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- Herausgeber: John Wiley & Sons
- Kategorie: Fachliteratur
- Sprache: Englisch
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: * Fundamental principles supporting commercial software * Detailed tools for estimating multiphase flow rates through flowlines, wells, and more * Integration of conservation principles with thermodynamic and transport properties * Coverage of legacy and modern simulation models 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.
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Veröffentlichungsjahr: 2024
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Table of Contents
Cover
Table of Contents
Title Page
Copyright
Dedication
Preface
About the Authors
Acknowledgments
Nomenclature
List of Symbols
Abbreviations
Dimensionless Groups
Greek Letters
Subscripts
Superscripts
About the Companion Website
1 Introduction
1.1 What Is Multiphase Flow
1.2 Single- and Multicomponent Fluids
1.3 Challenges to Model Multiphase Flow
1.4 Hydrocarbon Flow
1.5 Modeling Approaches
References
2 Fundamentals of Multiphase Flow
2.1 Multiphase Flow in the Production of Oil and Gas
2.2 Multiphase Flow Concepts
2.3 Modeling Strategy
2.4 Two-Phase Flow Measurements
2.5 Future Measuring Trends
References
3 Hydrocarbon Fluid Properties and Thermodynamics
3.1 Phase Behavior
3.2 Physical Properties
3.3 Equation of State (EOS)
3.4 C
7
+
Characterization
3.5 Thermal and Transport Properties
3.6 Types of Hydrocarbon Fluids
3.7 PVT Analyses
3.8 Strategy for Modeling Fluid Properties
3.9 Commercial Software
References
4 Multiphase Flow Patterns
4.1 Gas–Liquid Flow
4.2 Dispersed versus Separated Flow Regimes
4.3 Vertical and Inclined Flow Maps
4.4 Quasi-Horizontal Flow Maps
4.5 Liquid–Liquid Flow Map
4.6 Three-Phase Flow
4.7 Liquid–Solid Flow
4.8 Gas–Solid Flow
4.9 Conclusions
References
5 Two-Phase Flow in Pipelines
5.1 Introduction
5.2 Conservation Principles
5.3 Space-Averaged Equations
5.4 Time-Averaged Equations
5.5 Composite-Averaged Equations
5.6 Two-Fluid Model (TFM)
5.7 Constitutive Equations
5.8 One-Dimensional Modeling
5.9 Homogeneous Equilibrium Model (HEM)
5.10 Separated Flow Model
5.11 Kinematic Models
5.12 Mechanistic/Phenomenological Models
5.13 Empirical Models
5.14 Computational Fluid Dynamics (CFD)
References
6 Two-Phase Flow in Wells
6.1 Introduction
6.2 Reservoir Boundary Conditions
6.3 Nodal™ Analysis
6.4 Wells Cluster and Manifolds
6.5 Water and Gas Coning
6.6 Legacy Models
6.7 Mechanistic Models for Well Flow
6.8 Comparison of Flow Models
6.9 Severe Slugging Phenomenon
6.10 Gas Lift
References
7 Two-Phase Flow Through Restrictions and Piping Components
7.1 Introduction
7.2 Flow Through Restrictions
7.3 Critical Flow
7.4 Choke Valves
7.5 Sudden Pipe Enlargement
7.6 Sudden Pipe Contraction
7.7 Flow Orifice
7.8 Gate and Globe Valves
7.9 Elbows and Bends
7.10 Tee Junctions and Manifolds
References
8 Two-Phase Flow Thermal Modelling
8.1 Introduction
8.2 Normal and Transient Operation
8.3 Offshore and Onshore Pipelines
8.4 Heat Transfer Mechanisms
8.5 Internal Heat Transfer Coefficients
8.6 External Heat Transfer Coefficient
8.7 Thermal Insulation
8.8 Overall Heat Transfer Coefficient (OHTC)
8.9 Buried Pipelines
8.10 Temperature Profile
8.11 Flowline Cooldown
8.12 Document Navigation Heat Transfer in the Wellbore
References
9 Advanced Simulations
9.1 Introduction
9.2 Nature of Transient Flow
9.3 Transient Flow Applications
9.4 Transient Modeling Challenges
9.5 Current Weaknesses of Simulating Two-Phase Flow in Pipelines
9.6 Future of Two-Phase Flow Simulations
9.7 Simulation Philosophies
References
10 Multiphase Flow Simulations
10.1 Introduction: Simulation Challenges
10.2 Multiphase Flow Simulation Considerations
10.3 Multiphase Flow Applications
10.4 Production Wells Simulation
10.5 Offshore Flowlines
10.6 Summary
References
11 Fluid–Solid Transport
11.1 Characteristics of Solid–Fluid Flow
11.2 Fundamental Equations
11.3 Simplified Horizontal Flow Models
11.4 Minimum Deposit Velocity
11.5 Sand Production
11.6 Sand Distribution
11.7 Pipe Erosion and Erosional Velocity
11.8 Application Examples
References
Appendix A: Multiphase Flow Software Tools
A.1 Thermodynamics and Transport Properties Simulators
A.2 Steady-State Multiphase Simulators
A.3 Transient Multiphase Simulators
Index
End User License Agreement
List of Tables
Chapter 3
Table 3.1 Example of a natural gas composition.
Table 3.2 Dranchuk and Abou-Kassem correlation parameters.
Chapter 5
Table 5.1 Parameters for holdup correlation. Source: Adapted from Brill and ...
Chapter 6
Table 6.1 Comparison of seven models with database.
Chapter 8
Table 8.1 Order-of-magnitude single-phase heat transfer coefficients, Incrop...
Table 8.2 Order of magnitude of heat transfer coefficients in slug flow, Sho...
Table 8.3 Insulation thermal conductivity.
Table 8.4 Coating thermal conductivity.
Table 8.5 Other material thermal conductivities.
Table 8.6 Example of the calculation of
U
-value (in bold characters) based o...
