Details

Multiphase Transport of Hydrocarbons in Pipes

1. Aufl.

von: Juan J. Manzano-Ruiz, Jose G. Carballo
123,99 €
Verlag:	Wiley
Format:	EPUB
Veröffentl.:	26.03.2024
ISBN/EAN:	9781119888536
Sprache:	englisch
Anzahl Seiten:	352

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Titelbeschreibung

Multiphase Transport of Hydrocarbons in Pipes An introduction to multiphase flows in the oil and gas industry The term ‘multiphase flow’ refers to the concurrent flow of oil and/or gas, alongside other substances or materials such as production water, chemical inhibitors, and solids (e.g. sand). This is a critical topic in the oil and gas industry, where the presence of multiple flow phases in pipelines affects deliverability, generates serious complications in predicting flow performance for system design and operation, and requires specific risk mitigation actions and continuous maintenance. Chemical and Mechanical Engineers interested in working in this industry will benefit from understanding the basic theories and practices required to model and operate multiphase flows through pipelines, wells, and other components of the production system. Multiphase Transport of Hydrocarbons in Pipes meets this need with a comprehensive overview of five decades of research into multiphase flow. Incorporating fundamental theories, historic and cutting-edge multiphase flow models, and concrete examples of current and future applications. This book provides a sound technical background for prospective or working engineers in need of understanding this crucial area of industry. Readers will also find: <ul><li> Fundamental principles supporting commercial software</li> <li> Detailed tools for estimating multiphase flow rates through flowlines, wells, and more</li> <li> Integration of conservation principles with thermodynamic and transport properties</li> <li> Coverage of legacy and modern simulation models </li></ul> This book is ideal for flow assurance engineers, facilities engineers, oil and gas production engineers, and process engineers, as well as chemical and mechanical engineering students looking to work in any of these roles.

