Kooperativer Bibliotheksverbund

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Format: 1 online resource (510 pages)

ISBN: 0-12-821932-7

Series Statement: Enhanced oil recovery series

Note: Intro -- Chemical Methods -- Copyright -- Contents -- Contributors -- Preface -- Acknowledgments -- Chapter 1: Introduction to chemical enhanced oil recovery -- 1.1. Introduction -- 1.2. Chemical EOR methods -- 1.2.1. Polymer flooding -- 1.2.1.1. Mechanisms of polymer flooding -- Mobility ratio -- Reduction of permeability -- Polymer nature -- 1.2.1.2. Polymer type -- 1.2.2. Surfactant flooding -- 1.2.3. Alkali flooding -- 1.2.4. Foam flooding -- 1.2.5. Chemical EOR combined techniques -- 1.2.5.1. Alkali-surfactant-polymer (ASP) flooding -- 1.2.6. Nanoflooding -- 1.3. Conclusions -- References -- Chapter 2: Polymer flooding -- 2.1. Introduction -- 2.2. Classification of EOR polymers -- 2.2.1. Chemistry aspects -- 2.3. Polymers features and screening criteria -- 2.3.1. Fingering effects -- 2.3.2. Screening criteria -- 2.4. Polymer rheology -- 2.4.1. Polymer sensitivity to mechanical shearing -- 2.4.2. Viscoelastic behavior of the polymer -- 2.4.3. Theoretical model -- 2.4.3.1. Normal stress difference, N1 -- 2.4.3.2. Weissenberg number -- 2.4.3.3. Deborah number -- 2.4.4. Influence of polymer viscoelasticity on its injectivity -- 2.4.5. Viscoelastic influence of the polymer on residual resistance factor -- 2.5. Polymer as fracturing fluid in oil reservoir -- 2.6. Polymer adsorption -- 2.7. Displacement mechanisms in polymer flooding -- 2.7.1. Evaluation of volumetric sweep efficiency -- 2.7.2. Mobility control improvement -- 2.7.3. Influencing on relative permeability -- 2.8. Fractional flow curve analysis -- 2.8.1. Continuous polymer injection without adsorption -- 2.8.2. Influence of initial oil saturation -- 2.8.3. Influence of polymer slug size -- 2.9. Polymer flooding performance -- 2.9.1. Polymer flooding in high-temperature reservoir -- 2.10. Polymer flooding in heavy oil recovery -- 2.11. Polymer flooding design and offshore experiences. , 2.11.1. Salinity -- 2.11.2. Well space -- 2.12. Modeling and simulations -- 2.12.1. Analytical methods -- 2.12.1.1. Water flooding scenario -- 2.12.1.2. Polymer flooding scenario -- 2.13. Upscaling -- 2.14. Laboratory tests and interpretation of the results -- 2.14.1. Microscopic oil displacement tests -- 2.14.2. Polymer dynamic retention test -- 2.14.3. Measurement of viscoelastic properties -- 2.14.3.1. Emulsification tests -- 2.14.4. Displacement test for single-phase flow -- 2.14.4.1. UV analysis of the Effluent -- 2.14.4.2. SEM-EDS of flooded sand -- 2.14.4.3. Polymer flooding with low salinity -- 2.14.4.4. Three-layer oil displacement experiment -- 2.15. Field cases -- 2.15.1. Polymer flooding in the Tambaredjo field, Suriname -- 2.15.2. Polymer flooding in the Marmul field, Oman -- 2.15.3. Polymer flooding using high MW and high concentration polymer-Daqing field, China -- 2.15.4. Gudao field cases -- 2.15.5. East Bodo reservoir, Alberta Canada -- 2.15.6. Turkey case study -- 2.15.7. Oman case study -- 2.16. Injection scheme -- 2.16.1. Strategies for injection rates -- 2.17. Operation problems -- 2.18. Well pattern -- 2.19. Surface facilities -- 2.19.1. Polymer friendly choke valves -- 2.20. Economics and feasibility study of polymer flooding processes -- 2.20.1. Robust number of patterns -- References -- Chapter 3: Enhanced oil recovery using surfactants -- 3.1. Overview -- 3.2. Types of surfactants -- 3.2.1. Anionic -- 3.2.2. Cationic -- 3.2.3. Zwitterionic -- 3.2.4. Nonionic -- 3.3. Chemicals used in surfactant flooding -- 3.4. Thermal and aqueous stability -- 3.4.1. Aqueous and chemical stability -- 3.4.2. Thermal stability -- 3.5. Optimum salinity -- 3.5.1. Temperature -- 3.5.2. Surfactant structure -- 3.5.3. Oil characteristic -- 3.5.4. Cosolvent -- 3.6. Mechanisms -- 3.6.1. IFT reduction -- 3.6.2. Wettability alteration. , 3.6.3. Emulsification -- 3.7. Emulsion formation and treatment -- 3.7.1. Microemulsion rheology -- 3.8. Surfactant retention -- 3.8.1. Surfactant adsorption -- 3.8.1.1. Adsorption models -- Langmuir model -- Freundlich model -- 3.8.2. Phase trapping -- 3.8.2.1. Surfactant partitioning -- 3.8.3. Surfactant precipitation -- 3.8.4. Measurement of surfactants loss -- 3.8.4.1. Static retention -- 3.8.4.2. Dynamic retention -- 3.8.5. Modeling and simulations -- 3.8.6. Relative permeability -- 3.8.7. Capillary desaturation curve (CDC) -- 3.9. Upscaling -- 3.10. Screening criteria -- 3.11. Field cases -- 3.11.1. Cambridge Minnelusa field -- 3.11.2. Gudong field -- 3.11.3. Semoga field -- References -- Chapter 4: Alkaline flooding -- 4.1. Introduction -- 4.2. Commonly used alkaline agents -- 4.3. Alkaline reaction -- 4.3.1. Reaction with oil -- 4.3.2. Reaction with water -- 4.3.3. Reaction with rock -- 4.4. Mechanisms -- 4.4.1. Saponification -- 4.4.2. IFT reduction -- 4.4.3. Wettability alteration -- 4.4.4. Emulsification -- 4.5. Effect of reservoir condition on alkaline process -- 4.6. Geology and lithologic variation of reservoir -- 4.7. Effect of pH -- 4.8. Salinity effect on alkaline flooding -- 4.9. Effects of oil composition on alkaline flooding -- 4.10. Ternary diagram in alkaline flooding -- 4.11. Success rate and screening criteria -- 4.12. Displacement efficiency in alkaline process -- 4.13. Combined flooding processes -- 4.14. Simulation and modeling -- 4.14.1. Simulation -- 4.14.2. Modeling -- 4.14.3. Mathematical formulation of chemical reactions and equilibrium state -- 4.14.4. Mathematical formulation of alkaline flooding -- 4.15. Application of machine learning -- 4.16. Surveillance and monitoring of alkaline flooding -- 4.17. Application conditions of the alkaline flooding project -- A. Appendix -- A.1. Solution. , A.2. Dissolving ionic compounds in water -- A.3. Base dissociation in water (ionization) -- A.3.1. Dissociation or ionization of a strong base -- A.3.2. Dissociation or ionization of a weak base or ionization -- A.4. Bases strength comparison -- A.4.1. Dilute aqueous solutions electrical conductivity -- A.4.2. Dilute aqueous solution's pH -- A.4.3. Equilibrium constant -- A.5. pH calculation -- A.5.1. Strong bases (alkalis) -- References -- Chapter 5: Alkaline-surfactant polymer (ASP) -- 5.1. Introduction -- 5.2. Synergy of alkaline, surfactant, and polymer constituents -- 5.3. Polymer effect -- 5.4. Emulsion properties and stability -- 5.5. ASP compatibility -- 5.6. Mechanism descriptions -- 5.7. Factors that influence IFT -- 5.8. Factors that influence wettability -- 5.9. Phase separation -- 5.10. Surfactant polymer adsorption -- 5.11. Modeling and simulations -- 5.12. Application of machine learning -- 5.13. Optimization the design of ASP injection -- 5.14. Chemistry -- 5.15. Screening criteria -- 5.16. Laboratory tests -- 5.17. Field examples and performance -- 5.18. ASP flooding: Field challenges -- References -- Chapter 6: Improved oil recovery by gel technology: Water shutoff and conformance control -- 6.1. Introduction -- 6.2. Excessive water control -- 6.3. Polymer gels -- 6.3.1. Polymer gel classification -- 6.3.2. Resistance factor and residual resistance factor -- 6.4. In situ gel -- 6.4.1. Bulk gel (BG) -- 6.4.1.1. Disproportionate permeability reduction (DPR) -- 6.4.2. Colloidal dispersion gel (CDG) -- 6.4.2.1. CDG transport modeling -- 6.5. Preformed particle gel (PPG) -- 6.5.1. PPG preparation -- 6.5.2. Swelling characteristic of PPGs -- 6.5.3. PPG injection in porous media -- 6.5.3.1. PPG transport mechanisms in porous media -- 6.5.3.2. PPG retention in porous media -- 6.5.4. PPG transport modeling. , 6.6. Temperature-activated polymer gel (TAP) -- 6.6.1. TAP transport modeling -- 6.7. pH-sensitive microgel -- 6.7.1. Acid preflushing before pH-sensitive microgel injection -- 6.7.2. pH-sensitive microgel injection in sandstones and carbonates -- 6.7.3. pH-sensitive microgel transport modeling -- References -- Chapter 7: Smart water injection -- 7.1. Basic concepts -- 7.2. Condition for smart water injection in sandstone reservoirs -- 7.3. Condition for smart water injection in carbonate reservoirs -- 7.4. Factors influencing smart water -- 7.4.1. Effect of potential determining ions -- 7.4.2. Effect of nonpotential determining ions -- 7.4.3. Effect of rock type -- 7.4.4. Effect of temperature -- 7.5. Physical and chemical mechanisms of recovery -- 7.5.1. Fines migration -- 7.5.2. Mineral dissolution -- 7.5.3. Emulsion formation -- 7.5.3.1. Oil-in-water emulsions -- 7.5.3.2. Water-in-oil emulsions -- 7.5.4. pH increase -- 7.5.5. Double-layer expansion -- 7.5.6. Multiple-ion exchange -- 7.5.7. Salting effect -- 7.5.8. Wettability alteration -- 7.5.9. Mobilization of oil on solid -- 7.6. Injected and formation brine interaction -- 7.7. Optimum salinity -- 7.8. Zeta potential -- 7.9. Dynamic investigation of contact angle and interfacial tension -- 7.10. Heterogeneity and fluid diversion -- 7.11. Effect on relative permeability curve -- 7.12. Simulation -- 7.13. Machine learning -- 7.14. Upscaling -- 7.15. Screening criteria -- 7.16. Field study -- 7.17. Success rate -- 7.18. Field challenges -- 7.19. Operation problems -- 7.20. Economic and environmental feasibility -- References -- Chapter 8: A comprehensive review on the use of eco-friendly surfactants in oil industry -- 8.1. Overview -- 8.2. Surfactant -- 8.2.1. Synthetic surfactants -- 8.2.2. Natural surfactant -- 8.2.2.1. Sources of green surfactant -- 8.2.2.2. Classification of natural surfactant.