Table 8.7 Example of the calculation of
U
-value (in bold character) based on...
Table 8.8 Example of the calculation of
U
-value (in bold character) based on...
Table 8.9 Fluid composition for Example 8.4.
Table 8.10 Example of the calculation of OHTC (in bold characters) based on ...
Table 8.11 Representative
U
-values for well completions.
Chapter 10
Table 10.1 Simulated well characteristics—Onshore well.
Table 10.2 Initial well start-up schedule.
Table 10.3 Simulated subsea oil flowline characteristics.
Table 10.4 Flowline rupture simulation results.
Table 10.5 Normal operating condition differences during flowline rupture.
List of Illustrations
Chapter 1
Figure 1.1 Two-phase flow in horizontal flowline.
Figure 1.2 Boiling water reactor with steam–water flow.
Chapter 2
Figure 2.1 Flow regimes in vertical flow.
Figure 2.2 Partial view of onshore gathering system.
Figure 2.3 Subsea gathering system options.
Figure 2.4 Test separator.
Figure 2.5 Integrated MPFM and test separator.
Figure 2.6 Field array of MPFMs.
Chapter 3
Figure 3.1 Constant vapor pressure test.
Figure 3.2 Constant temperature test.
Figure 3.3 Simple-component phase change at constant pressure.
Figure 3.4 Simple-component phase change at constant temperature.
Figure 3.5 Example of gas mixture phase envelope.
Figure 3.6 Retrograde condensation phenomenon.
Figure 3.7 Isothermal performance of gas compressibility factor.
Figure 3.8 Oil density changes around the bubble point.
Figure 3.9 Pressure effect upon gas viscosity at constant temperature.
Figure 3.10 Oil viscosity at constant temperature.
Figure 3.11 Solution gas ratio at a constant temperature.
Figure 3.12 Oil formation value at a constant temperature at a constant temp...
Figure 3.13 Gas formation volume factor at constant temperature.
Figure 3.14 Black oil typical phase envelope.
Figure 3.15 Volatile oil phase envelope.
Figure 3.16 Retrograde gas phase envelope.
Figure 3.17 Wet gas phase behavior.
Figure 3.18 Dry gas phase behavior.
Figure 3.19 Constant composition expansion at constant temperature.
Figure 3.20 PVT cell equipment for CCE tests.
Figure 3.21 Saturation point determination for a black oil from CCE test res...
Figure 3.22 Differential liberation process at constant temperature.
Figure 3.23 Capillary tube viscometer.
Chapter 4
Figure 4.1 Evolution of gas phase in two-phase horizontal flow.
Figure 4.2 Typical flow patterns of upward-inclined flow.
Figure 4.3 Vertical flow map. Source: Hewitt and Roberts (1969)/U.S. Departm...
Figure 4.4 Vertical flow map. Source: Adapted from Taitel et al. (1980).
Figure 4.5 Diabatic gas–liquid horizontal flow in regime transition.
Figure 4.6 Flow pattern map for horizontal pipeline. Source: Adapted from Ba...
Figure 4.7 Flow pattern map for horizontal pipeline. Source: Mandhane et al....
Figure 4.8 Flow pattern map for horizontal pipeline. Source: Adapted from Ta...
Figure 4.9 Liquid–liquid flow map. Source: Edomwonyi-Otu and Angeli (2015)/E...
Figure 4.10 Flow pattern map for three-phase flow. Source: Adapted from Lee ...
Figure 4.11 Solid–liquid flow map. Source: Adapted from Doron and Barnea (19...
Figure 4.12 Typical gas–solid flow regimes in horizontal flow.
Chapter 5
Figure 5.1 Mass conservation equation for a control volume.
Figure 5.2 Momentum balance on a control volume element.
Figure 5.3 Conservation of total energy for a control volume.
Figure 5.4 Darcy–Weisbach friction factor.
Chapter 6
Figure 6.1 Well completion sketch.
Figure 6.2 Example of a Nodal Analysis™.
Figure 6.3 Subsea manifold.
Figure 6.4 Subsea wells tie into the manifold.
Figure 6.5
C
1
function for Griffith–Wallis model.
Figure 6.6
C
2
function for Griffith–Wallis model.
Figure 6.7 Duns and Ros flow pattern map.
Figure 6.8 Functions
L
1
and
L
2
to identify flow pattern.
Figure 6.9 Functions F1, F2, F3, and F4.
Figure 6.10 Functions F5, F6, and F7.
Figure 6.11 Function
f
2
.
Figure 6.12 Hagedorn–Brown model function
N
LC
.
Figure 6.13 Hagedorn–Brown model function
ψ
.
Figure 6.14 Hagedorn–Brown model function
H
L
/
ψ
.
Figure 6.15 Example 6.1 – Comparison of legacy models.
Figure 6.16 Example 6.2 – Comparison of mechanistic models.
Figure 6.17 Phenomenon of severe slugging.
Chapter 7
Figure 7.1
C
v
coefficient as a function of stem position.
Figure 7.2 Sudden pipe expansion.
Figure 7.3 Sudden pipe contraction.
Figure 7.4 Schematics of a mixing/joining adiabatic tee.
Figure 7.5 Splitting/dividing adiabatic tee.
Chapter 8
Figure 8.1 Thermal resistance network.
Figure 8.2 Buried pipeline heat transfer domain.
Figure 8.3 Fluid temperature profile of flowline.
Chapter 9
Figure 9.1 Typical transient operations for a production system.
Figure 9.2 Simplified ANN schematic example.
Chapter 10
Figure 10.1 Well geometry example.
Figure 10.2 Principal parameters profiles for a liquid rate of 8,000 blpd.
Figure 10.3 Well pressures and choke opening during the well initial start-u...
Figure 10.4 Well flow rates during the well initial start-up.
Figure 10.5 Temperatures during the well initial start-up.
Figure 10.6 Well holdup profile during well initial start-up.
Figure 10.7 Well subcooling profile during well initial start-up.