Inhaltsverzeichnis

Preface xv About the Authors xvii Acknowledgments xix Nomenclature xxi About the Companion Website xxix 1 Introduction 1 1.1 What Is Multiphase Flow 1 1.2 Single- and Multicomponent Fluids 3 1.3 Challenges to Model Multiphase Flow 4 1.3.1 Experiments and Scale-up 4 1.3.2 Multidimensional Fluid Flows 5 1.3.3 Time Fluctuations 6 1.3.4 Slow Transients 6 1.3.5 Compositional Simulation 7 1.4 Hydrocarbon Flow 7 1.5 Modeling Approaches 8 References 9 2 Fundamentals of Multiphase Flow 11 2.1 Multiphase Flow in the Production of Oil and Gas 11 2.2 Multiphase Flow Concepts 15 2.2.1 Void Fraction and Hold-up 15 2.2.2 Phase Velocity, Slip Factor, and Volumetric Flow 16 2.2.3 Volumetric Flux and Superficial Velocities 17 2.2.4 Density 18 2.2.5 Mass Flows 18 2.2.6 Mass Velocity 19 2.2.7 Mass Quality and Volumetric Quality 19 2.2.8 Drift Velocities and Drift Fluxes 19 2.3 Modeling Strategy 20 2.3.1 Area Averaging and One-dimensional Flow 20 2.3.2 Pseudo-steady Flow 20 2.3.3 Time Averaging of Turbulent Fluctuations 21 2.3.4 Mechanistic Approach 21 2.3.5 Boundary and Initial Conditions 21 2.3.6 Boundary-value and Marching-scheme Strategies 22 2.3.7 Closure Equations 23 2.4 Two-Phase Flow Measurements 23 2.4.1 Well Testing and Production Allocation 23 2.4.2 Multiphase Flow Meter (MPFM) and Field Application 24 2.4.3 Density Meters 27 2.4.4 Void Fraction Meters 28 2.4.5 Momentum Flux Meters 28 2.4.6 Flow Pattern Identification 28 2.4.7 Uncertainty in Multiphase Flow Measurement 29 2.5 Future Measuring Trends 30 References 31 3 Hydrocarbon Fluid Properties and Thermodynamics 33 3.1 Phase Behavior 33 3.1.1 Empirical Data 33 3.1.2 Pure Compound Phase Behavior 35 3.1.3 Binary Systems 36 3.1.4 Multicomponent Fluid Phase Behavior 36 3.2 Physical Properties 39 3.2.1 Gas Compressibility Factor 39 3.2.2 Gas and Oil Density 41 3.2.3 Gas, Oil, and Water Viscosity 43 3.2.4 Solution Gas Ratio (R s) 44 3.2.5 Bubble Point 45 3.2.6 Oil Formation Volume Factor (B o) 46 3.2.7 Gas Formation Volume Factor (B g) 47 3.3 Equation of State (EOS) 47 3.3.1 Ideal Gas 48 3.3.2 Van der Waals 49 3.3.3 Benedict–Webb–Rubin 49 3.3.4 Redlich–Kwong 50 3.3.5 Peng–Robinson 50 3.3.6 Other Equations of State 51 3.3.7 Equilibrium and Fugacity Coefficient 51 3.3.8 Mixing Rules 52 3.4 C7+ characterization 53 3.5 Thermal and Transport Properties 54 3.5.1 Enthalpy 54 3.5.2 Heat Capacity 55 3.5.3 Joule–Thomson Coefficient 56 3.5.4 Speed of Sound 56 3.5.5 Thermal Conductivity 57 3.5.6 Surface Tension 57 3.6 Types of Hydrocarbon Fluids 57 3.6.1 Black Oils 57 3.6.2 Volatile Oils 58 3.6.3 Retrograde Gas Condensate 59 3.6.4 Wet Gas 59 3.6.5 Dry Gas 61 3.7 PVT Analyses 61 3.7.1 Constant Composition Expansion (CCE) 62 3.7.2 Constant Volume Depletion (CVD) 62 3.7.3 Differential Liberation (DL) 63 3.7.4 Separator Test 64 3.7.5 Viscosities 64 3.8 Strategy for Modeling Fluid Properties 65 3.8.1 Compositional versus Tabular 65 3.8.2 EOS or Black Oil Models 66 3.8.3 Blending of Different Streams 66 3.9 Commercial Software 67 References 67 4 Multiphase Flow Patterns 69 4.1 Gas–Liquid Flow 69 4.2 Dispersed versus Separated Flow Regimes 70 4.3 Vertical and Inclined Flow Maps 71 4.4 Quasi-Horizontal Flow Maps 72 4.5 Liquid–Liquid Flow Map 77 4.6 Three-Phase Flow 78 4.7 Liquid–Solid Flow 79 4.8 Gas–Solid Flow 81 4.9 Conclusions 82 References 82 5 Two-Phase Flow in Pipelines 85 5.1 Introduction 85 5.2 Conservation Principles 85 5.2.1 Local Instantaneous Equations 86 5.3 Space-Averaged Equations 89 5.4 Time-Averaged Equations 91 5.5 Composite-Averaged Equations 92 5.6 Two-Fluid Model (TFM) 93 5.6.1 OLGA ® Software (SLB) 94 5.7 Constitutive Equations 96 5.8 One-Dimensional Modeling 97 5.9 Homogeneous Equilibrium Model (HEM) 98 5.10 Separated Flow Model 99 5.11 Kinematic Models 101 5.11.1 Bankoff Model (1960) 101 5.11.2 Zuber–Findlay Model (1965) 102 5.11.3 Drift–Flux Model (DFM) 103 5.12 Mechanistic/Phenomenological Models 105 5.13 Empirical Models 107 5.13.1 Flanigan Model (1958) 107 5.13.2 Beggs and Brill Model (1973) 108 5.13.3 Void Fraction Empirical Models 111 5.14 Computational Fluid Dynamics (CFD) 111 References 112 6 Two-Phase Flow in Wells 117 6.1 Introduction 117 6.2 Reservoir Boundary Conditions 118 6.2.1 Well Production String: Vertical, Inclined, and Horizontal Wells 118 6.3 Nodal TM Analysis 120 6.4 Wells Cluster and Manifolds 121 6.5 Water and Gas Coning 124 6.6 Legacy Models 125 6.6.1 Poettmann–Carpenter Model (1952) 126 6.6.2 Griffith–Wallis Model (1961) 126 6.6.3 Duns–Ros Model (1963) 129 6.6.4 Hagedorn–Brown Model (1965) 133 6.6.5 Orkiszeski Model (1967) 136 6.6.6 Beggs–Brill Model (1973) 137 6.6.7 Gray Model (1978) 137 6.6.8 Mukherjee and Brill Model (1985) 138 6.7 Mechanistic Models