8.1 Multiphase flow in pipelines

Multiphase flow in pipelines involves multiple phases flowing together, like gas and liquid. This complex phenomenon is crucial in oil and gas production, where mixtures of hydrocarbons and water flow through pipes. Understanding flow regimes, pressure gradients, and phase interactions is key to efficient pipeline design and operation.

This topic covers various aspects of multiphase flow, including flow types, key parameters, and modeling approaches. We'll explore flow regimes in horizontal, vertical, and inclined pipes, as well as methods for predicting pressure gradients, liquid holdup, and flow behavior in different regimes like slug, annular, and stratified flow.

Types of multiphase flow in pipelines

• Multiphase flow in pipelines involves the simultaneous flow of two or more phases, such as gas-liquid, liquid-liquid, or gas-liquid-solid mixtures
• The behavior and characteristics of multiphase flow depend on factors such as the properties of the fluids, the flow rates, and the pipeline geometry
• Common types of multiphase flow in pipelines include gas-liquid flow (natural gas and oil), liquid-liquid flow (oil and water), and gas-liquid-solid flow (gas, oil, and sand)

Key parameters of multiphase pipeline flow

Superficial velocities of phases

Top images from around the web for Superficial velocities of phases

• 

  Frontiers | Petrological Geodynamics of Mantle Melting I. AlphaMELTS + Multiphase Flow: Dynamic ... View original

  Is this image relevant?

• 

  Fluid Dynamics – University Physics Volume 1 View original

  Is this image relevant?

• 

  Computer Simulation of the Multiphase Flow in a Peirce-Smith Copper Converter View original

  Is this image relevant?

• 

  Frontiers | Petrological Geodynamics of Mantle Melting I. AlphaMELTS + Multiphase Flow: Dynamic ... View original

  Is this image relevant?

• 

  Fluid Dynamics – University Physics Volume 1 View original

  Is this image relevant?

1 of 3

Top images from around the web for Superficial velocities of phases

• 

  Frontiers | Petrological Geodynamics of Mantle Melting I. AlphaMELTS + Multiphase Flow: Dynamic ... View original

  Is this image relevant?

• 

  Fluid Dynamics – University Physics Volume 1 View original

  Is this image relevant?

• 

  Computer Simulation of the Multiphase Flow in a Peirce-Smith Copper Converter View original

  Is this image relevant?

• 

  Frontiers | Petrological Geodynamics of Mantle Melting I. AlphaMELTS + Multiphase Flow: Dynamic ... View original

  Is this image relevant?

• 

  Fluid Dynamics – University Physics Volume 1 View original

  Is this image relevant?

1 of 3

• Superficial velocity is the velocity of a phase assuming it occupies the entire cross-sectional area of the pipeline
• Calculated by dividing the volumetric flow rate of a phase by the cross-sectional area of the pipeline
• Superficial velocities are used to characterize the flow rates of individual phases in multiphase flow

In-situ phase fractions

• In-situ phase fractions represent the actual volume fraction of each phase present in the pipeline at a given location
• Determined by the ratio of the volume of a phase to the total volume of the mixture
• In-situ phase fractions are important for understanding the distribution and interaction of phases in multiphase flow

Fluid properties of phases

• Fluid properties such as density, viscosity, and surface tension significantly influence the behavior of multiphase flow in pipelines
• Density differences between phases affect the gravitational pressure gradient and phase distribution
• Viscosity impacts the frictional pressure gradient and the stability of flow regimes
• Surface tension affects the formation and stability of interfaces between phases

Pipeline geometry and inclination

• Pipeline diameter, roughness, and inclination angle have a significant impact on multiphase flow behavior
• Larger diameters generally result in lower pressure gradients and different flow regime transitions compared to smaller diameters
• Pipeline roughness influences the frictional pressure gradient and can promote or suppress certain flow regimes
• Inclination angle affects the gravitational pressure gradient and the distribution of phases along the pipeline (horizontal, vertical, or inclined)

