دانلود کتاب Physics of Fluid Flow and Transport in Unconventional Reservoir Rocks

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Cover
Title Page
Copyright Page
Contents
List of Contributors
Preface
Introduction
Chapter 1 Unconventional Reservoirs: Advances and Challenges
1.1 Background
1.2 Advances
1.2.1 Wettability
1.2.2 Permeability
1.3 Challenges
1.3.1 Multiscale Systems
1.3.2 Hydrocarbon Production
1.3.3 Recovery Factor
1.3.4 Unproductive Wells
1.4 Concluding Remarks
References
Part I Pore-Scale Characterizations
Chapter 2 Pore-Scale Simulations and Digital Rock Physics
2.1 Introduction
2.2 Physics of Pore-Scale Fluid Flow in Unconventional Rocks
2.2.1 Physics of Gas Flow
2.2.1.1 Gas Slippage and Knudsen Layer Effect
2.2.1.2 Gas Adsorption/Desorption and Surface Diffusion
2.2.2 Physics of Water Flow
2.2.3 Physics of Condensation
2.3 Theory of Pore-Scale Simulation Methods
2.3.1 The Isothermal Single-Phase Lattice Boltzmann Method
2.3.1.1 Bhatnagar–Gross–Krook (BGK) Collision Operator
2.3.1.2 The Multi-Relaxation Time (MRT)-LB Scheme
2.3.1.3 The Regularization Procedure
2.3.2 Multi-phase Lattice Boltzmann Simulation Method
2.3.2.1 Color-Gradient Model
2.3.2.2 Shan-Chen Model
2.3.3 Capture Fluid Slippage at the Solid Boundary
2.3.4 Capture the Knudsen Layer/Effective Viscosity
2.3.5 Capture the Adsorption/Desorption and Surface Diffusion Effects
2.3.5.1 Modeling of Adsorption in LBM
2.3.5.2 Modeling of Surface Diffusion Via LBM
2.4 Applications
2.4.1 Simulation of Gas Flow in Unconventional Reservoir Rocks
2.4.1.1 Gas Slippage
2.4.1.2 Gas Adsorption
2.4.1.3 Surface Diffusion of Adsorbed Gas
2.4.2 Simulation of Water Flow in Unconventional Reservoir Rocks
2.4.3 Simulation of Immiscible Two-Phase Flow
2.4.4 Simulation of Vapor Condensation
2.4.4.1 Model Validations
2.4.4.2 Vapor Condensation in Two Adjacent Nano-Pores
2.5 Conclusion
References
Chapter 3 Digital Rock Modeling: A Review
3.1 Introduction
3.2 Single-Scale Modeling of Digital Rocks
3.2.1 Experimental Techniques
3.2.1.1 Imaging Technique of Serial Sectioning
3.2.1.2 Laser Scanning Confocal Microscopy
3.2.1.3 X-Ray Computed Tomography Scanning
3.2.2 Computational Methods
3.2.2.1 Simulated Annealing
3.2.2.2 Markov Chain Monte Carlo
3.2.2.3 Sequential Indicator Simulation
3.2.2.4 Multiple-Point Statistics
3.2.2.5 Machine Learning
3.2.2.6 Process-Based Modeling
3.3 Multiscale Modeling of Digital Rocks
3.3.1 Multiscale Imaging Techniques
3.3.2 Computational Methods
3.3.2.1 Image Superposition
3.3.2.2 Pore-Network Integration
3.3.2.3 Image Resolution Enhancement
3.3.2.4 Object-Based Reconstruction
3.4 Conclusions and Future Perspectives
Acknowledgments
References
Chapter 4 Scale Dependence of Permeability and Formation Factor: A Simple Scaling Law
4.1 Introduction
4.2 Theory
4.2.1 Funnel Defect Approach
4.2.2 Application to Porous Media
4.3 Pore-network Simulations
4.4 Results and Discussion
4.5 Limitations
4.6 Conclusion
Acknowledgment
References
Part II Core-Scale Heterogeneity
Chapter 5 Modeling Gas Permeability in Unconventional Reservoir Rocks
5.1 Introduction
5.1.1 Theoretical Models
5.1.2 Pore-Network Models
5.1.3 Gas Transport Mechanisms
