Fluid Chemistry, Drilling and Completion (Volume One)

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Fluid Chemistry, Drilling and Completion
Copyright
Contents
List of contributors
1 Reservoir fluid geodynamics
	1.1 Introduction
	1.2 Reservoir fluid geodynamics
		1.2.1 Asphaltene science
			1.2.1.1 AFM and STM molecular imaging of asphaltenes
			1.2.1.2 AFM and STM images of diverse asphaltenes
			1.2.1.3 Asphaltene gradients in reservoirs
		1.2.2 Ora intelligent wireline formation testing platform and DFA
	1.3 RFG oilfield case studies
		1.3.1 RFG applied to a light oil reservoir
			1.3.1.1 RFG processes in this reservoir
		1.3.2 RFG applied to a black oil field
			1.3.2.1 RFG processes in this reservoir
	1.4 RFG workflow
	1.5 Conclusions
	Nomenclature
	References
2 Sampling petroleum fluids
	2.1 Introduction
		2.1.1 From upstream to downstream
		2.1.2 Sampling types—the short list
		2.1.3 Defining reservoir type
		2.1.4 Fluid initialization
		2.1.5 In situ-representative versus reservoir representative samples
		2.1.6 Developing PVT models
			2.1.6.1 Why do we need PVT data?
			2.1.6.2 How do we get PVT data?
	2.2 Sampling procedures and measurements
		2.2.1 Sampling types
			2.2.1.1 STO sampling
			2.2.1.2 Separator sampling
			2.2.1.3 Conventional Bottomhole sampling
			2.2.1.4 Openhole formation testing
		2.2.2 How do we use samples?
			2.2.2.1 Water samples
			2.2.2.2 STO samples
			2.2.2.3 Separator samples
		2.2.3 Sampling standards
		2.2.4 Compositional analyses
	2.3 Sampling strategies
		2.3.1 Balancing wish lists and costs
		2.3.2 Discovery wells
		2.3.3 Delineation wells
		2.3.4 Production wells
		2.3.5 EOR wells
		2.3.6 Problem wells
		2.3.7 Fluid system considerations
			2.3.7.1 Saturated gas–oil systems
			2.3.7.2 Near-saturated systems
			2.3.7.3 Highly undersaturated systems
			2.3.7.4 Compositionally grading systems
	2.4 Special issues in sampling
		2.4.1 Sample storage
		2.4.2 Separator sampling
			2.4.2.1 Liquid carryover in the gas wellstream
			2.4.2.2 Isokinetic sampling
		2.4.3 Using contaminated PVT samples
		2.4.4 Wax, asphaltenes, scale, and hydrates
		2.4.5 Mud gas sampling
		2.4.6 Tight unconventionals
			2.4.6.1 Recommended sampling strategy
			2.4.6.2 PVT data
	2.5 Conclusions
	Nomenclature
	References
3 Water chemistry
	3.1 Introduction
	3.2 Types of water samples
	3.3 Water sampling and analysis
	3.4 Water data evaluation
	3.5 Water chemistry data interpretation and reconciliation
	3.6 Factors that impact/change water chemistry
	3.7 Field case examples of water chemistry application
		3.7.1 Original oil in place (OOIP) estimate
		3.7.2 Water source identification
		3.7.3 Management of scale, corrosion, and other water-related production problems
		3.7.4 Produced water chemistry surveillance and applications in shale and tight plays
	3.8 Final remarks
	Nomenclature
	References
4 Drilling fluids
	4.1 Introduction
	4.2 Drilling fluid functions
		4.2.1 Formation pressure management and wellbore stability–fluid density
		4.2.2 Hole cleaning—fluid rheological properties
		4.2.3 Seal permeable formations—fluid loss control and bridging
		4.2.4 Reduce friction—fluid lubricity
		4.2.5 Other functions
	4.3 Drilling fluid types
	4.4 Aqueous-based fluids
		4.4.1 Water-based fluid additives