for Well Flow 141 6.7.1 Ansari et al. Model (1994) 141 6.7.2 Unified Mechanistic Models 144 6.7.3 Hasan and Kabir Model (2002) 144 6.8 Comparison of Flow Models 147 6.9 Severe Slugging Phenomenon 148 6.10 Gas Lift 151 References 151 7 Two-Phase Flow Through Restrictions and Piping Components 155 7.1 Introduction 155 7.2 Flow Through Restrictions 155 7.3 Critical Flow 156 7.4 Choke Valves 159 7.5 Sudden Pipe Enlargement 164 7.6 Sudden Pipe Contraction 165 7.7 Flow Orifice 166 7.8 Gate and Globe Valves 167 7.9 Elbows and Bends 168 7.10 Tee Junctions and Manifolds 168 References 171 8 Two-Phase Flow Thermal Modelling 173 8.1 Introduction 173 8.2 Normal and Transient Operation 174 8.3 Offshore and Onshore Pipelines 174 8.4 Heat Transfer Mechanisms 175 8.5 Internal Heat Transfer Coefficients 176 8.5.1 Turbulent Flow Forced-convection Inside Tubes 176 8.5.2 Laminar Flow Forced convection Inside Tubes 177 8.5.3 Two-phase Disperse bubble Flow in Horizontal Pipe 177 8.5.4 Two-phase Stratified Flow in Horizontal Pipe 178 8.5.5 Two-phase Slug flow in Horizontal Pipe 178 8.5.6 Natural Convection in a Stagnant Fluid Within a Horizontal Pipe 179 8.5.7 Forced Convection in Vertical Two-phase Flow 180 8.6 External Heat Transfer Coefficient 180 8.7 Thermal Insulation 181 8.8 Overall Heat Transfer Coefficient (OHTC) 183 8.9 Buried Pipelines 187 8.10 Temperature Profile 189 8.11 Flowline Cooldown 193 8.12 Document Navigation Heat Transfer in the Wellbore 194 References 197 9 Advanced Simulations 199 9.1 Introduction 199 9.2 Nature of Transient Flow 200 9.3 Transient Flow Applications 202 9.4 Transient Modeling Challenges 204 9.5 Current Weaknesses of Simulating Two-Phase Flow in Pipelines 205 9.6 Future of Two-Phase Flow Simulations 207 9.7 Simulation Philosophies 214 References 214 10 Multiphase Flow Simulations 217 10.1 Introduction: Simulation Challenges 217 10.1.1 Mathematical Models for Two-Phase Flow Simulation 217 10.1.2 Challenges in Two-Phase Flow Simulation 218 10.1.3 Results Validation 218 10.2 Multiphase Flow Simulation Considerations 220 10.2.1 Integration Time Step 220 10.2.2 CFL Condition 221 10.2.3 Round-off Error 221 10.2.4 Geometry Representation 222 10.2.5 Cell-Size Ratio - the Ratio of “2” 222 10.2.6 Dispersion Effects 223 10.2.7 Constant Composition Versus Compositional Simulation 223 10.2.8 Initial Conditions 224 10.2.9 Deepwater Settings 224 10.3 Multiphase Flow Applications 225 10.4 Production Wells Simulation 225 10.4.1 Onshore Well Operating in Steady State 227 10.4.2 Onshore Well Initial Start-up Example 229 10.4.3 Onshore Well Shutdown Example 235 10.5 Offshore Flowlines 236 10.5.1 Offshore Flowline Simulations in Steady State 238 10.5.2 Oil Flowline System in a Steady-State Example 239 10.5.3 Offshore Flowline Transient Simulations 242 10.5.4 Slugging Example 244 10.5.5 Hydrodynamic Slugging Example 244 10.5.6 Severe Slugging Example 245 10.5.7 Ramp-up and Ramp-down Operations 247 10.5.8 Offshore Flowline Ramp-down and Ramp-up Example 248 10.5.9 Cooldown Transient 249 10.5.10 Offshore Flowline Cooldown Example 249 10.5.11 Depressurization Operation 249 10.5.12 Offshore Flowline Depressurization Example 251 10.5.13 Blowdown (Flowline Rupture) Transient 254 10.5.14 Offshore Flowline Rupture Blowdown Example 256 10.5.15 Shutdown Operation 257 10.5.16 Offshore Flowline Planned Shutdown Example 258 10.5.17 Offshore Flowline Restart After Planned Shutdown Example 261 10.5.18 Unplanned Shutdown and Dead Oil Circulation in Flowline Loop 261 10.5.19 Offshore Flowline Loop with Hot Oil Circulation Example 264 10.5.20 Pigging Example 265 10.6 Summary 270 References 271 11 Fluid–Solid Transport 273 11.1 Characteristics of Solid–Fluid Flow 274 11.2 Fundamental Equations 276 11.2.1 Mixture Density 276 11.2.2 Fluid Phase Mass Conservation 276 11.2.3 Solid-Phase Mass Conservation 276 11.2.4 Solid–Fluid Mixture Mass Conservation 277 11.2.5 Mixture Momentum Equation 277 11.2.6 Dilute Suspensions in Turbulent Flow 277 11.3 Simplified Horizontal Flow Models 277 11.3.1 Homogeneous Flow Model 278 11.3.2 Heterogeneous Flow Model 279 11.4 Minimum Deposit Velocity 282 11.5 Sand Production 283 11.6 Sand Distribution 284 11.7 Pipe Erosion and Erosional Velocity 285 11.8 Application Examples 286 References 287 A Multiphase Flow Software Tools 289 A.1 Thermodynamics and Transport Properties Simulators 289 A.1 Pvtsim Nova® 290 A.1.2 Multiflash® 291 A.1.3 Aspen Hysys® 291 A.1.4 Refprop® 292 A.1.5 Pvtp® 293 A.1.6 Dwsim® 293 A.2 Steady-State Multiphase Simulators 294 A.2.1 Pipesim® 294 A.2.2 Gap® and Prosper® 295 A.2.3 Olga-S® (SLB) 296 A.2.4 Pipephase® 297 A.3 Transient Multiphase Simulators 297 A.3.1 Olga® 297 A.3.2 LedaFlow® 299 A.3.4 Gap Transient 300 Index 301

