Flow Assurance in Pipelines : A Reference Guide.

Format:

Book

Author/Creator:

Mokhatab, Saeid.

Language:

English

Subjects (All):

Petroleum pipelines.

Pipelines.

Physical Description:

1 online resource (910 pages)

Edition:

1st ed.

Place of Publication:

Chantilly : Elsevier, 2025.

Summary:

Flow assurance is critical for effective design and operation of hydrocarbon production and transmission systems.The aim is to ensure safe and economical flow of hydrocarbon fluids from the source to the markets.

Contents:

Intro

Flow Assurance in Pipelines

Copyright

Dedication

Contents

With contributions by

About the authors

Preface

Acknowledgments

Part I: Fundamentals

Chapter 1: Pipeline Transportation of Hydrocarbons

1.1. Introduction

1.2. Hydrocarbon production

1.2.1. Reservoir boundary conditions

1.2.2. Reservoir decline

1.2.3. Increment of gas-oil ratio

1.2.4. Reservoir pressure maintenance

1.2.5. Well nodal analysis

1.2.6. Produced water disposal

1.2.7. Delivery point boundary condition

1.2.8. Upstream processing

1.2.9. Production delivery to downstream processing facilities

1.2.10. Chemical injection

1.2.11. Midstream products

1.3. Types of wells

1.4. Hydrocarbon transmission

1.4.1. Flowlines

1.4.2. Other elements of the gathering system

1.4.3. Risers

1.4.4. Test line

1.5. Export pipelines

1.5.1. Gas pipelines

1.5.2. Crude oil pipelines

1.6. Pipelines layout

1.6.1. Environmental conditions

1.6.2. Bathymetry and terrain profile

1.7. Pipeline installation

1.8. Pipeline maintenance

References

Chapter 2: PVT and Phase Behavior of Petroleum Fluids

2.1. Introduction

2.2. Fluid composition

2.3. Phase behavior

2.3.1. Pure component

2.3.2. Binary mixtures

2.3.3. Multicomponent fluids

2.4. Classification of petroleum fluids

2.4.1. Oil systems

2.4.2. Retrograde condensate gas

2.4.3. Wet and dry gas

2.5. Compositional analysis, PVT experiments and correlations

2.5.1. Definitions

2.5.2. Compositional analysis

2.5.3. PVT experiments

2.5.3.1. Flash vaporization

2.5.3.2. Differential liberation

2.5.3.3. Separator tests

2.5.3.4. Constant volume depletion

2.5.4. Black oil correlations

2.5.4.1. Bubble point pressure

2.5.4.2. Oil formation volume factor

2.5.4.3. Solution gas-oil ratio.

2.5.4.4. Oil viscosity

2.6. Phase equilibria and equation of state

2.6.1. Equilibrium calculations

2.6.2. Cubic equations of state

2.6.3. Other equations of state

2.6.3.1. Statistical associating fluids theory

2.6.3.2. Cubic plus-association approach

2.6.3.3. Multiparameters equation of state

2.6.4. Multiphase isothermal flash

2.7. Fluid characterization

2.7.1. Critical and physical properties estimation

2.7.1.1. Critical properties estimation

2.7.1.2. Molecular weight estimation

2.7.1.3. Acentric factor estimation

2.7.1.4. Characterization methods based on PNA determination

2.7.1.5. Method selection

2.7.2. Splitting and lumping processes

2.7.2.1. Splitting process

2.7.2.2. Lumping process

2.8. Physical and transport properties

2.8.1. Density

2.8.1.1. Density determination

Experimental measurements

Estimation tools

Correlations

Equations of state

2.8.2. Enthalpy and heat capacity

2.8.3. Joule-Thomson coefficient

2.8.4. Speed of sound

2.8.4.1. Derived properties of a fluid

2.8.5. Viscosity

2.8.5.1. Hydrocarbon and gas viscosities

Residual viscosity theory

One reference fluid

Two reference fluids

Extended corresponding states (ECS) theory

Lennard-Jones model for mixtures

2.8.5.2. Water and produced water viscosities

2.8.5.3. Oil-water emulsion viscosities

2.8.6. Thermal conductivity

2.8.6.1. One reference fluid

2.8.6.2. Extended corresponding states (ECS) theory

2.8.7. Interfacial tension/surface tension

2.8.7.1. Gas-oil surface tension

2.8.7.2. Oil-water surface tension and gas-water surface tension

Chapter 3: Hydrocarbon Flow in Pipelines

3.1. Introduction

3.2. Single-phase one-dimensional flow for uniform diameter pipeline

3.2.1. Continuity equation

3.2.2. Momentum equation.

3.2.3. Energy equation

3.3. Two-phase flow

3.3.1. Two-phase flow occurrence during hydrocarbon transportation

3.3.2. Two-phase flow terminology

3.3.2.1. Mass conservation

3.3.2.2. Velocities

3.3.2.3. Densities

3.3.2.4. Mixture viscosity

3.3.2.5. Momentum

3.3.2.6. Shear stress and friction factor

3.3.2.7. Geometry

3.3.2.8. Pressure-drop

3.3.2.9. Heat transfer

3.3.3. Two-phase flow conservation equations-Integral models

3.3.3.1. Mass conservation

3.3.3.2. Momentum conservation

3.3.3.3. Energy conservation

3.4. Two-phase flow patterns

3.4.1. Gas-liquid flow in horizontal piping

3.4.1.1. Baker (1954) map

3.4.1.2. Mandhane et al. (1974) map

3.4.1.3. Taitel and Dukler (1976) map

