An authoritative theoretical explanation of enhanced oil recovery combined with practical, how-to instructions on the real-world implementation of EOR
In Methods for Enhanced Oil Recovery: Fundamentals and Practice, a team of distinguished researchers delivers a comprehensive and in-depth exploration of the rapidly evolving field of enhanced oil recovery (EOR). The authors dive deep into the granular details of petroleum geology, hydrocarbon classification, and oil reserve assessment, while also explaining a variety of EOR techniques, like thermal, chemical, gas injection, and microbial approaches.
The book is heavily focused on advanced methods of EOR with accompanying analyses of contemporary techniques. It includes innovative new approaches to the discipline, presenting each method with a theoretical background and practical guidelines for implementation in the field. Readers will also find specific coverage of the criteria they should use to select appropriate EOR methods for specific reservoirs and the technological processes necessary to implement these methods in operational settings.
Inside the book:
A thorough introduction to the laboratory evaluation of oil-bearing rock properties Contemporary case studies from oil fields in a variety of regions that illustrate the benefits and challenges of implementing EOR technologies Practical discussions of the economic implications of EOR methods Complete treatments of fundamental reservoir engineering concepts
Perfect for students of petroleum engineering, Methods for Enhanced Oil Recovery: Fundamentals and Practice will also benefit practicing petroleum engineers seeking a solid theoretical foundation into EOR combined with real-world, practical insights they can apply immediately.
Preface xv
Introduction xvii
1 Basic Concepts in Reservoir Engineering 1
1.1 Rocks and Their Types 1
1.1.1 The Rock Cycle 2
1.1.2 Erosion 5
1.2 Forms of Occurrence of Sedimentary Rocks 5
1.3 Hydrocarbon Reservoirs 6
1.4 Oil and Gas Traps 7
1.4.1 Structural Traps 8
1.4.2 Lithological Traps 8
1.4.3 Stratigraphic Traps 9
1.5 Rock Porosity 9
1.5.1 Primary and Secondary Porosity 9
1.5.2 Effective and Total Porosity 10
1.5.3 Diagenesis and Its Impact 10
1.5.4 Types of Porosity in Reservoir Rocks 12
1.6 Rock Permeability 14
1.6.1 Types of Permeabilities 16
1.6.2 Klinkenberg Effect 17
1.7 Geological Heterogeneity of Rocks 18
1.8 Saturations 19
1.8.1 Saturation Distribution in Reservoirs 19
1.8.2 Fluid Distribution in Reservoirs 20
1.9 Resistivity 23
1.9.1 Electrical Properties of Rocks 24
1.9.2 Basic Concepts: Ohms Law and Resistivity 24
1.9.3 Formation Resistivity Factor 25
1.9.4 Tortuosity and Porosity 26
1.9.5 Empirical Relationships and Cementation 26
1.9.6 Resistivity Index and Water Saturation 26
1.10 Capillary Pressure 27
Contents
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vi Contents
1.10.1 Capillary Pressure in Reservoirs 29
1.10.2 Laboratory Capillary Pressure Measurements 30
1.10.3 Entry Pressure 31
1.10.4 HysteresisImbibition Versus Drainage 31
1.10.5 Permeability Effects 32
1.10.6 Relative PermeabilityCapillary Pressure Relationship 33