Additional Edition: ISBN 0-12-821931-9

Language: English

UID:

Format: 444 pages : , illustrations (some color) ; , 24 cm

ISBN: 9780128219348

Series Statement: Enhanced Oil Recovery Series

Content: Thermal Methods, Volume Two, the latest release in the Enhanced Oil Recovery series, helps engineers focus on the latest developments in this fast-growing area. In the book, different techniques are described in addition to the latest technologies in data mining and hybrid processes. Supported field case studies are included to illustrate a bridge between research and practical applications, making it useful for both academics and practicing engineers. Structured to start with thermal concepts and steam flooding, the book's editors then advance to more complex content, guiding engineers into areas such as hybrid thermal methods and edgier technologies that bridge solar and nuclear energy.

Note: Intro -- Thermal Methods -- Copyright -- Contents -- Contributors -- Preface -- Chapter 1: Overview of thermal concepts in enhanced oil recovery -- 1.1. Introduction -- 1.2. Types of heat transfer -- 1.2.1. Conduction -- 1.2.2. Convection -- 1.2.3. Radiation -- 1.3. Heat-carrying capacity of steam -- 1.4. Heat of combustion -- 1.5. Heat losses -- 1.6. Fluid flow in porous media -- 1.6.1. Continuum modeling -- 1.6.2. Pore scale modeling -- 1.6.3. Multiple continua modeling -- 1.7. Thermal methods -- 1.7.1. Cyclic steam injection or cyclic steam stimulation (CSS) -- 1.7.2. Steam flooding (SF) -- 1.7.3. Steam-assisted gravity drainage (SAGD) -- 1.7.4. In situ combustion -- 1.8. Thermodynamic mechanisms -- 1.9. Effect of heat on fluid-rock properties -- 1.10. Effect of reservoir mineralogy and heterogeneity -- 1.11. Steam characteristics -- 1.12. Steam quality -- 1.13. Steam distillation -- 1.14. Beneficial effect of steam distillation -- 1.15. Saturation pressure and temperature -- 1.16. Oil viscosity -- 1.17. Hybrid thermal recovery processes -- 1.18. Future directions of heavy oil recovery processes -- References -- Chapter 2: Steam flooding (steam drive) -- 2.1. Introduction -- 2.2. Steam flooding concepts -- 2.2.1. Steam flooding dependence -- 2.3. Screening criteria -- 2.4. Water quality for steam generation -- 2.5. Steam generation -- 2.5.1. Preview -- 2.5.2. Steam generators -- 2.6. Steaming injection in heavy oil reservoir and tar sands -- 2.6.1. Mobilization of heavy oil and bitumen -- 2.6.2. Recovery methods -- 2.7. Mechanisms -- 2.8. Reservoir thickness, heterogeneity, and properties -- 2.9. Well spacing and proper well pattern -- 2.10. Improvement of an oil/water mobility ratio and relative permeability -- 2.11. Existing laboratory-scale recovery factor -- 2.12. Case studies -- 2.13. Models and simulation. , 2.14. Fracturing and reservoir expansion -- References -- Chapter 3: Cyclic steam stimulation -- 3.1. Introduction -- 3.2. CSS process -- 3.3. Recovery mechanisms of the CSS process -- 3.4. Steam-rock interactions -- 3.5. Relative permeability -- 3.6. Modeling and simulation -- 3.7. Upscaling -- 3.7.1. History of upscaling studies -- 3.7.2. Upscaling parameters -- 3.8. CSS with horizontal wells -- 3.9. Optimization -- 3.10. Screening criteria -- 3.11. Case studies -- 3.11.1. Case 1 -- 3.11.2. Case 2 -- 3.11.3. Case 3 -- 3.11.4. Case 4 -- References -- Further reading -- Chapter 4: Steam-assisted gravity drainage -- 4.1. Introduction -- 4.2. Operational parameters in the SAGD process -- 4.3. Preheating (startup phase) -- 4.4. Emulsification phenomenon -- 4.4.1. SAGD emulsion viscosity models -- 4.5. Multiphase fluid flow -- 4.6. Heat transmission mechanisms in the steam chamber boundary -- 4.7. Finger rise theory -- 4.8. Variations of the SAGD process -- 4.8.1. Single-well SAGD -- 4.8.2. Steam and gas push (SAGP) -- 4.8.3. SAGD wind-down -- 4.8.4. Expanding solvent SAGD (ES-SAGD) -- 4.8.5. Fast-SAGD -- 4.8.6. Solvent thermal resource innovation process (STRIP) -- 4.8.7. Multiple thermal fluids assisted gravity drainage (MFAGD) -- 4.8.8. Rich solvent-Steam-assisted gravity drainage (RS-SAGD) -- 4.9. Co-SAGD processes -- 4.9.1. Addition of chemicals -- 4.9.2. Noncondensable gas -- 4.9.3. Flue-gas assisted SAGD -- 4.9.4. Foam-assisted-SAGD (FA-SAGD) -- 4.10. Experimental studies -- 4.11. SAGD in reservoirs with a bottom aquifer -- 4.12. SAGD in fractured reservoirs -- 4.13. Effect of heterogeneity on SAGD -- 4.14. Hydraulic fracturing in SAGD -- 4.15. Impact of geomechanical effects during SAGD -- 4.16. Mathematical modeling and simulation -- 4.17. Artificial intelligence (AI)-based simulation -- 4.18. Optimization of SAGD -- 4.19. Screening criteria. , 4.20. Field-scale studies and challenges -- 4.21. Environmental issues -- 4.22. Economical evaluation and feasibility of the SAGD -- References -- Chapter 5: In situ combustion -- 5.1. Overview -- 5.2. In situ combustion conceptual reactions -- 5.3. In situ combustion mechanisms -- 5.4. Screening criteria -- 5.5. Reservoir fluid characterization for combustion studies -- 5.6. Laboratory experiments: From reaction kinetics development to combustion process evaluation -- 5.7. Combustion modeling and challenges-Process view -- 5.7.1. Actual chemical reactions -- 5.7.2. Displacement of reservoir fluids -- 5.7.3. Heat spread -- 5.7.4. Combustion gases -- 5.7.5. Advancement of combustion front -- 5.8. Forward and reverse combustion -- 5.8.1. Forward combustion -- 5.8.2. Reverse combustion -- 5.8.3. Pilot tests -- 5.8.4. HPAI (high-pressure air injection) for light oil recovery -- 5.9. Process variations -- 5.9.1. Dry and wet combustion -- 5.9.2. Cyclic combustion -- 5.9.2.1. Field pilot -- 5.9.3. Pressure cyclic combustion (pressure upblow down process) -- 5.9.4. Steam oxygen co-injection -- 5.9.5. THAI (toe to heel air injection) -- 5.9.6. THAI CAPRI (catalytic version of THAI) -- 5.9.7. CAGD (combustion assisted gravity drainage) process -- 5.9.8. COSH (combustion override split production horizontal well process) -- 5.9.9. COFCAW (combination of forward combustion and waterflooding) -- 5.10. Reservoir modeling and simulation -- 5.11. Upscaling -- 5.12. Field challenges -- 5.13. Economic and environmental feasibility -- 5.13.1. Economic feasibility -- 5.13.2. Environmental feasibility -- References -- Chapter 6: Hybrid thermal-solvent process -- 6.1. Introduction -- 6.2. Optimal conditions in the solvent steam process -- 6.2.1. Ideal solvent properties -- 6.2.2. Ideal solvent composition -- 6.2.3. Ideal solvent concentration. , 6.3. Advantages of a combination of solvent addition to steam -- 6.4. Classification of solvent recovery processes -- 6.4.1. Expanding solvent steam assisted gravity drainage (ES-SAGD) -- 6.4.2. Liquid addition to steam for enhanced recovery (LASER) -- 6.4.3. Steam alternating solvent (SAS) -- 6.4.4. Solvent-enhanced steam flooding (SESF) or solvent-aided process (SAP) -- 6.4.5. Alkaline steam flooding -- 6.5. Modeling and simulation -- 6.5.1. ES-SAGD process -- 6.5.2. SAS process -- 6.5.3. SESF or SAP process -- 6.6. Field implementation -- References -- Chapter 7: Hybrid thermal-NCG process -- 7.1. Introduction -- 7.2. Mechanisms -- 7.3. Oil viscosity reduction -- 7.4. Screening criteria -- 7.5. NCG-CSS process -- 7.5.1. N2-CSS process -- 7.5.2. CO2-CSS process -- 7.5.3. Flue gas-CSS process -- 7.5.4. Air-CSS process -- 7.6. The NCG-SAGD process -- 7.7. NCG-SAGD analytical model -- 7.8. Low-temperature oxidation reaction -- 7.9. Extra-heavy crude oil reserves techniques -- 7.10. Modeling and simulation -- 7.11. Upscaling -- 7.12. Field applications -- 7.13. Field challenges -- 7.14. Economic and environmental feasibility -- References -- Chapter 8: Hybrid thermal chemical EOR methods -- 8.1. Introduction -- 8.2. Chemical-assisted thermal methods -- 8.2.1. Surfactant-assisted thermal method -- 8.2.1.1. Basics of foam -- 8.2.1.2. Foaming agents -- 8.2.1.3. Foam stability, volume, and size -- 8.2.1.4. Foam transport in porous media -- 8.2.1.5. Foam EOR mechanisms -- 8.2.1.6. Foam-assisted SAGD -- Steam-assisted gravity drainage -- Reasons for foaming steam -- Challenges and limitations -- Modelling and simulation -- 8.2.2. Polymer-assisted thermal method -- 8.2.2.1. Introduction -- 8.2.2.2. Polymer-assisted SAGD -- 8.2.2.3. Polymer properties -- 8.2.2.4. EOR mechanisms -- 8.2.2.5. Alkali-surfactant-polymer (ASP) conjugated with thermal methods. , 8.2.2.6. Modeling and simulation of rheological behavior -- 8.2.2.7. Limitations and critical parameters -- 8.2.2.8. Upscaling -- Screening criteria -- 8.2.2.9. Challenges and limitations -- 8.2.3. Nanoparticle-assisted thermal method -- 8.2.3.1. Introduction -- 8.2.3.2. Interaction of nanoparticles in thermal EOR -- 8.2.3.3. Nano-assisted air injection processes -- 8.2.3.4. Nano-assisted steam injection processes -- 8.2.4. Other methods -- 8.2.4.1. Noncondensible gas foams -- Polymer enhanced foam -- 8.2.4.2. High-temperature gels -- 8.2.4.3. Exothermic chemical reactions -- 8.3. Thermal stability of chemicals -- 8.3.1. Thermal stability of surfactants -- 8.3.2. Thermal stability of polymers -- 8.3.3. Thermal stability of nanomaterials -- 8.4. Field applications -- 8.4.1. FA-SAGD -- 8.4.2. Polymer-assisted SAGD -- 8.4.3. Nanoparticle-assisted SAGD -- 8.5. Economical and environmental concerns -- 8.5.1. Surfactants -- 8.5.2. Polymers -- 8.5.3. Nanoparticles -- References -- Chapter 9: Other thermal methods -- 9.1. Introduction -- 9.2. Deep eutectic solvents (DESs) -- 9.2.1. Screening criteria -- 9.2.2. Existing laboratory tests -- 9.2.3. Challenges and future directions -- 9.2.4. Upscaling -- 9.2.5. Economic and environmental feasibility -- 9.3. In situ upgrading -- 9.3.1. Addition of catalysts -- 9.3.2. Addition of nanocatalysts -- 9.3.3. Screening criteria -- 9.3.4. Existing laboratory tests -- 9.3.5. Challenges and future directions -- 9.3.6. Field applications and challenges -- 9.3.7. Case studies -- 9.3.8. Economic and environmental feasibility -- 9.4. Electrical heating methods -- 9.4.1. Electrical resistive heating -- 9.4.2. Electromagnetic inductive heating -- 9.4.3. Microwaves/radio frequency heating method -- 9.4.4. Existing laboratory tests -- 9.4.5. Challenges and future directions -- 9.4.6. Field applications and challenges. , 9.4.7. Case studies.

