Flow Assurance

Front Cover
Flow Assurance
Copyright Page
Contents
List of contributors
1 Gas hydrate management
1.1 Introduction
1.2 Fundamentals of hydrate
1.2.1 Definition
1.2.2 Structures
1.2.3 Phase behavior
1.2.4 Properties
1.2.4.1 Mechanical properties
1.2.4.2 Self-preservation during dissociation
1.2.4.3 Large gas-to-hydrate volume ratio
1.3 Hydrate formation
1.3.1 Hydrate formation scenarios
1.3.1.1 Shut-in
1.3.1.2 Cold restart
1.3.1.3 Steady state
1.3.1.4 Gas injection, gas lift, or gas export
1.3.2 Hydrate formation mechanism
1.4 Hydrate management in production systems
1.4.1 Risk assessment
1.4.2 Hydrate modeling
1.4.2.1 Thermodynamic modeling
1.4.2.2 Kinetic modeling
1.5 Temperature control
1.5.1 Thermal insulation
1.5.1.1 Wet insulation
1.5.1.2 Dry insulation
1.5.1.3 Burial
1.5.2 Active heating
1.5.2.1 Electrical heating
1.5.2.2 Pipeline bundles
1.6 Chemical inhibition
1.6.1 Thermodynamic hydrate inhibitors
1.6.2 Low-dosage hydrate inhibitors
1.6.2.1 Kinetic hydrate inhibitors
1.6.2.2 Antiagglomerants
1.7 Dehydration
1.8 Hydrate remediation
1.8.1 Depressurization
1.8.2 Heating
1.8.3 Chemical dissociation
1.8.4 Model predictions for remediation
1.9 Case studies
1.9.1 Hydrate management in dry tree facility facilities
1.9.2 Low-dosage hydrate inhibitor field application
1.9.3 Tommeliten-gamma field
1.9.4 Remediation of hydrate plug in west Africa deepwater floating production storage and offloading
1.10 Summary
Nomenclature
References
2 Paraffin management
2.1 History of paraffin management developments
2.2 Crude oil and paraffin chemistry
2.3 Paraffin analysis and crude oil characterization
2.3.1 Paraffin analysis methods
2.3.2 Crude oil characterization
2.3.2.1 Wax appearance temperature
2.3.2.2 Pour point
2.3.2.3 Viscosity profile
2.4 Paraffin deposition
2.4.1 Paraffin deposition mechanisms
2.4.2 Paraffin deposition modeling
2.4.2.1 Flow loop testing
2.4.2.2 Modeling programs
2.4.3 Paraffin deposit characteristics
2.4.4 Paraffin deposition control
2.4.4.1 Thermal methods
Insulation
Heating
Heating for deposition prevention
Heating for deposition remediation
Hot oiling/hot water injection
Thermochemical Methods
2.4.4.2 Mechanical methods
Wireline cutting
Coiled tubing operations
Rod scrapers
Plunger-lift well design
Pigging
2.4.4.3 Chemical methods
Solvents
Dispersants
Paraffin inhibitors / crystal modifiers
Product formulations and applications
Cold finger testing for paraffin inhibitor evaluation
2.4.4.4 Treatment considerations for different problem locations
Formation damage
Well tubing deposition
Flowline deposition
Separation equipment
Tank bottoms
Export pipelines
2.5 Pour point/crude oil gelling problems
2.5.1 Crude oil gelling mechanism
2.5.2 Gelled flowline characteristics
2.5.3 Pour point treatment
2.5.3.1 Production management
2.5.3.2 Thermal methods
2.5.3.3 Chemical methods (Pour Point Depressants)
PPD testing: pour point, viscosity, and yield stress
2.5.3.4 Pour point depressant treatment considerations
2.6 Case histories
2.6.1 Formation damage
2.6.1.1 Case history no. 1
2.6.1.2 Case history no. 2
2.6.1.3 Case history no. 3
2.6.2 Well tubing deposition
2.6.2.1 Case history no. 1
2.6.2.2 Case history no. 2
2.6.3 Flowline deposition
2.6.3.1 Case history no. 1
2.6.3.2 Case history no. 2
2.6.4 Tank bottoms
2.6.4.1 Case history no. 1
2.6.4.2 Case history no. 2
2.7 Summary
Nomenclature
References
3 Asphaltene management
3.1 Introduction
3.2 Chemistry of asphaltenes
