Formation Damage during Improved Oil Recovery: Fundamentals and Applications

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Front-matter_2018_Formation-Damage-During-Improved-Oil-Recovery
	Formation Damage During Improved Oil Recovery
Copyright_2018_Formation-Damage-During-Improved-Oil-Recovery
	Copyright
Dedication_2018_Formation-Damage-During-Improved-Oil-Recovery
	Dedication
CONTENTS
Preface_2018_Formation-Damage-During-Improved-Oil-Recovery
	Preface
List-of-Contributors_2018_Formation-Damage-During-Improved-Oil-Recovery
	List of Contributors
Chapter-One---Overview-of-Formation-Damage-Dur_2018_Formation-Damage-During-
	One 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
Chapter-Two---Low-Salinity-Water-Flooding--F_2018_Formation-Damage-During-Im
	Two 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
		2.12 Conclusions
		Nomenclature
		References
Chapter-Three---Formation-Damage-by-Fines-Migrati_2018_Formation-Damage-Duri
	Three 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
			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
Chapter-Four---Using-Nanofluids-to-Control-F_2018_Formation-Damage-During-Im
	Four 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)
Chapter-Five---Formation-Damage-by-Inor_2018_Formation-Damage-During-Improve
	Five 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
				5.4.2.2 Passive scale treatment in well completion
				5.4.2.3 Periodic squeeze treatments
		5.5 Summary
		References
Chapter-Six---Formation-Damage-by-Orga_2018_Formation-Damage-During-Improved
	Six 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
Chapter-Seven---Formation-Damage-During-_2018_Formation-Damage-During-Improv
	Seven 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
					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
Chapter-Eight---Formation-Damage-Problems-A_2018_Formation-Damage-During-Imp
	Eight 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
				8.2.2.2 Precipitation
				8.2.2.3 Geochemistry of mineral reactions and illustrations of impact at the mineral grain scale
			8.2.3 Interactions between CO2 and crude Oil
				8.2.3.1 The nature of CO2-induced asphaltene precipitation
				8.2.3.2 Onset conditions of CO2-induced organic precipitation
			8.2.4 Wettability alterations
			8.2.5 Effect of asphaltene precipitation on oil recovery
		8.3 CO2 Flooding Formation Damage Monitoring, Prevention, and Remediation
			8.3.1 Monitoring and identification
			8.3.2 Prevention and remediation
				8.3.2.1 Chemical treatments
					8.3.2.1.1 Asphaltene inhibitors/dispersants
					8.3.2.1.2 Solvents
				8.3.2.2 Mechanical and physical remediation
			8.3.3 Field case studies
		8.4 Summary and Conclusions
		References
Chapter-Nine---Formation-Damage-by-Thermal-Met_2018_Formation-Damage-During-
	Nine Formation Damage by Thermal Methods Applied to Heavy Oil Reservoirs
		9.1 Mechanisms of Thermally Enhanced Oil Recovery Methods
			9.1.1 Cyclic steam stimulation
			9.1.2 Steam flooding
			9.1.3 Steam assisted gravity drainage
			9.1.4 In situ combustion
		9.2 Formation Damage by Thermal Methods
			9.2.1 Sands and fines migration
			9.2.2 Clay swelling and mineral transformations
			9.2.3 Minerals dissolution and precipitation
			9.2.4 Wettability alteration and change
			9.2.5 Deposition
			9.2.6 Emulsions and foams
			9.2.7 Dilatation and compaction
		9.3 Discussion
		9.4 Conclusions
		References
Chapter-Ten---A-Special-Focus-on-Formation-Damag_2018_Formation-Damage-Durin
	Ten A Special Focus on Formation Damage in Unconventional Reservoirs: Dynamic Production
		10.1 Introduction
			10.1.1 Damage mechanisms in shale reservoir
		10.2 Fracture Damage
			10.2.1 Proppant transport and placement
			10.2.2 Proppant embedment
			10.2.3 Proppant crushing
			10.2.4 Fines migration and plugging
			10.2.5 Gelling damage
			10.2.6 Multiphase and non-Darcy inertial flow
		10.3 Reservoir Formation Damage
			10.3.1 Intrinsic permeability—kozeny-carmen equation
			10.3.2 Power–law permeability equation
			10.3.3 Permeability as function of coordination number
			10.3.4 Intrinsic permeability reduction by effective stress
				10.3.4.1 Empirical models
				10.3.4.2 Effect of pore compressibility and connectivity loss
		10.4 Fluid Damage
			10.4.1 Clay swelling
			10.4.2 Water phase trapping and blockage
		10.5 Summary
		Nomenclature
		References
		Further Reading
Chapter-Eleven---A-Special-Focus-on-Formation-D_2018_Formation-Damage-During
	Eleven A Special Focus on Formation Damage in Offshore and Deepwater Reservoirs
		11.1 Introduction
		11.2 Pressure and Temperature of Deepwater Reservoirs
		11.3 Complex Well Structure With Intelligent Well Completion
		11.4 Frac-and-Pack Completion
		11.5 Formation Damage Due to Reservoir Compaction
		11.6 Deepwater Surveillance
		11.7 Summary of Deepwater Development
		Nomenclatures
		References
Chapter-Twelve---Formation-Damage-Challenge_2018_Formation-Damage-During-Imp
	Twelve Formation Damage Challenges in Geothermal Reservoirs
		12.1 Introduction
		12.2 Physics of Particle Mobilization and Straining in Porous Media
		12.3 Laboratory Study on Fines Migration in Geothermal Fields