Additional Edition: Print version: Hemmati Sarapardeh, Abdolhossein Thermal Methods San Diego : Elsevier Science & Technology,c2023 ISBN 9780128219331

Language: English

UID:

Format: 1 online resource (324 pages)

ISBN: 0-12-822385-5 , 0-12-818680-1

Language: English

UID:

Format: 312 Seiten

ISBN: 9780128186800

Language: English

Keywords: Maschinelles Lernen ; Erdöl- und Erdgastechnik ; Ingenieurgeologie

UID:

Format: 1 online resource (324 pages)

ISBN: 0-12-822385-5 , 0-12-818680-1

Language: English

UID:

Format: 1 online resource (324 pages)

ISBN: 0-12-822385-5 , 0-12-818680-1

Language: English

UID:

Format: 444 pages : , illustrations (some color) ; , 24 cm

ISBN: 9780128219348

Series Statement: Enhanced Oil Recovery Series

Content: Thermal Methods, Volume Two, the latest release in the Enhanced Oil Recovery series, helps engineers focus on the latest developments in this fast-growing area. In the book, different techniques are described in addition to the latest technologies in data mining and hybrid processes. Supported field case studies are included to illustrate a bridge between research and practical applications, making it useful for both academics and practicing engineers. Structured to start with thermal concepts and steam flooding, the book's editors then advance to more complex content, guiding engineers into areas such as hybrid thermal methods and edgier technologies that bridge solar and nuclear energy.

