Petroleum Engineer's Guide to Oil Field Chemicals and Fluids

 
 
Gulf Professional Publishing
  • 2. Auflage
  • |
  • erschienen am 31. August 2015
  • |
  • 854 Seiten
 
E-Book | ePUB mit Adobe DRM | Systemvoraussetzungen
E-Book | PDF mit Adobe DRM | Systemvoraussetzungen
978-0-12-803735-5 (ISBN)
 

The oil and gas engineer on the job requires knowing all the available oil field chemicals and fluid applications that are applicable to the operation. Updated with the newest technology and available products, Petroleum Engineer's Guide to Oil Field Chemicals and Fluids, Second Edition, delivers all the necessary lists of chemicals by use, their basic components, benefits, and environmental implications. In order to maintain reservoir protection and peak well production performance, operators demand to know all the options that are available. Instead of searching through various sources, Petroleum Engineer's Guide to Oil Field Chemicals and Fluids, Second Edition, presents a one-stop non-commercialized approach by organizing the products by function, matching the chemical to the process for practical problem-solving and extending the coverage with additional resources and supportive materials. Covering the full spectrum, including fluid loss additives, drilling muds, cement additives, and oil spill treating agents, this must-have reference answers to every oil and gas operation with more options for lower costs, safer use, and enhanced production.


