Antoine Thomas holds an MSc in Petroleum Geosciences from the Ecole Nationale Supérieure de Géologie in Nancy, France (2009). He joined SNF in 2011 as a reservoir engineer dealing with Polymer Flooding project design, implementation and assistance, for various customers worldwide. In 2013, he spent part of his time in the R&D department, building the core flooding capacities for SNF and managing R&D projects in enhanced oil recovery (EOR) and hydraulic fracturing. He moved to Moscow in 2018 to supervise the Oil & Gas business, from a technical standpoint, while maintaining contact with all SNF subsidiaries.

Select Guide Rating

• Preface xvAbbreviations xixAbout the Author xxiiiIntroduction xxv1. Why Enhanced Oil Recovery? 31.1. What Is a Reservoir? 41.2. Hydrocarbon Recovery Mechanisms 41.2.1. Anecdote 71.3. Definitions of IOR and EOR 81.4. What Controls Oil Recovery? 81.5. Classification and Description of EOR Processes 111.5.1. Thermal Processes 111.5.2. Chemical Processes 151.5.3. Miscible Processes 151.6. Why EOR? Cost, Reserve Replacement, and Recovery Factors 17References 202. Chemical Enhanced Oil Recovery Methods 232.1. Introduction 242.2. Chemical EOR Methods 262.2.1. Polymer Flooding 272.2.2. High‐Viscosity Polymer Slugs 322.2.3. Surfactant‐Polymer (SP) 332.2.3.1. Surfactants 332.2.3.2. Field Cases 372.2.4. Alkali‐Surfactant‐Polymer Flooding (ASP) 382.2.4.1. Theory 382.2.4.2. Laboratory Studies 402.2.4.3. Economics 442.2.4.4. Field Cases 452.2.5. Other Chemical Methods 492.2.5.1. Gels vs. Polymer Injection 492.2.5.2. Colloidal Dispersion Gels 502.2.5.3. Microgels and Nanogels 532.2.5.4. Relative Permeability Modifiers (RPM) 54References 563. Polymer Flooding 653.1. Introduction 663.2. Concept 673.2.1. Fractional Flow 673.2.2. Polymer Flooding Applicability 703.2.3. Timing 713.3. Envelope of Application 733.3.1. History 733.3.2. Reservoir Prescreening 773.3.2.1. Lithology 783.3.2.2. Wettability 783.3.2.3. Current Oil Saturation 803.3.2.4. Porosity Type 803.3.2.5. Gas Cap 803.3.2.6. Aquifer 813.3.2.7. Salinity/Hardness 813.3.2.8. Dykstra‐Parsons 823.3.2.9. Clays 833.3.2.10. Water-cut 843.3.2.11. Flooding Pattern and Spacing 853.4. Conclusions 85References 874. Polymers 914.1. Introduction 924.2. Polyacrylamide – Generalities 934.2.1. Introduction 934.2.2. Monomers 934.2.2.1. Acrylamide 934.2.2.2. Acrylic Acid 954.2.2.3. ATBS 954.2.2.4. N‐Vinylpyrrolidone 964.2.3. Polymerization Processes 964.2.3.1. Gel Polymerization Process 974.2.3.2. Inverse Emulsion Polymerization Process 984.3. Polymer Selection Guidelines 994.3.1. Generalities 994.3.1.1. Polymer Form 1004.3.1.2. Polymer Chemistry 1014.3.1.3. Polymer Molecular Weight 1014.3.2. Polymer Selection 1024.3.2.1. Molecular Weight 1034.3.3. Other Polymer Families 1034.3.3.1. Associative Polymers 1034.3.3.2. Thermoresponsive Polymers 1054.4. Polymer Characteristics and Rheology 1054.4.1. Viscosity 1064.4.1.1. Generalities 1064.4.2. Rheology 1094.4.3. Solubility 1104.5. Polymer Stability 1104.5.1. Chemical Degradation 1104.5.1.1. Oxygen 1114.5.1.2. Iron 1124.5.1.3. Protection from Chemical Degradation 1124.5.2. Mechanical Degradation 1144.5.3. Thermal Degradation 1154.5.4. Improving Polymer Stability 1174.6. Laboratory Evaluations 1184.6.1. Solubility and Filterability 1194.6.1.1. Solubility 1194.6.1.2. Filterability 1194.6.2. Viscosity 1214.6.3. Shear Resistance 1244.6.4. Screen Factor 1254.6.5. Long‐Term Stability 1264.6.6. Compatibility Tests 1274.6.7. Core Flooding 1284.6.7.1. Generalities 1294.6.7.2. Equipment and Tips for Injection 1404.6.8. Quality Control 1414.6.9. Heath, Safety, and Environment 1424.6.9.1. Product Handling 1424.6.9.2. Anionic Polyacrylamide in the Marine Environment 1434.6.9.3. Biodegradability 1444.6.9.4. Polyacrylamides as a Nitrogen Source 1454.6.9.5. Polyacrylamides as a Carbon Source 1454.6.9.6. About Acrylamide Reformation and Toxicity 147References 1495. Polymer Flooding – Pilot Design 1595.1. Reservoir Screening – Reminder 1605.2. Pilot Design 1615.2.1. Pattern Selection 1625.2.2. How Much Polymer? 