Note: Intro -- Thermal Methods -- Copyright -- Contents -- Contributors -- Preface -- Chapter 1: Overview of thermal concepts in enhanced oil recovery -- 1.1. Introduction -- 1.2. Types of heat transfer -- 1.2.1. Conduction -- 1.2.2. Convection -- 1.2.3. Radiation -- 1.3. Heat-carrying capacity of steam -- 1.4. Heat of combustion -- 1.5. Heat losses -- 1.6. Fluid flow in porous media -- 1.6.1. Continuum modeling -- 1.6.2. Pore scale modeling -- 1.6.3. Multiple continua modeling -- 1.7. Thermal methods -- 1.7.1. Cyclic steam injection or cyclic steam stimulation (CSS) -- 1.7.2. Steam flooding (SF) -- 1.7.3. Steam-assisted gravity drainage (SAGD) -- 1.7.4. In situ combustion -- 1.8. Thermodynamic mechanisms -- 1.9. Effect of heat on fluid-rock properties -- 1.10. Effect of reservoir mineralogy and heterogeneity -- 1.11. Steam characteristics -- 1.12. Steam quality -- 1.13. Steam distillation -- 1.14. Beneficial effect of steam distillation -- 1.15. Saturation pressure and temperature -- 1.16. Oil viscosity -- 1.17. Hybrid thermal recovery processes -- 1.18. Future directions of heavy oil recovery processes -- References -- Chapter 2: Steam flooding (steam drive) -- 2.1. Introduction -- 2.2. Steam flooding concepts -- 2.2.1. Steam flooding dependence -- 2.3. Screening criteria -- 2.4. Water quality for steam generation -- 2.5. Steam generation -- 2.5.1. Preview -- 2.5.2. Steam generators -- 2.6. Steaming injection in heavy oil reservoir and tar sands -- 2.6.1. Mobilization of heavy oil and bitumen -- 2.6.2. Recovery methods -- 2.7. Mechanisms -- 2.8. Reservoir thickness, heterogeneity, and properties -- 2.9. Well spacing and proper well pattern -- 2.10. Improvement of an oil/water mobility ratio and relative permeability -- 2.11. Existing laboratory-scale recovery factor -- 2.12. Case studies -- 2.13. Models and simulation. , 2.14. Fracturing and reservoir expansion -- References -- Chapter 3: Cyclic steam stimulation -- 3.1. Introduction -- 3.2. CSS process -- 3.3. Recovery mechanisms of the CSS process -- 3.4. Steam-rock interactions -- 3.5. Relative permeability -- 3.6. Modeling and simulation -- 3.7. Upscaling -- 3.7.1. History of upscaling studies -- 3.7.2. Upscaling parameters -- 3.8. CSS with horizontal wells -- 3.9. Optimization -- 3.10. Screening criteria -- 3.11. Case studies -- 3.11.1. Case 1 -- 3.11.2. Case 2 -- 3.11.3. Case 3 -- 3.11.4. Case 4 -- References -- Further reading -- Chapter 4: Steam-assisted gravity drainage -- 4.1. Introduction -- 4.2. Operational parameters in the SAGD process -- 4.3. Preheating (startup phase) -- 4.4. Emulsification phenomenon -- 4.4.1. SAGD emulsion viscosity models -- 4.5. Multiphase fluid flow -- 4.6. Heat transmission mechanisms in the steam chamber boundary -- 4.7. Finger rise theory -- 4.8. Variations of the SAGD process -- 4.8.1. Single-well SAGD -- 4.8.2. Steam and gas push (SAGP) -- 4.8.3. SAGD wind-down -- 4.8.4. Expanding solvent SAGD (ES-SAGD) -- 4.8.5. Fast-SAGD -- 4.8.6. Solvent thermal resource innovation process (STRIP) -- 4.8.7. Multiple thermal fluids assisted gravity drainage (MFAGD) -- 4.8.8. Rich solvent-Steam-assisted gravity drainage (RS-SAGD) -- 4.9. Co-SAGD processes -- 4.9.1. Addition of chemicals -- 4.9.2. Noncondensable gas -- 4.9.3. Flue-gas assisted SAGD -- 4.9.4. Foam-assisted-SAGD (FA-SAGD) -- 4.10. Experimental studies -- 4.11. SAGD in reservoirs with a bottom aquifer -- 4.12. SAGD in fractured reservoirs -- 4.13. Effect of heterogeneity on SAGD -- 4.14. Hydraulic fracturing in SAGD -- 4.15. Impact of geomechanical effects during SAGD -- 4.16. Mathematical modeling and simulation -- 4.17. Artificial intelligence (AI)-based simulation -- 4.18. Optimization of SAGD -- 4.19. Screening criteria. , 4.20. Field-scale studies and challenges -- 4.21. Environmental issues -- 4.22. Economical evaluation and feasibility of the SAGD -- References -- Chapter 5: In situ combustion -- 5.1. Overview -- 5.2. In situ combustion conceptual reactions -- 5.3. In situ combustion mechanisms -- 5.4. Screening criteria -- 5.5. Reservoir fluid characterization for combustion studies -- 5.6. Laboratory experiments: From reaction kinetics development to combustion process evaluation -- 5.7. Combustion modeling and challenges-Process view -- 5.7.1. Actual chemical reactions -- 5.7.2. Displacement of reservoir fluids -- 5.7.3. Heat spread -- 5.7.4. Combustion gases -- 5.7.5. Advancement of combustion front -- 5.8. Forward and reverse combustion -- 5.8.1. Forward combustion -- 5.8.2. Reverse combustion -- 5.8.3. Pilot tests -- 5.8.4. HPAI (high-pressure air injection) for light oil recovery -- 5.9. Process variations -- 5.9.1. Dry and wet combustion -- 5.9.2. Cyclic combustion -- 5.9.2.1. Field pilot -- 5.9.3. Pressure cyclic combustion (pressure upblow down process) -- 5.9.4. Steam oxygen co-injection -- 5.9.5. THAI (toe to heel air injection) -- 5.9.6. THAI CAPRI (catalytic version of THAI) -- 5.9.7. CAGD (combustion assisted gravity drainage) process -- 5.9.8. COSH (combustion override split production horizontal well process) -- 5.9.9. COFCAW (combination of forward combustion and waterflooding) -- 5.10. Reservoir modeling and simulation -- 5.11. Upscaling -- 5.12. Field challenges -- 5.13. Economic and environmental feasibility -- 5.13.1. Economic feasibility -- 5.13.2. Environmental feasibility -- References -- Chapter 6: Hybrid thermal-solvent process -- 6.1. Introduction -- 6.2. Optimal conditions in the solvent steam process -- 6.2.1. Ideal solvent properties -- 6.2.2. Ideal solvent composition -- 6.2.3. Ideal solvent concentration. , 6.3. Advantages of a combination of solvent addition to steam -- 6.4. Classification of solvent recovery processes -- 6.4.1. Expanding solvent steam assisted gravity drainage (ES-SAGD) -- 6.4.2. Liquid addition to steam for enhanced recovery (LASER) -- 6.4.3. Steam alternating solvent (SAS) -- 6.4.4. Solvent-enhanced steam flooding (SESF) or solvent-aided process (SAP) -- 6.4.5. Alkaline steam flooding -- 6.5. Modeling and simulation -- 6.5.1. ES-SAGD process -- 6.5.2. SAS process -- 6.5.3. SESF or SAP process -- 6.6. Field implementation -- References -- Chapter 7: Hybrid thermal-NCG process -- 7.1. Introduction -- 7.2. Mechanisms -- 7.3. Oil viscosity reduction -- 7.4. Screening criteria -- 7.5. NCG-CSS process -- 7.5.1. N2-CSS process -- 7.5.2. CO2-CSS process -- 7.5.3. Flue gas-CSS process -- 7.5.4. Air-CSS process -- 7.6. The NCG-SAGD process -- 7.7. NCG-SAGD analytical model -- 7.8. Low-temperature oxidation reaction -- 7.9. Extra-heavy crude oil reserves techniques -- 7.10. Modeling and simulation -- 7.11. Upscaling -- 7.12. Field applications -- 7.13. Field challenges -- 7.14. Economic and environmental feasibility -- References -- Chapter 8: Hybrid thermal chemical EOR methods -- 8.1. Introduction -- 8.2. Chemical-assisted thermal methods -- 8.2.1. Surfactant-assisted thermal method -- 8.2.1.1. Basics of foam -- 8.2.1.2. Foaming agents -- 8.2.1.3. Foam stability, volume, and size -- 8.2.1.4. Foam transport in porous media -- 8.2.1.5. Foam EOR mechanisms -- 8.2.1.6. Foam-assisted SAGD -- Steam-assisted gravity drainage -- Reasons for foaming steam -- Challenges and limitations -- Modelling and simulation -- 8.2.2. Polymer-assisted thermal method -- 8.2.2.1. Introduction -- 8.2.2.2. Polymer-assisted SAGD -- 8.2.2.3. Polymer properties -- 8.2.2.4. EOR mechanisms -- 8.2.2.5. Alkali-surfactant-polymer (ASP) conjugated with thermal methods. , 8.2.2.6. Modeling and simulation of rheological behavior -- 8.2.2.7. Limitations and critical parameters -- 8.2.2.8. Upscaling -- Screening criteria -- 8.2.2.9. Challenges and limitations -- 8.2.3. Nanoparticle-assisted thermal method -- 8.2.3.1. Introduction -- 8.2.3.2. Interaction of nanoparticles in thermal EOR -- 8.2.3.3. Nano-assisted air injection processes -- 8.2.3.4. Nano-assisted steam injection processes -- 8.2.4. Other methods -- 8.2.4.1. Noncondensible gas foams -- Polymer enhanced foam -- 8.2.4.2. High-temperature gels -- 8.2.4.3. Exothermic chemical reactions -- 8.3. Thermal stability of chemicals -- 8.3.1. Thermal stability of surfactants -- 8.3.2. Thermal stability of polymers -- 8.3.3. Thermal stability of nanomaterials -- 8.4. Field applications -- 8.4.1. FA-SAGD -- 8.4.2. Polymer-assisted SAGD -- 8.4.3. Nanoparticle-assisted SAGD -- 8.5. Economical and environmental concerns -- 8.5.1. Surfactants -- 8.5.2. Polymers -- 8.5.3. Nanoparticles -- References -- Chapter 9: Other thermal methods -- 9.1. Introduction -- 9.2. Deep eutectic solvents (DESs) -- 9.2.1. Screening criteria -- 9.2.2. Existing laboratory tests -- 9.2.3. Challenges and future directions -- 9.2.4. Upscaling -- 9.2.5. Economic and environmental feasibility -- 9.3. In situ upgrading -- 9.3.1. Addition of catalysts -- 9.3.2. Addition of nanocatalysts -- 9.3.3. Screening criteria -- 9.3.4. Existing laboratory tests -- 9.3.5. Challenges and future directions -- 9.3.6. Field applications and challenges -- 9.3.7. Case studies -- 9.3.8. Economic and environmental feasibility -- 9.4. Electrical heating methods -- 9.4.1. Electrical resistive heating -- 9.4.2. Electromagnetic inductive heating -- 9.4.3. Microwaves/radio frequency heating method -- 9.4.4. Existing laboratory tests -- 9.4.5. Challenges and future directions -- 9.4.6. Field applications and challenges. , 9.4.7. Case studies.