5.1.4 Objectives
5.2 Effective-Medium Theory
5.3 Single-Phase Gas Permeability
5.3.1 Gas Permeability in a Cylindrical Tube
5.3.2 Pore Pressure-Dependent Gas Permeability in Tight Rocks
5.3.3 Comparison with Experiments
5.3.4 Comparison with Pore-Network Simulations
5.3.5 Comparaison with Lattice-Boltzmann Simulations
5.4 Gas Relative Permeability
5.4.1 Hydraulic Flow in a Cylindrical Pore
5.4.2 Molecular Flow in a Cylindrical Pore
5.4.3 Total Gas Flow in a Cylindrical Pore
5.4.4 Gas Relative Permeability in Tight Rocks
5.4.5 Comparison with Experiments
5.4.6 Comparison with Pore-Network Simulations
5.5 Conclusions
Acknowledgment
References
Chapter 6 NMR and Its Applications in Tight Unconventional Reservoir Rocks
6.1 Introduction
6.2 Basic NMR Physics
6.2.1 Nuclear Spin
6.2.2 Nuclear Zeeman Splitting and NMR
6.2.3 Nuclear Magnetization
6.2.4 Bloch „Equations’and NMR Relaxation
6.2.5 Simple NMR Experiments: Free Induction Decay and CPMG Echoes
6.2.6 NMR Relaxation of a Pure Fluid in a Rock Pore
6.2.7 Measured NMR CPMG Echoes in a Formation Rock
6.2.8 Inversion
6.2.8.1 Regularized Linear Least Squares
6.2.8.2 Constrains of the Resulted NMR Spectrum in Inversion
6.2.9 Data from NMR Measurement
6.3 NMR Logging for Unconventional Source Rock Reservoirs
6.3.1 Brief Introduction of Unconventional Source Rocks
6.3.2 NMR Measurement of Source Rocks
6.3.2.1 NMR Log of a Source Rock Reservoir
6.3.3 Pore Size Distribution in a Shale Gas Reservoir
6.4 NMR Measurement of Long Whole Core
6.4.1 Issues of NMR Instrument for Long Sample
6.4.2 HSR-NMR of Long Core
6.4.3 Application Example
6.5 NMR Measurement on Drill Cuttings
6.5.1 Measurement Method
6.5.1.1 Preparation of Drill Cuttings
6.5.1.2 Measurements
6.5.2 Results
6.6 Conclusions
References
Chapter 7 Tight Rock Permeability Measurement in Laboratory: Some Recent Progress
7.1 Introduction
7.2 Commonly Used Laboratory Methods
7.2.1 Steady-State Flow Method
7.2.2 Pressure Pulse-Decay Method
7.2.3 Gas Research Institute Method
7.3 Simultaneous Measurement of Fracture and Matrix Permeabilities from Fractured Core Samples
7.3.1 Estimation of Fracture and Matrix Permeability from PPD Data for’Two’Flow’Regimes
7.3.2 Mathematical Model
7.3.3 Method Validation and Discussion
7.4 Direct Measurement of Permeability-Pore Pressure Function
7.4.1 Knudsen Diffusion, Slippage Flow, and Effective Gas Permeability
7.4.2 Methodology for Directly Measuring Permeability-Pore Pressure Function
7.4.3 Experiments
7.5 Summary and Conclusions
References
Chapter 8 Stress-Dependent Matrix Permeability in Unconventional Reservoir Rocks
8.1 Introduction
8.2 Sample Descriptions
8.3 Permeability Test Program
8.4 Permeability Behavior with Confining Stress Cycling
8.5 Matrix Permeability Behavior
8.6 Concluding Remarks
Acknowledgments
References
Chapter 9 Assessment of Shale Wettability from Spontaneous Imbibition Experiments
9.1 Introduction
9.2 Spontaneous Imbibition Theory
9.3 Samples and Analytical Methods
9.3.1 SI Experiments
9.3.2 Barnett Shale from United States
9.3.3 Silurian Longmaxi Formation and Triassic Yanchang Formation Shales from China