1655.2.3. Injection Protocol 1685.2.3.1. Start‐Up of Polymer Injection 1685.2.3.2. Ending Polymer Injection 1685.2.3.3. Voidage Replacement Ratio (VRR) 1695.3. Injectivity 1715.3.1. Discussion on Injectivity 1745.4. Monitoring 1805.5. Modeling 1815.6. Quality Control 1825.7. Specific Considerations for Offshore Implementation 183References 1866. Engineering 1896.1. Preliminary Requirements 1906.1.1. Water Quality 1906.1.2. Oxygen Removal 1916.1.3. Requirements for Design 1926.1.4. Powder vs. Emulsion 1946.2. Injection Equipment for Emulsions 1956.3. Injection Equipment for Powders 1956.3.1. Dispersion and Dissolution 1956.3.2. Maturation 1986.4. Field Development Approaches Onshore 1986.4.1. Existing Waterflooding in the Field 2006.4.1.1. One Pump per Well – Injecting Mother Solution 2016.4.1.2. One Pump for Several Wells – Injecting Mother Solution 2016.4.2. No Existing Waterflooding in the Field 2016.4.2.1. One Pump per Well – Injecting Diluted Solution 026.4.2.2. One Pump for Several Wells – Injecting Diluted Solution 2026.4.3. Logistics for Onshore Projects 2026.5. Key Considerations for Offshore Implementation 2056.6. ASP Process 2096.6.1. ASP Reminder 2096.6.2. Water Softening 2096.6.3. Chemicals 2116.6.3.1. Alkali 2116.6.3.2. Surfactant 2126.6.4. Mixing of All Products 2136.7. From the Dissolution Point to the Wellhead 2146.7.1. Viscosity Monitoring 2146.7.2. Non‐shearing Chokes 216References 2187. Produced Water Treatment 2217.1. Introduction 2227.2. Generalities 2247.2.1. Produced Water Characteristics 2247.2.2. Oil and Gas Processing 2267.3. Oil and Gas Separation 2267.3.1. Separators 2267.3.2. Heater Treaters 2287.4. Water Treatment 2297.4.1. Introduction and Generalities 2297.4.2. Gravity Separation 2297.4.2.1. Deoilers 2317.4.3. Gas Flotation 2327.4.4. Cyclonic Separation 2347.4.5. Centrifuges 2347.4.6. Filtration 2357.4.6.1. Media Filters 2357.4.6.2. Membranes 2377.5. Polymer Degradation 2397.5.1. Polymer Removal 2407.5.2. Chemical Oxidation 2417.5.3. Electro‐Oxidation 2417.5.4. Mechanical Degradation 2427.5.5. Ultrasonic Degradation 2427.5.6. Thermal Degradation 2437.5.7. UV – Advanced Oxidation Processes 2437.6. Conclusions and Discussion 244References 2488. Economics 2518.1. Introduction 2528.2. Cost Overview 2528.2.1. Water Handling and Injection 2538.2.2. Cost of EOR Chemicals 2558.2.3. Additional Costs for ASP Flooding 2568.3. Example – Polymer Flooding 2578.4. Examples – SP and ASP 2608.4.1. SP 2608.4.2. ASP 2628.4.3. Comparison P – SP – ASP 2648.5. Conclusions 265References 2689. Field Cases 2719.1. Introduction 2729.2. Envelope of Application 2759.3. Other Interesting Field Cases 2819.3.1. Economic Benefits of Polymer Injection 2819.3.2. Injection Under Fracturing Conditions 2819.3.3. High‐Temperature Reservoirs 2819.4. Conclusions 283References 285Index 289

Antoine Thomas holds an MSc in Petroleum Geosciences from the Ecole Nationale Supérieure de Géologie in Nancy, France (2009). He joined SNF in 2011 as a reservoir engineer dealing with Polymer Flooding project design, implementation and assistance, for various customers worldwide. In 2013, he spent part of his time in the R&D department, building the core flooding capacities for SNF and managing R&D projects in enhanced oil recovery (EOR) and hydraulic fracturing. He moved to Moscow in 2018 to supervise the Oil & Gas business, from a technical standpoint, while maintaining contact with all SNF subsidiaries.