			4.4.1.1 Weighting agents
			4.4.1.2 Rheology modifiers
			4.4.1.3 Fluid loss control additives
			4.4.1.4 pH and corrosion control
			4.4.1.5 Shale inhibitors
			4.4.1.6 Thinners/dispersants
			4.4.1.7 Lubricants
		4.4.2 Water-based fluids types
			4.4.2.1 Dispersed water-based fluids
			4.4.2.2 Low-solids, nondispersed water-based fluids
	4.5 Nonaqueous fluids
		4.5.1 Nonaqueous fluids additives
			4.5.1.1 Weighting agents
			4.5.1.2 Emulsifiers and wetting agents
			4.5.1.3 Base oil
			4.5.1.4 Rheology modifiers
			4.5.1.5 Shale inhibitors
			4.5.1.6 Fluid loss control additives
			4.5.1.7 pH and corrosion control
			4.5.1.8 Lubricants
			4.5.1.9 Thinners/dispersants
		4.5.2 Nonaqueous fluid types
			4.5.2.1 Conventional nonaqueous fluids
			4.5.2.2 High-performance nonaqueous fluids
	4.6 Reservoir drilling fluids
		4.6.1 Reservoir drilling fluid additives
			4.6.1.1 Weighting agents
			4.6.1.2 Filtration control (bridging)
			4.6.1.3 Viscosifiers
			4.6.1.4 Shale inhibition
			4.6.1.5 Lubricants
			4.6.1.6 Surfactants
			4.6.1.7 pH and corrosion control
	4.7 Conclusion
	Nomenclature
	References
5 Cementing additives
	5.1 Introduction
	5.2 Cement basics
		5.2.1 Chemical notation
		5.2.2 Portland cement chemistry
		5.2.3 Hydration of Portland cement
			5.2.3.1 Silicate phases
				5.2.3.1.1 Metastable barrier hypothesis
				5.2.3.1.2 Slow dissolution step hypothesis
			5.2.3.2 Aluminates
			5.2.3.3 Portland cement
				5.2.3.3.1 Chemical shrinkage
		5.2.4 Interparticle interactions
		5.2.5 Application to well cements
	5.3 Slurry formulation
		5.3.1 Temperature
		5.3.2 Slurry density
			5.3.2.1 Changing the water-to-cement ratio
			5.3.2.2 Including density adjusting additives
			5.3.2.3 Foaming
			5.3.2.4 Extenders
				5.3.2.4.1 Bentonite
				5.3.2.4.2 Sodium silicate
				5.3.2.4.3 Pozzolans
			5.3.2.5 Commercial lightweight cements
			5.3.2.6 Density adjusting particles
		5.3.3 Placement time
			5.3.3.1 Retarders
				5.3.3.1.1 Sugars
				5.3.3.1.2 Lignosulfonates
				5.3.3.1.3 Hydroxycarboxylic acids
				5.3.3.1.4 Synthetic polymeric retarders
				5.3.3.1.5 Organophosphonates
				5.3.3.1.6 Borates
				5.3.3.1.7 Phosphates
				5.3.3.1.8 Silicates
				5.3.3.1.9 Zinc oxide
				5.3.3.1.10 Summary
			5.3.3.2 Accelerators
				5.3.3.2.1 Inorganic calcium salts
				5.3.3.2.2 C–S–H seeds
				5.3.3.2.3 Sodium silicate
				5.3.3.2.4 Colloidal silica
		5.3.4 Rheological properties
			5.3.4.1 Properties under shear
			5.3.4.2 Properties at rest
			5.3.4.3 Dispersants
				5.3.4.3.1 Sulfonated polyanionic resin dispersants
				5.3.4.3.2 PCE dispersants
			5.3.4.4 Antisettling agents
		5.3.5 Fluid loss control
			5.3.5.1 Filtration control and testing
			5.3.5.2 “Particulate” fluid loss control additives
			5.3.5.3 Soluble polymers as fluid loss control additives
			5.3.5.4 “Combined mechanism” fluid loss control additives
		5.3.6 Gas migration control
		5.3.7 Other additives
			5.3.7.1 Antifoam/defoamers
			5.3.7.2 Foaming agents
			5.3.7.3 Expansion additives
				5.3.7.3.1 Delayed ettringite formation
				5.3.7.3.2 Magnesium oxide
			5.3.7.4 Special blends
				5.3.7.4.1 CO2-resistant cement
				5.3.7.4.2 Flexible cement systems
				5.3.7.4.3 Self-healing cement systems
	5.4 Summary