Figure 10.8 Well shutdown conditions after a 120-hour shutdown.
Figure 10.9 Flowline elevation profile as function of horizontal and total l...
Figure 10.10 Flowline-riser J curve, arrival temperature, and EVR.
Figure 10.11 Flowline profiles for normal operation (rate 80,000 blpd).
Figure 10.12 Hydrodynamic slugging example.
Figure 10.13 Severe slugging example.
Figure 10.14 Ramp-down to 40,000 blpd and ramp-up to 80,000 blpd.
Figure 10.15 Holdup, pressure, and temperature profiles during the cooldown....
Figure 10.16 Flowline initial condition profile for depressurization (after ...
Figure 10.17 Flowline profile after 120 hours of depressurization (1-inch ch...
Figure 10.18 Flowline profile after 120 hours of depressurization (2-inch ch...
Figure 10.19 Topside gas and liquid rate, 1-inch choke depressurization.
Figure 10.20 Topside gas and liquid rates (2-inch choke).
Figure 10.21 Planned shutdown holdup profiles.
Figure 10.22 Planned shutdown profile at the start of cooldown.
Figure 10.23 Planned shutdown profile after 120 hours of cooldown.
Figure 10.24 Flowline restart after a planned shutdown trend.
Figure 10.25 Flowline loop elevation profile.
Figure 10.26 Flowline loop dead oil circulation profiles.
Figure 10.27 Flowline loop dead oil circulation trend.
Figure 10.28 Flowline loop hot oil circulation profiles.
Figure 10.29 Flowline loop hot oil circulation trend.
Figure 10.30 Flowline loop pigging simulation profiles.
Figure 10.31 Flowline pigging simulation trends (Part 1).
Figure 10.32 Flowline pigging simulation trends (Part 2).
Chapter 11
Figure 11.1 Rheogram plot of solid–liquid two-phase fluids.
Figure 11.2 Flow regimes for a settling solid–liquid mixture.
Figure 11.3 Pseudo-homogeneous solid–liquid mixture flow.
Figure 11.4 Heterogeneous mixture flow with suspended particles.
Figure 11.5 Moving bed flow with saltation.
Figure 11.6 Mixture flow with stationary bed.
Figure 11.7 Slurry head loss gradient.
Figure 11.8 Example of sand grain size distribution.
Figure 11.9 Microphotography of sand fine sample.
Guide
Cover
Table of Contents
Title Page
Copyright
Dedication
Preface
About the Authors
Acknowledgments
Nomenclature
About the Companion Website
Begin Reading
Appendix A: Multiphase Flow Software Tools
Index
End User License Agreement
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Multiphase Transport of Hydrocarbons in Pipes
Juan J. Manzano-Ruiz
PetroConsulting and Associates
USA
Jose G. Carballo
USA
Copyright © 2024 by John Wiley & Sons Inc All rights reserved.
Published by John Wiley & Sons, Inc., Hoboken, New Jersey.Published simultaneously in Canada.
No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning, or otherwise, except as permitted under Section 107 or 108 of the 1976 United States Copyright Act, without either the prior written permission of the Publisher, or authorization through payment of the appropriate per-copy fee to the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, (978) 750-8400, fax (978) 750-4470, or on the web at www.copyright.com. Requests to the Publisher for permission should be addressed to the Permissions Department, John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, (201) 748-6011, fax (201) 748-6008, or online at http://www.wiley.com/go/permission.
Trademarks: Wiley and the Wiley logo are trademarks or registered trademarks of John Wiley & Sons, Inc. and/or its affiliates in the United States and other countries and may not be used without written permission. All other trademarks are the property of their respective owners. John Wiley & Sons, Inc. is not associated with any product or vendor mentioned in this book.
Limit of Liability/Disclaimer of Warranty: While the publisher and author have used their best efforts in preparing this book, they make no representations or warranties with respect to the accuracy or completeness of the contents of this book and specifically disclaim any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representatives or written sales materials. The advice and strategies contained herein may not be suitable for your situation. You should consult with a professional where appropriate. Further, readers should be aware that websites listed in this work may have changed or disappeared between when this work was written and when it is read. Neither the publisher nor authors shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages.
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Library of Congress Cataloging-in-Publication Data:
Names: Manzano-Ruiz Juan, J., author. | Carballo, Jose G., author.
Title: Multiphase transport of hydrocarbons in pipes / Juan J. Manzano-Ruiz, Jose G. Carballo.
Description: Hoboken, New Jersey : Wiley, [2024] | Includes index.
Identifiers: LCCN 2023057850 (print) | LCCN 2023057851 (ebook) | ISBN 9781119888512 (cloth) | ISBN 9781119888529 (adobe pdf) | ISBN 9781119888536 (epub)
Subjects: LCSH: Multiphase flow. | Hydrocarbons.
Classification: LCC TA357.5.M84 M36 2024 (print) | LCC TA357.5.M84 (ebook) | DDC 665.5/44–dc23/eng/20240128
LC record available at https://lccn.loc.gov/2023057850
LC ebook record available at https://lccn.loc.gov/2023057851
Cover Design: WileyCover Image: © Hirkophoto/Getty Images
To my Parents Juan Vicente and Carmen Teresa; my wife Lucy; my children Juan Carlos, Anabella, Andres Simon, and Raul Rodrigo; my beloved grandsons Juan Diego and Marcelo; my siblings Liliana and Juan Vicente; and my in-laws
August 2023
Juan J. Manzano-Ruiz
To my beloved wife Mariale; my cherished son Benjamin; and my parents Gilberto and Nicole
August 2023
Jose G. Carballo
Preface
Welcome to Multiphase Flow in Pipelines, an in-depth journey into the subject of the co-current flow of gas, liquids, and solids resulting from the production of hydrocarbons from underground reservoirs. This book is designed to be a comprehensive guide for both novices and experts seeking to gain a profound understanding of the core principles, best practices, and cutting-edge advancements in the realm of multiphase flow.