3.2.1 Composition and structure
3.2.2 Solubility and aggregation
3.3 Experimental techniques for asphaltene stability prediction
3.3.1 Solids detection system
3.3.2 DeBoer plot
3.3.3 Dead oil tests
3.3.3.1 Colloidal instability index
3.3.3.2 The flocculation point analyzer/asphaltene precipitation detection unit
3.4 Asphaltene stability modeling
3.4.1 Asphaltene instability trend modeling
3.4.2 Asphaltene deposition model
3.5 Asphaltene inhibitor lab tests
3.5.1 Precipitation tests
3.5.1.1 Asphaltene dispersion test
3.5.1.2 Turbidity tests
3.5.2 Deposition tests
3.5.2.1 Capillary deposition unit
3.5.2.2 Coupon deposition test
3.5.2.3 Packed bed column
3.5.2.4 Microfluidic device
3.5.2.5 Core-flooding test
3.5.3 Live oil tests
3.5.3.1 Solid detection system
3.5.3.2 Organic solids deposition and control and realview deposition cell
3.5.3.3 Asphaltene rocking cell test
3.6 Asphaltene control in oil production
3.6.1 Prevention
3.6.1.1 Operating condition
3.6.1.2 Chemical inhibitors and dispersants
3.6.2 Remediation
3.7 Case studies
3.7.1 Lab screening methods for field applications
3.7.2 Evaluating asphaltene inhibitors for an offshore alaskan producer
3.7.3 Development of multifunctional stabilizers of asphaltenes
3.8 Conclusion and path forward
Acknowledgment
Nomenclature
References
4 Naphthenate and carboxylate soap treatment
4.1 Introduction
4.1.1 Overview and chapter orientation
4.1.2 Naphthenates and recent history
4.1.3 Definitions: acid crude oil and “naphthenates”
4.1.4 Origin of acidic crude
4.1.5 Carboxylate and naphthenate soap operational challenges
4.1.6 The continuum model
4.2 Fouling mechanisms of naphthenate and carboxylate soaps
4.2.1 Analytical techniques for acidic species in crude oils
4.2.1.1 Analytical chemistry basics of acid characterization
4.2.1.2 The “ARN” acid discovery: an analytical breakthrough
4.2.1.3 ARN acid physicochemical properties
4.2.2 Soap emulsions
4.2.2.1 Overview and field examples
4.2.2.2 Mechanism of soap emulsion formation and factors that influence stability
4.2.2.3 Impact of emulsion soap formation
4.2.3 Naphthenate soap solids
4.2.3.1 Overview and field examples
4.2.3.2 Mechanism of calcium naphthenate soap scale and factors that influence stability
4.2.3.3 Impact of calcium naphthenate soap scale formation
4.2.4 High calcium in crude caused by oil-dispersible naphthenates
4.2.4.1 Overview and field examples
4.2.4.2 Mechanism of calcium in crude naphthenate soap and factors that influence stability
4.2.4.3 Impact of calcium in crude salts
4.2.5 Refinery challenges overview
4.3 Chemical control methodologies and laboratory testing
4.3.1 Introduction
4.3.2 Preventive chemical strategies
4.3.2.1 Acids and acidic demulsifiers
4.3.2.2 Nonacidic chemicals and low dose naphthenate inhibitors
4.3.3 Remediation and remedial chemical strategies
4.3.4 Laboratory and field testing
4.4 Concluding remarks and remaining challenges
Nomenclature
Acknowledgments
References
5 Inorganic mineral scale mitigation
5.1 Introduction
5.1.1 The role of water
5.1.2 Inorganic mineral scaling in the oil environment
5.2 Basic principles of inorganic scale formation
5.2.1 Types of inorganic mineral scale
5.2.1.1 Acid-soluble versus acid-insoluble scales
5.2.1.2 Iron scales
5.2.1.3 Solid solutions and mixed scales
5.2.2 Inorganic mineral scale formation
5.2.2.1 Self-scaling: carbonate scales
5.2.2.2 Incompatible mixing: sulfate scales
5.2.2.2.1 Formation water chemistries
5.2.2.2.2 Unconventional reservoir production