Additional Edition: Print version: Hemmati Sarapardeh, Abdolhossein Thermal Methods San Diego : Elsevier Science & Technology,c2023 ISBN 9780128219331

Language: English

UID:

Format: 444 pages : , illustrations (some color) ; , 24 cm

ISBN: 9780128219348

Series Statement: Enhanced Oil Recovery Series

Content: Thermal Methods, Volume Two, the latest release in the Enhanced Oil Recovery series, helps engineers focus on the latest developments in this fast-growing area. In the book, different techniques are described in addition to the latest technologies in data mining and hybrid processes. Supported field case studies are included to illustrate a bridge between research and practical applications, making it useful for both academics and practicing engineers. Structured to start with thermal concepts and steam flooding, the book's editors then advance to more complex content, guiding engineers into areas such as hybrid thermal methods and edgier technologies that bridge solar and nuclear energy.

Note: Intro -- Thermal Methods -- Copyright -- Contents -- Contributors -- Preface -- Chapter 1: Overview of thermal concepts in enhanced oil recovery -- 1.1. Introduction -- 1.2. Types of heat transfer -- 1.2.1. Conduction -- 1.2.2. Convection -- 1.2.3. Radiation -- 1.3. Heat-carrying capacity of steam -- 1.4. Heat of combustion -- 1.5. Heat losses -- 1.6. Fluid flow in porous media -- 1.6.1. Continuum modeling -- 1.6.2. Pore scale modeling -- 1.6.3. Multiple continua modeling -- 1.7. Thermal methods -- 1.7.1. Cyclic steam injection or cyclic steam stimulation (CSS) -- 1.7.2. Steam flooding (SF) -- 1.7.3. Steam-assisted gravity drainage (SAGD) -- 1.7.4. In situ combustion -- 1.8. Thermodynamic mechanisms -- 1.9. Effect of heat on fluid-rock properties -- 1.10. Effect of reservoir mineralogy and heterogeneity -- 1.11. Steam characteristics -- 1.12. Steam quality -- 1.13. Steam distillation -- 1.14. Beneficial effect of steam distillation -- 1.15. Saturation pressure and temperature -- 1.16. Oil viscosity -- 1.17. Hybrid thermal recovery processes -- 1.18. Future directions of heavy oil recovery processes -- References -- Chapter 2: Steam flooding (steam drive) -- 2.1. Introduction -- 2.2. Steam flooding concepts -- 2.2.1. Steam flooding dependence -- 2.3. Screening criteria -- 2.4. Water quality for steam generation -- 2.5. Steam generation -- 2.5.1. Preview -- 2.5.2. Steam generators -- 2.6. Steaming injection in heavy oil reservoir and tar sands -- 2.6.1. Mobilization of heavy oil and bitumen -- 2.6.2. Recovery methods -- 2.7. Mechanisms -- 2.8. Reservoir thickness, heterogeneity, and properties -- 2.9. Well spacing and proper well pattern -- 2.10. Improvement of an oil/water mobility ratio and relative permeability -- 2.11. Existing laboratory-scale recovery factor -- 2.12. Case studies -- 2.13. Models and simulation. , 2.14. Fracturing and reservoir expansion -- References -- Chapter 3: Cyclic steam stimulation -- 3.1. Introduction -- 3.2. CSS process -- 3.3. Recovery mechanisms of the CSS process -- 3.4. Steam-rock interactions -- 3.5. Relative permeability -- 3.6. Modeling and simulation -- 3.7. Upscaling -- 3.7.1. History of upscaling studies -- 3.7.2. Upscaling parameters -- 3.8. CSS with horizontal wells -- 3.9. Optimization -- 3.10. Screening criteria -- 3.11. Case studies -- 3.11.1. Case 1 -- 3.11.2. Case 2 -- 3.11.3. Case 3 -- 3.11.4. Case 4 -- References -- Further reading -- Chapter 4: Steam-assisted gravity drainage -- 4.1. Introduction -- 4.2. Operational parameters in the SAGD process -- 4.3. Preheating (startup phase) -- 4.4. Emulsification phenomenon -- 4.4.1. SAGD emulsion viscosity models -- 4.5. Multiphase fluid flow -- 4.6. Heat transmission mechanisms in the steam chamber boundary -- 4.7. Finger rise theory -- 4.8. Variations of the SAGD process -- 4.8.1. Single-well SAGD -- 4.8.2. Steam and gas push (SAGP) -- 4.8.3. SAGD wind-down -- 4.8.4. Expanding solvent SAGD (ES-SAGD) -- 4.8.5. Fast-SAGD -- 4.8.6. Solvent thermal resource innovation process (STRIP) -- 4.8.7. Multiple thermal fluids assisted gravity drainage (MFAGD) -- 4.8.8. Rich solvent-Steam-assisted gravity drainage (RS-SAGD) -- 4.9. Co-SAGD processes -- 4.9.1. Addition of chemicals -- 4.9.2. Noncondensable gas -- 4.9.3. Flue-gas assisted SAGD -- 4.9.4. Foam-assisted-SAGD (FA-SAGD) -- 4.10. Experimental studies -- 4.11. SAGD in reservoirs with a bottom aquifer -- 4.12. SAGD in fractured reservoirs -- 4.13. Effect of heterogeneity on SAGD -- 4.14. Hydraulic fracturing in SAGD -- 4.15. Impact of geomechanical effects during SAGD -- 4.16. Mathematical modeling and simulation -- 4.17. Artificial intelligence (AI)-based simulation -- 4.18. Optimization of SAGD -- 4.19. Screening criteria. , 4.20. Field-scale studies and challenges -- 4.21. Environmental issues -- 4.22. Economical evaluation and feasibility of the SAGD -- References -- Chapter 5: In situ combustion -- 5.1. Overview -- 5.2. In situ combustion conceptual reactions -- 5.3. In situ combustion mechanisms -- 5.4. Screening criteria -- 5.5. Reservoir fluid characterization for combustion studies -- 5.6. Laboratory experiments: From reaction kinetics development