UID:
almahu_9948026356202882
Format:
1 online resource (678 pages)
ISBN:
0-12-813783-5
,
0-12-813782-7
Note:
Front Cover -- Formation Damage During Improved Oil Recovery -- Copyright Page -- Dedication -- Contents -- List of Contributors -- Preface -- 1. Overview of Formation Damage During Improved and Enhanced Oil Recovery -- 1.1 Introduction -- 1.2 Summary of Formation Damage during EOR -- 1.3 Low-Salinity Water Flooding (LSWF) -- 1.4 Chemical Flooding -- 1.5 Thermal Recovery in Heavy Oil -- 1.6 Produced-Water-Re-Injection (PWRI) -- 1.7 CO2 Flooding -- 1.8 Hydraulic Fracturing in Shale Formations -- 1.9 Coal-Bed Methane (CBM) -- 1.10 Geothermal Reservoirs -- 1.11 Deepwater Reservoirs -- 1.12 Summary -- References -- 2. Low-Salinity Water Flooding: from Novel to Mature Technology -- 2.1 Introduction -- 2.2 Origins of LSWF and Identification of Reservoir Mechanism Driving Incremental Oil Recovery -- 2.3 Fines Migration: Detachment, Transport, and Redeposition -- 2.4 Clay Swelling, Detachment, and Pore Blocking Leading to Reductions in Permeability and Porosity -- 2.5 Salinity Thresholds and Reservoir Heterogeneity Influences on Particle Detachment -- 2.6 Exploiting Pore Plugging to Preferentially Enhance Oil Recovery -- 2.6.1 Quantifying and modeling fines migration and pore plugging -- 2.6.2 LSWF to induce fines-migration-related formation damage -- 2.6.3 Enhanced sweep efficiency by induced fines migration during LSW flooding -- 2.7 Factors Influencing EOR in Sandstone Reservoirs Subjected to LSWF -- 2.8 Relationships Between Oil Recovery, Salinity, and Wettability Variables -- 2.9 Wetting Mechanisms in Carbonates and Sandstones -- 2.10 Example Field Field-scale Tests and Outcomes of LSWF -- 2.11 Potential to Combine LSWF with Other IOR Mechanisms -- 2.11.1 LSWF combined with surfactants -- 2.11.2 LSWF combined with polymers -- 2.11.3 LSWF combined with CO2 water-alternating gas injection -- 2.11.4 LSWF combined with nanofluid treatments.
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2.12 Conclusions -- Nomenclature -- References -- 3. Formation Damage by Fines Migration: Mathematical and Laboratory Modeling, Field Cases -- 3.1 Introduction -- 3.2 Governing Equations for Flow with Fines Migration -- 3.2.1 Torque balance of forces acting on particle -- 3.2.2 Using the torque balance to derive expressions for the maximum retention function -- 3.2.2.1 Internal filter cake of multilayer with mono-sized fine particles -- 3.2.2.2 Monolayer of multisized fine particles -- 3.2.3 Single-phase equations for fines transport -- 3.3 Fines Migration Resulting from High Fluid Velocities -- 3.3.1 Formulation of mathematical model -- 3.3.2 Exact analytical solution for 1D problem -- 3.3.3 Qualitative analysis of the solution -- 3.3.4 Analysis of laboratory data -- 3.4 Productivity Decline due to Fines Migration -- 3.4.1 Mathematical formulation -- 3.4.2 Analytical solution -- 3.4.3 Calculation of impedance -- 3.5 Fines Detachment and Migration at Low Salinity -- 3.5.1 1D analytical solution with instant fines detachment -- 3.5.1.1 Qualitative analysis of the model -- 3.5.2 Tuning experimental data -- 3.5.3 Well injectivity decline during low-salinity water injection -- 3.5.3.1 Qualitative analysis of the model -- 3.5.3.2 Injectivity decline prediction -- 3.5.4 Field cases -- 3.6 Effects of Nonequilibrium/Delay in Particle Detachment on Fines Migration -- 3.6.1 Introduction of a delay in detachment -- 3.6.2 Exact solution for 1D problem accounting for delay with detachment -- 3.6.3 Analysis of laboratory data and tuning of the model coefficients -- 3.6.4 Semianalytical model for axisymmetric flow -- 3.6.5 Prediction of injection well behavior -- 3.7 Two-Phase Fines Migration During Low-Salinity Waterflood: Analytical Modeling -- 3.7.1 Fines migration in two-phase flow -- 3.7.2 Splitting method for integration of two-phase systems.
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3.7.3 Exact solution for the auxiliary system -- 3.7.4 Lifting equation -- 3.7.5 Inverse mapping -- 3.7.6 Implementation of fines migration using reservoir simulators -- 3.8 Conclusions -- Nomenclature -- Greek symbols -- Super/Subscripts -- References -- 4. Using Nanofluids to Control Fines Migration in Porous Systems -- 4.1 Introduction -- 4.2 Laboratory Proof and Field Cases -- 4.3 Nanoparticles Transport in Porous Media: Adsorption, Straining, and Detachment Behaviors -- 4.4 Effectiveness of Nanoparticles Utilization to Mitigate Fines Migration in Water Flow -- 4.4.1 Approach I: Coinjection of nanoparticles and fines into porous media -- 4.4.2 Approach II: Precoat porous media with nanofluids prior to fines invasion -- 4.5 Using Nanoparticles to Control Fines Suspension in Oil and Water-Saturated Porous Systems -- 4.5.1 Nanofluid coinjection to reduce fines migration in two mobile fluids -- 4.5.2 Nanofluid preflush to control fines migration in a radial flow system saturated with two immiscible fluids -- 4.6 Combined Nanofluids with Low-Salinity Waterflooding -- 4.7 Conclusions -- Nomenclature -- References -- Appendix A: Method of Characteristics to Solve System of Quasilinear First-order Partial Differential Equations (PDEs) -- 5. Formation Damage by Inorganic Deposition -- 5.1 Introduction -- 5.2 Types of Scales in Formation Damage -- 5.2.1 Carbonate scales -- 5.2.2 Sulfate scales -- 5.2.3 Other inorganic solids -- 5.3 Processes of Scale Formation -- 5.3.1 Solubility and supersaturation -- 5.3.2 Dynamics of scale formation -- 5.3.3 Formation damage from scale deposition -- 5.3.4 Scale inhibitors -- 5.4 Management of Scaling in Development and Production -- 5.4.1 Water sampling and analysis -- 5.4.2 Options for scale prevention and remediation -- 5.4.2.1 Removal of the scaling ions before mixing occurs.