1.11 Types of Reservoir Fluids 36
1.11.1 Black Oil 36
1.11.2 Volatile Oil 37
1.11.3 Gas Condensate 37
1.11.4 Wet Gas 37
1.11.5 Dry Gas 39
2 Fluid Flow in Porous Media 41
2.1 Introduction 41
2.2 Applications of Darcys Law 42
2.2.1 Radial Flow 42
2.2.2 Permeability of Combination Layers 43
2.2.2.1 Case I: Interbedded Reservoir Rocks 43
2.2.2.2 Case II: Composite Reservoirs 44
2.2.2.3 Radial Flow in Multiple Beds 44
2.2.3 High-velocity Flow 45
2.2.3.1 Estimating the Non-Darcy Flow Coefficient ( ) 46
2.2.4 Fracture Flow 46
2.2.4.1 Effect of Fracture Shape 48
2.2.4.2 Hydraulic Radius of a Fracture 49
2.3 Differential Equations for Fluid Flow 50
2.3.1 Real Gas Flow in Porous Media 52
2.3.2 Conservation Principle in Fluid Flow 52
2.3.2.1 Initial and Boundary Conditions 53
2.3.3 Discontinuities in Porous Media 54
2.4 Steady-state Flow 54
2.5 Basic Solutions of the Constant Terminal Rate Case for Radial
Models 55
2.5.1 Initial Condition 56
2.5.2 Boundary Conditions 56
2.5.3 Solution and Flow Regimes 56
2.5.4 The Steady-state Solution 56
2.5.4.1 Solution Using Darcys Law 58
2.5.5 Non-steady-state Flow Regimes and Dimensionless Variables 58
2.5.6 Unsteady State Solution 59
2.5.6.1 General Considerations 59
2.5.6.2 Hurst and Van Everdingen Solution 61
2.5.6.3 The Line Source Solution 63
2.5.6.3.1 Range of Application and Limitations 66
2.5.6.4 The Skin Factor 67
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Contents vii
2.5.7 Semi-steady State Solution 69
2.5.7.1 Pressure Drop from Initial Reservoir Pressure 71
2.5.7.2 Generalized Reservoir Geometry: Flowing Equation under Semi-steady
State Conditions 72
2.5.8 The Application of the CTR Solution in Well Testing 73
2.6 The Constant Terminal Pressure Solution 76
2.7 Superposition 76
2.7.1 Effects of Multiple Wells 77
2.7.2 Principle of Superposition and Approximation of Variable-rate
Pressure
Histories 78
2.7.3 Effects of Rate Changes 81
2.7.4 Simulating Boundary Effects (Image Wells) 83
2.8 Ideal Gas Flow 86
2.8.1 Streamlines, Isopotentials, and Source/Sink Representation 86
3 Classification of Hydrocarbons and Oil Reserves 89
3.1 Common Classification of Hydrocarbons 89
3.2 Classification of Oil Reserves 90
3.2.1 Possible ORF 90
3.2.2 Degree of Proof of Reserves 90
3.2.3 Current State of Production and Field Development 91
3.2.4 Energy Resource 92
3.3 Oil Recovery Factor 93
3.4 SPE/WPC/AAPG Classification of Reserves 93
3.4.1 Resource Uncertainty Categories 98
3.4.2 Risk-based Philosophy 99
3.4.3 Uncertainty-based Philosophy 99
3.4.4 Project Status Categories 100
3.4.5 Prospective Resources 101
3.5 Russian Classification of Reserves 103
3.5.1 Explored Reserves 103
3.5.2 Preliminary Estimated Reserves 104
3.5.3 Potential Resources 104
3.5.4 Forecasted Resources 105
3.5.5 Evaluation Methods 105
3.5.6 Regulatory Framework 105
3.6 The United Nations Framework Classification for Resources 105
3.6.1 Key Components of UNFC 106
3.6.1.1 E AxisEnvironmental-Socio-Economic Viability 106
3.6.1.2 F AxisTechnical Feasibility and Maturity 107
3.6.1.3 G AxisDegree of Confidence 108
3.6.2 Classes and Subclasses 108