In today’s fast-paced and ever-evolving technological landscape, staying ahead of the curve is vital for engineers, technicians, and students alike. The purpose of this book is to provide you with the practical knowledge and tools needed to understand field operations or to participate in projects to develop new fields.
We have chosen a variety of topics, blending theory, and practice, illustrated with examples taken from real projects. This book could be helpful to students embarking on an educational journey or to seasoned practitioners aiming to sharpen skills by understanding the first principles underlying the fluid flow and heat transfer models built into the commercial software available.
Key features of this book include the following:
Coverage: We explore all fundamental concepts and advanced topics related to multiphase flow in pipes that could add value to real projects or improve production performance. From basic models to the most intricate aspects, each chapter builds upon the previous one to foster a solid understanding.
Real-world applications: We believe in bridging the gap between theory and practice. As such, every concept discussed within these pages is accompanied by real-world applications, and examples to illustrate how the knowledge can be put to use effectively.
References: We include key references that provide in-depth knowledge supporting the material presented in each chapter.
Future horizons: A brief introductory chapter is included expressing the authors’ views regarding potential technology evolution into the world of artificial intelligence, machine learning, data science, and artificial neural networks, with the humble hope that the reader may be initiated in the brilliant future developments in these amazing fields.
We encourage you to approach this book with curiosity, determination, and an open mind. Our hope is that the book triggers your interest in the transport of hydrocarbons through pipelines and empowers you to explore, innovate, and make significant contributions to the field. Should you have any feedback, questions, or suggestions, we look forward to your correspondence. Please refer to the companion website for color graphs included in this book.
2024, KatyTexas
Juan J. Manzano-Ruiz
Jose G. Carballo
About the Authors
Juan J. Manzano-Ruiz, M.Sc., M.E., Ph.D., P.E., is a mechanical engineer by background, who gathers 40-plus years of experience in the energy industry, holding leadership and executive managerial positions with PdVSA-Intevep, BP-Amoco, Jacobs Engineering, Technip, and Bechtel O, G, and C. He earned three diplomas from the Massachusetts Institute of Technology and completed an MBA minor from the Sloan School of MIT. He taught undergraduate and graduate engineering courses for 16 years at universities in Caracas, Venezuela. He is currently a consultant and President of Petroconsulting and Associates LLC in Texas, USA (Email: [email protected]).
Jose G. Carballo, M.Sc., P.E., is a flow assurance and hydraulics engineer, with 20 years of experience consulting for the energy industry. He is currently Vice President of FlowAssure Engineering in Texas, USA (Email: [email protected]).
Acknowledgments
In the first place, I acknowledge the organizations that allowed me to learn and gain field experience in the subject of multiphase flow. These remarkable organizations include PdVSA-Intevep, BP-Amoco Venezuela, Jacobs Engineering, Technip, and Bechtel Oil, Gas, and Chemicals. The positions held at these organizations exposed me to practical situations comprising research and development, projects, field operations, and facilities construction. Thanks to such experiences I had the immense privilege of applying lessons learned from four giants in this field, namely Prof. Pete Griffith, the key advisor for my doctoral thesis at MIT; Dr. Jean-Marc Delhaye, a legend in the most rigorous analyses in this discipline; the late Prof. “Abe” Dukler; and Prof. Yehuda Taitel, who were the pioneers of the modern mechanistic methodology.
To my friend and co-author in this endeavor, Jose G. Carballo, M.Sc., P.E., who deserves the greatest acknowledgment for his work, thanks to his valuable 20 years of project experience, fine skills performing difficult simulations with commercial code, his ability to simplify field conditions, and for his great character and integrity. It has been a real pleasure working with Jose, who was my undergraduate student almost three decades ago.
I was extremely lucky to have a huge technical and editorial review collaboration in this book from Maria A. Nass, M.Sc., P.E., MBA, who happens to be Jose’s wife. Maria has a long-standing and successful career in projects requiring advanced multiphase flow knowledge, while holding positions for Total, BP p.l.c., and currently for Subsea 7. Many thanks, Maria, for your outstanding contributions.
On a personal level, this work could not have been even attempted without the loving, permanent, and unconditional support from my family for the past two and a half years. Their time sacrifices do not go unrecognized because their backing was the true driver to bring this book to fruition. My endless love and heartfelt recognition to them all.
Juan J. Manzano-Ruiz,
Katy, Texas
I wish to convey my sincere appreciation to my dear friend, esteemed mentor, and lead author, Dr. Juan J Manzano-Ruiz, for graciously involving me in this project, and for his exceptional dedication in sharing his wealth of knowledge and expertise that has been instrumental in bringing this book to fruition.
Additionally, I express my sincere gratitude to my wife Mariale for her contribution to reviewing this text.
Jose G. Carballo
Katy, Texas
Nomenclature
List of Symbols
SI units
FPS units
A
Cross-sectional area
m
2
ft
2
B
Formation volume factor
m
3
/sm
3
bbl/stb
c
Speed of sound
m/s
ft/s
c
solid
Volumetric concentration of solids
% vol.
% vol.