3.4.2. Gas-liquid flow in vertical upward piping

3.4.2.1. Hewitt and Roberts (1969) map

3.4.2.2. Govier and Aziz (1972) map

Flow pattern map examples

3.4.3. Gas-liquid flow in inclined piping

3.4.4. Gas-condensate flow regimes

3.5. Two-phase flow conservation equations-Differential models

3.5.1. Homogenous equilibrium model (HEM)

3.5.1.1. HEM mass conservation

3.5.1.2. HEM momentum conservation

3.5.1.3. HEM energy conservation

3.5.2. Drift-flux model (DFM)

3.5.2.1. Vertical upward pipe flow concentration parameter (any regime)

3.5.2.2. Vertical upward bubbly flow drift-velocity

3.5.2.3. Vertical upward slug flow drift-velocity

3.5.2.4. Vertical upward churn flow drift-velocity

3.5.2.5. Vertical upward annular flow drift-velocity

3.5.2.6. Horizontal pipe flow

3.5.3. Two-fluid model (2FM)

3.5.3.1. 2FM liquid-phase mass conservation

3.5.3.2. 2FM gas-phase mass conservation

3.5.3.3. 2FM liquid-phase momentum conservation

3.5.3.4. 2FM gas-phase momentum conservation

3.5.3.5. 2FM liquid-phase energy conservation.

3.5.3.6. 2FM gas-phase energy conservation

3.5.4. Mixture flow (separate flow) model

3.5.4.1. Mixture model mass conservation

3.5.4.2. Mixture model momentum conservation

3.5.4.3. Mixture model energy conservation

3.5.5. Mechanistic models

3.5.6. Legacy models

3.5.6.1. Beggs and Brill (1973) model

3.5.6.2. Brill and Mukherjee (1999) model

3.5.6.3. Hasan and Kabir (2002) model

3.6. Heat transfer in pipelines

3.6.1. Internal heat transfer coefficient

3.6.1.1. Single-phase turbulent flow forced convection

3.6.1.2. Single-phase laminar flow forced convection

3.6.1.3. Two-phase disperse-bubble flow in horizontal pipe

3.6.1.4. Two-phase stratified flow in horizontal pipe

3.6.1.5. Two-phase slug flow in horizontal flow

3.6.1.6. Natural convection in stagnant fluid in horizontal pipe

3.6.1.7. Forced convection in vertical two-phase flow

3.6.2. External heat transfer coefficient

3.6.3. Buried pipelines

3.6.4. Insulation materials and coatings

3.6.5. Active pipelines heating

3.6.6. Predicting temperature profile of two-phase flow pipelines

3.7. Thermohydraulic simulations workflow

Chapter 4: Flow Assurance Concept

4.1. Introduction

4.2. Importance of flow assurance

4.3. Flow assurance principal constraints

4.4. Flow assurance tasks

4.5. Pipeline design

4.6. Pipeline operations

4.6.1. Normal operation

4.6.2. Transient operations

4.6.2.1. Well shutdown

4.6.2.2. Production and transmission system shutdown

4.6.2.3. Well start-up

4.6.2.4. Production and transmission system start-up

4.6.2.5. Flowlines cooldown

4.6.2.6. Changes in production rate

4.6.2.7. Pigging

4.6.2.8. Production system venting

4.6.2.9. Trapped fluid displacement

4.6.2.10. Line packing

4.6.2.11. Other transient operations in pipelines.

4.7. Safe operation

4.8. Environmental concerns

4.9. Flow assurance methodology

4.10. Prework

4.11. Fluid sampling

4.12. Laboratory analyses

4.13. Concept definition

4.14. Flow assurance strategy

4.14.1. Prediction

4.14.2. Prevention and mitigation

4.14.3. Remediation

4.14.4. Optimization

4.14.5. Scenario modeling

4.14.6. Operability assurance

4.15. Flow assurance outlook

Part II: Fluid Related Risks

Chapter 5: Gas Hydrates

5.1. Introduction

5.2. Hydrate thermodynamics and structures

5.2.1. Gas hydrate formation and stability zone

5.2.2. Where can gas hydrates form?

5.2.2.1. Drilling

5.2.2.2. Production and transportation

5.2.3. Common structures of gas hydrates

5.2.4. Hydrate formers

5.2.5. Other hydrate structures and structure transition

5.2.6. Hydration number

5.3. Water content determination of natural gas system

5.4. Predicting the hydrate stability zone and phase equilibria

5.4.1. Hand calculation methods

5.4.2. Computer aided-Thermodynamic modeling

5.5. Hydrate prevention techniques

5.5.1. Water removal

5.5.2. Pipeline system depressurization

5.5.3. Thermal methods

5.5.4. Chemical methods

5.5.4.1. Thermodynamic inhibitors

Thermodynamic hydrate inhibitor selection

Prediction of inhibitor requirements

5.5.4.2. Low-dosage hydrate inhibitors

Kinetic hydrate inhibitors (KHIs)

Antiagglomerants (AAs)

5.6. Case history

Chapter 6: Petroleum Waxes

6.1. Introduction

6.2. What is petroleum wax?

6.2.1. Wax appearance temperature versus wax disappearance temperature

6.2.2. Pour point

6.2.3. Wax precipitation and deposition

6.3. Phase behavior of wax in petroleum fluids

6.4. Measurement of WAT and WDT

6.5. Thermodynamic of wax precipitation

6.5.1. Thermodynamic modeling.

6.5.1.1. UNIQUAC model.

Notes:

Description based on publisher supplied metadata and other sources.

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ISBN:

0-323-99389-3

9780323993890

OCLC:

1559218691