to combustion process evaluation -- 5.7. Combustion modeling and challenges-Process view -- 5.7.1. Actual chemical reactions -- 5.7.2. Displacement of reservoir fluids -- 5.7.3. Heat spread -- 5.7.4. Combustion gases -- 5.7.5. Advancement of combustion front -- 5.8. Forward and reverse combustion -- 5.8.1. Forward combustion -- 5.8.2. Reverse combustion -- 5.8.3. Pilot tests -- 5.8.4. HPAI (high-pressure air injection) for light oil recovery -- 5.9. Process variations -- 5.9.1. Dry and wet combustion -- 5.9.2. Cyclic combustion -- 5.9.2.1. Field pilot -- 5.9.3. Pressure cyclic combustion (pressure upblow down process) -- 5.9.4. Steam oxygen co-injection -- 5.9.5. THAI (toe to heel air injection) -- 5.9.6. THAI CAPRI (catalytic version of THAI) -- 5.9.7. CAGD (combustion assisted gravity drainage) process -- 5.9.8. COSH (combustion override split production horizontal well process) -- 5.9.9. COFCAW (combination of forward combustion and waterflooding) -- 5.10. Reservoir modeling and simulation -- 5.11. Upscaling -- 5.12. Field challenges -- 5.13. Economic and environmental feasibility -- 5.13.1. Economic feasibility -- 5.13.2. Environmental feasibility -- References -- Chapter 6: Hybrid thermal-solvent process -- 6.1. Introduction -- 6.2. Optimal conditions in the solvent steam process -- 6.2.1. Ideal solvent properties -- 6.2.2. Ideal solvent composition -- 6.2.3. Ideal solvent concentration. , 6.3. Advantages of a combination of solvent addition to steam -- 6.4. Classification of solvent recovery processes -- 6.4.1. Expanding solvent steam assisted gravity drainage (ES-SAGD) -- 6.4.2. Liquid addition to steam for enhanced recovery (LASER) -- 6.4.3. Steam alternating solvent (SAS) -- 6.4.4. Solvent-enhanced steam flooding (SESF) or solvent-aided process (SAP) -- 6.4.5. Alkaline steam flooding -- 6.5. Modeling and simulation -- 6.5.1. ES-SAGD process -- 6.5.2. SAS process -- 6.5.3. SESF or SAP process -- 6.6. Field implementation -- References -- Chapter 7: Hybrid thermal-NCG process -- 7.1. Introduction -- 7.2. Mechanisms -- 7.3. Oil viscosity reduction -- 7.4. Screening criteria -- 7.5. NCG-CSS process -- 7.5.1. N2-CSS process -- 7.5.2. CO2-CSS process -- 7.5.3. Flue gas-CSS process -- 7.5.4. Air-CSS process -- 7.6. The NCG-SAGD process -- 7.7. NCG-SAGD analytical model -- 7.8. Low-temperature oxidation reaction -- 7.9. Extra-heavy crude oil reserves techniques -- 7.10. Modeling and simulation -- 7.11. Upscaling -- 7.12. Field applications -- 7.13. Field challenges -- 7.14. Economic and environmental feasibility -- References -- Chapter 8: Hybrid thermal chemical EOR methods -- 8.1. Introduction -- 8.2. Chemical-assisted thermal methods -- 8.2.1. Surfactant-assisted thermal method -- 8.2.1.1. Basics of foam -- 8.2.1.2. Foaming agents -- 8.2.1.3. Foam stability, volume, and size -- 8.2.1.4. Foam transport in porous media -- 8.2.1.5. Foam EOR mechanisms -- 8.2.1.6. Foam-assisted SAGD -- Steam-assisted gravity drainage -- Reasons for foaming steam -- Challenges and limitations -- Modelling and simulation -- 8.2.2. Polymer-assisted thermal method -- 8.2.2.1. Introduction -- 8.2.2.2. Polymer-assisted SAGD -- 8.2.2.3. Polymer properties -- 8.2.2.4. EOR mechanisms -- 8.2.2.5. Alkali-surfactant-polymer (ASP) conjugated with thermal methods. , 8.2.2.6. Modeling and simulation of rheological behavior -- 8.2.2.7. Limitations and critical parameters -- 8.2.2.8. Upscaling -- Screening criteria -- 8.2.2.9. Challenges and limitations -- 8.2.3. Nanoparticle-assisted thermal method -- 8.2.3.1. Introduction -- 8.2.3.2. Interaction of nanoparticles in thermal EOR -- 8.2.3.3. Nano-assisted air injection processes -- 8.2.3.4. Nano-assisted steam injection processes -- 8.2.4. Other methods -- 8.2.4.1. Noncondensible gas foams -- Polymer enhanced foam -- 8.2.4.2. High-temperature gels -- 8.2.4.3. Exothermic chemical reactions -- 8.3. Thermal stability of chemicals -- 8.3.1. Thermal stability of surfactants -- 8.3.2. Thermal stability of polymers -- 8.3.3. Thermal stability of nanomaterials -- 8.4. Field applications -- 8.4.1. FA-SAGD -- 8.4.2. Polymer-assisted SAGD -- 8.4.3. Nanoparticle-assisted SAGD -- 8.5. Economical and environmental concerns -- 8.5.1. Surfactants -- 8.5.2. Polymers -- 8.5.3. Nanoparticles -- References -- Chapter 9: Other thermal methods -- 9.1. Introduction -- 9.2. Deep eutectic solvents (DESs) -- 9.2.1. Screening criteria -- 9.2.2. Existing laboratory tests -- 9.2.3. Challenges and future directions -- 9.2.4. Upscaling -- 9.2.5. Economic and environmental feasibility -- 9.3. In situ upgrading -- 9.3.1. Addition of catalysts -- 9.3.2. Addition of nanocatalysts -- 9.3.3. Screening criteria -- 9.3.4. Existing laboratory tests -- 9.3.5. Challenges and future directions -- 9.3.6. Field applications and challenges -- 9.3.7. Case studies -- 9.3.8. Economic and environmental feasibility -- 9.4. Electrical heating methods -- 9.4.1. Electrical resistive heating -- 9.4.2. Electromagnetic inductive heating -- 9.4.3. Microwaves/radio frequency heating method -- 9.4.4. Existing laboratory tests -- 9.4.5. Challenges and future directions -- 9.4.6. Field applications and challenges. , 9.4.7. Case studies.