Select Guide Rating

• Preface xvAbbreviations xixAbout the Author xxiiiIntroduction xxv1. Why Enhanced Oil Recovery? 31.1. What Is a Reservoir? 41.2. Hydrocarbon Recovery Mechanisms 41.2.1. Anecdote 71.3. Definitions of IOR and EOR 81.4. What Controls Oil Recovery? 81.5. Classification and Description of EOR Processes 111.5.1. Thermal Processes 111.5.2. Chemical Processes 151.5.3. Miscible Processes 151.6. Why EOR? Cost, Reserve Replacement, and Recovery Factors 17References 202. Chemical Enhanced Oil Recovery Methods 232.1. Introduction 242.2. Chemical EOR Methods 262.2.1. Polymer Flooding 272.2.2. High‐Viscosity Polymer Slugs 322.2.3. Surfactant‐Polymer (SP) 332.2.3.1. Surfactants 332.2.3.2. Field Cases 372.2.4. Alkali‐Surfactant‐Polymer Flooding (ASP) 382.2.4.1. Theory 382.2.4.2. Laboratory Studies 402.2.4.3. Economics 442.2.4.4. Field Cases 452.2.5. Other Chemical Methods 492.2.5.1. Gels vs. Polymer Injection 492.2.5.2. Colloidal Dispersion Gels 502.2.5.3. Microgels and Nanogels 532.2.5.4. Relative Permeability Modifiers (RPM) 54References 563. Polymer Flooding 653.1. Introduction 663.2. Concept 673.2.1. Fractional Flow 673.2.2. Polymer Flooding Applicability 703.2.3. Timing 713.3. Envelope of Application 733.3.1. History 733.3.2. Reservoir Prescreening 773.3.2.1. Lithology 783.3.2.2. Wettability 783.3.2.3. Current Oil Saturation 803.3.2.4. Porosity Type 803.3.2.5. Gas Cap 803.3.2.6. Aquifer 813.3.2.7. Salinity/Hardness 813.3.2.8. Dykstra‐Parsons 823.3.2.9. Clays 833.3.2.10. Water-cut 843.3.2.11. Flooding Pattern and Spacing 853.4. Conclusions 85References 874. Polymers 914.1. Introduction 924.2. Polyacrylamide – Generalities 934.2.1. Introduction 934.2.2. Monomers 934.2.2.1. Acrylamide 934.2.2.2. Acrylic Acid 954.2.2.3. ATBS 954.2.2.4. N‐Vinylpyrrolidone 964.2.3. Polymerization Processes 964.2.3.1. Gel Polymerization Process 974.2.3.2. Inverse Emulsion Polymerization Process 984.3. Polymer Selection Guidelines 994.3.1. Generalities 994.3.1.1. Polymer Form 1004.3.1.2. Polymer Chemistry 1014.3.1.3. Polymer Molecular Weight 1014.3.2. Polymer Selection 1024.3.2.1. Molecular Weight 1034.3.3. Other Polymer Families 1034.3.3.1. Associative Polymers 1034.3.3.2. Thermoresponsive Polymers 1054.4. Polymer Characteristics and Rheology 1054.4.1. Viscosity 1064.4.1.1. Generalities 1064.4.2. Rheology 1094.4.3. Solubility 1104.5. Polymer Stability 1104.5.1. Chemical Degradation 1104.5.1.1. Oxygen 1114.5.1.2. Iron 1124.5.1.3. Protection from Chemical Degradation 1124.5.2. Mechanical Degradation 1144.5.3. Thermal Degradation 1154.5.4. Improving Polymer Stability 1174.6. Laboratory Evaluations 1184.6.1. Solubility and Filterability 1194.6.1.1. Solubility 1194.6.1.2. Filterability 1194.6.2. Viscosity 1214.6.3. Shear Resistance 1244.6.4. Screen Factor 1254.6.5. Long‐Term Stability 1264.6.6. Compatibility Tests 1274.6.7. Core Flooding 1284.6.7.1. Generalities 1294.6.7.2. Equipment and Tips for Injection 1404.6.8. Quality Control 1414.6.9. Heath, Safety, and Environment 1424.6.9.1. Product Handling 1424.6.9.2. Anionic Polyacrylamide in the Marine Environment 1434.6.9.3. Biodegradability 1444.6.9.4. Polyacrylamides as a Nitrogen Source 1454.6.9.5. Polyacrylamides as a Carbon Source 1454.6.9.6. About Acrylamide Reformation and Toxicity 147References 1495. Polymer Flooding – Pilot Design 1595.1. Reservoir Screening – Reminder 1605.2. Pilot Design 1615.2.1. Pattern Selection 1625.2.2. How Much Polymer? 