5.2.3 Scale nucleation and growth
5.2.3.1 Nucleation
5.2.3.2 Crystal growth
5.2.3.3 Influence of hydrodynamics on scaling kinetics
5.2.4 Thermodynamics and kinetics
5.3 Scale prediction
5.3.1 Scale prediction as a component of scale management
5.3.2 Scale prediction outputs
5.3.2.1 Scale risk summary tables
5.3.3 Theory of scale prediction
5.3.3.1 Solubility product and saturation ratio
5.3.3.2 Excess solute
5.3.4 Importance of quality input data
5.3.4.1 Reservoir equilibration
5.3.5 Example of the utility of modern scale prediction packages
5.3.6 Limitations of scale prediction
5.4 Scale control
5.4.1 Treatment options and scale control strategies
5.4.1.1 Judicious modification/selection of flood water
5.4.1.1.1 Selection of compatible injection waters
5.4.1.1.2 Produced water reinjection
5.4.1.1.3 Geochemical reactions in the reservoir
5.4.1.1.4 Desulfation of the injected water
5.4.1.2 Flow modification
5.4.1.3 Nonchemical approaches: surface coatings and other “electromagnetic devices”
5.4.1.3.1 Surface coatings
5.4.1.3.2 Electromagnetic devices
5.4.2 Chemical inhibition
5.4.2.1 Scale inhibition versus chemical removal of scaling ions
5.4.2.1.1 Chemical complexation
5.4.2.2 Introduction to scale inhibition
5.4.3 Types of scale inhibitors commonly used in oil industry
5.4.3.1 Functional groups of scale inhibitors
5.4.3.2 Chemical structures of scale inhibitors
5.4.3.3 Attributes of scale inhibitors
5.4.3.3.1 Thermal stability
5.4.3.3.2 Brine compatibility
5.4.3.3.3 Effect of chemical structure
5.4.4 Brief history of scale inhibitor development
5.4.5 Chemical deployment
5.4.5.1 Other approaches
5.4.6 Chemical inhibition
5.4.6.1 Mechanisms in inhibition
5.4.7 Factors controlling the performance of generically different inhibitor chemistries
5.4.7.1 Structural features: active functional groups, pKa, and pH
5.4.7.2 Structural features: lattice matching and adsorption considerations
5.4.7.3 Structural features: molecular-weight considerations
5.4.7.4 Influencing conditions: brine composition, the controlling influence of Ca2+ and Mg2+
5.4.7.5 Influencing conditions: dissolved iron
5.4.7.6 Influencing conditions: effect of solution pH, bicarbonate and pressure
5.4.7.7 Influencing conditions: effect of temperature
5.4.7.8 Summary of factors controlling performance
5.4.8 Laboratory assessment of scale inhibitors
5.4.8.1 Continual injection inhibitors
5.4.8.2 Squeeze treatment inhibitors
5.4.8.3 Conventional bulk or “static” jar test
5.4.8.4 Dynamic tube blocking tests
5.4.8.5 Kinetic turbidity testing
5.4.8.6 Jet impingement testing
5.4.8.7 Summary: SI performance and qualification tests
5.4.9 Chemical qualification: final considerations
5.5 Scale inhibitor squeeze
5.5.1 Chemical squeeze process
5.5.1.1 General requirements of scale inhibitor squeeze treatments
5.5.1.2 Squeeze optimization
5.5.2 Chemical retention mechanisms
5.5.2.1 Adsorption/desorption
5.5.2.2 Precipitation /re-dissolution
5.5.2.3 In-situ surface precipitation
5.5.2.4 Importance of temperature
5.5.2.5 Squeeze life enhancers and extenders
5.5.3 Chemical testing of scale inhibitor squeeze treatments: reservoir condition core flooding
5.5.4 The importance of appropriate core flood testing protocols
5.5.4.1 Scale inhibitor/rock reactivity
5.5.4.2 Cautionary notes on combined formation damage and core flooding and core flood artefacts
5.5.5 SI Application considerations: formation damage and inhibitor retention/release properties