3.6.3 Detailed Explanation of Subcategories 109
3.6.3.1 E Axis Subcategories 109
3.6.3.2 F Axis Subcategories 109
3.6.3.3 G Axis Subcategories 109
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viii Contents
4 Oil Recovery Methods 113
4.1 Introduction 113
4.2 Primary Recovery 113
4.3 Secondary Recovery 113
4.3.1 Water Injection 114
4.3.2 Gas Injection 116
4.4 Tertiary Recovery 117
4.5 Sweep Efficiency 120
5 Thermal Enhanced Oil Recovery (EOR) 123
5.1 Introduction 123
5.2 Steam Injection 123
5.2.1 Process Mechanism 124
5.2.2 Applicability Criteria 125
5.2.3 Field Implementation 126
5.2.4 Implementation Technology 128
5.3 In situ Combustion 131
5.3.1 Process Mechanism 132
5.3.1.1 Dry Forward Combustion 132
5.3.1.2 Wet Forward Combustion 133
5.3.1.3 Reverse Combustion 134
5.3.2 Applicability Criteria 135
5.3.3 Field Implementation 137
5.3.4 Implementation Technology 138
6 Gas Flooding 143
6.1 Introduction 143
6.2 Injection of Hydrocarbon Gases 145
6.2.1 Process Mechanism 146
6.2.2 Applicability Criteria 153
6.2.3 Field Implementation 154
6.2.4 Implementation Technology 155
6.3 Nitrogen Injection 157
6.3.1 Process Mechanism 158
6.3.2 Applicability Criteria 160
6.3.3 Field Implementation 161
6.3.4 Implementation Technology 163
6.4 CO2 Injection 167
6.4.1 Process Mechanism 169
6.4.2 Applicability Criteria 171
6.4.3 Field Implementation 171
6.4.4 Implementation Technology 175
6.5 WaterGas Impact on the Formation 180
6.5.1 Process Mechanism 181
6.5.2 Applicability Criteria 184
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Contents ix
6.5.3 Field Implementation 186
6.5.4 Implementation Technology 189
7 Chemical Enhanced Oil Recovery (EOR) 197
7.1 Introduction 197
7.2 Polymer Flooding 198
7.2.1 Process Mechanism 198
7.2.2 Applicability Criteria 202
7.2.3 Field Implementation 202
7.2.4 Implementation Technology 204
7.3 Micellar-polymer Flooding 205
7.3.1 Process Mechanism 205
7.3.1.1 Structure and Composition of Micellar Solutions 207
7.3.2 Applicability Criteria 210
7.3.3 Field Implementation 210
7.3.4 Implementation Technology 213
7.3.4.1 Injection Sequence, Composition, and Structure of Solutions 213
7.3.4.2 Well Placement 213
7.4 Alkaline Flooding 214
7.4.1 Process Mechanism 214
7.4.1.1 Oil Activity 214
7.4.1.2 Rock Wettability 214
7.4.1.3 Reservoir Heterogeneity 215
7.4.1.4 Effect of Salts 216
7.4.1.5 Influence of Clays 216
7.4.1.6 Carbonate Reservoirs 216
7.4.2 Applicability Criteria 217
7.4.3 Field Implementation 218
7.4.4 Implementation Technology 219
7.4.4.1 Alkaline Flooding Options 219
7.4.4.2 Preparation of an Alkaline Solution 222
7.4.4.3 Fields with High-viscosity Oils 222
7.4.4.4 Well Placement 223
8 Microbial EOR 225
8.1 Introduction 225
8.2 Introduction to Microorganisms in MEOR 225
8.2.1 Environmental Factors Affecting Microorganisms 225
8.2.1.1 Temperature 225
8.2.1.2 pH 226
8.2.1.3 Salinity 227
8.2.2 Biosurfactants 227
8.2.3 Biopolymers 231
8.2.3.1 Selective Plugging Strategies 231
8.2.4 Biofilms 233
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x Contents
8.2.4.1 Composition and Properties 234
8.2.4.2 EPS Production Influences 235