9.3.4 Jurassic Ziliujing Formation Shale from China
9.4 Results and Discussion
9.4.1 Complicated Wettability of Barnett Shale Inferred Qualitatively from SI Experiments
9.4.1.1 Wettability of Barnett Shale
9.4.1.2 Properties of Barnett Samples and Their Correlation to Wettability
9.4.1.3 Low Pore Connectivity to Water of Barnett Samples
9.4.2 More Oil-Wet Longmaxi Formation Shale and More Water-Wet Yanchang Formation Shale
9.4.2.1 TOC and Mineralogy
9.4.2.2 Pore Structure Difference Between Longmaxi and Yanchang Samples
9.4.2.3 Water and Oil Imbibition Experiments
9.4.2.4 Wettability of Longmaxi and Yanchang Shale Samples Deduced from SI Experiments
9.4.3 Complicated Wettability of Ziliujing Formation Shale
9.4.3.1 TOC and Mineralogy
9.4.3.2 Pore Structure
9.4.3.3 Water and Oil Imbibition Experiments
9.4.3.4 Wettability of Ziliujing Formation Shale Indicated from SI Experiments and its Correlation to Shale Pore Structure and Composition
9.4.4 Shale Wettability Evolution Model
9.5 Conclusions
Acknowledgments
References
Chapter 10 Permeability Enhancement in Shale Induced by Desorption
10.1 Introduction
10.1.1 Shale Mineralogical Characteristics
10.1.2 Flow Network
10.1.2.1 Bedding-Parallel Flow Network
10.1.2.2 Bedding-Perpendicular Flow Paths
10.2 Adsorption in Shales
10.2.1 Langmuir Theory
10.2.2 Competing Strains in Permeability Evolution
10.2.2.1 Poro-Sorptive Strain
10.2.2.2 Thermal-Sorptive Strain
10.3 Permeability Models for Sorptive Media
10.3.1 Strain Based Models
10.4 Competing Processes during Permeability Evolution
10.4.1 Resolving Competing Strains
10.4.2 Solving for Sorption-Induced Permeability Evolution
10.5 Desorption Processes Yielding Permeability Enhancement
10.5.1 Pressure Depletion
10.5.2 Lowering Partial Pressure
10.5.3 Sorptive Gas Injection
10.5.4 Desorption with Increased Temperature
10.6 Permeability Enhancement Due to Nitrogen Flooding
10.7 Discussion
10.8 Conclusion
References
Chapter 11 Multiscale Experimental Study on Interactions Between Imbibed Stimulation Fluids and Tight Carbonate Source Rocks
11.1 Introduction
11.2 Fluid Uptake Pathways
11.2.1 Experimental Methods
11.2.1.1 Materials
11.2.1.1.1 Rock Sample
11.2.1.2 Experimental Procedure
11.2.1.2.1 3D Microscale Visualization of Thin-Section Rock Sample in As-Received State
11.2.1.2.2 Dynamic Study of Spontaneous Imbibition Test
11.2.2 Results and Discussion
11.2.2.1 Surface Characterization
11.2.2.2 Spontaneous Imbibition Tests
11.3 Mechanical Property Change After Fluid Exposure
11.3.1 Experimental Methods
11.3.1.1 Materials
11.3.1.1.1 Rock Sample
11.3.1.1.2 Treatment Fluids for Cylindrical Core Plugs
11.3.1.2 Experimental Procedure
11.3.1.2.1 UCS and Brazilian Tensile Strength Test
11.3.1.2.2 Fluid Treatment for Cylindrical Core Plugs
11.3.1.2.3 Microindentation Testing and Its Mapping Procedure
11.3.2 Results and Discussion
11.3.2.1 UCS and Brazilian Test on Cylindrical Core Plugs
11.3.2.2 Microindentation Test
11.4 Morphology and Minerology Changes After Fluid Exposure
11.4.1 Experimental Methods
11.4.1.1 Materials
11.4.1.1.1 Rock Samples
11.4.1.1.2 Treatment Fluids
11.4.1.2 Experimental Procedure
11.4.1.2.1 Surface Characterization using SEM Coupled with EDS