5.5.5.1 Formation damage vs. inhibitor return profiles: Sandstone pre-emptive squeeze
5.5.5.2 Formation damage vs. inhibitor return profiles: implications on limestone formation
5.5.5.2.1 Inhibitor retention and release properties, treatment lifetimes
5.5.5.2.2 Formation damage aspects
5.5.5.3 Examples of other factors controlling chemical retention
5.5.5.3.1 Effect of clay content in sandstone reservoirs
5.5.5.3.2 Effect of produced brine composition
5.5.5.4 Nonaqueous deployment packages for squeeze treatments
5.5.5.4.1 Modified preflush and hybrid packages
5.5.5.4.2 Invert emulsion
5.5.5.4.3 Oil soluble scale inhibitors
5.5.5.4.4 Oil-miscible/oil-flowable scale inhibitors
5.5.6 Importance of accurate assay and monitoring
5.5.6.1 SEM analysis of produced scale particles
5.5.7 Isotherm derivation and near-wellbore simulation
5.5.7.1 Isotherm derivation
5.5.7.1.1 Types of isotherms
5.5.7.1.2 Matching the isotherm with core flood data
5.5.7.2 Treatment modeling
5.5.7.2.1 Base case model: comparison of chemicals
5.5.7.2.2 Treatment optimization
5.5.7.2.3 Cautionary note: core flood modeling
5.5.7.3 Example of isotherm derivation and treatment modeling
5.5.7.4 Simulating treatments in tight fractured reservoirs
5.6 Scale remediation
5.6.1 Acid soluble vs acid insoluble scales
5.6.2 Mechanical Remediation/Physical Methods
5.6.3 Chemical dissolution
5.6.4 Chemical deployment in scale dissolution
5.6.5 Acids for Scale Dissolution
5.6.5.1 Common acids used for scale removal
5.6.5.2 Carbonate scale removal
5.6.5.3 Iron scales
5.6.5.4 Scale conversion
5.6.6 Chelating agents for scale dissolution
5.6.6.1 Barium sulfate dissolution
5.6.6.2 Chelating agents for sulfide scales
5.7 Summary
Nomenclature
References
6 Sand control completion using in-situ resin consolidation
6.1 Sand control
6.1.1 Mechanisms and causes of sand production
6.1.2 Problems/issues of sand production
6.1.3 Sand control methods
6.1.3.1 Mechanical sand bridging
6.1.3.1.1 Sand screens
6.1.3.1.2 Gravel packing
6.1.3.1.3 Frac-packing
6.1.3.1.4 Shunt tubes
6.1.3.1.5 Packing voids behind perforated casing
6.1.4 Other wellbore stabilization methods for sand control
6.1.4.1 Perforating
6.1.4.2 Oriented perforating
6.1.5 Perforating techniques for completions using sand-consolidation treatments
6.1.5.1 New intervals
6.1.5.2 Deep penetrating perforating charges
6.1.5.3 Big-hole perforating charges
6.1.5.4 Shot density
6.1.5.5 Hole size
6.1.5.6 Cleaning perforations
6.1.5.7 Prepacking perforation guidelines
6.1.5.8 Prepack procedure
6.1.5.9 Prepacking correlation with success
6.1.6 Chemical sand consolidation
6.1.6.1 Preferred resin characteristics
6.1.6.2 General resin descriptions
6.1.6.3 Curable resins
6.1.6.3.1 Phenolic resins
6.1.6.3.2 Epoxy resins
6.1.6.3.3 Furan resins
6.1.6.4 Design parameters for consolidation treatments
6.1.6.4.1 Short-interval consolidation
6.1.6.4.2 Long-interval consolidation
6.1.6.4.3 Consolidation depth
6.1.6.4.4 Zonal isolation
6.1.6.4.5 Mineralogy
6.1.6.4.6 Effect of clay content
6.1.6.4.7 Effects of over-flush volumes
6.1.6.4.8 Consolidation strengths
6.1.6.4.9 Regained permeability
6.1.6.4.10 Formation water salinity
6.1.6.4.11 Wellbore integrity
6.1.6.4.12 Cleaning the wellbore tubulars
6.1.6.4.13 Determining the bottomhole treating temperature
6.1.6.4.14 Wellbore cleanout/washout
6.1.6.4.15 Gas lift valves and landing nipples
6.1.6.4.16 Fluid control
6.1.6.4.17 Rathole
6.1.6.4.18 Annulus fluid