8.2.4.3 Representative Biofilm-bacterial Species 235
8.2.5 Biogenic Gases 236
8.2.6 Solvents and Acids 237
8.3 Process Mechanism of MEOR 237
8.4 Applicability Criteria 241
8.5 Field Implementations 242
8.6 Implementation Technology 243
9 Forefront EOR 245
9.1 Introduction 245
9.2 In Depth Fluid Diversion 245
9.2.1 Injection of Thermoactive Polymers 245
9.2.1.1 Process Mechanism 246
9.2.1.2 Applicability Criteria 247
9.2.1.3 Field Implementations 247
9.2.1.4 Implementation Technology 248
9.2.2 Injection of Colloidal Dispersed Gels 248
9.2.2.1 Process Mechanism 248
9.2.2.2 Applicability Criteria 249
9.2.2.3 Completed Projects 249
9.2.2.4 Implementation Technology 252
9.2.3 Injection of Preformed Particle Gels 254
9.2.3.1 Process Mechanism 254
9.2.3.2 Applicability Criteria 254
9.2.3.3 Field Implementation 255
9.2.3.4 Implementation Technology 255
9.3 Injection of Low-salinity Water 256
9.3.1 Process Mechanism 257
9.3.2 Applicability Criteria 258
9.3.3 Field Implementation 259
9.3.4 Implementation Technology 260
9.4 High Pressure Air Injection 261
9.4.1 Process Mechanism 262
9.4.2 Applicability Criteria 264
9.4.3 Field Implementation 264
9.4.4 Implementation Technology 268
9.5 Overview of Organic Oil Recovery Methods 268
10 Practical Implementation of Enhanced Oil Recovery (EOR) 281
10.1 Screening Assessment 281
10.2 Phase Behavior of Formation Fluids and Core Analysis 284
10.2.1 Study of the Phase Behavior of Formation Fluids 284
10.2.2 Core Analysis 285
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Contents xi
10.3 EOR Simulation 286
10.3.1 Geological Modeling 286
10.3.2 Hydrodynamic Modeling 291
10.3.3 Hydrodynamic Modeling of EOR 292
10.4 Implementation of EOR 294
10.5 Technology Readiness Level 297
11 Laboratory Evaluation of Oil-bearing Rock Properties 301
11.1 Introduction 301
11.2 Granulometric Composition of Rock 301
11.3 Determining the Density of Rocks 302
11.3.1 Methods of Liquid Weighing 303
11.3.2 Porosimeter Method 304
11.3.3 Geometric Method 305
11.3.4 Procedure for Determination of the Apparent Density of Rock 306
11.3.5 Procedure for Determination of True Density of Rocks by Pycnometric
Method 308
11.4 Determining the Carbonate Content of Rocks 310
11.4.1 Definition of Carbonate Content 310
11.4.2 Determination of Carbonate Content of Rocks by Gasometric Method
Using the Clark Apparatus 312
11.5 Collector Properties 315
11.5.1 Extraction of Oil-saturated Rock Samples 315
11.6 Porosity Measurements 316
11.6.1 Helium Grain Volume and Grain Density 316
11.6.1.1 Sample Preparation 316
11.6.1.2 Test Equipment 317
11.6.1.3 Test Procedures 318
11.6.1.4 Grain Volume and Grain Density Calculation 319
11.6.2 Helium Pore Volume 320
11.6.2.1 Sample Preparation 320
11.6.2.2 Test Equipment for Helium Pore Volume 320
11.6.2.3 Test Procedures for Helium Pore Volume 321
11.6.2.4 Pore Volume and Porosity Calculation 322
11.6.3 Bulk Volume 322
11.6.3.1 Sample Preparation 324
11.6.3.2 Test EquipmentMercury Pycnometer 324
11.6.3.3 Test ProceduresMercury Pycnometer 326
11.6.3.4 Test EquipmentMercury Immersion System 326
11.6.3.5 Test ProceduresMercury Immersion System 327