			12.3.1 Materials
			12.3.2 Experimental setup
			12.3.3 Experimental procedures
			12.3.4 Electrostatic particle–rock interaction analysis
				12.3.4.1 Effect of fluid ionic strength on rock permeability
				12.3.4.2 SEM-EDX analyses for released fines
				12.3.4.3 DLVO interaction between the particles and pore matrix
		12.4 Analytical Modeling of Fines Migration in Laboratory Coreflooding
			12.4.1 Model assumptions
			12.4.2 System of governing equations
			12.4.3 Analytical solution
		12.5 History Matching of the Laboratory Coreflood Test Results
		12.6 Mathematical Model for Fines Migration During Flow Toward Well
			12.6.1 System of equations
			12.6.2 Analytical model
		12.7 Field Application
		12.8 Conclusions
		Nomenclature
			Greek letters
			Super/Subscripts
		References
Chapter-Thirteen---Formation-Damage-in-Co_2018_Formation-Damage-During-Impro
	Thirteen Formation Damage in Coalbed Methane Recovery
		13.1 Introduction
		13.2 Formation Damage in Coalbed Methane Reservoirs
			13.2.1 Drilling-related formation damage
			13.2.2 Formation damage associated with hydraulic fracturing
			13.2.3 Changes in coal matrix
			13.2.4 Production-related reservoir failure
			13.2.5 Diagnosis of formation damage and evaluation of damage potential
		13.3 Summary and Conclusions
		References
		Further Reading
Chapter-Fourteen---Special-Focus-on-Produced-Water-_2018_Formation-Damage-Du
	Fourteen Special Focus on Produced Water in Oil and Gas Fields: Origin, Management, and Reinjection Practice
		14.1 Origin, Characteristic, and Production of Produced Water
			14.1.1 Origin of produced water
			14.1.2 Characteristics of produced water
				14.1.2.1 Major compounds of produced water
				14.1.2.2 Compounds contained in produced water from conventional oil fields
				14.1.2.3 Compounds contained in produced water from conventional gas fields
				14.1.2.4 Compounds contained in produced water from coalbed methane fields
				14.1.2.5 Compounds contained in produced water from shale/tight gas fields
			14.1.3 Produced water volume and affecting factors
				14.1.3.1 Typical features of the produced water volume for different types of reservoirs
				14.1.3.2 Factors affecting produced water volume
				14.1.3.3 Produced water volume from onshore, offshore, and unconventional oil fields
		14.2 Produced Water Management Methods and Techniques
			14.2.1 Produced water management methods
				14.2.1.1 Produced water minimization
				14.2.1.2 Produced water recycling and reuse
				14.2.1.3 Produced water disposal
			14.2.2 Legal framework, policy, and regulations
			14.2.3 Produced water treatment technologies
				14.2.3.1 Adsorption technology
				14.2.3.2 Chemical oxidation technology
				14.2.3.3 Chemical precipitation technology
				14.2.3.4 Electrodialysis and electrodialysis reversal technology
				14.2.3.5 Evaporation technology
				14.2.3.6 Gas flotation technology
				14.2.3.7 Hydrocyclone technology
				14.2.3.8 Ion exchange technology
				14.2.3.9 Media filtration technology
				14.2.3.10 Membrane filtration technologies
				14.2.3.11 Thermal technologies
				14.2.3.12 Produced water treatments cost
		14.3 Formation Damage by PWRI
			14.3.1 Formation damage mechanisms
			14.3.2 Mathematical model for quantification of formation damage
				14.3.2.1 Injectivity ratio and flow resistance in different damage zones
				14.3.2.2 Internal filtration model
				14.3.2.3 Transition time model
				14.3.2.4 External cake filtration model
				14.3.2.5 Other PWRI mathematical models
			14.3.3 Type curves for water injectivity test
			14.3.4 Case studies
		14.4 Summary and conclusion
		References
		Further Reading
Chapter-Fifteen---Integrated-Risks-Assessment-and_2018_Formation-Damage-Duri
	Fifteen Integrated Risks Assessment and Management of IOR/EOR Projects: A Formation Damage View
		15.1 Introduction
		15.2 Identification and Recognition of Formation Damage Risks in IOR Projects
			15.2.1 Low-salinity waterflooding risks
			15.2.2 Timing of fines migration
			15.2.3 CO2 injection—EOR/sequestration formation damage risks
			15.2.4 Formation damage associated with waterflooding and produced water blockage
			15.2.5 Formation damage induced during well stimulation and hydraulic fracturing
			15.2.6 Formation damage associated with alkali–surfactant–polymer flooding
			15.2.7 Geomechanical and reservoir stress-sensitivity impacts on formation damage
			15.2.8 Geochemical reactions leading to salt precipitation and related formation damage
			15.2.9 The potential for nanofluids to mitigate certain types of formation damage
			15.2.10 Thermal formation damage related to steam injection of heavy oil reservoirs
			15.2.11 Formation damage associated with microbial activity in the reservoir
		15.3 Semiquantitative and Quantitative Risk and Opportunity Assessment
		15.4 A Structured Approach to Risk/Opportunity Assessment
		15.5 Quantitative Risk/Opportunity Assessment
		15.6 Conclusions
		References
Index_2018_Formation-Damage-During-Improved-Oil-Recovery
	Index
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