6.1.6.5 Acid stimulation treatment
6.1.6.5.1 Acid volume
6.1.6.5.2 Acid additives
6.1.6.5.3 Pickling or cleaning the workstring
6.1.6.5.4 Neutralizing the acid
6.1.6.6 Equipment Cleanup
6.1.6.7 Field consolidation treatment procedure/method
6.1.6.7.1 Placement volumes
6.1.6.7.2 Injectivity testing
6.1.6.7.3 Pumping rates
6.1.6.7.4 Preflush
6.1.6.7.5 Post-flush fluid
6.1.6.7.6 Catalyst (if Applicable)
6.1.6.8 Placement techniques
6.1.6.8.1 Direct (matrix) injection
6.1.6.8.2 Bullhead
6.1.6.8.3 Application through coiled tubing
6.1.6.8.4 Application with coiled tubing and jetting
6.1.6.8.5 Application of nitrified sand consolidation and gravel-pack screen repairs
6.1.6.8.6 Application using selective injection packer or straddle packer
6.1.6.9 Restoring well to production
6.1.6.9.1 HCl acidizing
6.1.6.9.2 Reperforating
6.1.6.10 Lessons learned and recommendations
6.1.6.10.1 Typical reasons for failure of a consolidation treatment
6.2 Fines Migration control
6.2.1 Mechanisms and causes
6.2.2 Previous fines migration control methods
6.2.3 Controlling fines migration into proppant pack
6.2.3.1 Primary fines control
6.2.3.2 Remedial fines migration control—treating unconsolidated/weakly consolidated formations or propped fractures
6.2.3.2.1 Solvent-Based ultra-thin tackifying agent
6.2.3.2.2 Aqueous-based ultra-thin tackifying agent
6.2.3.2.3 Applications of ultra-thin tackifying agent
6.2.4 Fines migration field case histories
6.3 Proppant flowback control
6.3.1 Primary proppant flowback control
6.3.1.1 Curable resin pre-coated proppant
6.3.1.2 Fibers and deformable particulate
6.3.1.3 On-site liquid resin coating
6.3.1.4 Liquid-curable resins
6.3.1.4.1 Advantages of liquid-curable resins treatments
On-the-fly application
Enhances or maintains proppant-pack conductivity
Consolidation strength
6.3.1.4.2 Field application of liquid-curable resins
6.3.1.4.3 Case histories of liquid-curable resins
6.3.1.5 Non-curable surface-modification agents
6.3.1.5.1 Field application of surface-modification agent
6.3.1.5.2 Case histories of surface-modification agents
6.3.1.6 Other proppant flowback control methods
6.3.1.6.1 Forced closure
6.3.1.6.2 Mechanical screens
6.3.1.6.3 Screenless frac-pack with near-wellbore consolidation
6.3.2 Remedial methods for proppant flowback
6.3.2.1 Reducing production rate
6.3.2.2 Remedial proppant treatments
6.3.2.2.1 Curable resin systems
Field treatment of curable resins
6.3.2.2.2 Aqueous-based curable resin
6.3.2.2.3 Case histories
6.3.3 Lessons learned/recommendations
Nomenclature
References
7 Condensate and water blocking removal
7.1 Introduction
7.2 Background theory
7.2.1 Fluid phase behavior
7.2.2 Pressure profiles
7.2.3 Two-phase flow challenges
7.2.3.1 Relative permeability
7.2.3.2 Condensate saturation regions in gas-condensate reservoirs
7.2.3.3 Impact of two-phase flow on the productivity index
7.3 Field examples and industry practice
7.3.1 Ichthys gas-condensate field in Australia
7.3.2 Cupiagua gas-condensate field in Columbia
7.3.3 Other examples
7.3.3.1 Solvent injection
7.3.3.2 Gas cycling
7.3.3.3 Nonhydrocarbon gas injection
7.3.3.4 Well stimulation
7.4 Recent advances in research and development
7.4.1 Wettability alteration
7.4.1.1 Impact of wettability on two-phase flow
7.4.1.2 Wettability alteration to mitigate condensate blocking; experimental studies
7.4.1.3 Wettability alteration to mitigate condensate blocking; simulation studies