1655.2.3. Injection Protocol 1685.2.3.1. Start‐Up of Polymer Injection 1685.2.3.2. Ending Polymer Injection 1685.2.3.3. Voidage Replacement Ratio (VRR) 1695.3. Injectivity 1715.3.1. Discussion on Injectivity 1745.4. Monitoring 1805.5. Modeling 1815.6. Quality Control 1825.7. Specific Considerations for Offshore Implementation 183References 1866. Engineering 1896.1. Preliminary Requirements 1906.1.1. Water Quality 1906.1.2. Oxygen Removal 1916.1.3. Requirements for Design 1926.1.4. Powder vs. Emulsion 1946.2. Injection Equipment for Emulsions 1956.3. Injection Equipment for Powders 1956.3.1. Dispersion and Dissolution 1956.3.2. Maturation 1986.4. Field Development Approaches Onshore 1986.4.1. Existing Waterflooding in the Field 2006.4.1.1. One Pump per Well – Injecting Mother Solution 2016.4.1.2. One Pump for Several Wells – Injecting Mother Solution 2016.4.2. No Existing Waterflooding in the Field 2016.4.2.1. One Pump per Well – Injecting Diluted Solution 026.4.2.2. One Pump for Several Wells – Injecting Diluted Solution 2026.4.3. Logistics for Onshore Projects 2026.5. Key Considerations for Offshore Implementation 2056.6. ASP Process 2096.6.1. ASP Reminder 2096.6.2. Water Softening 2096.6.3. Chemicals 2116.6.3.1. Alkali 2116.6.3.2. Surfactant 2126.6.4. Mixing of All Products 2136.7. From the Dissolution Point to the Wellhead 2146.7.1. Viscosity Monitoring 2146.7.2. Non‐shearing Chokes 216References 2187. Produced Water Treatment 2217.1. Introduction 2227.2. Generalities 2247.2.1. Produced Water Characteristics 2247.2.2. Oil and Gas Processing 2267.3. Oil and Gas Separation 2267.3.1. Separators 2267.3.2. Heater Treaters 2287.4. Water Treatment 2297.4.1. Introduction and Generalities 2297.4.2. Gravity Separation 2297.4.2.1. Deoilers 2317.4.3. Gas Flotation 2327.4.4. Cyclonic Separation 2347.4.5. Centrifuges 2347.4.6. Filtration 2357.4.6.1. Media Filters 2357.4.6.2. Membranes 2377.5. Polymer Degradation 2397.5.1. Polymer Removal 2407.5.2. Chemical Oxidation 2417.5.3. Electro‐Oxidation 2417.5.4. Mechanical Degradation 2427.5.5. Ultrasonic Degradation 2427.5.6. Thermal Degradation 2437.5.7. UV – Advanced Oxidation Processes 2437.6. Conclusions and Discussion 244References 2488. Economics 2518.1. Introduction 2528.2. Cost Overview 2528.2.1. Water Handling and Injection 2538.2.2. Cost of EOR Chemicals 2558.2.3. Additional Costs for ASP Flooding 2568.3. Example – Polymer Flooding 2578.4. Examples – SP and ASP 2608.4.1. SP 2608.4.2. ASP 2628.4.3. Comparison P – SP – ASP 2648.5. Conclusions 265References 2689. Field Cases 2719.1. Introduction 2729.2. Envelope of Application 2759.3. Other Interesting Field Cases 2819.3.1. Economic Benefits of Polymer Injection 2819.3.2. Injection Under Fracturing Conditions 2819.3.3. High‐Temperature Reservoirs 2819.4. Conclusions 283References 285Index 289

Antoine Thomas holds an MSc in Petroleum Geosciences from the Ecole Nationale Supérieure de Géologie in Nancy, France (2009). He joined SNF in 2011 as a reservoir engineer dealing with Polymer Flooding project design, implementation and assistance, for various customers worldwide. In 2013, he spent part of his time in the R&D department, building the core flooding capacities for SNF and managing R&D projects in enhanced oil recovery (EOR) and hydraulic fracturing. He moved to Moscow in 2018 to supervise the Oil & Gas business, from a technical standpoint, while maintaining contact with all SNF subsidiaries.