11.6.4 Liquid Saturation Porosity 327
11.6.4.1 Sample Preparation 328
11.6.4.2 Test Equipment 329
11.6.4.3 Test Procedures 329
11.6.4.4 Porosity Calculation 330
xii Contents
11.6.4.5 Re-saturation Porosity Quality Control Issues, Checks, and
Diagnostics 330
11.6.5 Accuracy and Repeatability of Porosity Measurements 331
11.7 Wettability and Wettability Tests 332
11.7.1 Contact Angle Method 333
11.7.1.1 Sample Preparation for Sessile Drop Method 334
11.7.1.2 Equipment Setup 334
11.7.1.3 Test Procedures 335
11.7.1.4 Results 336
11.7.1.5 Data Reporting Requirements 337
11.7.1.6 Contact Angle Summary 337
11.7.2 Amott (AmottHarvey) Method 339
11.7.2.1 Sample Preparation 340
11.7.2.2 Test Conditions 342
11.7.2.3 Test Equipment 344
11.7.2.4 Test Procedures 345
11.7.2.5 AmottHarvey Wettability Index Calculation 346
11.7.3 USBM Method 348
11.7.3.1 Sample Preparation 349
11.7.3.2 Test Equipment 349
11.7.3.3 Key Processes 349
11.7.3.4 Test Procedures 350
11.7.3.5 USBM Index Calculation 352
11.7.4 Combined AmottUSBM (Combination) Method 352
11.7.4.1 Sample Preparation 352
11.7.4.2 Test Equipment 354
11.7.4.3 Test Procedures 354
11.7.4.4 USBM and AmottHarvey Index Calculation 355
11.8 Interfacial Tension 356
11.8.1 Methods to Determine IFT 357
11.8.1.1 From Compositional Data 357
11.8.1.2 The Pendant Drop Method 357
11.8.1.3 Force Tensiometry 359
11.8.1.4 Du Noüy Ring 359
11.8.1.5 Wilhelmy Plate 360
11.9 Steady-State Permeability Measurements 361
11.9.1 Sample Preparation 361
11.9.2 Test Equipment 362
11.9.3 Test Procedures 363
11.9.4 Gas Permeability and Klinkenberg Permeability 364
11.9.5 Evaluation of Klinkenberg and Non-Darcy Effects in Steady-State
Flow 364
11.10 Unsteady-state Permeability Measurements 366
11.10.1 Test Equipment 368
11.10.2 Test Procedures and Permeability Calculation 369
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Contents xiii
11.11 Steady-State Liquid (Absolute) Permeability Measurements 371
11.11.1 Sample Preparation 371
11.11.2 Saturation Procedures 372
11.11.3 Test Procedures and Permeability Calculation 372
12 Economic Assessment of Enhanced Oil Recovery (EOR) 377
12.1 Introduction 377
12.2 Determining the Optimal Time to Start EOR 377
12.3 Technological Efficiency of EOR 378
12.4 Economic Efficiency of EOR 380
12.4.1 Sensitivity to Risks 386
12.4.2 Calculation example 387
Index 393
{| TOC-Start |}
Content
Preface
Introduction
1. Basic Concepts in Reservoir Engineering
1.1. Rocks and Their Types[ CE1]
1.2. Forms of Occurrence of Sedimentary Rocks[ CE2]
1.3. Hydrocarbon Reservoirs
1.4. Oil and Gas Traps
1.4.1. Structural Traps
1.4.2.Lithological Traps
1.4.3.Stratigraphic Traps
1.5. Rock Porosity
1.5.1 Primary and Secondary Porosity
1.5.2 Effective and Total Porosity
1.5.3 Diagenesis and Its Impact
1.5.4 Types of Porosity in Reservoir Rocks
1.6. Rock Permeability
1.6.1Types of Permeabilities
1.6.2Klinkenberg Effect
1.7. Geological Heterogeneity of Rocks
1.8.Saturations
1.8.1Saturation Distribution in Reservoirs
1.9.Resistivity
1.10.Capillary Pressure
1.10.1Entry Pressure
1.10.2HysteresisImbibition Versus Drainage
