Fundamentals of Enhanced Oil and Gas Recovery from Conventional and Unconventional Reservoirs

Cover
Front-ma_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-Conventiona
	Fundamentals of Enhanced Oil and Gas Recovery From Conventional and Unconventional Reservoirs
Copyrig_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-Conventional
	Copyright
CONTENTS
List-of-Contr_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-Conven
	List of Contributors
Chapter-One---An-Introduct_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recover
	One An Introduction to Enhanced Oil Recovery
		1.1 Overview
		1.2 Reservoir Rock Properties
		1.3 Porosity
		1.4 Saturation
		1.5 Permeability
		1.6 Wettability
		1.7 Capillary Pressure
		1.8 Relative Permeability
		1.9 Reservoir Fluid Properties
			1.9.1 Hydrocarbon Phase Behavior
			1.9.2 Classification of Reservoir Based on Reservoir Fluid
			1.9.3 Natural Gas Properties
				1.9.3.1 Apparent Molecular Weight
				1.9.3.2 Density
				1.9.3.3 Specific Gravity
			1.9.4 Compressibility Factor
			1.9.5 Gas Formation Volume Factor
			1.9.6 Gas Viscosity
			1.9.7 Crude Oil Properties
			1.9.8 Crude Oil-Specific Gravity
			1.9.9 Solution Gas Ratio
			1.9.10 Bubble Point Pressure
			1.9.11 Oil Formation Volume Factor
			1.9.12 Crude Oil Viscosity
			1.9.13 Surface Tension
		1.10 Reservoir Drive Mechanisms
			1.10.1 Rock and Liquid Expansion
			1.10.2 Solution Gas Drive
			1.10.3 Gas Cap Drive
			1.10.4 Water Drive
			1.10.5 Gravity Drainage Drive
		1.11 Mechanisms of Oil Trapping and Mobilization
			1.11.1 EOR: What, Why, and How?
			1.11.2 Different EOR Processes
			1.11.3 Gas Injection
			1.11.4 Thermal Injection
			1.11.5 Chemical Injection
			1.11.6 Screening Criteria
		1.12 Viscous, Capillary, and Gravity Forces
		1.13 Pore Scale Trapping, Mobilization of Trapped Oil
		1.14 Microscopic Displacement of Fluids in the Reservoir (ED)
			1.14.1 Macroscopic Displacement Efficiency
			1.14.2 Macroscopic Displacement Mechanism
			1.14.3 Volumetric Displacement Efficiency and Material Balance
			1.14.4 Areal and Vertical Sweep Efficiency
			1.14.5 Areal (Sweep) Displacement Efficiency
				1.14.5.1 Factors Affecting EA
			1.14.6 Vertical Displacement Efficiency
				1.14.6.1 Factors Affecting Vertical Displacement Efficiency
				1.14.6.2 Effect of Gravity Segregation on Vertical Displacement Efficiency
				1.14.6.3 Gravity Segregation in Dipping Reservoirs
				1.14.6.4 Effect of Vertical Heterogeneity and Mobility Ratio on Vertical Displacement Efficiency
				1.14.6.5 Factors That Influence Displacement Efficiency
		1.15 Mobility Ratio Control
			1.15.1 Mobility Ratio Control Processes
				1.15.1.1 Polymers Along With Water Injection
				1.15.1.2 Foam and Gas Injection
			1.15.2 Mobility Ratio Control Through EOR Process
				1.15.2.1 Chemical Injection
				1.15.2.2 Miscible Gas Injection
			1.15.3 Steam Flooding
				1.15.3.1 A Review on Enhanced Oil Recovery Methods From Reservoirs
			1.15.4 Primary Recovery
				1.15.4.1 Dissolved Gas Mechanism
				1.15.4.2 Gravity Drainage Mechanism
				1.15.4.3 Gas Cap Expansion Mechanism
				1.15.4.4 Water Flooding Mechanism
				1.15.4.5 Rock and Fluid Density Mechanism
			1.15.5 Secondary Recovery
				1.15.5.1 Miscible Gas Injection