11.4.1.2.2 Fluid Treatment
11.4.1.2.3 Quantification of Dissolved Ions in the Treatment Fluids
11.4.2 Results and Discussion
11.4.2.1 SEM and EDS Mapping of Thin-Section Surface before Fluid Treatment
11.4.2.1.1 Morphology Characterization
11.4.2.1.2 Mineral Identification
11.4.2.2 SEM and EDS Mapping of Thin-Section Surface after Fluid Treatment
11.4.2.2.1 Treatment with Fluid 4 (2 wt% KCl)
11.4.2.2.2 Treatment with Fluid 5 (0.015 wt% Friction Reducer)
11.4.2.2.3 Treatment with Fluid 6 „(Synthetic Seawater)
11.4.2.3 Quantification of Dissolved Ions in the Treatment Fluids
11.5 Flow Property Change After Fluid Exposure
11.5.1 Experimental Methods
11.5.1.1 Materials
11.5.1.1.1 Rock Sample
11.5.1.1.2 Treatment Fluids
11.5.1.2 Experimental Procedure
11.5.1.2.1 Fluid Treatment and Flow Characteristics Assessment for Core Plugs
11.5.2 Results and Discussion
11.5.2.1 Changes in Flow Characteristics
11.6 Conclusions
References
Part III Large-Scale Petrophysics
Chapter 12 Effective Permeability in Fractured Reservoirs
12.1 Introduction
12.1.1 Percolation Theory
12.1.2 Effective-Medium Theory
12.2 Objectives
12.3 Percolation-Based Effective-Medium Theory
12.4 Comparison with Simulations
12.4.1 Chen et al. (2019)
12.4.1.1 Two-Dimensional Simulations
12.4.1.2 Three-Dimensional Simulations
12.4.2 New Three-Dimensional Simulations
12.5 Conclusion
Acknowledgment
References
Chapter 13 Modeling of Fluid Flow in Complex Fracture Networks for Shale Reservoirs
13.1 Shale Reservoirs with Complex Fracture Networks
13.2 Complex Fracture Reservoir Simulation
13.3 Embedded Discrete Fracture Model
13.4 EDFM Verification
13.5 Well Performance Study – Base Case
13.6 Effect of Natural Fracture Connectivity on Well Performance
13.6.1 Effect of Natural Fracture Azimuth
13.6.2 Effect of Number of Natural Fractures
13.6.3 Effect of Natural Fracture Length
13.6.4 Effect of Number of Sets of Natural Fractures
13.6.5 Effect of Natural Fracture Dip Angle
13.7 Effect of Natural Fracture Conductivity on Well Performance
13.8 Conclusions
References
Chapter 14 A Closed-Form Relationship for Production Rate in Stress-Sensitive Unconventional Reservoirs
14.1 Introduction
14.2 Production Rate as a Function of Time in the Linear Flow Regime Under the Constant Pressure Drawdown Condition
14.3 An Approximate Relationship Between Parameter A and Stress-.Dependent Permeability
14.4 Evaluation of the Relationship Between Parameter A and Stress-Dependent Permeability
14.5 Equivalent State Approximation for the Variable Pressure Drawdown Conditions
14.6 Discussions
14.7 Concluding Remarks
Nomenclature
Subscript
Appendix 14.A Derivation of Eq. (14.22) with Integration by Parts
References
Chapter 15 Sweet Spot Identification in Unconventional Shale Reservoirs
15.1 Introduction
15.2 Reservoir Characterization
15.3 Sweet Spot Identification
15.3.1 The Method Based on Organic, Rock and Mechanical Qualities
15.3.2 Methods Based on Geological and Engineering Sweet Spots
15.3.3 Methods Based on Other Quality Indicators
15.3.4 Methods Based on Data Mining and Machine Learning
15.4 Discussion
15.5 Conclusion
References
Index
EULA