1.10.3Permeability Effects
1.10.4Relative PermeabilityCapillary Pressure Relationship
1.11.Types of Reservoir Fluids
1.11.1Black Oil
1.11.2Volatile Oil
1.11.3Gas Condensate
1.11.4Wet Gas
1.11.5Dry Gas
2. Fluid Flow in Porous Media
2.1. Applications of Darcys Law
2.1.1Radial Flow
2.1.2Permeability of Combination Layers
2.1.3High-velocity Flow
2.1.4Fracture Flow
2.2. Differential Equations for Fluid Flow
2.3. Steady-State Flow
2.4. Basic Solutions of the Constant Terminal Rate Case for Radial Models
2.4.1The Steady State Solution
2.4.2Non-steady State Flow Regimes and Dimensionless Variables
2.4.3Unsteady State Solution
2.4.3.1 General Considerations
2.4.3.2 Hurst and Van Everdingen Solution
2.4.3.3 The Line Source Solution
2.4.3.3.1 Range of Application and Limitations
2.4.3.4 The Skin Factor
2.4.4Semi-steady-state Solution
2.4.4.1 Pressure Drop from Initial Reservoir Pressure
2.4.4.2 Generalized Reservoir Geometry: Flowing Equation under Semi-steady
State Conditions
2.4.5The Application of the CTR Solution in Well Testing
2.5. The Constant Terminal Pressure Solution
2.6. Superposition
2.6.1Effects of Multiple Wells
2.6.2Principle of Superposition and Approximation of VariableRate Pressure
Histories
2.6.3Effects of Rate Changes
2.6.4Simulating Boundary Effects (Image Wells)
2.7. Ideal Gas Flow
2.7.1Streamlines, Isopotentials, and Source/Sink Representation
3. Classification of Hydrocarbons and Oil Reserves
3.1. Common Classification of Hydrocarbons
3.2. Classification of Oil Reserves
3.3. Oil Recovery Factor
3.4. SPE/WPC/AAPG Classification of Reserves
3.5. Russian Classification of Reserves
3.6. The United Nations Framework Classification for Resources (UNFC)
4. Oil Recovery Methods
4.1. Primary Recovery[ CE3]
4.2. Secondary Recovery
4.2.1. Water Injection
4.2.2. Gas Injection
4.3. Tertiary Recovery
4.4. Conformance Control
5. Thermal Enhanced Oil Recovery (EOR)
5.1. Steam Injection[ CE4]
5.1.1. Process Mechanism
5.1.2. Applicability Criteria
5.1.3. Field Implementation
5.1.4. Implementation Technology
5.2. In Situ Combustion
5.2.1. Process Mechanism
5.2.2. Applicability Criteria
5.2.3. Field Implementation
5.2.4. Implementation Technology
6. Gas Flooding
6.1. Injection of Hydrocarbon Gases[ CE5]
6.1.1. Process Mechanism
6.1.2. Applicability Criteria
6.1.3. Field Implementation
6.1.4. Implementation Technology
6.2. Nitrogen Injection
6.2.1. Process Mechanism
6.2.2. Applicability Criteria
6.2.3. Field Implementation
6.2.4. Implementation Technology
6.3. CO2 Injection
6.3.1. Process Mechanism
6.3.2. Applicability Criteria
6.3.3. Field Implementation
6.3.4. Implementation Technology
6.4. Water Alternating Gas Injection
6.4.1. Process Mechanism
6.4.2. Applicability Criteria
6.4.3. Field Implementation
6.4.4. Implementation Technology
7. Chemical Enhanced Oil Recovery (EOR)
7.1. Polymer Flooding
7.1.1. Process Mechanism
7.1.2. Applicability Criteria
7.1.3. Field implementation
7.1.4. Implementation Technology
7.2. Micellar-polymer Flooding
7.2.1. Process Mechanism
7.2.2. Applicability Criteria
7.2.3. Field Implementation
7.2.4. Implementation Technology
7.3. Alkaline Flooding