Additional Edition: Print version: Hemmati Sarapardeh, Abdolhossein Thermal Methods San Diego : Elsevier Science & Technology,c2023 ISBN 9780128219331

Language: English

UID:

Format: 1 online resource (510 pages)

ISBN: 0-12-821932-7

Series Statement: Enhanced oil recovery series

Note: Intro -- Chemical Methods -- Copyright -- Contents -- Contributors -- Preface -- Acknowledgments -- Chapter 1: Introduction to chemical enhanced oil recovery -- 1.1. Introduction -- 1.2. Chemical EOR methods -- 1.2.1. Polymer flooding -- 1.2.1.1. Mechanisms of polymer flooding -- Mobility ratio -- Reduction of permeability -- Polymer nature -- 1.2.1.2. Polymer type -- 1.2.2. Surfactant flooding -- 1.2.3. Alkali flooding -- 1.2.4. Foam flooding -- 1.2.5. Chemical EOR combined techniques -- 1.2.5.1. Alkali-surfactant-polymer (ASP) flooding -- 1.2.6. Nanoflooding -- 1.3. Conclusions -- References -- Chapter 2: Polymer flooding -- 2.1. Introduction -- 2.2. Classification of EOR polymers -- 2.2.1. Chemistry aspects -- 2.3. Polymers features and screening criteria -- 2.3.1. Fingering effects -- 2.3.2. Screening criteria -- 2.4. Polymer rheology -- 2.4.1. Polymer sensitivity to mechanical shearing -- 2.4.2. Viscoelastic behavior of the polymer -- 2.4.3. Theoretical model -- 2.4.3.1. Normal stress difference, N1 -- 2.4.3.2. Weissenberg number -- 2.4.3.3. Deborah number -- 2.4.4. Influence of polymer viscoelasticity on its injectivity -- 2.4.5. Viscoelastic influence of the polymer on residual resistance factor -- 2.5. Polymer as fracturing fluid in oil reservoir -- 2.6. Polymer adsorption -- 2.7. Displacement mechanisms in polymer flooding -- 2.7.1. Evaluation of volumetric sweep efficiency -- 2.7.2. Mobility control improvement -- 2.7.3. Influencing on relative permeability -- 2.8. Fractional flow curve analysis -- 2.8.1. Continuous polymer injection without adsorption -- 2.8.2. Influence of initial oil saturation -- 2.8.3. Influence of polymer slug size -- 2.9. Polymer flooding performance -- 2.9.1. Polymer flooding in high-temperature reservoir -- 2.10. Polymer flooding in heavy oil recovery -- 2.11. Polymer flooding design and offshore experiences. , 2.11.1. Salinity -- 2.11.2. Well space -- 2.12. Modeling and simulations -- 2.12.1. Analytical methods -- 2.12.1.1. Water flooding scenario -- 2.12.1.2. Polymer flooding scenario -- 2.13. Upscaling -- 2.14. Laboratory tests and interpretation of the results -- 2.14.1. Microscopic oil displacement tests -- 2.14.2. Polymer dynamic retention test -- 2.14.3. Measurement of viscoelastic properties -- 2.14.3.1. Emulsification tests -- 2.14.4. Displacement test for single-phase flow -- 2.14.4.1. UV analysis of the Effluent -- 2.14.4.2. SEM-EDS of flooded sand -- 2.14.4.3. Polymer flooding with low salinity -- 2.14.4.4. Three-layer oil displacement experiment -- 2.15. Field cases -- 2.15.1. Polymer flooding in the Tambaredjo field, Suriname -- 2.15.2. Polymer flooding in the Marmul field, Oman -- 2.15.3. Polymer flooding using high MW and high concentration polymer-Daqing field, China -- 2.15.4. Gudao field cases -- 2.15.5. East Bodo reservoir, Alberta Canada -- 2.15.6. Turkey case study -- 2.15.7. Oman case study -- 2.16. Injection scheme -- 2.16.1. Strategies for injection rates -- 2.17. Operation problems -- 2.18. Well pattern -- 2.19. Surface facilities -- 2.19.1. Polymer friendly choke valves -- 2.20. Economics and feasibility study of polymer flooding processes -- 2.20.1. Robust number of patterns -- References -- Chapter 3: Enhanced oil recovery using surfactants -- 3.1. Overview -- 3.2. Types of surfactants -- 3.2.1. Anionic -- 3.2.2. Cationic -- 3.2.3. Zwitterionic -- 3.2.4. Nonionic -- 3.3. Chemicals used in surfactant flooding -- 3.4. Thermal and aqueous stability -- 3.4.1. Aqueous and chemical stability -- 3.4.2. Thermal stability -- 3.5. Optimum salinity -- 3.5.1. Temperature -- 3.5.2. Surfactant structure -- 3.5.3. Oil characteristic -- 3.5.4. Cosolvent -- 3.6. Mechanisms -- 3.6.1. IFT reduction -- 3.6.2. Wettability alteration. , 3.6.3. Emulsification -- 3.7. Emulsion formation and treatment -- 3.7.1. Microemulsion rheology -- 3.8. Surfactant retention -- 3.8.1. Surfactant adsorption -- 3.8.1.1. Adsorption models -- Langmuir model -- Freundlich model -- 3.8.2. Phase trapping -- 3.8.2.1. Surfactant partitioning -- 3.8.3. Surfactant precipitation -- 3.8.4. Measurement of surfactants loss -- 3.8.4.1. Static retention -- 3.8.4.2. Dynamic retention -- 3.8.5. Modeling and simulations -- 3.8.6. Relative permeability -- 3.8.7. Capillary desaturation curve (CDC) -- 3.9. Upscaling -- 3.10. Screening criteria -- 3.11. Field cases -- 3.11.1. Cambridge Minnelusa field -- 3.11.2. Gudong field -- 3.11.3. Semoga field -- References -- Chapter 4: Alkaline flooding -- 4.1. Introduction -- 4.2. Commonly used alkaline agents -- 4.3. Alkaline reaction -- 4.3.1. Reaction with oil -- 4.3.2. Reaction with water -- 4.3.3. Reaction with rock -- 4.4. Mechanisms -- 4.4.1. Saponification -- 4.4.2. IFT reduction -- 4.4.3. Wettability alteration -- 4.4.4. Emulsification -- 4.5. Effect of reservoir condition on alkaline process -- 4.6. Geology and lithologic variation of reservoir -- 4.7. Effect of pH -- 4.8. Salinity effect on alkaline flooding -- 4.9. Effects of oil composition on alkaline flooding -- 4.10. Ternary diagram in alkaline flooding -- 4.11. Success rate and screening criteria -- 4.12. Displacement efficiency in alkaline process -- 4.13. Combined flooding processes -- 4.14. Simulation and modeling -- 4.14.1. Simulation -- 4.14.2. Modeling -- 4.14.3. Mathematical formulation of chemical reactions and equilibrium state -- 4.14.4. Mathematical formulation of alkaline flooding -- 4.15. Application of machine learning -- 4.16. Surveillance and monitoring of alkaline flooding -- 4.17. Application conditions of the alkaline flooding project -- A. Appendix -- A.1. Solution. , A.2. Dissolving ionic compounds in water -- A.3. Base dissociation in water (ionization) -- A.3.1. Dissociation or ionization of a strong base -- A.3.2. Dissociation or ionization of a weak base or ionization -- A.4. Bases strength comparison -- A.4.1. Dilute aqueous solutions electrical conductivity -- A.4.2. Dilute aqueous solution's pH -- A.4.3. Equilibrium constant -- A.5. pH calculation -- A.5.1. Strong bases (alkalis) -- References -- Chapter 5: Alkaline-surfactant polymer (ASP) -- 5.1. Introduction -- 5.2. Synergy of alkaline, surfactant, and polymer constituents -- 5.3. Polymer effect -- 5.4. Emulsion properties and stability -- 5.5. ASP compatibility -- 5.6. Mechanism descriptions -- 5.7. Factors that influence IFT -- 5.8. Factors that influence wettability -- 5.9. Phase separation -- 5.10. Surfactant polymer adsorption -- 5.11. Modeling and simulations -- 5.12. Application of machine learning -- 5.13. Optimization the design of ASP injection -- 5.14. Chemistry -- 5.15. Screening criteria -- 5.16. Laboratory tests -- 5.17. Field examples and performance -- 5.18. ASP flooding: Field challenges -- References -- Chapter 6: Improved oil recovery by gel technology: Water shutoff and conformance control -- 6.1. Introduction -- 6.2. Excessive water control -- 6.3. Polymer gels -- 6.3.1. Polymer gel classification -- 6.3.2. Resistance factor and residual resistance factor -- 6.4. In situ gel -- 6.4.1. Bulk gel (BG) -- 6.4.1.1. Disproportionate permeability reduction (DPR) -- 6.4.2. Colloidal dispersion gel (CDG) -- 6.4.2.1. CDG transport modeling -- 6.5. Preformed particle gel (PPG) -- 6.5.1. PPG preparation -- 6.5.2. Swelling characteristic of PPGs -- 6.5.3. PPG injection in porous media -- 6.5.3.1. PPG transport mechanisms in porous media -- 6.5.3.2. PPG retention in porous media -- 6.5.4. PPG transport modeling. , 6.6. Temperature-activated polymer gel (TAP) -- 6.6.1. TAP transport modeling -- 6.7. pH-sensitive microgel -- 6.7.1. Acid preflushing before pH-sensitive microgel injection -- 6.7.2. pH-sensitive microgel injection in sandstones and carbonates -- 6.7.3. pH-sensitive microgel transport modeling -- References -- Chapter 7: Smart water injection -- 7.1. Basic concepts -- 7.2. Condition for smart water injection in sandstone reservoirs -- 7.3. Condition for smart water injection in carbonate reservoirs -- 7.4. Factors influencing smart water -- 7.4.1. Effect of potential determining ions -- 7.4.2. Effect of nonpotential determining ions -- 7.4.3. Effect of rock type -- 7.4.4. Effect of temperature -- 7.5. Physical and chemical mechanisms of recovery -- 7.5.1. Fines migration -- 7.5.2. Mineral dissolution -- 7.5.3. Emulsion formation -- 7.5.3.1. Oil-in-water emulsions -- 7.5.3.2. Water-in-oil emulsions -- 7.5.4. pH increase -- 7.5.5. Double-layer expansion -- 7.5.6. Multiple-ion exchange -- 7.5.7. Salting effect -- 7.5.8. Wettability alteration -- 7.5.9. Mobilization of oil on solid -- 7.6. Injected and formation brine interaction -- 7.7. Optimum salinity -- 7.8. Zeta potential -- 7.9. Dynamic investigation of contact angle and interfacial tension -- 7.10. Heterogeneity and fluid diversion -- 7.11. Effect on relative permeability curve -- 7.12. Simulation -- 7.13. Machine learning -- 7.14. Upscaling -- 7.15. Screening criteria -- 7.16. Field study -- 7.17. Success rate -- 7.18. Field challenges -- 7.19. Operation problems -- 7.20. Economic and environmental feasibility -- References -- Chapter 8: A comprehensive review on the use of eco-friendly surfactants in oil industry -- 8.1. Overview -- 8.2. Surfactant -- 8.2.1. Synthetic surfactants -- 8.2.2. Natural surfactant -- 8.2.2.1. Sources of green surfactant -- 8.2.2.2. Classification of natural surfactant.

Additional Edition: ISBN 0-12-821931-9

Language: English

UID:

Format: 1 online resource (510 pages)