Select Guide Rating

• Preface xvAbbreviations xixAbout the Author xxiiiIntroduction xxv1. Why Enhanced Oil Recovery? 31.1. What Is a Reservoir? 41.2. Hydrocarbon Recovery Mechanisms 41.2.1. Anecdote 71.3. Definitions of IOR and EOR 81.4. What Controls Oil Recovery? 81.5. Classification and Description of EOR Processes 111.5.1. Thermal Processes 111.5.2. Chemical Processes 151.5.3. Miscible Processes 151.6. Why EOR? Cost, Reserve Replacement, and Recovery Factors 17References 202. Chemical Enhanced Oil Recovery Methods 232.1. Introduction 242.2. Chemical EOR Methods 262.2.1. Polymer Flooding 272.2.2. High‐Viscosity Polymer Slugs 322.2.3. Surfactant‐Polymer (SP) 332.2.3.1. Surfactants 332.2.3.2. Field Cases 372.2.4. Alkali‐Surfactant‐Polymer Flooding (ASP) 382.2.4.1. Theory 382.2.4.2. Laboratory Studies 402.2.4.3. Economics 442.2.4.4. Field Cases 452.2.5. Other Chemical Methods 492.2.5.1. Gels vs. Polymer Injection 492.2.5.2. Colloidal Dispersion Gels 502.2.5.3. Microgels and Nanogels 532.2.5.4. Relative Permeability Modifiers (RPM) 54References 563. Polymer Flooding 653.1. Introduction 663.2. Concept 673.2.1. Fractional Flow 673.2.2. Polymer Flooding Applicability 703.2.3. Timing 713.3. Envelope of Application 733.3.1. History 733.3.2. Reservoir Prescreening 773.3.2.1. Lithology 783.3.2.2. Wettability 783.3.2.3. Current Oil Saturation 803.3.2.4. Porosity Type 803.3.2.5. Gas Cap 803.3.2.6. Aquifer 813.3.2.7. Salinity/Hardness 813.3.2.8. Dykstra‐Parsons 823.3.2.9. Clays 833.3.2.10. Water-cut 843.3.2.11. Flooding Pattern and Spacing 853.4. Conclusions 85References 874. Polymers 914.1. Introduction 924.2. Polyacrylamide – Generalities 934.2.1. Introduction 934.2.2. Monomers 934.2.2.1. Acrylamide 934.2.2.2. Acrylic Acid 954.2.2.3. ATBS 954.2.2.4. N‐Vinylpyrrolidone 964.2.3. Polymerization Processes 964.2.3.1. Gel Polymerization Process 974.2.3.2. Inverse Emulsion Polymerization Process 984.3. Polymer Selection Guidelines 994.3.1. Generalities 994.3.1.1. Polymer Form 1004.3.1.2. Polymer Chemistry 1014.3.1.3. Polymer Molecular Weight 1014.3.2. Polymer Selection 1024.3.2.1. Molecular Weight 1034.3.3. Other Polymer Families 1034.3.3.1. Associative Polymers 1034.3.3.2. Thermoresponsive Polymers 1054.4. Polymer Characteristics and Rheology 1054.4.1. Viscosity 1064.4.1.1. Generalities 1064.4.2. Rheology 1094.4.3. Solubility 1104.5. Polymer Stability 1104.5.1. Chemical Degradation 1104.5.1.1. Oxygen 1114.5.1.2. Iron 1124.5.1.3. Protection from Chemical Degradation 1124.5.2. Mechanical Degradation 1144.5.3. Thermal Degradation 1154.5.4. Improving Polymer Stability 1174.6. Laboratory Evaluations 1184.6.1. Solubility and Filterability 1194.6.1.1. Solubility 1194.6.1.2. Filterability 1194.6.2. Viscosity 1214.6.3. Shear Resistance 1244.6.4. Screen Factor 1254.6.5. Long‐Term Stability 1264.6.6. Compatibility Tests 1274.6.7. Core Flooding 1284.6.7.1. Generalities 1294.6.7.2. Equipment and Tips for Injection 1404.6.8. Quality Control 1414.6.9. Heath, Safety, and Environment 1424.6.9.1. Product Handling 1424.6.9.2. Anionic Polyacrylamide in the Marine Environment 1434.6.9.3. Biodegradability 1444.6.9.4. Polyacrylamides as a Nitrogen Source 1454.6.9.5. Polyacrylamides as a Carbon Source 1454.6.9.6. About Acrylamide Reformation and Toxicity 147References 1495. Polymer Flooding – Pilot Design 1595.1. Reservoir Screening – Reminder 1605.2. Pilot Design 1615.2.1. Pattern Selection 1625.2.2. How Much Polymer? 