C
Empirical constant of erosional velocity
kg
1/2
/s.m
1/2
lb
1/2
/s.ft
1/2
C
p
Specific heat coefficient at constant pressure
J/Kg K
Btu/lbmF
C
V
Valve’s flow coefficient
gpm/psi
0.5
d
Pipe internal diameter
m
Inch
D
Pipe external diameter
m
inch
D
h
Hydraulic diameter
m
Inch
e
Fluid internal energy
J/kg
Btu/lbm
f
Friction factor
—
—
g
Gravitation acceleration
m/s
2
ft/s
2
g
c
Force–mass conversion factor
—
32.17 lbm ft/lbf s
2
G
Mass velocity
kg/m
2
s
lbm/ft
2
h
GOR
Gas–oil ratio at standard conditions
sm
3
/sm
3
scf/stb
h
Fluid enthalpy
J/kg
Btu/lbm
h
f
Friction head
m
ft
h
i
Internal heat transfer coefficient
W/m
2
K
Btu/hr ft
2
F
h
L
Depth of liquid in stratified flow
m
ft
H
Enthalpy
J/kg
Btu/lbm
HFT
Hydrate formation temperature
°C or °K
°F or °R
H
L
Liquid holdup
—
—
ID
Internal diameter
mm
inch
j
Superficial velocity, volumetric flux
m/s
ft/s
j
lg
Slip drift flux
m/s
ft/s
k
Thermal conductivity
W/m K
Btu/h ft R
L
Pipeline length
m
ft
m
Mass flow rate
kg/s or kg/h
lbm/h
M
Amount of mass
kg
lbm
MW
Molecular weight
kg/kgmol
lbm/lbmol
n
Number of moles in ideal gas model
—
—
p
Pressure
Pa,abs or bara
psia
P
i
Phase-to-phase contact interface
m
inch
P
w
Wet (in contact with pipe wall) perimeter
m
inch
q”
Heat flux per unit area
W/m
2
Btu/h ft
2
Q
Flow rate
m
3
/s
ft
3
/s
Q
Heat flow rate
W
Btu/h
Gas universal constant
J/kgmol K
lbf ft/lbmol R
Specific gas constant
J/kg K
lbf ft/lbm R
R
s
Solution gas ratio
sm
3
/sm
3
scf/stb
s
Entropy
J/kg K
Btu/lb F
S
Slip factor
—
—
S
Specific gravity
—
—
S
g
Wet perimeter of gas phase
m
inch
S
HT
Heat transfer shape factor
m
ft
S
i
Perimeter of gas–liquid interface
m
inch
S
l
Wet perimeter of liquid phase
m
inch
S
Salinity
% w.
% w.
t
Time
s
s
T
Temperature
°C or °K
°F or °R
u
Actual fluid velocity
m/s
ft/s
V, v
Volume
m
3
ft
3
V
M
Volume of one molecular weight
m
3
ft
3
y
c
Critical pressure ratio (orifice)
—
—
y
i
Molar fraction of component “i” in gas phase
% m.
% m.
x
Mass quality
—
—
x
Direction of change for 1-D models
m
ft
x
i
Molar fraction of component “i” in liquid phase
% m.
% m.
z
Elevation (vertical) coordinate
m
ft
Z
c
Compressibility factor
—
—
z
i
Molar fraction of component “i” in the feed
% m.
% m.
Abbreviations
AERE
Atomic Energy Research Establishment, Harwell, Oxfordshire, UK
AGA
American Gas Association, Washington, D.C., USA
ANS
American Nuclear Society, Illinois, USA
API
American Petroleum Institute, Washington, D.C., USA
ASME
American Society of Mechanical Engineers, New York, N.Y., USA
bbl, bbls
barrels at local conditions
bpd,blpd
barrels of liquid per day
bopd
barrels of oil per day
CAPEX
capital expenditures
CD
cooldown transient
CS
control surface
CV
control volume
DC
drill center
DOC
dead-oil circulation
EOS
equation of state
EVR
erosion velocity ratio
FPSO
Floating Production Storage and Offloading Vessel
gpm
U.S. gallons per minute
GPSA
Gas Processors Suppliers Association, Tulsa, OK, USA
HC
Hydrocarbons
HOC
hot-oil circulation
IPR
inflow performance relationship
mscfd
thousands of standard cubic feet per day
mmscfd
millions of standard cubic feet per day
ODE
ordinary differential equation
OHTC
overall heat transfer coefficient
OPEX
operational expenditures
PDE
partial differential equation
ppg
density expressed in pounds per gallon
R&D
research and development
scf
cubic feet @ standard conditions
SPS
subsea production system
stb
barrels of liquid @ stock-tank conditions
TOTEX
combined CAPEX and OPEX expenditures
TPR
tubing performance relationship
TUFFP
Tulsa University Fluid Flow Projects, Tulsa, OK, USA
USC
upstream of choke condition
VIT
vacuum insulated tubing
VLP
vertical lift performance
WC
water cut
Dimensionless Groups
Fr
Froude number,
V/(gL)
0.5
Gr
Grashof number,
L
3
ρ
2
βgΔT/μ
2
Nu
Nusselt number,
hD/k
Pr
Prandtl number,
c
p
μ/k
Ra
Rayleigh number,
gβΔTd
3
/(μ/ρ)
2
Re
Reynolds number,
ρDV/μ
Greek Letters
SI units
FPS units
α
void fraction
—
—
β
volumetric quality
—
—
β
s
isentropic compressibility
Pa
−1
psi
−1
χ
Lockhart–Martinelli parameter
—
—
γ
specific gravity
—
—
Γ
volumetric mass transfer rate
kg/m
3
s
lbm/ft
2
hr
δ
layer thickness or property increment
mm
inch
δ
increment of a parameter
—
—
Δ
change in a property
ε
wall roughness
mm
inch
η
efficiency
—
—
η
Joule–Thomson coefficient
K/Pa
F/psi
η
apparent viscosity of non-Newtonian fluid
s Pa
cP
θ
inclination with respect to horizontal direction
radian
radian
μ
dynamic viscosity
s Pa
cP
υ
specific volume
m
3
/kg
ft
3
/lbm
ξ
isentropic expansion coefficient
—
—
π
Pi number
3.1416
3.1416
ρ
density
kg/m
3
lbm/ft
3
σ
surface tension
N/m
dyne/cm
τ
shear stress
Pa
psi
τ
time
sec
sec
ϕ
two-phase multiplier
—
—
ϕ
fugacity coefficient
—
—
φ
subtended angle in stratified horizontal flow
radian
radian
ω
acentric factor
—
—
Subscripts
a
air phase
acc
acceleration
b
bubble point, bubble
coat
coating conductance or resistance
ch
choke
crit
,
c
critical condition
CS
control surface around a control volume
CV
control volume
D-W
Darcy–Weisbach friction factor
ext
external heat transfer to environment
f, fric
friction
f
fluid
fric
friction component
F
fanning friction factor
G, g, gas
gas phase
geoth
geothermal gradient
grav
gravitation
h
hydraulic diameter
H
homogeneous model
HC
hydrocarbon
HT
heat transfer
i
interface
int
internal heat transfer
ℓ
axial pipeline direction
L, l, liq
liquid phase
m
,
mix
mixture
o
,
oil
oil phase
p
pipe
pc
pseudo-critical
pr
pseudo-reduced
r
radial direction
r
reduced condition for pressure or temperature
s, solid
solid phase
s
slip, slip velocity
S
superficial flow (based on overall cross-section)
stag
stagnation (rest) condition
std
standard conditions: 15.56 °C and 1.01325 bara
total
total thermal conductance or resistance
w
water phase
wf
downhole well flowing
wh
wellhead
W
pipe’s internal wall surface
x
axial pipeline direction
z
vertical (gravity) direction
1
inlet conditions
2
outlet conditions
Superscripts
″
double prime: property per unit flux area
–
bar above variable: time average over a period
About the Companion Website
This book is accompanied by a companion websites.