				1.15.5.2 Hydrocarbon Injection
				1.15.5.3 Nitrogen and Generated Gases
			1.15.6 Required Condition for Miscible Injection
			1.15.7 Immiscible Gas Injection
				1.15.7.1 Gas Cap Injection
				1.15.7.2 Water Injection
		References
Chapter-Two---Screening-Crite_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Reco
	Two Screening Criteria of Enhanced Oil Recovery Methods
		2.1 Introduction
		2.2 Gas Methods
			2.2.1 CO2 Injection
			2.2.2 Hydrocarbon Gas Injection
			2.2.3 N2-Flue Gas Injection
		2.3 Chemical Methods
			2.3.1 Polymer Flooding
			2.3.2 Surfactant Flooding
			2.3.3 Alkaline Flooding
			2.3.4 Combination of Chemical Methods
				2.3.4.1 Alkaline–Polymer Flooding and Alkaline–Surfactant Flooding
				2.3.4.2 Alkaline–Surfactant–Polymer Flooding
				2.3.4.3 Surfactant–Polymer Flooding
		2.4 Thermal Methods
			2.4.1 Steam Flooding
			2.4.2 Cyclic Steam Stimulation
			2.4.3 Steam-Assisted Gravity Drainage
			2.4.4 In Situ Combustion
		References
Chapter-Three---Enhanced_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-
	Three Enhanced Oil Recovery Using CO2
		3.1 Introduction
		3.2 CO2 Injection Fundamentals
			3.2.1 Miscible Flooding
				3.2.1.1 First-Contact Miscibility
				3.2.1.2 Multiple-Contact Miscibility
					3.2.1.2.1 Liquid (Vapor) Dropout
					3.2.1.2.2 Vaporization/Condensation Gas Drive
					3.2.1.2.3 Minimum Miscibility Enrichment
				3.2.1.3 Screening Factors for Miscible Flooding
				3.2.1.4 Miscible Flooding in Actual Fields
			3.2.2 Immiscible Flooding
				3.2.2.1 CO2 Solubility in Oil
					3.2.2.1.1 Simon and Graue [37]
					3.2.2.1.2 Mulliken and Sandler [38]
					3.2.2.1.3 Mehrotra and Svrcek [39]
					3.2.2.1.4 Chung et al. [40]
					3.2.2.1.5 Emera and Sarma [41]
					3.2.2.1.6 Rostami et al. [42]
				3.2.2.2 Swelling Effects
					3.2.2.2.1 Welker [43]
					3.2.2.2.2 Simon and Graue [37]
					3.2.2.2.3 Mulliken and Sadler [38]
					3.2.2.2.4 Emera and Sarma [41]
					3.2.2.2.5 Viscosity Reduction
					3.2.2.2.6 Welker and Dunlop [43]
					3.2.2.2.7 Simon and Graue [37]
					3.2.2.2.8 Beggs and Robinson [50]
					3.2.2.2.9 Mehrotra and Svrcek [39]
					3.2.2.2.10 Chung et al. [40]
					3.2.2.2.11 Emera and Sarma [41]
					3.2.2.2.12 IFT Reduction
					3.2.2.2.13 Blowdown Effects
					3.2.2.2.14 Injectivity Increase
				3.2.2.3 Immiscible Flooding Field Cases
					3.2.2.3.1 Lick Creek Field, United States [53]
					3.2.2.3.2 Bati Raman Field, Turkey [54]
					3.2.2.3.3 Wilmington Field, United States [55]
					3.2.2.3.4 Forest-Oropouche Reserves, Trinidad [56]
		3.3 CO2 Injection Methods
			3.3.1 Injection Location
				3.3.1.1 Crestal Injection
				3.3.1.2 Pattern Injection
			3.3.2 Injection Mode
		3.4 CO2 Injection Laboratory Tests
		3.5 CO2 Injection Facilities and Process Design Considerations
			3.5.1 Surface Facilities
			3.5.2 Process Design Considerations
		3.6 CO2 Injection in Tight Reservoir
		3.7 CO2 Injection for Enhanced Gas Recovery
		3.8 Environmental Aspects of CO2 Injection
		References
Chapter-Four---Miscible-_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-
	Four Miscible Gas Injection Processes
		4.1 Enhanced Oil Recovery
		4.2 Immiscible and Miscible Processes
		4.3 Minimum Miscibility Determination