  • Effectively locate and utilize the right chemical application specific to your oil and gas operation with author's systematic approach by use
  • Gain coverage on all oil field chemicals and fluids needed throughout the entire oil and gas life cycle, including drilling, production, and cementing
  • Understand environmental factors and risks for oil field chemicals, along with pluses and minuses of each application, to make the best and safest choice for your operation
  • Englisch
  • USA
Elsevier Science
  • 9,96 MB
978-0-12-803735-5 (9780128037355)
0128037350 (0128037350)
weitere Ausgaben werden ermittelt
  • Front Cover
  • Petroleum Engineer's Guide to Oil Field Chemicals and Fluids
  • Copyright
  • Preface to Second Edition
  • Preface
  • How to Use This Book
  • Index
  • Bibliography
  • Acknowledgments
  • Contents
  • Chapter 1: Drilling muds
  • 1.1 Classification of muds
  • 1.1.1 Dispersed noninhibited systems
  • 1.1.2 Phosphate-treated muds
  • 1.1.3 Lignite muds
  • 1.1.4 Quebracho muds
  • 1.1.5 Lignosulfonate muds
  • 1.1.6 Lime muds
  • 1.1.7 Sea water muds
  • 1.1.8 Nondispersed noninhibited systems
  • 1.1.9 Low-solids fresh water muds
  • 1.1.10 Variable density fluids
  • 1.1.11 Gas-based muds
  • 1.1.12 Drill-in fluids
  • Heavy brine completion fluids
  • 1.2 Mud compositions
  • 1.2.1 Inhibitive water-based muds
  • 1.2.2 Water-based muds
  • Compositions with improved thermal stability
  • Shale encapsulator
  • Membrane formation
  • 1.2.3 Oil-based drilling muds
  • Poly(ether)cyclicpolyols
  • Emulsifier for deep drilling
  • Biodegradable composition
  • Electric conductive nonaqueous mud
  • Water removal
  • 1.2.4 Synthetic muds
  • 1.2.5 Inverted emulsion drilling muds
  • Esters
  • Acetals
  • Anti-settling properties
  • Glycosides
  • Miscellaneous
  • Reversible phase inversion
  • 1.2.6 Foam drilling
  • 1.2.7 Chemically enhanced drilling
  • Temperature and salinity effects
  • 1.2.8 Supercritical carbon dioxide drilling
  • 1.3 Additives
  • 1.3.1 Thickeners
  • Polymers
  • pH responsive thickeners
  • Mixed metal hydroxides
  • 1.3.2 Lubricants
  • Hagfish slime
  • 1.3.3 Bacteria
  • 1.3.4 Corrosion inhibitors
  • 1.3.5 Viscosity control
  • 1.3.6 Clay stabilization
  • 1.3.7 Formation damage
  • 1.3.8 Shale stabilizer
  • 1.3.9 Fluid loss additives
  • Water swellable polymers
  • Shear degradation of lost circulation materials
  • Anionic association polymer
  • Fragile gels
  • Aphrons
  • Permanent grouting
  • 1.3.10 Scavengers
  • Oxygen scavenger
  • Hydrogen sulfide removal
  • 1.3.11 Surfactants
  • Surfactant in hydrocarbon solvent
  • Biodegradable surfactants
  • Deflocculants and dispersants
  • Shale stabilizing surfactants
  • Toxicity
  • Defoamers
  • 1.3.12 Hydrate inhibitors
  • 1.3.13 Weighting materials
  • Barite
  • Ilmenite
  • Carbonate
  • Zinc oxide, zirconium oxide, and manganese tetroxide
  • Hollow glass microspheres
  • 1.3.14 Organoclay compositions
  • Biodegradable organophilic clay
  • Poly(vinyl neodecanoate)
  • 1.3.15 Miscellaneous
  • Reticulated bacterial cellulose
  • Scleroglucan
  • Uintaite
  • Sodium asphalt sulfonate
  • Formation damage by gilsonite and sulfonated asphalt
  • Illitic sandstone outcrop cores
  • 1.3.16 Multicomponent additives
  • 1.4 Cleaning operations
  • 1.4.1 Cuttings removal
  • 1.4.2 Junk removal
  • 1.4.3 Filter cake removal
  • 1.5 Drilling fluid disposal
  • 1.5.1 Toxicity
  • 1.5.2 Conversion into cements
  • 1.5.3 Environmental regulations
  • 1.6 Characterization of drilling muds
  • 1.6.1 Viscosity
  • 1.6.2 API Filtration
  • 1.6.3 Alkalinity and pH
  • 1.6.4 Total hardness
  • 1.6.5 Roller oven
  • 1.6.6 Effects on log data
  • References
  • Chapter 2: Fluid loss additives
  • 2.1 Mechanism of action of fluid loss agents
  • 2.1.1 Pore size measurement by nanoparticles
  • 2.1.2 Action of macroscopic particles
  • 2.1.3 Action of cement fluid loss additives
  • 2.1.4 Testing of fluid loss additives
  • 2.1.5 Formation damage
  • 2.1.6 Reversible gels
  • 2.1.7 Bacteria
  • 2.2 Inorganic additives
  • 2.2.1 Bentonite
  • 2.2.2 Sodium metasilicate
  • 2.2.3 Ultra-fine filtrate-reducing agents
  • 2.2.4 Bridging agents for fluid loss control
  • 2.3 Organic additives
  • 2.3.1 Tall oil pitch
  • 2.3.2 Mercaptans for iron control
  • 2.4 Poly(saccharide)s
  • 2.4.1 Cellulose-based fluid loss additives
  • Polyanionic cellulose
  • Sulfonate
  • Carboxymethyl cellulose
  • Hydroxyethyl cellulose
  • 2.4.2 Starch
  • Crosslinked starch
  • Pregelatinized starch
  • Granular starch and mica
  • Depolymerized starch
  • Controlled degradable fluid loss additives
  • Multimodal distributed polymers
  • 2.4.3 Borate crosslinkers
  • 2.4.4 Guar
  • Hydroxypropyl guar gum
  • 2.4.5 Succinoglycan
  • 2.4.6 Poly(ether)-modified poly(saccharide)s
  • 2.4.7 Scleroglucan
  • 2.4.8 Gellan
  • 2.5 Humic acid derivates
  • Oil-based well working fluids
  • 2.5.1 Lignosulfonates
  • Grafted lignin or lignite
  • Greek lignites
  • 2.6 Synthetic polymers
  • 2.6.1 Poly(orthoester)s
  • 2.6.2 Poly(hydroxyacetic acid)
  • 2.6.3 Polydrill
  • Polymer of monoallylamine
  • Polyphenolics
  • 2.6.4 Latex
  • Colloidally stabilized latex
  • 2.6.5 Poly(vinyl alcohol)
  • 2.6.6 Poly(ethyleneimine)
  • 2.6.7 Acrylics
  • Permeability control
  • Copolymers
  • Oil soluble styrene acrylate copolymers
  • AMPS terpolymer
  • 2.6.8 Silicones
  • 2.6.9 Phthalimide as a diverting material
  • 2.6.10 Control of degradation rates for polymericdiverting agents
  • 2.6.11 Special applications
  • Coal-bed methane drilling
  • Sand control
  • Reduction of fines migration
  • Fracturing
  • Biomimetic adhesive compositions
  • Cement compositions
  • Viscoelasticity
  • Viscoelastic surfactants
  • Enhanced shear recovery agents
  • Enzyme-based gel breaking
  • Breaker enhancers for VES
  • Surfactant polymer compositions
  • Additives to reduce fluid loss
  • References
  • Chapter 3: Clay stabilization
  • 3.1 Properties of clays
  • 3.1.1 Swelling of clays
  • 3.1.2 Montmorillonite
  • 3.1.3 Guidelines
  • 3.2 Mechanisms causing instability
  • 3.2.1 Kinetics of swelling of clays
  • 3.2.2 Hydrational stress
  • 3.2.3 Borehole stability model
  • 3.2.4 Shale inhibition with water-based muds
  • 3.2.5 Inhibiting reactive argillaceous formations
  • 3.2.6 Thermal treatment to increase the permeability
  • 3.2.7 Formation damage by fluids
  • 3.2.8 Formation damage in gas productionshut-in
  • 3.3 Inhibitors of swelling
  • 3.4 Inhibitors in detail
  • 3.4.1 Salts