ISBN: 0-12-821932-7

Series Statement: Enhanced oil recovery series

Note: Intro -- Chemical Methods -- Copyright -- Contents -- Contributors -- Preface -- Acknowledgments -- Chapter 1: Introduction to chemical enhanced oil recovery -- 1.1. Introduction -- 1.2. Chemical EOR methods -- 1.2.1. Polymer flooding -- 1.2.1.1. Mechanisms of polymer flooding -- Mobility ratio -- Reduction of permeability -- Polymer nature -- 1.2.1.2. Polymer type -- 1.2.2. Surfactant flooding -- 1.2.3. Alkali flooding -- 1.2.4. Foam flooding -- 1.2.5. Chemical EOR combined techniques -- 1.2.5.1. Alkali-surfactant-polymer (ASP) flooding -- 1.2.6. Nanoflooding -- 1.3. Conclusions -- References -- Chapter 2: Polymer flooding -- 2.1. Introduction -- 2.2. Classification of EOR polymers -- 2.2.1. Chemistry aspects -- 2.3. Polymers features and screening criteria -- 2.3.1. Fingering effects -- 2.3.2. Screening criteria -- 2.4. Polymer rheology -- 2.4.1. Polymer sensitivity to mechanical shearing -- 2.4.2. Viscoelastic behavior of the polymer -- 2.4.3. Theoretical model -- 2.4.3.1. Normal stress difference, N1 -- 2.4.3.2. Weissenberg number -- 2.4.3.3. Deborah number -- 2.4.4. Influence of polymer viscoelasticity on its injectivity -- 2.4.5. Viscoelastic influence of the polymer on residual resistance factor -- 2.5. Polymer as fracturing fluid in oil reservoir -- 2.6. Polymer adsorption -- 2.7. Displacement mechanisms in polymer flooding -- 2.7.1. Evaluation of volumetric sweep efficiency -- 2.7.2. Mobility control improvement -- 2.7.3. Influencing on relative permeability -- 2.8. Fractional flow curve analysis -- 2.8.1. Continuous polymer injection without adsorption -- 2.8.2. Influence of initial oil saturation -- 2.8.3. Influence of polymer slug size -- 2.9. Polymer flooding performance -- 2.9.1. Polymer flooding in high-temperature reservoir -- 2.10. Polymer flooding in heavy oil recovery -- 2.11. Polymer flooding design and offshore experiences. , 2.11.1. Salinity -- 2.11.2. Well space -- 2.12. Modeling and simulations -- 2.12.1. Analytical methods -- 2.12.1.1. Water flooding scenario -- 2.12.1.2. Polymer flooding scenario -- 2.13. Upscaling -- 2.14. Laboratory tests and interpretation of the results -- 2.14.1. Microscopic oil displacement tests -- 2.14.2. Polymer dynamic retention test -- 2.14.3. Measurement of viscoelastic properties -- 2.14.3.1. Emulsification tests -- 2.14.4. Displacement test for single-phase flow -- 2.14.4.1. UV analysis of the Effluent -- 2.14.4.2. SEM-EDS of flooded sand -- 2.14.4.3. Polymer flooding with low salinity -- 2.14.4.4. Three-layer oil displacement experiment -- 2.15. Field cases -- 2.15.1. Polymer flooding in the Tambaredjo field, Suriname -- 2.15.2. Polymer flooding in the Marmul field, Oman -- 2.15.3. Polymer flooding using high MW and high concentration polymer-Daqing field, China -- 2.15.4. Gudao field cases -- 2.15.5. East Bodo reservoir, Alberta Canada -- 2.15.6. Turkey case study -- 2.15.7. Oman case study -- 2.16. Injection scheme -- 2.16.1. Strategies for injection rates -- 2.17. Operation problems -- 2.18. Well pattern -- 2.19. Surface facilities -- 2.19.1. Polymer friendly choke valves -- 2.20. Economics and feasibility study of polymer flooding processes -- 2.20.1. Robust number of patterns -- References -- Chapter 3: Enhanced oil recovery using surfactants -- 3.1. Overview -- 3.2. Types of surfactants -- 3.2.1. Anionic -- 3.2.2. Cationic -- 3.2.3. Zwitterionic -- 3.2.4. Nonionic -- 3.3. Chemicals used in surfactant flooding -- 3.4. Thermal and aqueous stability -- 3.4.1. Aqueous and chemical stability -- 3.4.2. Thermal stability -- 3.5. Optimum salinity -- 3.5.1. Temperature -- 3.5.2. Surfactant structure -- 3.5.3. Oil characteristic -- 3.5.4. Cosolvent -- 3.6. Mechanisms -- 3.6.1. IFT reduction -- 3.6.2. Wettability alteration. , 3.6.3. Emulsification -- 3.7. Emulsion formation and treatment -- 3.7.1. Microemulsion rheology -- 3.8. Surfactant retention -- 3.8.1. Surfactant adsorption -- 3.8.1.1. Adsorption models -- Langmuir model -- Freundlich model -- 3.8.2. Phase trapping -- 3.8.2.1. Surfactant partitioning -- 3.8.3. Surfactant precipitation -- 3.8.4. Measurement of surfactants loss -- 3.8.4.1. Static retention -- 3.8.4.2. Dynamic retention -- 3.8.5. Modeling and simulations -- 3.8.6. Relative permeability -- 3.8.7. Capillary desaturation curve (CDC) -- 3.9. Upscaling -- 3.10. Screening criteria -- 3.11. Field cases -- 3.11.1. Cambridge Minnelusa field -- 3.11.2. Gudong field -- 3.11.3. Semoga field -- References -- Chapter 4: Alkaline flooding -- 4.1. Introduction -- 4.2. Commonly used alkaline agents -- 4.3. Alkaline reaction -- 4.3.1. Reaction with oil -- 4.3.2. Reaction with water -- 4.3.3. Reaction with rock -- 4.4. Mechanisms -- 4.4.1. Saponification -- 4.4.2. IFT reduction -- 4.4.3. Wettability alteration -- 4.4.4. Emulsification -- 4.5. Effect of reservoir condition on alkaline process -- 4.6. Geology and lithologic variation of reservoir -- 4.7. Effect of pH -- 4.8. Salinity effect on alkaline flooding -- 4.9. Effects of oil composition on alkaline flooding -- 4.10. Ternary diagram in alkaline flooding -- 4.11. Success rate and screening criteria -- 4.12. Displacement efficiency in alkaline process -- 4.13. Combined flooding processes -- 4.14. Simulation and modeling -- 4.14.1. Simulation -- 4.14.2. Modeling -- 4.14.3. Mathematical formulation of chemical reactions and equilibrium state -- 4.14.4. Mathematical formulation of alkaline flooding -- 4.15. Application of machine learning -- 4.16. Surveillance and monitoring of alkaline flooding -- 4.17. Application conditions of the alkaline flooding project -- A. Appendix -- A.1. Solution. , A.2. Dissolving ionic compounds in water -- A.3. Base dissociation in water (ionization) -- A.3.1. Dissociation or ionization of a strong base -- A.3.2. Dissociation or ionization of a weak base or ionization -- A.4. Bases strength comparison -- A.4.1. Dilute aqueous solutions electrical conductivity -- A.4.2. Dilute aqueous solution's pH -- A.4.3. Equilibrium constant -- A.5. pH calculation -- A.5.1. Strong bases (alkalis) -- References -- Chapter 5: Alkaline-surfactant polymer (ASP) -- 5.1. Introduction -- 5.2. Synergy of alkaline, surfactant, and polymer constituents -- 5.3. Polymer effect -- 5.4. Emulsion properties and stability -- 5.5. ASP compatibility -- 5.6. Mechanism descriptions -- 5.7. Factors that influence IFT -- 5.8. Factors that influence wettability -- 5.9. Phase separation -- 5.10. Surfactant polymer adsorption -- 5.11. Modeling and simulations -- 5.12. Application of machine learning -- 5.13. Optimization the design of ASP injection -- 5.14. Chemistry -- 5.15. Screening criteria -- 5.16. Laboratory tests -- 5.17. Field examples and performance -- 5.18. ASP flooding: Field challenges -- References -- Chapter 6: Improved oil recovery by gel technology: Water shutoff and conformance control -- 6.1. Introduction -- 6.2. Excessive water control -- 6.3. Polymer gels -- 6.3.1. Polymer gel classification -- 6.3.2. Resistance factor and residual resistance factor -- 6.4. In situ gel -- 6.4.1. Bulk gel (BG) -- 6.4.1.1. Disproportionate permeability reduction (DPR) -- 6.4.2. Colloidal dispersion gel (CDG) -- 6.4.2.1. CDG transport modeling -- 6.5. Preformed particle gel (PPG) -- 6.5.1. PPG preparation -- 6.5.2. Swelling characteristic of PPGs -- 6.5.3. PPG injection in porous media -- 6.5.3.1. PPG transport mechanisms in porous media -- 6.5.3.2. PPG retention in porous media -- 6.5.4. PPG transport modeling. , 6.6. Temperature-activated polymer gel (TAP) -- 6.6.1. TAP transport modeling -- 6.7. pH-sensitive microgel -- 6.7.1. Acid preflushing before pH-sensitive microgel injection -- 6.7.2. pH-sensitive microgel injection in sandstones and carbonates -- 6.7.3. pH-sensitive microgel transport modeling -- References -- Chapter 7: Smart water injection -- 7.1. Basic concepts -- 7.2. Condition for smart water injection in sandstone reservoirs -- 7.3. Condition for smart water injection in carbonate reservoirs -- 7.4. Factors influencing smart water -- 7.4.1. Effect of potential determining ions -- 7.4.2. Effect of nonpotential determining ions -- 7.4.3. Effect of rock type -- 7.4.4. Effect of temperature -- 7.5. Physical and chemical mechanisms of recovery -- 7.5.1. Fines migration -- 7.5.2. Mineral dissolution -- 7.5.3. Emulsion formation -- 7.5.3.1. Oil-in-water emulsions -- 7.5.3.2. Water-in-oil emulsions -- 7.5.4. pH increase -- 7.5.5. Double-layer expansion -- 7.5.6. Multiple-ion exchange -- 7.5.7. Salting effect -- 7.5.8. Wettability alteration -- 7.5.9. Mobilization of oil on solid -- 7.6. Injected and formation brine interaction -- 7.7. Optimum salinity -- 7.8. Zeta potential -- 7.9. Dynamic investigation of contact angle and interfacial tension -- 7.10. Heterogeneity and fluid diversion -- 7.11. Effect on relative permeability curve -- 7.12. Simulation -- 7.13. Machine learning -- 7.14. Upscaling -- 7.15. Screening criteria -- 7.16. Field study -- 7.17. Success rate -- 7.18. Field challenges -- 7.19. Operation problems -- 7.20. Economic and environmental feasibility -- References -- Chapter 8: A comprehensive review on the use of eco-friendly surfactants in oil industry -- 8.1. Overview -- 8.2. Surfactant -- 8.2.1. Synthetic surfactants -- 8.2.2. Natural surfactant -- 8.2.2.1. Sources of green surfactant -- 8.2.2.2. Classification of natural surfactant.

Additional Edition: ISBN 0-12-821931-9

Language: English