		5.4.1 Polymers in cement formulations
		5.4.2 Formulation approach
	Nomenclature
	Conversion Factors
	Acknowledgments
	References
6 Completion and workover fluids
	6.1 Introduction
	6.2 Types of completion brines
		6.2.1 Halide brines (inorganic salts)
		6.2.2 Formate brines (organic salts)
		6.2.3 Potassium carbonate brine
	6.3 Considerations for completion brine selection
		6.3.1 Density requirement
		6.3.2 Crystallization temperature
		6.3.3 Hydrate inhibition
		6.3.4 Compatibility with formation fluids
		6.3.5 Compatibility with reservoir matrix
		6.3.6 Corrosion of completion hardware
		6.3.7 Environmental and safety
		6.3.8 Cost
	6.4 Completion brine properties measurement
		6.4.1 Density
		6.4.2 Iron content
		6.4.3 Turbidity
		6.4.4 Total suspended solids
	6.5 Completion brine additives
		6.5.1 Corrosion inhibitors
		6.5.2 Lubricants
		6.5.3 Viscosifier and fluid loss control
			6.5.3.1 Hydroxyethylcellulose
			6.5.3.2 Cross-linked HEC pills
			6.5.3.3 Solid laden pills
			6.5.3.4 Solid-sized salt pills
	6.6 Conclusion
	Nomenclature
	References
7 Packer fluids
	7.1 Introduction
	7.2 Types of packer fluids
	7.3 Solids-free brines
	7.4 Packer fluid properties
		7.4.1 Density
		7.4.2 Crystallization temperature
		7.4.3 Fluid clarity
		7.4.4 Corrosion and corrosion inhibition
		7.4.5 Fluid compatibility
	7.5 Displacement
	7.6 Safety
	7.7 Summary
	Nomenclature
	References
8 Carbonate matrix stimulation
	8.1 Introduction
	8.2 Candidate selection
	8.3 Chemical and physical processes in carbonate acidizing
		8.3.1 Reactions of carbonate rocks with strong inorganic acids
		8.3.2 Reactions of carbonate rocks with weak organic acids and chelants
		8.3.3 Carbonate dissolution patterns: influence of transport and reaction
		8.3.4 Wormhole growth models
		8.3.5 Influence of mineralogy and porosity type
	8.4 Stimulation fluid engineering
		8.4.1 Single-phase retarders for HCl–carbonate reaction
		8.4.2 Organic acids and chelants
		8.4.3 Polymer and viscoelastic surfactant gelled acids
		8.4.4 Emulsified acids
		8.4.5 Foamed acids
	8.5 Stimulation treatment design
		8.5.1 Design challenges
			8.5.1.1 Placement of acid in each pay zone
			8.5.1.2 Fluid selection
			8.5.1.3 Treatment simulation
		8.5.2 Design optimization
	8.6 Summary
	Nomenclature
	References
9 Sandstone matrix stimulation
	9.1 Introduction
	9.2 Formation damage mechanisms in sandstone reservoirs
		9.2.1 Clay swelling
		9.2.2 Fines migration
		9.2.3 Inorganic scale deposition
		9.2.4 Organic scale deposition
		9.2.5 Damage during drilling and completion
		9.2.6 Damage during reservoir stimulation
	9.3 Acid types
		9.3.1 Hydrofluoric acid and mud acid
			9.3.1.1 Mud acid–mineral reaction stoichiometry
			9.3.1.2 Acid–mineral reaction kinetics
			9.3.1.3 Reservoir problems associated with conventional mud acid treatment
		9.3.2 HCl acid
		9.3.3 Retarded acids
		9.3.4 Chelating agents
		9.3.5 Organic acid mixtures
		9.3.6 New developments
	9.4 Acid additives
		9.4.1 Corrosion inhibitor
		9.4.2 Surfactants
		9.4.3 Clay stabilizers
		9.4.4 Iron control agents
		9.4.5 Liquefied gases and foaming agents
	9.5 Acid diversion and placement
		9.5.1 Mechanical means
		9.5.2 Chemical means
	9.6 Laboratory testing techniques and equipment
		9.6.1 Rock solubility tests