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5.4.2.2 Passive scale treatment in well completion -- 5.4.2.3 Periodic squeeze treatments -- 5.5 Summary -- References -- 6. Formation Damage by Organic Deposition -- 6.1 Introduction, Definition, Existence State of Asphaltene in Crude Oil, Molecular Structure of Asphaltene, Monitoring, an... -- 6.1.1 Introduction -- 6.1.2 Definition -- 6.1.3 Molecular structure of asphaltene -- 6.1.4 Monitoring and remediation -- 6.1.5 Experimental techniques to determine asphaltene-onset-pressure and wax-appearance-temperature -- 6.2 Asphaltene Formation Mechanisms Review: Precipitation, Aggregation and Deposition Mechanism, Solubility -- 6.2.1 Asphaltene precipitation -- 6.2.2 Solubility parameter -- 6.2.3 Asphaltene precipitation models -- 6.2.3.1 Coloidal model -- 6.2.3.2 Thermodynamic model -- 6.2.4 Asphaltene deposition -- 6.3 Issues With Asphaltene Deposition -- 6.3.1 Asphaltene issues during oil production -- 6.3.2 Formation damage and field experience -- 6.3.3 Asphaltene deposition during CO2 flooding -- 6.4 Deposition in Porous Media -- 6.4.1 Microfluidic experiments -- 6.4.1.1 Asphaltene depostion in capillary flow -- 6.4.2 Taylor Couette device studies -- 6.4.3 (Imaging) Core flood experiments -- 6.4.4 Porous media studies -- 6.5 Permeability Damage Models -- 6.5.1 Permeability reduction: effect of surface deposition and pore plugging -- 6.5.2 Plugging and nonplugging parallel pathways model -- 6.5.3 Power-law permeability reduction -- 6.5.4 Case studies: evaluation of surface deposition and pore plugging effects -- 6.5.4.1 Particle to pore size ratio -- 6.5.5 Effect of flow rate-particle entrainment -- 6.6 Conclusions -- References -- Further Reading -- 7. Formation Damage During Chemical Flooding -- 7.1 Introduction -- 7.2 Formation Damage by Polymer Flooding -- 7.2.1 The retention of polymers in the porous medium -- 7.2.1.1 Adsorption retention.
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7.2.1.1.1 Mechanism of polymer adsorption retention -- 7.2.1.1.2 Factors influencing adsorption retention -- 7.2.1.2 Mechanical trapping -- 7.2.1.3 Hydraulic retention -- 7.2.2 Incompatibility of polymer solution with formation -- 7.2.2.1 Incompatibility of polymer solution with formation fluids -- 7.2.2.1.1 Incompatibility of polymer solution with formation water -- 7.2.2.1.2 Incompatibility of polymer solution with crude oil -- 7.2.2.1.3 Incompatibility of polymer solution with formation rocks -- 7.3 Formation Damage by Surfactant/Polymer Binary Combination Flooding -- 7.3.1 Precipitation of the surfactants -- 7.3.2 Emulsification -- 7.3.3 Phase separation -- 7.4 Formation Damage by Ternary Combination Flooding -- 7.4.1 Roles of each component in ASP system -- 7.4.1.1 Roles of alkali in ASP systems -- 7.4.1.2 Role of surfactant in ASP system -- 7.4.1.3 Role of polymer in ASP system -- 7.4.2 Formation damage by ASP flooding -- 7.4.2.1 Scale formation due to alkaline -- 7.4.2.2 Scale formation due to surfactant -- 7.4.2.3 Scale formation due to polymer -- 7.4.3 Main factors affecting the scaling during ASP flooding -- 7.4.3.1 Mineral composition -- 7.4.3.2 Ionic concentration -- 7.4.3.3 Colloidal matters -- 7.4.3.4 Temperature and pressure -- 7.4.3.5 pH value -- 7.4.3.6 Flow velocity and flow state -- 7.4.4 Scaling mitigation and prevention techniques -- 7.4.4.1 Chemical techniques to prevent scaling -- 7.4.4.2 Physical techniques to prevent scaling -- 7.5 Summary and Conclusions -- References -- 8. Formation Damage Problems Associated With CO2 Flooding -- 8.1 Introduction -- 8.1.1 Review of CO2 flooding sites -- 8.1.2 Formation damage in CO2 EOR fields -- 8.2 CO2 Flooding Formation Damage Mechanisms -- 8.2.1 Overview of formation damage induced by CO2 injection -- 8.2.2 Interactions between CO2 and rock minerals -- 8.2.2.1 Dissolution.
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8.2.2.2 Precipitation.
Language:
English
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