7.4.1.4 Wettability alteration to mitigate condensate blocking; field applications
7.4.2 CO2 huff-n-puff
7.4.3 Other new technologies
7.5 Final remarks
Nomenclature
References
8 Foam-assisted liquid lift
8.1 Introduction
8.2 Liquid loading and deliquification
8.2.1 Liquid loading
8.2.1.1 Turner criterion
8.2.1.2 Modified Turner criterion
8.2.2 Continuous deliquification
8.2.3 Intermittent deliquification
8.3 Foam-assisted lift
8.3.1 Foam-assisted lift performance
8.3.2 Foam-assisted lift operating envelope
8.3.3 Foam-assisted gas lift
8.3.4 Surface foam-assisted lift
8.4 Foam-assisted lift application
8.5 Well performance
8.5.1 Collect well data
8.5.2 Diagnose and forecast liquid loading
8.5.3 Predict foam-assisted lift operating parameters
8.6 Laboratory testing
8.6.1 Foamer performance
8.6.1.1 Sparging test (modified ASTM D892)
8.6.1.2 Dynamic foaming test (modified ASTM D892)
8.6.2 Secondary performance
8.6.2.1 Physical properties and stability
8.6.2.2 Compatibility with existing chemical injection program
8.6.2.3 Compatibility with injection system
8.6.2.4 Compatibility with separation process
8.7 Foam-assisted lift field testing
8.7.1 Batch foam-assisted lift trial
8.7.2 Continuous foam-assisted lift trial
8.8 Foam-assisted lift application
8.8.1 Continuous or intermittent foam-assisted lift
8.8.2 Solid or liquid foamer
8.8.3 Annulus or capillary
8.8.3.1 External annulus (A-annulus)
8.8.3.2 Internal annulus (new annulus)
8.8.3.3 External control line
8.8.3.4 Internal capillary
8.8.4 Capillary specifications
8.8.4.1 Depth of capillary
8.8.4.2 Capillary size and material
8.8.5 Surface injection system
8.8.5.1 Solid injection
8.8.5.2 Continuous liquid injection
8.8.5.3 Intermittent liquid injection
8.8.5.4 Antifoamer, demulsifier, and clarifier
8.9 Foam-assisted lift operation
8.9.1 Optimizing foam-assisted lift
8.9.2 Sustaining foam-assisted lift
8.9.2.1 Injection rate
8.9.2.2 Capillary string
8.9.2.3 Compatibility
8.10 Case studies of successful foamer applications
8.10.1 Optimize horizontal wells with batch foamer treatment
8.10.1.1 Background and challenges
8.10.1.2 Results
8.10.2 Continuous foam in conjunction with dry-gas-lift
8.10.2.1 Background
8.10.2.2 Results
8.10.3 Innovative foamer as sustainable deliquification solution
8.10.3.1 Background
8.10.3.2 Results
8.10.4 Use foam to remove liquid in subsea flow lines and enhance production
8.10.4.1 Background
8.10.4.2 Results
8.10.5 Foam-assisted lift to optimize mature oil wells
8.11 Remaining challenges
Nomenclature
References
9 Corrosion inhibition
9.1 Corrosion inhibitors
9.1.1 Environmental conditioners/scavengers
9.1.2 Interface inhibitors
9.1.2.1 Cathodic inhibitors
9.1.2.2 Anodic inhibitors
9.1.2.3 Mixed inhibitors
9.2 Mechanism of corrosion inhibition
9.2.1 Environmental conditioners/scavengers
9.2.2 Interface inhibitors
9.2.2.1 Cathodic inhibitors
9.2.2.2 Anodic inhibitors
9.2.2.3 Mixed inhibitors
9.3 Measurement of corrosion inhibition
9.4 Oilfield corrosion inhibitor chemistry examples
9.5 Molecular modeling of corrosion inhibitors
9.5.1 Computation of quantum chemical descriptors
9.5.2 Metal inhibitor interactions using density functional theory
9.5.3 Molecular dynamics study
9.5.4 Monte Carlo simulations
9.5.5 Synergistic effect study using molecular modeling
9.5.6 Screening of corrosion inhibitors using machine learning
9.6 Corrosion inhibitor performance evaluation
9.6.1 Metal samples
9.6.2 Solution chemistry
9.6.3 Test parameters
9.6.3.1 Wheel box test (or rotating wheel test)
