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