  • 3.4.2 Quaternary ammonium salts
  • 3.4.3 Potassium formate
  • 3.4.4 Saccharide derivatives
  • 3.4.5 Sulfonated asphalt
  • 3.4.6 Grafted copolymers
  • 3.4.7 Poly(oxyalkylene amine)s
  • 3.4.8 Anionic polymers
  • 3.4.9 Amine salts of maleic imide
  • Environmentally friendly clay stabilizer
  • 3.4.10 Comparative study
  • 3.5 Test methods
  • 3.5.1 Shale erosion test
  • Disintegration of particles
  • Change of mesh size
  • 3.5.2 Hassler cell
  • References
  • Chapter 4: Lubricants
  • 4.1 Synthetic greases
  • 4.1.1 Base fluids
  • 4.1.2 Extreme pressure agents
  • 4.1.3 Anti-seize agents
  • 4.1.4 Anti-wear additives
  • 4.1.5 Metal deactivators
  • 4.1.6 Solubility aids
  • 4.1.7 Antioxidants
  • 4.1.8 Base stocks
  • 4.2 Lubricant compositions
  • 4.2.1 Molybdenum disulfide
  • 4.2.2 Polarized graphite
  • 4.2.3 Ellipsoidal glass granules
  • 4.2.4 Calcium sulfonate based greases
  • 4.2.5 Paraffins
  • 4.2.6 Olefins
  • 4.2.7 Phospholipids
  • 4.2.8 Alcohols
  • Alcohol glucoside mixture
  • Partial glycerides
  • Aminoethanols
  • Polymeric alcohols
  • 4.2.9 Ethers
  • 4.2.10 Esters
  • Ester-based oils
  • Ester alcohol mixtures
  • Phosphate esters
  • Biodegradable compositions
  • 4.2.11 Polymers
  • 4.2.12 Starch
  • 4.2.13 Amides
  • 4.3 Special issues
  • 4.3.1 Side reactions
  • 4.3.2 Silicate-based muds
  • 4.3.3 Studies on pipe sticking
  • 4.3.4 Differential sticking reducer
  • References
  • Chapter 5: Bacteria control
  • 5.1 Mechanisms of growth
  • 5.1.1 Growth of bacteria supported by oilfield chemicals
  • 5.1.2 Mathematical models
  • Model of colony growth
  • 5.1.3 Modeling of nitrate injection
  • 5.1.4 Detection of bacteria
  • API serial dilution method
  • Enzymatic assay
  • Electrochemical determination
  • Colorimetry
  • Most probable number technique
  • DNA sequencing
  • 5.1.5 Sulfate-reducing bacteria
  • Issues in the oilfield
  • 5.1.6 Bacterial corrosion
  • 5.1.7 Mechanisms of microbial corrosion
  • Simultaneous mechanisms of corrosion
  • pH regulation
  • Biocide enhancers
  • 5.1.8 Corrosion monitoring
  • Bacterial hydrogenase
  • Lipid biomarkers
  • Electron microscopy
  • Electrochemical impedance spectroscopy
  • 5.1.9 Assessment of activity of biocides
  • 5.1.10 Synergistic action of biocides
  • 5.2 Treatments with biocides
  • 5.2.1 Previously fractured formations
  • 5.2.2 Intermittent addition of biocide
  • 5.2.3 Nonbiocidal control
  • Biocompetitive exclusion technology
  • Inhibitors for bacterial films
  • Periodic change in ionic strengths
  • 5.3 Biocides
  • 5.3.1 Various biocides
  • Formaldehyde
  • Glutaraldehyde
  • Bisulfite adduct
  • Combined chlorine-aldehyde treatment
  • Green biocide enhancer
  • Quaternary ammonium based biocides
  • Bis[tetrakis(hydroxymethyl)phosphonium] sulfate
  • Thiones for treatment fluids
  • Halogen compounds
  • Bromine chloride
  • Chlorine dioxide
  • Nitrogen containing compounds
  • Effervescent biocide compositions
  • References
  • Chapter 6: Corrosion inhibitors
  • 6.1 Specific issues
  • 6.1.1 Sweet corrosion
  • 6.1.2 Absorption of hydrogen sulfide
  • 6.1.3 Predicting inhibited erosion corrosion
  • 6.2 Corrosion: application of chicory as corrosion inhibitor for acidic environments
  • 6.3 Classification of corrosion inhibitors
  • 6.4 Fields of application
  • 6.4.1 Acidization
  • 6.4.2 Oil storage tanks
  • 6.4.3 Pipelines
  • 6.4.4 Production wells
  • 6.4.5 Scale removal treatments using acids
  • 6.5 Application techniques
  • 6.5.1 Batch application versus continuous application
  • 6.5.2 Emulsions
  • 6.5.3 Application in solid form
  • 6.6 Characterization
  • 6.6.1 Dye transfer method
  • 6.6.2 Liquid chromatography
  • 6.6.3 Thin layer chromatography
  • 6.6.4 Ultraviolet spectroscopy
  • 6.6.5 Corrosion tests
  • 6.6.6 Micelle concentration
  • 6.7 Side effects
  • 6.7.1 Stabilizer for emulsions
  • 6.7.2 Antisynergism with alcohols
  • 6.7.3 Synergism with surfactants
  • 6.7.4 Interactions with kinetic gas hydrate inhibitors
  • 6.7.5 Effect of flow on inhibitor film life
  • 6.8 Inhibitor chemicals
  • 6.8.1 Amides and imidazolines
  • Amides
  • Poly(imido amine)s
  • Polypeptides
  • Ampholytes
  • Slow-release formulation
  • 6.8.2 Salts of nitrogenous bases
  • 6.8.3 Nitrogen quaternaries
  • Thio-substituted salts
  • Synergism of thiosulfate
  • 6.8.4 Polyoxylated amines, amides, and imidazolines
  • Mercaptan modified products
  • Poly(amine) derivatives
  • Fatty amine adducts
  • Adducts to polymers
  • Formaldehyde condensates with amines
  • Lignin amines
  • Amido amine salts
  • Fatty acid amides
  • 6.8.5 Nitrogen heterocyclics
  • Hexamethylenetramine
  • Imidazolines
  • Pyridinium compounds
  • Azoles
  • Aminopyrazine with epoxide compound
  • 6.8.6 Carbonyl compounds
  • Aldehydes with surfactants
  • Aldose group antioxidants
  • Phosphate esters
  • 6.8.7 Silicate-based inhibitors
  • 6.8.8 Thioacetals
  • 6.9 Miscellaneous inhibitors
  • 6.9.1 Antimony halides
  • 6.9.2 Aldol-amine adducts
  • 6.9.3 Inulin
  • 6.9.4 Encapsulated types
  • 6.9.5 Anti biofoulant corrosion inhibitors
  • 6.9.6 Formic acid free formulation
  • 6.9.7 Acrolein
  • 6.9.8 Intensifiers
  • References
  • Chapter 7: Scale inhibitors
  • 7.1 Scale prediction
  • 7.2 Classification and mechanism
  • 7.2.1 Thermodynamic inhibitors
  • 7.2.2 Kinetic inhibitors
  • 7.2.3 Adherence inhibitors
  • 7.3 Mathematical models
  • 7.3.1 Optimal dose
  • 7.3.2 Precipitation squeeze method
  • 7.4 Inhibitor chemicals
  • 7.4.1 Water-soluble inhibitors
  • Acids
  • Hydrofluoric acid
  • Encapsulated scale inhibitors
  • Chelating agents
  • EDTA
  • Phosphonates
  • Alkaline earth sulfates
  • Synergistic properties
  • Testing of scale inhibitors for barite
  • Biodegradable scale inhibitors
  • Sodium iminodisuccinate
  • Disodium hydroxyethyleneiminodiacetic acid
  • Sodium gluconate and sodium glucoheptonate
  • Sodium poly(aspartate)
  • 7.4.2 Oil soluble scale inhibitors
  • Aloe based scale inhibitor
  • 7.4.3 Inhibitors special tasks
  • Iron sulfide
  • Lead sulfide
  • Zinc sulfide
  • Naturally occurring radioactive materials
  • High-reservoir temperatures
  • 7.5 Characterization
  • 7.5.1 Spectroscopic methods
  • 7.5.2 Turbidimetry
  • 7.5.3 Static bottle test
  • 7.5.4 Thermal degradation
  • 7.5.5 Sorption of nanoparticle-crosslinked polymeric scale inhibitors
  • References
  • Chapter 8: Gelling agents
  • 8.1 Placing gels
  • 8.2 Basic mechanisms of gelling agents
  • 8.2.1 Polymer-crosslinker-retarder systems