			4.3.1 Minimum Miscibility Pressure and Interfacial Tension Measurement
			4.3.2 Minimum Miscibility Pressure Correlations
				4.3.2.1 Cronquist [33]
				4.3.2.2 Lee [34]
				4.3.2.3 Yellig and Metcalfe [35]
				4.3.2.4 Orr and Jensen [36]
				4.3.2.5 Alston et al. [37]
				4.3.2.6 Impurity Correction Factor by Alston et al. [37]
				4.3.2.7 Impurity Correction Factor by Sebastian et al. [38]
			4.3.3 CO2 Flooding Properties and Design
			4.3.4 CO2 Field Case Study
				4.3.4.1 Slaughter Estate Unit CO2 Flood
				4.3.4.2 Immiscible Weeks Island Gravity Stable CO2 Flood
				4.3.4.3 Jay Little Escambia Creek Nitrogen Flood
				4.3.4.4 Overview of Field Experience
		4.4 First Contact Miscible Versus Multicontact Miscible
		4.5 Heavy Oil Recovery Using CO2
			4.5.1 Vapor ExtractionsHeavy Oil
				4.5.1.1 The Solvent Requirement for the Vapor Extractions Process
				4.5.1.2 Diffusion Coefficient for Solvent–Heavy Oil System
		4.6 Hydrocarbon: LPG, Enriched Gas, and Lean Gas
		4.7 Reservoir Screening
		4.8 Corrosion
			4.8.1 Facility and Corrosion
			4.8.2 Corrosion Control
		4.9 Design Standards and Recommended Practices
			4.9.1 Wellbore Design
			4.9.2 Cement Technology
		4.10 Water-alternating-gas Process
			4.10.1 Factors Influencing Water-Alternating-Gas
			4.10.2 WAG Ratio Optimization
		4.11 Estimating Recovery
		4.12 CO2 Properties and Required Volumes
			4.12.1 Correlation of CO2/Heavy Oil Properties
			4.12.2 Required Volume
		References
Chapter-Five---Thermal_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-fr
	Five Thermal Recovery Processes
		5.1 Introduction
		5.2 Various Thermal Enhanced Oil Recovery Processes
			5.2.1 Steam Flood and Steam-Assisted Gravity Drainage
				5.2.1.1 SAGD-Material Balance
			5.2.2 Cyclic Steam Stimulation Technique (Huff-and-Puff)
				5.2.2.1 Underlying Technology
				5.2.2.2 Reservoir Properties Changes With CSI
				5.2.2.3 CSS Aziz and Gontijo Model
				5.2.2.4 CSS−Boberg–Lantz Model [36]
			5.2.3 Fire Flood and In Situ Combustion
				5.2.3.1 Description of the Method
			5.2.4 Toe-to-Heel Air Injection
				5.2.4.1 Benefits of THAI Process
				5.2.4.2 Criteria for THAI Application
			5.2.5 THAI With Catalyst (THAI–CAPRI)
			5.2.6 Steam/Solvent-Based Hybrid Processes
				5.2.6.1 Comparison of Steam/Solvent-Based Hybrid Processes
			5.2.7 Formation Heating by Hot Fluid Injection
			5.2.8 Steam Generation
				5.2.8.1 Heater Fuel
				5.2.8.2 Steam Distribution
				5.2.8.3 Feed Water
			5.2.9 Heat Loss Rate From Distribution Lines
				5.2.9.1 Heat Transfer Through Insulation/L
				5.2.9.2 Rate of Heat Loss−Distribution Lines
				5.2.9.3 Forced Convection /L (Normal to Tube)
				5.2.9.4 Radiation Heat Loss/L
			5.2.10 Heat Loss Rate From Wellbore
				5.2.10.1 Overall Heat Transfer Coefficient
				5.2.10.2 Radiation Heat-Transfer Rate/L
				5.2.10.3 Heat Transfer-Rate Through Wellbore/L
				5.2.10.4 Natural Convection Heat-Transfer Rate
				5.2.10.5 Unit Definitions in hnc Term
			5.2.11 Reservoir Heating by Steam Injection Using Marx–Langenheim Model
				5.2.11.1 The Assumptions of Marx–Langenheim Model
				5.2.11.2 Heat Loss to O/U
			5.2.12 Steam Drive Oil Recovery Mechanism
				5.2.12.1 Steam Distillation
				5.2.12.2 Myhill and Stegemeier Model (MS Model) [75]