www.wiley.com/go/Manzano-Ruiz/Multiphasetransport
The website includes:
Coloured Figures
1Introduction
1.1 What Is Multiphase Flow
Multiphase flow means the simultaneous transport of matter in the form of liquids, gases, solids, or any combination of these. The coexistence of at least two of these phases poses a complex time-dependent topology to describe even in the simplest cases. The spatial distribution of phases adopts the form of droplets, bubbles, solid particles, films, and chunks of liquids in an ever-changing process (time-dependent), determining the transfer phenomena of mass, species, thermal energy, and momentum. Figure 1.1 shows a sketch of typical flow patterns in horizontal flow.
Figure 1.1a corresponds to an evaporating liquid flowing from left to right. Figure 1.1b shows separated flows with distinctive continuous phases. Figure 1.1c shows dispersed flows of either bubbles in liquids or droplets in gas. Needless to say the current state of the art in multiphase pipeline flow modeling requires several approximations and simplifications.
An effortless way to tackle the topology conundrum is to identify flow regimes that show similar patterns and characteristics with a set of boundaries expressed in terms of key parameters or non-dimensional groups. Many flow pattern maps are available in the two-phase (gas–liquid) flow literature aimed to predict different flow orientations, that is, quasi-horizontal, vertical upward and downward, and inclined flow upward and downward. Chapter 4 of this book reviews the principal flow pattern maps proposed.
Multiphase flow in hydrocarbon production systems may include various phases, namely oil, gas, produced water, and solids (e.g. sand fines, asphaltene, and wax). In this book, the approach is to consider a single liquid phase made up of oil and produced water. Comprehensive coverage of solid–gas or solid–liquid transport in pipelines is beyond the scope of this book. However, a very brief introduction to the field of solid–fluid transport is included in Chapter 11. Thus, the main focus of this book is on two-phase gas–liquid flow.
Figure 1.1 Two-phase flow in horizontal flowline.
Another important characteristic of multiphase flow is phase slippage, easily distinguished when an integral modeling approach is adopted. The differences in phases’ velocities cause flow instabilities, flow regime transitions, and enhanced transport phenomena at the interfaces.
In this book, the one-dimensional methodology is followed. This means that conservation principles and closure equations will be expressed with equations aligned to the pipeline axis. This simplification stems from the cross-sectional integral application to obtain representative one-dimensional(1-D) properties and parameters for each phase. Such a methodology, on the one hand, simplifies the governing set of equations but, on the other hand, introduces the need for additional closure equations to account for the phases’ interactions.
1.2 Single- and Multicomponent Fluids
Multiphase flow is present in the steam–water phases of the boiling water reactors (BWR, Figure 1.2) of the nuclear industry, for which intense R&D work has been done during the past 70 years. Introduction to the field of nuclear power generation utilizing the technology of BWR can be found in the texts by Lahey and Moody (1993) and Tong and Tang (1997). The boiling water within the BWR experiences a variety of successive changes in flow regime, ranging from bubble, plug, slug, churn, annular, and misty flow, inside vertical tubes. There is inclusive a possibility to have reverse liquid flow within the tubes, a phenomenon known as flooding.
Due to advances in the nuclear power generation industry, the study of single-component two-phase flow has enjoyed impressive R&D financing, producing a wealth of valuable experimental data and proposed models to match the data.
Vapor–liquid phases are also present in evaporators and condensers of a mechanical refrigeration system. Flows of steam and hot water are also observed in oilfield distribution systems to stimulate heavy-oil production (enhanced oil recovery technique). All these examples have in common that working fluid is a simple substance with well-known properties, described by simple thermodynamics relationships.
Figure 1.2 Boiling water reactor with steam–water flow.
Multicomponent mixtures are completely different fluids from the standpoint of the thermodynamics description and mathematical handling. The common hydrocarbon produced from a reservoir comprises thousands of single components, subject to attraction and repulsion intermolecular forces. The prediction of fluid thermodynamic and transport properties is in general a challenge in comparison to a single-component system. Chapter 3 addresses the challenges and issues of compositional models required to describe the flow performance of hydrocarbons in pipeline systems.
1.3 Challenges to Model Multiphase Flow
This section summarizes the majority of the challenges experienced in attempting to predict the two-phase flow performance of oil and gas through a production system. As pointed out before, the flow topology and the complexity of the phases’ interaction hinder rigorous analysis, for which available simplified models provide approximate answers in many situations. A brief comment on the primary challenges follows.