  • Carboxylic acids as retarders
  • 8.3 Gelling in oil-based systems
  • 8.3.1 Aluminum phosphate ester salts
  • 8.3.2 Low-volatile phosphoric acid esters
  • 8.3.3 Aluminum trichloride
  • 8.3.4 Biopolymers
  • Curdlan
  • Poly-3-hydroxybutyrate
  • Succinoglycan
  • 8.3.5 Organic polysilicate ester
  • 8.3.6 Latex
  • Reversible gelling system
  • 8.4 Gelling in water-based systems
  • 8.4.1 Xanthan gum
  • 8.4.2 Carboxymethyl cellulose
  • Poly(dimethyl diallyl ammonium chloride)
  • Lignosulfonate and carboxymethyl cellulose
  • 8.4.3 Poly(acrylamide)-based formulations
  • Retention
  • Delayed gelation
  • Complexing agents
  • Adjustment of pH
  • Poly(acrylamide) and urotropin-based mixture
  • Reinforcement by fibers
  • Metal ions and salts as crosslinking agents
  • Waste materials
  • Chromium (III) propionate
  • Gelation process and gel breaking
  • Aluminum citrate
  • Interactions of metal salts with the formation
  • Bentonite clay and poly(acrylamide)
  • Thermal insulation compositions
  • 8.4.4 Poly(acrylic acid)
  • 8.4.5 Alkali-silicate aminoplast compositions
  • 8.5 In situ formed polymers
  • 8.5.1 Epoxide resins
  • 8.5.2 Urea-formaldehyde resins
  • 8.5.3 Vinyl monomers
  • 8.5.4 Polymeric acids
  • References
  • Chapter 9: Filter cake removal
  • 9.1 Simulation of a filter cake formation
  • 9.2 Bridging agents
  • 9.2.1 Degradable bridging agents
  • 9.2.2 Dissolvable bridging agents
  • 9.3 Degradation by acids
  • 9.3.1 Citric acid
  • Horizontal well acid breaker
  • 9.3.2 Acetic acid
  • 9.3.3 Acid generating coatings
  • 9.3.4 Acidic foam
  • 9.4 Orthoesters
  • 9.5 Enzymatic degradation
  • 9.6 Nonaqueous breaker fluids
  • 9.7 Peroxides
  • 9.7.1 Hydrogen peroxide
  • 9.7.2 Metal peroxides
  • 9.7.3 Magnesium peroxide in filter cake
  • 9.8 Degradation by oligosaccharides
  • 9.9 Breaking by emulsions
  • 9.9.1 Surfactant nanotechnology
  • 9.10 Special issues
  • 9.10.1 Manganese tetroxide
  • Removal of manganese tetraoxide
  • Formation damage caused by improper manganese tetraoxide-based filter cake cleanup treatments
  • 9.10.2 Multiply active compositions
  • 9.10.3 Self-destructing filter cake
  • 9.10.4 Oscillatory flow
  • References
  • Chapter 10: Cement additives
  • 10.1 Cementing Technologies
  • 10.1.1 Primary Cementing
  • 10.1.2 Secondary Cementing
  • 10.1.3 Squeeze Cementing
  • 10.1.4 Plug Cementing
  • 10.2 Basic composition of portland cement
  • 10.2.1 Manufacturing
  • Grinding and mixing
  • Burning
  • 10.2.2 Active Components in Cements
  • 10.2.3 Chemistry of Setting
  • 10.2.4 Standardization of Cements
  • 10.2.5 Mixing with Additives
  • 10.2.6 Important Properties of Cement Slurriesand Set Cement
  • Specific weight
  • Thickening time
  • Strength of the set cement
  • 10.3 Special cement types
  • 10.3.1 Resin Cement
  • 10.3.2 Oil-Based Cement
  • 10.3.3 High-Temperature Cement
  • Silica flour and silica fume
  • 10.3.4 Low-Temperature Cement
  • 10.3.5 High-Alumina Cement
  • 10.3.6 Magnesian Cement
  • 10.3.7 Fiber Cement
  • 10.3.8 Acid Gas Resistant Cement
  • 10.3.9 Permeable Cement
  • 10.3.10 Salt Water Stable Latex Cement
  • 10.3.11 Settable Drilling Fluids
  • 10.4 Classification of cement additives
  • 10.4.1 Synergistic and Antagonistic Effects BetweenCement Additives
  • 10.4.2 Light-weight Cement
  • Bentonite
  • Furnace slag
  • Hollow glass microspheres
  • Ceramic microspheres
  • Gilsonite
  • Pozzolan
  • Rubber
  • Coal
  • Diatomaceous earth
  • Perlite
  • 10.4.3 Foam Cement
  • 10.4.4 Density-Increasing or Weighting Agents
  • 10.4.5 Thickening and Setting Time Control
  • Cement retarders
  • Cement accelerators
  • Nanosilicas
  • Zeolites
  • 10.4.6 Viscosity Control
  • Thermal thinning
  • 10.4.7 Dispersants
  • 10.4.8 Expansion Additives
  • 10.4.9 Set Strength Enhancement
  • Fibers
  • 10.4.10 Adhesion Improvement
  • 10.4.11 Fluid Loss Control
  • Organic fluid loss additives
  • 10.4.12 Clay Control Additives
  • 10.4.13 Anti-Gas-Migration Agents
  • 10.4.14 Corrosion Inhibitors
  • 10.4.15 Other Chemical Attack
  • 10.4.16 Use of Waste of Other Industrial Branches
  • Cement manufacture with wastes
  • Disposal of oil sludge
  • References
  • Chapter 11: Transport
  • 11.1 Tracers
  • 11.2 Modelling of the viscosity
  • 11.3 Pretreatment of the products
  • 11.3.1 Pretreatment for corrosion prevention
  • 11.3.2 Natural gas
  • 11.3.3 Sulfur contamination of refined products
  • 11.3.4 Phosphorus free gelling agents
  • 11.3.5 Demulsifiers
  • 11.3.6 Heavy crudes
  • Emulsions for heavy crudes
  • Activation of natural surfactants
  • Low-temperature transportation
  • 11.4 Corrosion control
  • 11.4.1 Weld corrosion
  • 11.4.2 Crude oil treatment
  • 11.4.3 Chemical inhibition
  • Synergism with drag reducers
  • 11.4.4 Coatings
  • Alternative plastic materials
  • 11.5 Carbon dioxide removal
  • 11.6 Paraffin inhibitors
  • 11.7 Pour point depressants
  • 11.8 Drag reducers
  • 11.8.1 Drag reduction in gas transmission lines
  • 11.8.2 Synergism with paraffin deposition
  • 11.9 Hydrate control
  • 11.10 Additives for slurry transport
  • 11.11 Additives for odorization
  • 11.12 Cleaning
  • 11.12.1 Acidic fluids
  • 11.12.2 Sand removal
  • 11.12.3 Gelled pigs
  • Ablating gelatin
  • Coacervate gels
  • References
  • Chapter 12: Drag reducers
  • 12.1 Operating costs
  • 12.2 Mechanism of drag reducers
  • 12.2.1 Damping of transmission of eddies
  • 12.2.2 Viscoelastic fluid thread
  • 12.2.3 Polymer degradation in turbulent flow
  • 12.2.4 Drag reduction in two-phase flow
  • 12.2.5 Drag reduction in gas flow
  • 12.2.6 Microfibrils
  • 12.2.7 Drag reducing surfactant solutions
  • 12.2.8 Soapy industrial cleaner
  • 12.2.9 Lyophobic performance of the lining material
  • 12.2.10 Interpolymer complexes
  • 12.3 Drag reducer chemicals
  • 12.3.1 Ultra-high-molecular weight poly(ethylene)
  • 12.3.2 Copolymers of a-olefins
  • 12.3.3 Latex drag reducers
  • 12.3.4 Poly(ether) compounds for oil-based welldrilling fluids
  • 12.3.5 Tylose
  • 12.3.6 Microencapsulated polymers
  • 12.3.7 Aluminum carboxylate
  • References
  • Chapter 13: Gas hydrate control
  • 13.1 Naturally Occurring Gas Hydrates
  • 13.2 Problems with gas hydrates in petroleum technology
  • 13.3 Nature of inclusion compounds
  • 13.3.1 Gas Hydrates
  • Type I hydrates
  • Type II hydrates
  • Type H hydrates
  • 13.4 Conditions for formation
  • 13.4.1 Water Content
  • 13.4.2 Decomposition
  • 13.4.3 Stability Diagram
  • 13.4.4 Clausius-Clapeyron Equation
  • 13.4.5 Hammerschmidt Equation