7.3.1. Process Mechanism
7.3.2. Applicability Criteria
7.3.3. Field Implementation
7.3.4. Implementation Technology
8. Microbial EOR
8.1. Introduction to Microorganisms in MEOR
8.1.1. Environmental Factors Affecting Microorganisms[ CE6]
8.1.2. Biosurfactants
8.1.3. Biopolymers
8.1.4. Biofilms
8.1.5. Biogenic Gases
8.1.6. Solvents and Acids
8.2. Process Mechanisms of MEOR
8.3. Applicability Criteria
8.4. Field Implementation
8.5. Implementation Technology
8.6. Overview of Organic Oil Recovery Methods
9. Forefront EOR
9.1. In-depth Fluid Diversion
9.1.1. Injection of Thermoactive Polymers
9.1.1.1Process Mechanism
9.1.1.2Applicability Criteria
9.1.1.3Field Implementations
9.1.1.4Implementation Technology
9.1.2. Injection of Colloidal Dispersed Gels (CDG)
9.1.2.1Process Mechanism
9.1.2.2Applicability Criteria
9.1.2.3Completed Projects
9.1.2.4Implementation Technology
9.1.3. Preformed Particle Gel (PPG) injection
9.1.3.1Process Mechanism
9.1.3.2Applicability Criteria
9.1.3.3Field Implementations
9.1.3.4Implementation Technology
9.2.Injection of Low Salinity Water
9.2.1. Process Mechanism
9.2.2. Applicability Criteria
9.2.3. Field Implementations
9.2.4. Implementation Technology
9.3. High Pressure Air Injection (HPAI)
9.3.1. Process Mechanism
9.3.2. Applicability Criteria
9.3.3. Field Implementations
9.3.4. Implementation Technology
10. Practical Implementation of Enhanced Oil Recovery (EOR)
10.1. Screening Assessment
10.2. Phase Behavior of Reservoir Fluids and Core Analysis
10.2.1 Study of the Phase Behavior of Reservoir Fluids
10.2.2. Core Analysis
10.3. EOR Simulation
10.4. Implementation of EOR
10.5. Technology Readiness Level (TRL)
11. Laboratory Evaluation of Oil-bearing Rock Properties
11.1. Granulometric Composition of Rock
11.2. Determining the Density of Rocks
11.2.1 Methods of Liquid Weighing
11.2.2 Porosimeter Method
11.2.3 Geometric Method
11.2.4 Procedure for Determination of the Apparent Density of Rock
11.2.5 Procedure for Determination of True Density of Rocks by Pycnometric
Method
11.3. Determining the Carbonate Content of Rocks
11.3.1 Definition of Carbonate Content
11.3.2 Determination of Carbonate Content of Rocks by Gasometric Method
Using the Clark Apparatus
11.4. Collector Properties
11.4.1 Extraction of Oil-saturated Rock Samples
11.5. Porosity Measurements
11.5.1. Helium Grain Volume and Grain Density
11.5.1.1Sample Preparation
11.5.1.2Test Equipment
11.5.1.3Test Procedures
11.5.1.4Grain Volume and Grain Density Calculation
11.5.2.Helium Pore Volume
11.5.2.1Sample Preparation
11.5.2.2Test Equipment for Helium Pore Volume
11.5.2.3Test Procedures for Helium Pore Volume
11.5.2.4Pore Volume and Porosity Calculation
11.5.3.Bulk Volume
11.5.3.1Sample Preparation
11.5.3.2Test EquipmentMercury Pycnometer
11.5.3.3Test ProceduresMercury Pycnometer
11.5.3.4Test EquipmentMercury Immersion System
11.5.3.5Test ProceduresMercury Immersion System
11.5.4.Liquid Saturation Porosity
11.5.4.1Sample Preparation
11.5.4.2Test Equipment
11.5.4.3Test Procedures
11.5.4.4Porosity Calculation
11.5.4.5Re-Saturation Porosity Quality Control Issues, Checks, and
Diagnostics