9.6.3.2 Bubble tests/kettle tests
9.6.3.3 Rotating cylinder electrode
9.6.3.4 Rotating disk electrode
9.6.3.5 Rotating cage
9.6.3.6 Jet impingement cell
9.6.3.7 Flow loops
9.6.3.8 Under-deposit corrosion
9.6.3.9 Top-of-the-line corrosion
9.6.3.10 Dissimilar metals
9.7 Corrosion rate measurement techniques
9.7.1 Gravimetry (weight loss measurements)
9.7.2 Electrochemical techniques
9.7.2.1 Basic instrumentation
9.7.2.2 Corrosion potential measurement
9.7.2.3 Linear polarization
9.7.2.4 Electrochemical impedance spectroscopy
9.7.2.5 Electrochemical noise
9.8 Additional performance evaluations
9.8.1 Partitioning
9.8.2 Persistency
9.8.3 Pitting tendency analysis
9.9 Surface characterization
9.9.1 Atomic force microscopy
9.9.2 Fourier transform infrared spectroscopy
9.9.3 X-ray photoelectron spectroscopy
9.9.4 Others
9.10 Compatibility tests
9.10.1 Compatibility with metallic materials
9.10.2 Compatibility with nonmetallic materials
9.10.3 Foaming and emulsion tendency
9.10.4 Physical properties, product stability, and additional considerations
9.11 Field performance evaluation
9.11.1 Corrosion monitoring
9.11.2 Corrosion inhibitor residual measurements
9.11.3 Water chemistry analysis
9.12 Case studies
9.12.1 Field application of corrosion inhibitors in sweet (carbon dioxide containing) systems
9.12.1.1 The presence of solids
9.12.1.2 Presence of additional production chemicals
9.12.1.3 Corrosion inhibitor chemical squeeze application
9.12.1.4 Corrosion inhibition under high-velocity environments
9.12.1.5 Tubing displacement for downhole corrosion inhibitor application
9.12.1.6 Top-of-the-line corrosion inhibition
9.12.2 Field application of corrosion inhibitors in sour (hydrogen sulfide containing) systems
9.12.2.1 Corrosion inhibition facilitates successful operations under high hydrogen sulfide conditions
9.12.2.2 Presence of elemental sulfur
9.12.2.3 Effective pipeline cleaning complements corrosion inhibitor application
9.12.3 Learnings from the literature case studies
9.13 Summary
Acknowledgments
Nomenclature
References
10 Microbial control
10.1 Introduction
10.2 Major microorganisms in oil and gas industry
10.2.1 Sulfate-reducing bacteria and archaea
10.2.2 Methanogens
10.2.3 Acid-producing bacteria
10.2.4 Iron- and manganese-oxidizing bacteria
10.3 Biocide classification
10.3.1 Nonoxidizing biocides
10.3.1.1 Formaldehyde and glutaraldehyde
10.3.1.2 Tetrakis hydroxymethyl phosphonium sulfate
10.3.1.3 Quaternary ammonium compounds
10.3.1.4 2,2-Dibromo-3-nitrilopropionamide
10.3.1.5 Isothiazolones
10.3.2 Oxidizing biocides
10.3.2.1 Chlorine dioxide
10.3.2.2 Hypochlorites
10.3.2.3 Bromine chloride
10.3.2.4 Peracetic acid
10.3.3 Preservatives
10.4 Biocide selection and performance evaluation
10.4.1 Considerations for biocide selection and performance evaluation
10.4.2 Methods for biocide evaluation
10.4.2.1 Most probable number test
10.4.2.2 Rapid sulfate-reducing bacteria detection pouch
10.4.2.3 ATP bioluminescence test
10.4.2.4 Quantitative polymerase chain reaction and reverse transcriptase quantitative polymerase chain reaction
10.4.2.5 Flow cytometry
10.5 Biocide treatment practices
10.6 Biocide residual monitoring
10.7 Microbial monitoring for treatment effectiveness
10.8 Alternative methods for microbial control
10.8.1 Nitrate
10.8.2 Bacteriophage
10.8.3 Physical processes
10.9 Final remarks
Nomenclature
References
Index
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