  • 13.5 Formation and properties of gas hydrates
  • 13.5.1 Two-Step Mechanism of Formation
  • 13.5.2 Nucleation Particle Sizes
  • 13.5.3 Clustering Before Nucleation
  • 13.5.4 Experimental Methods
  • 13.5.5 Modeling the Formation of Gas Hydrates
  • 13.5.6 Optimizing the Dose Rate
  • 13.6 Test Procedures for Inhibitors
  • 13.6.1 Screening Method
  • 13.6.2 High Pressure Sapphire Cell
  • 13.6.3 Circulating Loop
  • 13.7 Hydrate reformation in methane hydrate bearing sediments
  • 13.8 Inhibition of gas hydrate formation
  • 13.8.1 Drying
  • 13.8.2 Thermodynamic Inhibition with Additives
  • 13.8.3 Kinetic Inhibition
  • Nanoparticle kinetic gas hydrate inhibitors
  • 13.8.4 Nucleation Inhibitors
  • Poly(ethylene oxide)
  • 13.8.5 Crystal Growth Inhibitors
  • Vinyl polymers
  • Bimodal distributions
  • Poly(N-vinyl-2-pyrrolidone)
  • Functionalization
  • Dendrimers
  • Poly(ether) amines
  • Amines
  • Poly(imine) adducts
  • Antifreeze proteins
  • Hyperbranched polymers
  • 13.8.6 Agglomeration Inhibitors
  • 13.8.7 Gas Hydrate Inhibitors with Corrosion Inhibition
  • 13.8.8 Recyclable Antifreeze Agents
  • 13.8.9 Degradable Polymer Compositions
  • 13.9 Hydrate inhibitors for drilling fluids
  • References
  • Chapter 14: Antifreeze agents
  • 14.1 Theory of Action
  • 14.2 Antifreeze Chemicals
  • 14.3 Heat Transfer Liquids
  • 14.3.1 Brines
  • 14.3.2 Alcohols
  • 14.3.3 Glycols
  • Properties of glycol-based antifreeze formulations
  • Pour point
  • Corrosion
  • Foam inhibitors
  • Damage of elastomers
  • 14.3.4 Toxicity and Environmental Aspects
  • Human toxicity
  • Aquatic toxicity
  • Biodegradation
  • Recycling
  • 14.4 Special Uses
  • 14.4.1 Hydraulic Cement Additives
  • 14.4.2 Pipeline Transportation of Aqueous Emulsionsof Oil
  • 14.4.3 Low Temperature Drilling Fluids
  • References
  • Chapter 15: Odorization
  • 15.1 General Aspects
  • 15.1.1 Limits of Explosion
  • 15.1.2 Desirable Properties of Odorants
  • 15.2 Measurement and odor monitoring
  • 15.2.1 Olfactoric Response
  • Perceptual threshold and olfactoric intensity
  • Odor index
  • Olfactory power
  • 15.2.2 Physiological Methods
  • Triangle odor bag method
  • Standardized methods
  • 15.2.3 Chemical and Physical Methods
  • Chromatographic and spectroscopic methods
  • Colorimetric methods
  • Electronic nose
  • 15.3 Additives for odorization
  • 15.3.1 Sulfur Compounds
  • Thermodynamic properties of odorants
  • Structure property relationships
  • 15.3.2 Other Compounds
  • 15.4 Industrial synthesis of odorants
  • 15.5 Uses and properties
  • 15.5.1 Odorant Injection Techniques
  • 15.5.2 Leak Detection
  • 15.5.3 Fuel Cells
  • 15.5.4 Odor-Fading
  • 15.5.5 Environmental Problems
  • References
  • Chapter 16: Enhanced oil recovery
  • 16.1 Waterflooding
  • 16.1.1 Surfactants
  • Kinetics of low-salinity flooding
  • Implicit simulation of surfactant flooding
  • Frontal-stability analysis of surfactant floods
  • Critical velocity required for a gravity stable surfactant flood
  • Monte Carlo method in surfactant flooding implementation
  • Alkyl-aryl sulfonates
  • Surfactants of high activity
  • Interactions of crude oil and alkaline solutions
  • Effect of alkalinity
  • Effect of initial water saturation
  • Effect of pressure and solution gas on oil recovery
  • Effects of connate water in alkaline flooding
  • Combination of primary and secondary surfactant systems
  • Lignosulfonate acrylic acid graft copolymers as sacrificial agents
  • Silicone compounds with surfactants
  • Nonionic tensides
  • Ethoxylated nonyl phenols
  • Interactions between ethoxy nonyl phenol and poly(acrylamide)
  • Hybrid ionic nonionic surfactants
  • Olefin surfactants
  • Anionic gemini surfactants
  • 16.1.2 Inter-phase structure
  • Sandwich structures
  • Dynamic IFT behavior with in situ-formed surfactants
  • 16.1.3 Interfacial rheological properties
  • 16.1.4 Microemulsion phase diagrams
  • 16.1.5 Interfacial tension
  • 16.1.6 Imbibition experiments
  • Spontaneous imbibition of water using nanofluids
  • 16.1.7 Wettability alteration model
  • 16.2 Caustic waterflooding
  • 16.2.1 Injection strategies
  • 16.2.2 Foam-enhanced caustic waterflooding
  • 16.2.3 Alkaline surfactant polymer flooding
  • Deep eutectic solvents
  • Propagation of a nanodispersed catalyst
  • Use of cosolvents
  • 16.2.4 Sweep efficiency
  • 16.2.5 Interphase properties
  • 16.2.6 Clay dissolution
  • 16.3 Smart waterflooding
  • 16.4 Acid flooding
  • 16.4.1 Hydrochloric acid
  • 16.4.2 Sulfuric acid
  • 16.5 Emulsion flooding
  • 16.5.1 Micellar polymer flooding
  • Micellar and alkaline surfactant polymer flooding
  • Scale-up methods for micellar flooding
  • 16.6 Chemical injection
  • 16.6.1 Ammonium carbonate
  • 16.6.2 Hydrogen peroxide
  • 16.6.3 Alcohol-waterflooding
  • Butanol
  • Isopropanol and ammonia
  • Residue from the production of glycerol or ethylene glycol
  • 16.6.4 Chemical injection of waste gases
  • 16.7 Polymer waterflooding
  • 16.7.1 Polymer degradation
  • 16.7.2 Low-tension polymer flood technique
  • 16.7.3 Influence of viscosity on ionic strength
  • 16.7.4 pH-Responsive amphiphilic systems
  • Effect of gas on the injectivity
  • 16.7.5 Modified acrylics
  • Shear stability
  • 16.7.6 Biopolymers
  • Pseudozan
  • Xanthan
  • 16.8 Combination flooding
  • 16.8.1 Low-tension polymer flood
  • 16.8.2 Effect of alkaline agents on the retention
  • 16.8.3 Alkaline steamflooding
  • 16.8.4 Sediment-forming materials
  • 16.8.5 Water-alternating gas technology
  • 16.8.6 Low tension gas flooding
  • 16.8.7 Cyclic steam injection
  • 16.8.8 Hydrocarbon-assisted steam injection
  • 16.9 Foam flooding
  • 16.9.1 Optimal design of foams
  • 16.9.2 Experimental study of foam flow
  • 16.9.3 Basic principles of foam flooding
  • 16.9.4 Air foam injection
  • 16.9.5 Ambient pressure foam tests
  • Foam mobility control
  • Foam propagation
  • Trapped gas in foam
  • Sand pack model
  • Foaming agents
  • Fluorocarbon surfactant
  • 16.9.6 Alkaline steam foaming
  • 16.9.7 Polymer-enhanced foams
  • 16.10 Carbon dioxide flooding
  • 16.11 Steamflooding
  • 16.11.1 Carbon dioxide
  • 16.11.2 Air injection
  • 16.11.3 Chemical reactions
  • 16.12 In situ combustion
  • 16.12.1 Analysis of in situ combustion in afractured core
  • 16.13 Special techniques
  • 16.13.1 Viscous oil recovery
  • Low-temperature oxidation
  • Cap gas
  • Special surfactant formulations
  • Visbreaking
  • 16.13.2 Low-permeability flooding
  • 16.13.3 Permeability reduction
