
	9.3 Thermodynamic considerations
		9.3.1 The carbon dioxide system
		9.3.2 The CO2-H2O-NaCl system
		9.3.3 The CO2-H2O-MeCO3 system
	9.4 Kinetic considerations
		9.4.1 Rates of CO2 dissolution into water
		9.4.2 Rates of mineral dissolution reactions with CO2-charged water
		9.4.3 Mineral precipitation rates
	9.5 Kinetic modeling
	9.6 Case studies
		9.6.1 The Weyburn EOR and CO2 storage project
		9.6.2 The fate of the injected CO2 at Weyburn
		9.6.3 The CarbFix mineral storage project
	9.7 Carbonate chemistry and wellbore integrity
		9.7.1 Carbonation and cement alteration
		9.7.2 Effects of the fluid composition on cement alteration
		9.7.3 Impacts of the cement composition
		9.7.4 Calcite precipitation and self-sealing effects
		9.7.5 Corrosion and cement degradation of the Weyburn wells
	9.8 Conclusions
	Nomenclature
	References
10 Carbon conversion: opportunities in chemical productions
	10.1 Introduction
		10.1.1 The carbon dioxide question
		10.1.2 Carbon dioxide thermodynamics, reactivity, and catalysis
		10.1.3 Current and potential uses of carbon dioxide
		10.1.4 Routes for carbon dioxide oxidation state reduction
	10.2 Supporting concerns for technology selection
		10.2.1 Sources and costs of carbon dioxide
		10.2.2 Purification of carbon dioxide
	10.3 Examples of commercialized technologies addressing the criteria and concerns
	10.4 Promising technology areas for the future
		10.4.1 Examples from chemical transformations
			10.4.1.1 Carbon dioxide to chemicals via Fischer-Tropsch processes
			10.4.1.2 Two-step conversion of carbon dioxide using cobalt catalysts and the reverse water gas shift reaction
			10.4.1.3 Direct conversion of carbon dioxide using iron catalysts
			10.4.1.4 Conversion of carbon dioxide to light alkenes
			10.4.1.5 Conversion of carbon dioxide into aromatics
			10.4.1.6 Synthesis of methanol from carbon dioxide
		10.4.2 The use of electrochemical systems for carbon dioxide conversion
			10.4.2.1 The current state of direct carbon dioxide reduction
			10.4.2.2 System improvements and cell geometries
			10.4.2.3 Economic challenges
			10.4.2.4 Future perspectives
		10.4.3 Continuous bio-catalysis for carbon dioxide conversion
			10.4.3.1 Introduction to the bio-catalytic conversion of carbon dioxide
			10.4.3.2 Anaerobic and aerobic carbon dioxide conversion technologies
			10.4.3.3 Techno-economics and life cycle assessment
			10.4.3.4 Future perspectives
	10.5 Final remarks
	Acknowledgments
	Nomenclature
	References
Index
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