1655.2.3. Injection Protocol 1685.2.3.1. Start‐Up of Polymer Injection 1685.2.3.2. Ending Polymer Injection 1685.2.3.3. Voidage Replacement Ratio (VRR) 1695.3. Injectivity 1715.3.1. Discussion on Injectivity 1745.4. Monitoring 1805.5. Modeling 1815.6. Quality Control 1825.7. Specific Considerations for Offshore Implementation 183References 1866. Engineering 1896.1. Preliminary Requirements 1906.1.1. Water Quality 1906.1.2. Oxygen Removal 1916.1.3. Requirements for Design 1926.1.4. Powder vs. Emulsion 1946.2. Injection Equipment for Emulsions 1956.3. Injection Equipment for Powders 1956.3.1. Dispersion and Dissolution 1956.3.2. Maturation 1986.4. Field Development Approaches Onshore 1986.4.1. Existing Waterflooding in the Field 2006.4.1.1. One Pump per Well – Injecting Mother Solution 2016.4.1.2. One Pump for Several Wells – Injecting Mother Solution 2016.4.2. No Existing Waterflooding in the Field 2016.4.2.1. One Pump per Well – Injecting Diluted Solution 026.4.2.2. One Pump for Several Wells – Injecting Diluted Solution 2026.4.3. Logistics for Onshore Projects 2026.5. Key Considerations for Offshore Implementation 2056.6. ASP Process 2096.6.1. ASP Reminder 2096.6.2. Water Softening 2096.6.3. Chemicals 2116.6.3.1. Alkali 2116.6.3.2. Surfactant 2126.6.4. Mixing of All Products 2136.7. From the Dissolution Point to the Wellhead 2146.7.1. Viscosity Monitoring 2146.7.2. Non‐shearing Chokes 216References 2187. Produced Water Treatment 2217.1. Introduction 2227.2. Generalities 2247.2.1. Produced Water Characteristics 2247.2.2. Oil and Gas Processing 2267.3. Oil and Gas Separation 2267.3.1. Separators 2267.3.2. Heater Treaters 2287.4. Water Treatment 2297.4.1. Introduction and Generalities 2297.4.2. Gravity Separation 2297.4.2.1. Deoilers 2317.4.3. Gas Flotation 2327.4.4. Cyclonic Separation 2347.4.5. Centrifuges 2347.4.6. Filtration 2357.4.6.1. Media Filters 2357.4.6.2. Membranes 2377.5. Polymer Degradation 2397.5.1. Polymer Removal 2407.5.2. Chemical Oxidation 2417.5.3. Electro‐Oxidation 2417.5.4. Mechanical Degradation 2427.5.5. Ultrasonic Degradation 2427.5.6. Thermal Degradation 2437.5.7. UV – Advanced Oxidation Processes 2437.6. Conclusions and Discussion 244References 2488. Economics 2518.1. Introduction 2528.2. Cost Overview 2528.2.1. Water Handling and Injection 2538.2.2. Cost of EOR Chemicals 2558.2.3. Additional Costs for ASP Flooding 2568.3. Example – Polymer Flooding 2578.4. Examples – SP and ASP 2608.4.1. SP 2608.4.2. ASP 2628.4.3. Comparison P – SP – ASP 2648.5. Conclusions 265References 2689. Field Cases 2719.1. Introduction 2729.2. Envelope of Application 2759.3. Other Interesting Field Cases 2819.3.1. Economic Benefits of Polymer Injection 2819.3.2. Injection Under Fracturing Conditions 2819.3.3. High‐Temperature Reservoirs 2819.4. Conclusions 283References 285Index 289