				5.2.12.3 MS Uniform Model Limitations
				5.2.12.4 Capture Factor and Steam-to-Oil Ratio (SOR)
				5.2.12.5 Steam-to-Oil Ratio
				5.2.12.6 Oil-Production Rate
				5.2.12.7 Oil-Production Rate From Steam Zone
		Problems
		References
Chapter-Six---Chem_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-C
	Six Chemical Flooding
		6.1 Introduction
		6.2 Chemical-Based Enhanced Oil Recovery Method
			6.2.1 Surfactant Flooding
				6.2.1.1 Type of Surfactant
					6.2.1.1.1 Nonionic Surfactant
					6.2.1.1.2 Ionic Surfactant
					6.2.1.1.3 Cationic Surfactant
					6.2.1.1.4 Zwitterionic Surfactant
				6.2.1.2 Concerns Associated With Surfactant Flooding
			6.2.2 Alkaline Flooding
			6.2.3 Polymer Flooding
			6.2.4 Alkaline–Surfactant–Polymer Flooding
				6.2.4.1 Concerns Associated With Surfactant–Polymer Flooding
			6.2.5 Application of Nanoparticles in Enhanced Oil Recovery Schemes
		References
Chapter-Seven---W_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-Co
	Seven Waterflooding
		7.1 Introduction
		7.2 Derivation of Continuity Equation for Displacement Front of Linear Displacement System
		7.3 Derivation of Continuity Equation for Displacement Front of Radial Displacement System
		7.4 Importance and Capability of Fractional Flow in Radial Flow System
		7.5 Application of Buckley–Leverett Theory and Fractional Flow Concept
		7.6 Low-Salinity Waterflooding
			7.6.1 Effect of Rock and Fluid Properties on Low-Salinity Waterflooding Performance
				7.6.1.1 Effect of Connate Water Saturation
				7.6.1.2 Effect of the Salinity of Connate Water
				7.6.1.3 Effect of Injection Water Salinity
				7.6.1.4 Effect of Wettability
			7.6.2 Mechanisms Behind Low-Salinity Waterflooding
				7.6.2.1 Fine Mobilization
				7.6.2.2 Limited Release of Mixed-Wet Particles
				7.6.2.3 Increased pH and Reduced IFT Similar to Alkaline Flooding
				7.6.2.4 Multicomponent Ion Exchange
				7.6.2.5 Double Layer Effect
				7.6.2.6 Salt-in Effect
				7.6.2.7 Osmotic Pressure
				7.6.2.8 Wettability Alteration
			7.6.3 Field Tests of Low-Salinity Waterflooding
		References
Chapter-Eight---Enhanced-Gas-Reco_2018_Fundamentals-of-Enhanced-Oil-and-Gas-
	Eight Enhanced Gas Recovery Techniques From Coalbed Methane Reservoirs
		8.1 Introduction
		8.2 Coalbed Methane Reservoir Properties
			8.2.1 Coal Rank
			8.2.2 Macerals
			8.2.3 Coal Porosity
			8.2.4 Coal Permeability
			8.2.5 Coal Density
			8.2.6 Coal Rock Mechanical Properties
		8.3 Production Profile in Coals
		8.4 Gas-Flow Mechanism in Coals
			8.4.1 Sorption
			8.4.2 Diffusion
				8.4.2.1 Unipore Model
				8.4.2.2 Bidisperse Model
				8.4.2.3 Pseudo Steady State Model
				8.4.2.4 Upscaling From Laboratory to Reservoir Scale
		8.5 Coalbed Methane Productivity and Recovery Enhancement
			8.5.1 Hydraulic Stimulation
				8.5.1.1 Hydraulic Fracturing
				8.5.1.2 Natural Fracture Stimulation
				8.5.1.3 Proppant Placement
			8.5.2 Enhanced Coalbed Methane Recovery
				8.5.2.1 The Governing Equations for Modeling ECBM
					8.5.2.1.1 Mass Continuity Equations
					8.5.2.1.2 Darcy’s Law
					8.5.2.1.3 Fick’s Law
					8.5.2.1.4 Sorption Model
					8.5.2.1.5 Equation of State
					8.5.2.1.6 Porosity Model
		References