  • 16.13.4 Gravity drainage
  • Interfacial stability
  • Gravity override
  • 16.14 Microbial enhanced oil recovery techniques
  • 16.14.1 Basic principles and methods
  • 16.14.2 Bioavailability of nutrient additions
  • 16.14.3 Economics
  • Potential health hazard of bacteria
  • Metabolism
  • Microbial control of the production of sulfide
  • Bacillus licheniformis
  • Microbial ecology of corrosion
  • 16.14.4 Strict anaerobic bacteria
  • Shewanella putrefaciens
  • Thauera strains
  • Methanohalophilus
  • Sulfate-reducing desulfovibrio
  • 16.14.5 Ultramicrobacteria
  • Lactic acid bacteria
  • 16.14.6 Scale inhibitors as a microbial nutrient
  • 16.14.7 Extremophile anaerobic indigenousmicroorganisms
  • 16.14.8 Interfacial properties
  • Interfacial tension
  • Interfacial rheologic properties
  • Caustic waterflooding
  • 16.14.9 Tracers
  • Application of tracers
  • Retention of the tracer
  • Radioactive tracers
  • Nonradioactive tracers
  • 16.14.10 Thermal stability of alkyl benzene sulfonate
  • 16.14.11 Asphaltene deposition
  • 16.14.12 Stabilizer dispersant
  • 16.15 Reservoir properties
  • 16.15.1 Reservoir models
  • 16.15.2 Gas permeability of shale
  • 16.15.3 Permeability reduction
  • 16.15.4 Viscosity improvement
  • 16.15.5 Profile control
  • AAm polymers
  • Melamine and phenol-formaldehyde resins
  • Latex
  • In situ carbonate precipitation
  • In situ silica cementation
  • Hydratable clay
  • Silicate gel
  • 16.15.6 Formation damage
  • 16.15.7 Water salinity and ionic content
  • 16.15.8 Wettability
  • 16.15.9 Flooding of oil in chalk
  • 16.16 Treatment of produced water
  • 16.17 Soil remediation
  • References
  • Chapter 17: Fracturing fluids
  • 17.1 Stresses and Fractures
  • 17.2 Comparison of stimulation techniques
  • 17.2.1 Action of a Fracturing Fluid
  • 17.2.2 Stages in a Fracturing Job
  • 17.3 Types of hydraulic fracturing fluids
  • 17.3.1 Comparison of Different Techniques
  • 17.3.2 Expert Systems for Assessment
  • 17.4 Water-based systems
  • 17.4.1 Thickeners and Gelling Agents
  • Guar
  • Hydroxyethyl cellulose
  • Biotechnologic products
  • Gellan gum and wellan gum
  • Reticulated bacterial cellulose
  • Xanthan gum
  • Viscoelastic formulations
  • Miscellaneous polymers
  • Lactide polymers
  • Biodegradable formulations
  • 17.4.2 Concentrates
  • 17.4.3 Friction Reducers
  • 17.4.4 Fluid Loss Additives
  • Degradation of fluid loss additives
  • 17.4.5 pH Control Additives
  • 17.4.6 Clay Stabilizers
  • 17.4.7 Biocides
  • 17.4.8 Surfactants
  • 17.4.9 Crosslinkers
  • Kinetics of crosslinking
  • Delayed crosslinking
  • Borate systems
  • Titanium compounds
  • Zirconium compounds
  • 17.4.10 Gel Breaking in Water-Based Systems
  • Basic studies
  • Oxidative breakers
  • Hypochlorite salts
  • Peroxide breakers
  • Nonoxidative breakers
  • Redox gel breakers
  • Delayed release of acid
  • Enzyme gel breakers
  • Basic studies
  • Interactions
  • Encapsulated gel breakers
  • Gel breaking of guar
  • Gel breaking of viscoelastic surfactant gelled fluids
  • Granules
  • 17.4.11 Scale inhibitors
  • Interference of chelate formers
  • Encapsulated scale inhibitors
  • 17.4.12 Environmentally friendly activator solvents
  • 17.4.13 Treatment of Flowback Water
  • 17.5 Oil-based systems
  • 17.5.1 Organic Gel Aluminum Phosphate Ester
  • 17.5.2 Increasing the Viscosity of Diesel
  • 17.5.3 Gel Breakers
  • 17.6 Foam-based fracturing fluids
  • 17.6.1 Foamed Fluids
  • 17.6.2 Defoamers
  • 17.7 Fracturing in Coal-Beds
  • 17.8 Horizontal wells
  • 17.9 Propping agents
  • 17.9.1 Sand
  • 17.9.2 Ceramic Particles
  • 17.9.3 Bauxite
  • 17.9.4 Cordierite
  • 17.9.5 Light-Weight Proppants
  • 17.9.6 Porous Pack with Fibers
  • 17.9.7 Coated Proppants
  • Zeta potential modifiers
  • 17.9.8 Antisettling Additives
  • 17.9.9 Proppant Diagenesis
  • 17.9.10 Proppant Flowback
  • Thermoplastic films
  • Adhesive-coated material
  • Magnetized material
  • 17.10 Acid fracturing
  • 17.10.1 Encapsulated Acids
  • 17.10.2 In Situ Formation of Acids
  • 17.10.3 Fluid Loss
  • 17.10.4 Gel Breaker for Acid Fracturing
  • 17.10.5 Viscoelastic Diverting Acids
  • 17.11 Matrix acidizing
  • 17.11.1 Fines Migration in Carbonate Rock
  • 17.11.2 Reaction of In Situ Gelled Acids With Calcite
  • 17.12 Matrix stimulation
  • 17.13 Special problems
  • 17.13.1 Corrosion Inhibitors
  • 17.13.2 The Problem of Iron Control in Fracturing
  • 17.13.3 Enhanced Temperature Stability
  • 17.13.4 Chemical Blowing
  • 17.13.5 Frost-Resistant Formulation
  • 17.13.6 Formation Damage in Gas Wells
  • 17.14 Characterization of fracturing fluids
  • 17.14.1 Rheologic Characterization
  • 17.14.2 Zirconium-Based Crosslinking Agent
  • 17.14.3 Oxidative Gel Breaker
  • 17.14.4 Size Exclusion Chromatography
  • 17.14.5 Assessment of Proppants
  • References
  • Chapter 18: Water shutoff
  • 18.1 Classification of the methods
  • 18.2 In situ polymerization
  • 18.3 Acrylic gels
  • 18.3.1 Crosslinkers
  • Physical crosslinking
  • Syneresis
  • Chemical crosslinking
  • Phenol-formaldehyde-type crosslinkers
  • Poly(ethyleneimine) crosslinker
  • Aluminum phosphate ester salts for gelling organic liquids
  • 18.4 Special applications
  • Shear-initiated inversion of emulsions
  • 18.5 Thermally stable gels
  • 18.6 Blocked isocyanate gels
  • 18.7 Disproportionate permeability reduction
  • 18.7.1 Field Experience
  • 18.8 Silicate-based agents
  • 18.8.1 Combined Polymer-Silicate Technology
  • 18.8.2 Gel-Foam Technique
  • Gel system
  • Foam system
  • 18.9 Resin types
  • 18.9.1 Epoxide Resins
  • 18.9.2 Urea-Formaldehyde Resins
  • Curing of urea-formaldehyde and phenol-formaldehyde
  • Acid curing
  • Aluminum trichloride
  • Alkaline curing
  • 18.9.3 Furan-silicone resins
  • 18.10 Cement with additives
  • 18.10.1 Poly(methyl methacrylate) Modified withMonoethanolamine
  • 18.10.2 Crude Light Pyridine Bases
  • 18.10.3 Granulated Fly Ash
  • 18.10.4 Phosphonic Acid Derivates
  • 18.10.5 Phosphonium Complexone
  • 18.10.6 Aerated Plugging Solution
  • 18.10.7 Compressed Foam Mixture
  • 18.10.8 Furfuramide
  • 18.10.9 Cellulosics and Polyacrylics
  • 18.10.10 Smectite Clays
  • 18.10.11 Plasticizers
  • 18.10.12 Water Glass
  • 18.10.13 Organosilicones
  • 18.10.14 Formaldehyde Resin
  • 18.10.15 Liquid Metal Alloy
  • 18.10.16 Bentonite
  • 18.10.17 Blast Furnace Slag
  • 18.10.18 Fiber Reinforcement
  • 18.10.19 Gel from Aluminum Hydroxychloride
  • 18.11 Organosilicones
  • 18.12 Non-Crosslinked copolymers