		9.6.2 Core flooding experiments
		9.6.3 Petrographic tests
		9.6.4 Zeta potential measurement/surface charge
	9.7 Treatment design
		9.7.1 Preflush stage
		9.7.2 Main flush stage
		9.7.3 Postflush stage
	9.8 Sandstone acidizing models
		9.8.1 Conventional permeability models
		9.8.2 Permeability model with mineralogy effect
			9.8.2.1 Two-mineral model
			9.8.2.2 Two-acid, three-mineral model
		9.8.3 Precipitation models
	9.9 Field treatments
	9.10 Summary
	Nomenclature
	References
10 Acid fracturing stimulation
	10.1 Petroleum engineering and geological aspects
	10.2 Acid fracturing chemistry
	10.3 Reaction kinetics
	10.4 System of chemical additives in acid
		10.4.1 Corrosion inhibitors
		10.4.2 Iron-control agents
		10.4.3 Hydrogen sulfide (H2S) scavenger
		10.4.4 Antisludging agents
	10.5 Acid fracturing process
		10.5.1 Pickling the tubing
		10.5.2 Injectivity assessment
		10.5.3 Fracture breakdown
		10.5.4 Main acid stimulation
		10.5.5 Diversion
			10.5.5.1 Solid diverters
			10.5.5.2 Viscous fluid diverter
	10.6 Acid fracturing examples
	10.7 Conclusion
	Nomenclature
	References
11 Hydraulic fracturing stimulation
	11.1 Introduction
	11.2 Types of fracturing fluids
		11.2.1 Aqueous-based fracturing fluids
			11.2.1.1 Polymer-based linear fracturing fluid
				11.2.1.1.1 Guar or guar derivatives
				11.2.1.1.2 Xanthan gum
				11.2.1.1.3 Cellulose derivatives
				11.2.1.1.4 Polyacrylamides
			11.2.1.2 Guar-based crosslinked fracturing fluid
				11.2.1.2.1 Borate crosslinkers
				11.2.1.2.2 Metal crosslinkers
			11.2.1.3 Cellulose-based crosslinked fracturing fluid
			11.2.1.4 Synthetic polymer-based crosslinked fracturing fluid
			11.2.1.5 Viscoelastic surfactant fluid
		11.2.2 Less-water to waterless fracturing fluids
			11.2.2.1 Foam-based fracturing fluid
			11.2.2.2 Oil-based fracturing fluid
			11.2.2.3 LPG-based fracturing fluid
			11.2.2.4 Liquid CO2-based fracturing fluid
			11.2.2.5 N2-based fracturing fluid
	11.3 Fluids additives
		11.3.1 Biocides
		11.3.2 Buffers and pH adjusting agents
		11.3.3 Breakers
			11.3.3.1 Oxidative breakers
			11.3.3.2 Enzymes
			11.3.3.3 pH-modifying agents
			11.3.3.4 Decrosslinking agents
		11.3.4 Clay stabilizers
		11.3.5 Gel stabilizers
		11.3.6 Surfactants
	11.4 Advancements in thickening fluid chemistry
		11.4.1 Pristine nanoparticles
		11.4.2 Oligomeric boron-containing crosslinker for guar-based fluid
		11.4.3 Polymeric multifunctional boronic acid crosslinker for guar-based fluid
		11.4.4 Nanocrosslinker for guar-based fluid
		11.4.5 Nanocrosslinker for AM-based fluid system
		11.4.6 Polymer-treated degradable fibers
	11.5 Alternative ways for proppant suspension
		11.5.1 Preformed gel fluid/soft particle fluid
		11.5.2 Self-suspending proppant
			11.5.2.1 Self-suspending proppant in aqueous-based fluid
			11.5.2.2 Self-suspending proppant in CO2-based fluid
		11.5.3 Solid-free fracturing fluid
	11.6 Recent trend and advancements in unconventional fracturing
		11.6.1 Operational cost reduction through innovation and efficiency
		11.6.2 High-viscosity friction reducer
		11.6.3 Microproppant
		11.6.4 Channel fracturing
		11.6.5 Increasing SRV
			11.6.5.1 Far-field diversion
			11.6.5.2 Reactive components
	11.7 Conclusions
	Nomenclature
	References
Index