Chapter-Nine---Enhanced-Oil-Re_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Rec
	Nine Enhanced Oil Recovery (EOR) in Shale Oil Reservoirs
		9.1 Introduction
		9.2 Shale Oil and Oil Shale
		9.3 EOR Methods in Shale Oil and Gas Reservoirs
			9.3.1 Gas Injection
				9.3.1.1 Continuous Gas Flooding
				9.3.1.2 Huff-n-Puff Gas Injection
				9.3.1.3 Advantages and Drawbacks of Gas Injection
				9.3.1.4 Field Test of Gas Injection
			9.3.2 Water Injection
				9.3.2.1 Continuous Waterflooding
				9.3.2.2 Huff-n-Puff Water Injection
				9.3.2.3 Field Test of Water Injection
		9.4 Environmental Aspects of Shale Oil and Gas Production
			9.4.1 Air Emissions
			9.4.2 Impacts to Water
			9.4.3 Impacts to Land
			9.4.4 Recommendations
		References
Chapter-Ten---Microbial-Enhanced_2018_Fundamentals-of-Enhanced-Oil-and-Gas-R
	Ten Microbial Enhanced Oil Recovery: Microbiology and Fundamentals
		10.1 Introduction
		10.2 Definition
		10.3 Recovery Efficiency
		10.4 History
		10.5 Microbial Ecology
			10.5.1 Microorganisms Based on Origin
			10.5.2 Microorganisms Based on Action
				10.5.2.1 Methanogens
				10.5.2.2 Sulfate-Reducing Bacteria (SRB)
				10.5.2.3 Fermentative Microorganisms
				10.5.2.4 Nitrate-Reducing Bacteria
				10.5.2.5 Iron-Reducing Bacteria (IRB)
			10.5.3 Microorganisms Based on Metabolic Processes
				10.5.3.1 Aerobic Microorganisms
				10.5.3.2 Anaerobic Microorganisms
		10.6 Microbe Selection for MEOR
		10.7 Nutrients
		10.8 MEOR Applying Approaches in Field
			10.8.1 Microbial Flooding
			10.8.2 Cyclic Microbial Recovery
		10.9 MEOR Methods
			10.9.1 Injection of Microbial Bioproducts
			10.9.2 Stimulation of Indigenous Microorganisms
			10.9.3 Injection and Stimulation of Exogenous Microorganisms
		10.10 Produce Biochemicals and Their Role in MEOR
			10.10.1 Biosurfactants and Bioemulsifiers
			10.10.2 Biopolymers
			10.10.3 Bioacids
			10.10.4 Biosolvents
			10.10.5 Biogases
			10.10.6 Biomass
		10.11 MEOR Mechanisms
			10.11.1 Hydrocarbon Metabolisms and Biodegradation
			10.11.2 Lowering the Entrapped Oil Viscosity
			10.11.3 Increasing the Water Viscosity
			10.11.4 Selective Plugging To Modify the Permeability Profile
			10.11.5 Dissolution of Some Parts of Reservoir Rocks
			10.11.6 Wettability Alteration
			10.11.7 Emulsification
			10.11.8 Surface and Interfacial Tension Alteration
			10.11.9 Repressurizing the Reservoir
			10.11.10 Oil Swelling
			10.11.11 Well Stimulation via Removing the Wellbore Damages
		10.12 MEOR Constraints and Screening Criteria
			10.12.1 Reservoir Engineering Considerations
			10.12.2 Considering Microbiological Principles
			10.12.3 Temperature
			10.12.4 Pressure
			10.12.5 Salinity
			10.12.6 pH
			10.12.7 Lithology
			10.12.8 Porous Media and Microorganisms’ Size
			10.12.9 Oil Gravity
			10.12.10 Depth
			10.12.11 Well Spacing
			10.12.12 Residual Oil Saturation
			10.12.13 Metals
			10.12.14 Souring Due to the Presence of Sulfate-Reducing Bacteria (SRB)
		10.13 Field Trials
		10.14 Enzyme Enhanced Oil Recovery
		10.15 Genetically-Engineered Microbial Enhanced Oil Recovery
		References
Biograp_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-Conventional
	Biography
Inde_2018_Fundamentals-of-Enhanced-Oil-and-Gas-Recovery-from-Conventional-an
	Index
Backcover