  • 18.12.1 Anchoring
  • 18.13 Inorganic colloids
  • 18.14 Water swelling additives
  • 18.14.1 Water Swelling Cellulose
  • 18.14.2 Hydrolyzed Poly(acrylonitrile)
  • 18.14.3 Guar
  • 18.14.4 Clays
  • Organophilic swelling clay
  • 18.15 Wastes
  • 18.15.1 Waste Oil Sludge
  • 18.15.2 Aluminum Trichloride
  • 18.15.3 Antifoaming with Sulfite-Waste Liquor
  • 18.16 Surfactants
  • 18.16.1 Polymeric Surfactants
  • 18.16.2 Viscoelastic Surfactant Solutions
  • Amphoteric and zwitterionic surfactants
  • Ionic strength
  • Mixtures of a surfactant with polymers
  • Surfactant polymer compositions
  • 18.17 Tailoring the hydrodynamic volume
  • 18.17.1 Temperature Sensitive Latex Particles
  • References
  • Chapter 19: Oil spill treating agents
  • 19.1 History
  • 19.1.1 List of Major Oil Spills
  • 19.1.2 General Requirements
  • Storage
  • 19.1.3 Mechanisms
  • Influence of the dispersant performance on the crude oil type
  • Surface chemical aspects of oil spill dispersant behavior
  • Photocatalytic oxidation of organic compounds on water
  • 19.1.4 Application
  • Boat
  • Herding effect
  • Hydrofoils
  • Aircraft
  • 19.1.5 Environmental Aspects
  • Biodegradation
  • Standardized measurement of ecologic effects
  • Toxicity
  • Seagrasses, Mangroves, and Corals
  • Response on Daphnia magna
  • 19.1.6 Implementation Application Programs
  • Guidelines
  • Computerized model
  • 19.1.7 Tests
  • Wave basin
  • Broken ice
  • Finite difference models
  • Small scale testing
  • Water extraction process
  • Rotating flask test and variants
  • EXDET test
  • Portable equipment
  • Comparison of effectiveness tests
  • Correlations among the different test methods
  • Effectiveness of chemical dispersants under real conditions
  • Special aspects
  • Arctic conditions
  • Effectiveness in salt solutions
  • Effectiveness testing
  • Natural dispersion
  • Analysis of Corexit 9527
  • 19.1.8 Subsurface, Soil, and Ground Water
  • 19.1.9 In Situ Chemical Oxidation
  • 19.1.10 Ground Water
  • 19.1.11 Chemicals in Detail
  • Oxyethylated alkyl Phenol
  • Sorbitan oleates for oil slicks
  • Fatty alcohols
  • Proteins
  • Polymer
  • Cyclic monoterpenes
  • Special chemicals for oiled shorelines
  • Coagulants
  • References
  • Chapter 20: Waste disposal
  • 20.1 Produced water
  • 20.1.1 Gas well production waste waters
  • 20.2 Drilling fluids
  • 20.2.1 Bioremediation
  • 20.2.2 Assessment of biodegradability
  • 20.2.3 Supercritical fluid extraction
  • 20.3 Cuttings
  • 20.3.1 Environmental impact
  • 20.3.2 Modeling the discharge
  • Fuzzy logics
  • 20.3.3 Microwave treatment
  • 20.3.4 Discharge in cement
  • 20.3.5 Fillers in bitumen
  • 20.3.6 Chromium removal
  • 20.4 Injection techniques
  • 20.4.1 Acid gas injection
  • 20.4.2 Storage of carbon dioxide
  • 20.4.3 Carbon capture and storage
  • Suitability analysis
  • Local risks
  • Impurities
  • Well Integrity
  • Energy implications
  • Estimating carbon dioxide fluxes along leaky wellbores
  • 20.4.4 Slurry fracture injection technique
  • 20.4.5 Use as sealants
  • References
  • Chapter 21: Dispersions, emulsions, and foams
  • 21.1 Dispersions
  • 21.1.1 Dispersants
  • Aqueous drilling muds
  • Low molecular weight dispersants
  • Synthetic polymers
  • Polymers containing maleic anhydride
  • Acrylics
  • Polymers with amine sulfide terminal moieties
  • Polycarboxylates
  • Natural modified polymers
  • Modified poly(saccharide)s
  • Sulfonated asphalt
  • Humic acids
  • Cement
  • Poly(melamine sulfonate) and hydroxyethyl cellulose
  • Poly(ethyleneimine) phosphonate derivatives
  • Acetone formaldehyde cyanide resins
  • Napthalenosulfonic acid formaldehyde condensates
  • Sulfoalkylated naphthols
  • Azolignosulfonate
  • Polymers from allyloxybenzene sulfonate
  • Sulfonated isobutylene maleic anhydride copolymer
  • Miscellaneous dispersants
  • Sulfur
  • Asphalts
  • Oil spill
  • 21.2 Emulsions
  • 21.2.1 Invert emulsions
  • Breakers
  • Drilling fluid systems
  • Drill cuttings removal
  • 21.2.2 Water-in-water emulsions
  • 21.2.3 Oil-in-water-in-oil emulsions
  • 21.2.4 Microemulsions
  • 21.2.5 Solids-stabilized emulsion
  • 21.2.6 Biotreated emulsion
  • 21.2.7 Bioconcentration factor of linear alcoholethoxylates
  • Partition coefficient (n-octanol/water) using shake flask method
  • High-pressure hydrocarbon systems
  • 21.2.8 Shale inhibition
  • 21.2.9 Transportation
  • 21.2.10 Acid-rich oils
  • 21.2.11 Characterization of emulsions
  • Hansen solubility parameters
  • Micro-percolation test
  • Field bottle test
  • Separation index
  • Differential scanning calorimetry
  • Stability of invert emulsions
  • 21.2.12 Low-fluorescent emulsifiers
  • 21.3 Foams
  • 21.3.1 Aphrons
  • References
  • Chapter 22: Defoamers
  • 22.1 Theory of defoaming
  • 22.1.1 Stability of foams
  • 22.1.2 Action of defoamers
  • Spreading coefficient
  • 22.2 Classification of defoamers
  • 22.2.1 Active ingredients
  • Liquid components
  • Synergistic antifoam action by solid particles
  • Silicone antifoaming agents
  • 22.2.2 Ancillary agents
  • Surface active components
  • Carriers
  • 22.3 Uses in petroleum technology
  • 22.3.1 Aqueous fluid systems
  • Alcohols
  • Fatty acid esters
  • Aerosil
  • Poly(oxirane)
  • 22.3.2 Well treatment and cementation
  • 22.3.3 Plugging agents
  • 22.3.4 Gas-oil separation
  • Fluorosilicones and fluorocarbons
  • Polydienes
  • High-temperature defoamers
  • 22.3.5 Natural gas
  • 22.3.6 Distillation and petroleum production
  • 22.3.7 Antimicrobial antifoam compositions
  • References
  • Chapter 23: Demulsifiers
  • 23.1 Emulsions in produced crude oil
  • 23.2 Waterflooding
  • 23.3 Oil spill treatment
  • 23.4 Desired properties
  • 23.5 Mechanisms of demulsification
  • 23.5.1 Stabilization of water-oil emulsions
  • 23.5.2 Interfacial tension relaxation
  • 23.6 Performance testing
  • 23.6.1 Spreading pressure
  • 23.6.2 Characterization by dielectric constant
  • 23.6.3 Shaker test methods
  • 23.6.4 Viscosity measurements
  • 23.6.5 Screening
  • 23.7 Classification of demulsifiers
  • 23.7.1 Common precursor chemicals
  • Poly(alkylene oxide)s
  • Poly(amine)s
  • Ethoxylation
  • Acetylenic surfactants
  • 23.8 Demulsifiers in detail
  • 23.8.1 Polyoxyalkylenes
  • 23.8.2 Vinyl polymers
  • 23.8.3 Poly(amine)s
  • 23.8.4 Poly(amide)s
  • 23.8.5 Phenolics
  • 23.8.6 Alkoxylated fatty oils
  • 23.8.7 Biodemulsifiers
  • Cactus extract
  • Alkylpolyglycosides
  • References
  • Abbreviation Index
  • Chemical Index
  • Index
Chapter 2

