Physics of Fluid Flow and Transport in Unconventional Reservoir Rocks

Physics of Fluid Flow and Transport in Unconventional Reservoir Rocks Understanding and predicting fluid flow in hydrocarbon shale and other non-conventional reservoir rocks Oil and natural gas reservoirs found in shale and other tight and ultra-tight porous rocks have become increasingly important sources of energy in both North America and East Asia. As a result, extensive research in recent decades has focused on the mechanisms of fluid transfer within these reservoirs, which have complex pore networks at multiple scales. Continued research into these important energy sources requires detailed knowledge of the emerging theoretical and computational developments in this field. Following a multidisciplinary approach that combines engineering, geosciences and rock physics, Physics of Fluid Flow and Transport in Unconventional Reservoir Rocks provides both academic and industrial readers with a thorough grounding in this cutting-edge area of rock geology, combining an explanation of the underlying theories and models with practical applications in the field. Readers will also find: An introduction to the digital modeling of rocks Detailed treatment of digital rock physics, including decline curve analysis and non-Darcy flow Solutions for difficult-to-acquire measurements of key petrophysical characteristics such as shale wettability, effective permeability, stress sensitivity, and sweet spots Physics of Fluid Flow and Transport in Unconventional Reservoir Rocks is a fundamental resource for academic and industrial researchers in hydrocarbon exploration, fluid flow, and rock physics, as well as professionals in related fields. 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 "Shale and tight oil-gas reservoirs have been successfully explored and produced not only in the United States and North America but also in China. Henceforth, they became one of the major contributors to energy supplies. Although research on fluid flow in tight and ultra-tight porous rocks had significant progress in the past decade, there is still a long way to fully understand mechanisms and factors contributing to oil and gas transport in such reservoirs. The complexity of fluid transport in shales is because of the pore network in such media is multi-scale and composed of nano- and micro-scale pores within organic patches and inorganic matrix. Understanding factors and mechanisms affecting fluid flow in shales has numerous practical applications, particularly in oil-gas exploration and production. This volume is a valuable source for recent developments and applications of unconventional techniques to shales and mudrocks, such as novel theoretical and computational developments as applied to ultra-tight rocks, digital rock physics, single- and multi-phase flow, decline curve analysis, non-Darcy flow and its applications to unconventional reservoirs, upscaling fluid flow in shales, effects of pore structure and connectivity on transport, oil and gas recovery in unconventional reservoirs, multiscale and multiresolution modeling of shales, stress- and scale-dependences of petrophysical quantities, and measurement of flow parameters"-- Provided by publisher