11.5.5.Accuracy and Repeatability of Porosity Measurements
11.6. Wettability and Wettability Tests
11.6.1.Contact Angle Method
11.6.1.1Sample Preparation for Sessile Drop Method
11.6.1.2Equipment Setup
11.6.1.3Test Procedures
11.6.1.4Results
11.6.1.5Data Reporting Requirements
11.6.1.6Contact Angle Summary
11.6.2.Amott (AmottHarvey) Method
11.6.2.1Sample Preparation
11.6.2.2Test Conditions
11.6.2.3Test Equipment
11.6.2.4Test Procedures
11.6.2.5AmottHarvey Wettability Index Calculation
11.6.3.USBM Method
11.6.3.1Sample Preparation
11.6.3.2Test Equipment
11.6.3.3Key Processes
11.6.3.4Test Procedures
11.6.3.5USBM Index Calculation
11.6.4.Combined AmottUSBM (Combination) Method
11.6.4.1Sample Preparation
11.6.4.2Test Equipment
11.6.4.3Test Procedures
11.6.4.4USBM and AmottHarvey Index Calculation
11.7.Interfacial tension
11.7.1.Methods to Determine IFT
11.7.1.1From Compositional Data
11.7.1.2The Pendant Drop Method
11.7.1.3Force Tensiometry
11.7.1.3.1 Du Noüy Ring
11.7.1.3.2 Wilhelmy Plate
11.8. Steady-State Permeability Measurements
12.8.1.Sample Preparation
12.8.2.Test Equipment
12.8.3.Test Procedures
12.8.4.Gas Permeability and Klinkenberg Permeability
12.8.5.Evaluation of Klinkenberg and Non-Darcy Effects in Steady-state Flow
11.9. Unsteady-state Permeability Measurements
12.9.1.Test Equipment
12.9.2.Test Procedures and Permeability Calculation
11.10. Steady-state Liquid (Absolute) Permeability Measurements
12.10.1.Sample Preparation
12.10.2.Saturation Procedures
12.10.3.Test Procedures and Permeability Calculation
12. Economic Assessment of Enhanced Oil Recovery (EOR)
12.1. Determining the Optimal Start Time for EOR
12.2. Technological Efficiency of EOR
12.3. Economic Efficiency of EOR
Index
{| TOC-End |}
[ CE1]COMP: Subheadings are not included.
[ CE2]COMP: 2.1 Introduction
[ CE3]COMP: 4.1 Introduction/check heading levels
[ CE4]COMP: 5.1 Introduction
[ CE5]COMP: 6.1 Introduction
[ CE6]COMP: EOR expanded in all chapters in title except 8 and 9, check
and change both in chapters 8 and 9 and TOC.
Baghir A. Suleimanov, PhD, Deputy Director of the Oil-Gas Scientific Research and Project Institute of SOCAR, Doctor of Technical Sciences, Professor, and Corresponding Member of the Azerbaijan National Academy of Sciences. He delivers lectures and supervises postgraduate and PhD students in the field of petroleum engineering. Prof. Suleimanov is the author of over 200 scientific publications, 2 monographs, 4 textbooks, and holds 118 patents. He has successfully supervised 26 PhD students and 9 Doctors of Sciences. He has been recognized in the list of the worlds top 2% most influential scientists, compiled by Stanford University.
Elchin F. Veliyev, PhD, Manager of the Laboratory of Analytical Researches at the Oil-Gas Scientific Research and Project Institute of SOCAR. Dr. Veliyev lectures and supervises postgraduate and PhD students in petroleum engineering. He is the author of 85 scientific papers, 3 monographs, and 4 textbooks, and holds 6 patents. He has been included in the list of the worlds top 2% most influential scientists, compiled by Stanford University.