Autorenportrait

Juan J. Manzano-Ruiz has worked for more than 40 years in all sectors of the oil and gas industry, including offshore shallow/deepwater fields, onshore oil and gas plants, LNG, and refining, in different technical leadership and managerial roles with E&P corporations. He has proven theoretical and operational experience with Flow Assurance and with the development of program simulation tools designed to meet challenging flow-modeling needs. He is the President of the corporation Petroconsulting and Associates and is a registered Professional Engineer in the state of Texas. Jose G. Carballo is a flow assurance engineer with over a decade of experience with steady-state and transient simulation for wells, flowlines, and risers. He is a co-founder and Vice President of FlowAssure Engineering, and a registered Professional Engineer in the state of Texas.

Back cover copy

An introduction to multiphase flows in the oil and gas industry The term ‘multiphase flow’ refers to the concurrent flow of oil and/or gas, alongside other substances or materials such as production water, chemical inhibitors, and solids (e.g. sand). This is a critical topic in the oil and gas industry, where the presence of multiple flow phases in pipelines affects deliverability, generates serious complications in predicting flow performance for system design and operation, and requires specific risk mitigation actions and continuous maintenance. Chemical and Mechanical Engineers interested in working in this industry will benefit from understanding the basic theories and practices required to model and operate multiphase flows through pipelines, wells, and other components of the production system. Multiphase Transport of Hydrocarbons in Pipes meets this need with a comprehensive overview of five decades of research into multiphase flow. Incorporating fundamental theories, historic and cutting-edge multiphase flow models, and concrete examples of current and future applications. This book provides a sound technical background for prospective or working engineers in need of understanding this crucial area of industry. Readers will also find: <ul><li> Fundamental principles supporting commercial software</li> <li> Detailed tools for estimating multiphase flow rates through flowlines, wells, and more</li> <li> Integration of conservation principles with thermodynamic and transport properties</li> <li> Coverage of legacy and modern simulation models </li></ul> This book is ideal for flow assurance engineers, facilities engineers, oil and gas production engineers, and process engineers, as well as chemical and mechanical engineering students looking to work in any of these roles.