Fluid loss additives


Abstract


This chapter deals with the special chemicals used for fluid loss additives. Fluid losses may occur when the fluid comes in contact with a porous formation. This is relevant for drilling and completion fluids, fracturing fluids, and cement slurries. Thus, fluid loss additives are used in a variety of fluids used for different purposes. Because the fluids used in petroleum technology are in some cases quite expensive, an extensive fluid loss may not be tolerable. Of course there are also environmental reasons to prevent fluid loss. Reduced fluid loss can be achieved by plugging a porous rock in some way.

Keywords

Pore size measurement

Reversible gels

Cellulose-based fluid loss additives

Humic acid derivates

Permeability control

Biomimetic compositions

Special additives to reduce fluid loss

Hassler cell

Comparative tables of fluid loss additives can be found in the internet [1]. Fluid loss additives are also called filtrate-reducing agents. Fluid losses may occur when the fluid comes in contact with a porous formation. This is relevant for drilling and completion fluids, fracturing fluids, and cement slurries.

The extent of fluid loss is dependent on the porosity and thus the permeability of the formation and may reach approximately 10 t/h. Because the fluids used in petroleum technology are in some cases quite expensive, an extensive fluid loss may not be tolerable. Of course there are also environmental reasons to prevent fluid loss.

2.1 Mechanism of action of fluid loss agents


Reduced fluid loss is achieved by plugging a porous rock in some way. The basic mechanisms are shown in Table 2.1.

Table 2.1

Mechanisms of Fluid Loss Prevention

Particle Types Description Macroscopic particles Suspended particles may clog the pores, forming a filter cake with reduced permeability Microscopic particles Macromolecules form a gel in the boundary layer of a porous formation Chemical grouting A resin is injected in the formation, which cures irreversibly; suitable for bigger caverns

2.1.1 Pore size measurement by nanoparticles


The development of temperature sensitive and pressure sensitive nanosensors will enable in situ measurements within the reservoir. The parameters involved in the mobility of nanoparticles through porous and fractured media were investigated [2]. These parameters were particle size or size distribution, shape, and surface charge or affinity to rock materials.

It was found that spherically shaped nanoparticles of a certain size and surface charge are compatible with that expected in formation rock are most likely to be transported successfully, without being trapped because of physical straining, chemical, or electrostatic effects. Tin-bismuth nanoparticles of 200 nm and smaller can be transported through Berea sandstone. Larger particles were trapped at the inlet of the core, indicating that there was an optimum particle-size range. On the other hand, the entrapment of silver nanowires occurs primarily because of their shape [2].

The investigation of the flow mechanism of nanoparticles through a naturally fractured greywacke core was conducted by injecting fluorescent silica microspheres. Silica microspheres of different sizes (smaller than the fracture opening) could be transported through the fracture.

Thus, it was demonstrated that by using microspheres it is possible to estimate fracture aperture by injecting a polydisperse microsphere sample [2].

2.1.2 Action of macroscopic particles


A monograph concerning the mechanism of invasion of particles into the formation is given by Chin [3].

One of the basic mechanisms in fluid loss prevention is shown in Figure 2.1. The fluid contains suspended particles. These particles move with the lateral flow out of the drill hole into the porous formation. The porous formation acts like a sieve for the suspended particles. The particles therefore will be captured near the surface and accumulated as a filter cake.

Figure 2.1 Formation of a filter cake in a porous formation from suspension () in a drilling fluid.

The hydrodynamic forces acting on the suspended colloids determine the rate of cake buildup and therefore the fluid loss rate. A simple model has been proposed in the literature that predicts a power law relationship between the filtration rate and the shear stress at the cake surface [4].

The model shows that the cake formed will be inhomogeneous with smaller particles being deposited as the filtration proceeds. An equilibrium cake thickness is achieved when no particles small enough to be deposited are available in the suspension. The cake thickness as a function of time can be computed from the model.

For a given suspension rheology and flow rate there is a critical permeability of the filter, below which no cake will be formed. The model also suggests that the equilibrium cake thickness can be precisely controlled by an appropriate choice of suspension flow rate and filter permeability.

2.1.3 Action of cement fluid loss additives


Two stages are considered with respect to the fluid loss behavior of a cement slurry [5]:

1. a dynamic stage corresponding to placement and

2. a static stage, awaiting the setting of the cement.

During the first period, the slurry flow is eroding the filter cake as it is growing; thus a steady state, in which the filtration occurs through a cake of constant thickness, is rapidly reached. At the same time, because the slurry is losing water but no solid particles, its density is increasing in line with the fluid loss rate.

During the second period, the cake grows because of the absence of flow. It may grow to a point at which it locally but completely fills the annulus: Bridging takes place and the hydrostatic pressure is no longer transmitted to the deeper zones. From the typical mud cake resistance it can be estimated that under both dynamic and static conditions, the fluid loss could require reduction to an American Petroleum Institute (API) value lower than what is generally considered a fair control of fluid loss.

2.1.4 Testing of fluid loss additives


Fluid loss prevention is a key performance attribute of drilling fluids. For water-based drilling fluids, significant loss of water or fluid from the drilling fluid into the formation can cause irreversible change in the drilling fluid properties, such as density and rheology occasioning instability of the borehole. Fluid loss control is measured in the laboratory according to a standard procedure for testing drilling fluids [6].

Predictions on the effectiveness of a fluid loss additive formulation can be made on a laboratory scale by characterizing the properties of the filter cake formed by appropriate experiments. Most of the fluids containing fluid loss additives are thixotropic.

Therefore, the apparent viscosity will change when a shear stress in a vertical direction is applied, as is very normal in a circulating drilling fluid. For this reason, the results from static filtering experiments are expected to be different in comparison with dynamic experiments.

Static fluid loss measurements, provide inadequate results for comparing fracturing fluid materials or for understanding the complex mechanisms of viscous fluid invasion, filter cake formation, and filter cake erosion [7]. On the other hand, dynamic fluid loss studies have inadequately addressed the development of proper laboratory methods, which has led to erroneous and conflicting results.

Results from a large-scale, high-temperature, high-pressure simulator were compared with laboratory data, and significant differences in spurt loss values were found [8].

Static experiments with pistonlike filtering can be reliable, however, to obtain information on the fluid loss behavior in certain stages of a cementation process, in particular when the slurry is at rest.

2.1.5 Formation damage


The damage of the formation resulting from the use of a filtration loss agent can be a serious problem for certain fields of application. Providing effective fluid loss control without damaging formation permeability in completion operations has been a prime requirement for an ideal fluid loss control pill.

Filter cakes are hard to remove and thus can cause considerable formation damage. Cakes with very low permeability can be broken up by reverse flow. No high-pressure spike occurs during the removal of the filter cake.

Typically, a high-pressure spike indicates damage to the formation and wellbore surface because damage typically reduces the overall permeability of the formation. Often formation damage results from the incomplete back-production of viscous, fluid loss control pills, but there may be other reasons.

2.1.6 Reversible gels


Another mechanism for fluid loss prevention is caused by other additives, which are able to form gels on a molecular mechanism.

2.1.7 Bacteria


Instead of using polymers, the addition of bacteria cultures, which may form natural polymers and could then prevent fluid loss, has been...

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