1.3.1 Experiments and Scale-up
The need to add closure equations to complement the conservation principles still requires laboratory testing to generate reliable data. The issue with lab testing is threefold: test fluid(s), pressure, and scale. Traditional modeling fluids at the test labs have been air and water because of cost, availability, and safety. Most flow pattern maps were developed using air–water mixtures at different mass ratios to cover a wide range of fluid velocities in vertical and horizontal flow. Unfortunately, the fluid properties of air–water mixtures are quite different from the fluid properties of oil and natural gas, requiring property-scaling parameters or mechanistic approaches to make use of the experimental data.
Very few data at high pressure and field-size piping are available to validate the two-phase flow models for hydrocarbon transport applications. Proprietary databases obtained from hydrocarbon flow at field conditions have been gathered with the financial support of the members of joint industry projects (JIP). Renown JIPs include OLGA’s software, initially developed under the Statoil, IFE, and SINTEF JIP in 1984; LedaFlow Improvements to Flow Technology (LIFT), initially developed in 2013 under the Chevron, ConocoPhillips, ExxonMobil, Shell, Statoil, TotalEnergies, and Woodside JIP; and the University of Tulsa Fluid Flow Projects (TUFFP) since 1973. Thus, the most reliable technical information about multiphase flow in pipes is reserved for the JIP members. Additional data obtained from research in the academic world make their way into journal papers although to a limited extent. For these reasons, the most prestigious commercial codes in the market today tap experimental data through the JIP to fill the gap left between conservation principles and the number of unknowns, that is, valuable closure equations.
1.3.2 Multidimensional Fluid Flows
The standard practice to deal with the intractable three-dimensional field of multiphase flow has led most practitioners to focus on 1-D models. This strategy simplifies the governing equations for system’s sections with large L/D ratio and makes the set amenable to mathematical solution. However, there is a price for this simplification in terms of additional closure equations to compensate for the loss of multidimensional information. In general, the 1-D models rely on the cross-sectional integral methodology.
Given that most production systems are exceedingly long compared to the piping ID, the 1-D axis-line approach has gained overwhelming acceptance for multiphase flow simulations. More recently, since 2016, two-dimensional (2-D) and quasi-three-dimensional (Q3D) analyses are becoming commercially available, obviously adding noticeable computation time if the full production system is simulated. For the simulation of specific pipeline accessories (e.g. a choke) with sudden changes in flow properties and geometry, the preferred option is computational fluid dynamics (CFD) code, enabling either Eulerian or Lagrangian formulations of the gas–liquid–solid flow field over a huge amount of nodes/cells.
The hold-up property (or its converse, the void fraction) captures part of the essence of the topology challenge. The 1-D hold-up is defined as the ratio of the cross-sectional pipe area occupied by the liquid(s) phase to the total cross-sectional area. This parameter embodies the relative weight of liquid(s) and gas phases to estimate important mixture properties such as density, viscosity, and thermal conductivity.
The other challenge of the flow topology is to identify distinctive flow regimes with common similarities in phase distribution. The objective is to have a limited number of flow patterns with common characteristics to apply specific models that capture the core of each regime. The best option to focus on flow topology is to identify either dispersed flows or separated flows (Brennen, 2005). A dispersed flow comprises bubbles in a continuous liquid phase or droplets in a continuous vapor phase. The dispersed flow regime is more difficult to represent due to the numerous particles interacting with the continuous phase and among themselves. The separated flow consists of two continuous phases exchanging transport phenomena (mass, momentum, and energy).
1.3.3 Time Fluctuations
The standard multiphase flow modeling approach rests on the assumption that the time scale of interest is orders of magnitude larger than the turbulence frequency of the smallest eddies. Nevertheless, the fluctuating nature of intermittent flow and the phases’ topology pose daunting challenges.
Rigorous modeling of the instantaneous multiphase flow properties and parameters is unfeasible. A time-filtering methodology, similar to the traditional velocity fluctuations smoothing technique for turbulent flows, is necessary to obtain a well-approximated set of equations with reasonable computation time. We can speculate that commercial codes work utilizing time-filtering techniques for multiphase flow parameters, but without access to the code program, it is not possible to confirm such conjecture.
1.3.4 Slow Transients
One important simplification of the dynamic performance of multiphase flow is the distinction between fast and slow transients. Transient operations are planned and executed to change the production flow rate from state A to state B.
An example of a transient operation is a well startup, originating from a shut-in state and aiming to achieve a target production rate. This example may be regarded as a slow transient because the rate of change in fluid properties is gradual, and there are no appreciable compressibility phenomena. Similar examples are quite common in the industry, such as well shutdown, system planned shutdown, ramp-up, and system pigging, among others. In general, most transient field operations could be classified as slow transients and are characterized by their time and velocity scales.
On the other hand, a fast transient is triggered by an abrupt change in operation, involving substantial elastic phenomena (i.e. compressibility) in the bulk of the fluid. In fast transients, fluid compressibility dominates over the friction and gravity factors, and wave perturbations travel at very high velocities labeled the speed of sound. Such waves are usually modeled assuming that the fluid compressibility is an elastic phenomenon transmitted via isentropic processes. Fast transients have very small characteristic time and very large characteristic velocity (i.e. speed of sound), quite the opposite of slow transients. One example of a fast transient is when bulk fluid is subject to exceedingly high acceleration due to the rupture (loss of containment) of a pipeline operating at high pressure, followed by the system inventory blowdown. In this example, at the rupture location, gas could attain the speed of sound, and the flow is considered “choked,” which means that the phenomenon is not controlled by the downstream (surroundings) conditions but rather by the upstream conditions.
It is important to point out that localized choked flow may occur at pipeline accessories, having a small flow cross area, despite the pipeline being operated under a steady state. This scenario happens when gas flows through a choke valve partly open, and the production flow rate remains constant because the fluid(s) cannot flow faster than the speed of sound.
A simple criterion to identify a slow transient from a fast transient is the criterion expressed by equation (1.1), if it holds across the entire production system.
1.3.5 Compositional Simulation
An exact representation of the fluid properties is never possible with state-of-the-art thermodynamic modeling, although impressive approximations are nowadays feasible with cubic equations of state (EOS) and newer PC-SAFT EOS. Exact representation means, in this regard, the capability to precisely match all laboratory results of the PVT routine assays. For this reason, before multiphase simulations of multicomponent pipeline flow are attempted, it is necessary to characterize the fluid composition with a number of pseudo-components to enable the equation to state to reproduce the lab assays performed. This characterization process is painstaking and does not always guarantee that all lab test results can be replicated with the EOS chosen.
The customary way to generate look-up fluid properties tables has been to perform pressure-temperature flashing calculations. This is the preferred approach to save time during thermo-hydraulics modeling, instead of calculating thermodynamic equilibrium at each point and for every time step. However, there are several instances in which the compositional simulation is needed at the excessive cost of computational time; one example is when commingling vastly different streams at a node. A newer trend that adds accuracy to the properties estimations for single-component systems is based on pressure–enthalpy relationships.
1.4 Hydrocarbon Flow
Multicomponent mixtures of hydrocarbons show a variety of pipe flow characteristics not found in single-phase flow. At one end, we have live oil carrying dissolved light hydrocarbons that are released from solution by pressure and temperature changes. This process generates a two-phase flow with marked characteristics of oil properties. Once the dissolved gas and any possible water are removed in a process plant, the remaining oil phase is known as dead oil and shows fluid properties of single-phase flow, just as the gas and water will do as well.
On the other end, we have gas-condensate fluids with prevalent fluid properties of the gas phase, although along the production system will drop liquid hydrocarbon condensate. Between these two limits, any combination of fluid properties can arise adding to the complexity of the simulations.
1.5 Modeling Approaches
The challenges aforementioned define a strategy to model hydrocarbon flows based on a set of abridging assumptions. These assumptions have proved to yield reasonable modeling results in agreement with field measurements while making the set of equations tractable for calculations. The principal assumptions are as follows:
The representation of the thermodynamic fluid properties using cubic EOS,
The interpolation of fluid properties from look-up
P
–
T
tables to save computing simulation time,
The use of a point-to-point compositional model to predict fluid properties for unusual cases such as fluid blending, gas-condensate flows, and processes with high acceleration effects (e.g. blowdown),
One-dimensional fluid flow to simulate long spans of pipelines,
Slow-transient operations without wave phenomena,
Division of production system domain into cells small enough to consider uniform properties within the control volume,
Explicit integration schemes with small time-integration steps to satisfy the
Courant–Friedrich–Lewy
(
CFL
) condition (Peyret,
1983
),
Implicit integration schemes to warrant computational stability with methodologies such as Crank–Nicholson (Peyret,
1983
), but at the cost of handling large sparse matrices,
Closing the set of equations by means of complementing closure equations and jump conditions (e.g. hold-up correlations),
Using flow-regime-specific correlations to close a system of equations (mechanistic approach),
Heat transfer to the environment is accounted for through an energy equation, in order to predict temperature changes along the flowline which introduce major changes in phases’ composition, and
Neglecting heat-transfer transient effects in pipeline steel and thermal-insulation coatings (to be addressed later).
In the next sections, use of the assumptions listed is made to present two-phase flow models applicable to quasi-horizontal, inclined, and vertical flow.
References
Brennen, C. (2005).
Fundamentals of Multiphase Flow
. Cambridge, UK: Cambridge University Press.
Lahey, R. and Moody, F. (1993).
The Thermal-Hydraulics of a Boiling Water Nuclear Reactor
, 2e. La Grange Park, Illinois, USA: American Nuclear Society.
Peyret, R. (1983).
Computational Methods for Fluid Flow
. New York, NY, USA: Springer-Verlag.
Tong, L. and Tang, Y. (1997).
Boiling Heat Transfer and Two-Phase Flow
, 2e. Washington, D.C., USA: Taylor and Francis Publishers.
2Fundamentals of Multiphase Flow
The following sections address the basis for having a solid foundation to simulate multiphase flow in pipelines that unfolds in subsequent chapters. The topics covered herein are as follows:
Examples of multiphase flow in the oil and gas industry
Nomenclature of multiphase flow
Strategy to model multiphase flow
Measurement techniques for two-phase flow
2.1 Multiphase Flow in the Production of Oil and Gas
In the oil and gas industry, the production activity from the reservoir to the fluid processing facilities might encompass several phases, namely oil, natural gas, produced water, sand fines, and potentially other solid particles resulting from the precipitation of heavy ends.
Multiphase flow may be present in various places along the production path of oil and gas. First, in the reservoir, there may exist a gas cap when the trapped fluid is below the bubble point, leading to the production of a two-phase flow from the reservoir. Multiphase flow in porous media is beyond the scope of this book and will not be addressed. Second, in the tubing string of a production well, gas may progressively separate from the bulk of the hydrocarbon liquid due to the pressure loss in the ascending flow. In this case, the wellhead flowing pressure would be below the bubble point of the mixture. The flow may adopt different patterns (Figure 2.1) depending on the relative amount of gas and liquid, as well as on the average velocities of each phase. Third, the production system is quite likely to have flowing mixtures of multiphase flow, in particular at the production riser of offshore facilities.
Figure 2.1 Flow regimes in vertical flow.
The regimes in vertical flow are strongly influenced by gravity and tend to form axisymmetric patterns. The presence of phases in the well string determines local mixture density, hold-up, and total pressure drop. Therefore, the well production depends on the driving pressure gradient imposed by both the single- and the two-phase flow sections. The latter is always larger than the single-phase flow gradient, and the point within the well at which the bubble point is reached is key to knowing which regime is dominating the performance.
Downstream of the well choke, there is a production system comprising flowlines (and a riser for offshore wells). In offshore fields, subsea wells tie well trees to a subsea manifold via subsea flowlines. For onshore fields with multiple wells, a gathering system collects production from the cluster via flowlines that deliver the hydrocarbons to a battery station (Figure 2.2) where gas and liquids are separated.
Figure 2.2 Partial view of onshore gathering system.