Flow regimes in multiphase pipelines

Horizontal pipeline flow regimes

• Horizontal multiphase flow exhibits distinct flow regimes depending on the superficial velocities and fluid properties
• Common flow regimes in horizontal pipelines include stratified flow (smooth or wavy), intermittent flow (plug or slug), annular flow, and dispersed bubble flow
• The occurrence of specific flow regimes depends on the balance between gravitational, inertial, and interfacial forces

Vertical pipeline flow regimes

• Vertical multiphase flow is characterized by different flow regimes compared to horizontal flow
• Typical flow regimes in vertical pipelines include bubbly flow, slug flow, churn flow, and annular flow
• The transition between flow regimes in vertical pipelines is influenced by the gas and liquid velocities, as well as the fluid properties

Inclined pipeline flow regimes

• Inclined multiphase flow exhibits a combination of characteristics from horizontal and vertical flow, depending on the inclination angle
• Flow regimes in inclined pipelines can include stratified flow (with a tilted interface), slug flow (with elongated bubbles), and churn flow (with oscillatory behavior)
• The inclination angle affects the gravitational force component acting on the phases and can lead to unique flow regime transitions

Flow regime maps and transitions

• Flow regime maps are used to predict the occurrence of different flow regimes based on the superficial velocities of the phases
• Common flow regime maps include the Mandhane map, the Taitel-Dukler map, and the Barnea map
• Flow regime transitions occur when the balance between forces acting on the phases changes, leading to a shift from one flow regime to another
• Predicting flow regime transitions is essential for the accurate modeling and design of multiphase pipeline systems

Pressure gradient in multiphase pipelines

Gravitational pressure gradient

• The gravitational pressure gradient is caused by the elevation change along the pipeline and the density difference between the phases
• In horizontal pipelines, the gravitational pressure gradient is zero, while in vertical or inclined pipelines, it depends on the in-situ density of the mixture
• Calculating the gravitational pressure gradient requires knowledge of the in-situ phase fractions and the inclination angle of the pipeline

Frictional pressure gradient

• The frictional pressure gradient arises from the shear stress between the fluids and the pipeline wall, as well as the interfacial shear stress between the phases
• Frictional pressure gradient depends on factors such as the flow regime, fluid properties, and pipeline roughness
• Various empirical correlations and mechanistic models are used to predict the frictional pressure gradient in multiphase flow, such as the Lockhart-Martinelli correlation and the Beggs-Brill correlation

Accelerational pressure gradient

• The accelerational pressure gradient is caused by the change in kinetic energy of the fluids along the pipeline
• It is significant in cases where there is a substantial change in the velocity of the phases, such as in the case of phase change or rapid expansion/contraction of the pipeline
• The accelerational pressure gradient is usually negligible compared to the gravitational and frictional components in most multiphase pipeline flow scenarios

Liquid holdup in multiphase pipelines

Liquid holdup vs flow regimes

• Liquid holdup refers to the fraction of the pipeline volume occupied by the liquid phase
• The liquid holdup varies significantly depending on the flow regime and the operating conditions
• In stratified flow, the liquid holdup is relatively low and depends on the liquid level in the pipeline
• In slug flow, the liquid holdup is higher due to the presence of liquid slugs, which occupy a larger portion of the pipeline volume
• Annular flow typically has a lower liquid holdup compared to slug flow, with the liquid phase flowing as a film along the pipeline wall

Liquid holdup prediction methods

• Accurate prediction of liquid holdup is crucial for the design and operation of multiphase pipelines, as it affects the pressure gradient, flow assurance, and corrosion management
• Empirical correlations, such as the Beggs-Brill correlation and the Mukherjee-Brill correlation, are widely used to estimate liquid holdup based on flow conditions and fluid properties
• Mechanistic models, such as the drift-flux model and the two-fluid model, provide a more rigorous approach to predicting liquid holdup by considering the physical interactions between the phases
• Computational fluid dynamics (CFD) simulations can also be employed to predict liquid holdup, especially in complex pipeline geometries or flow conditions

Slug flow in multiphase pipelines

Slug flow characteristics and behavior

• Slug flow is characterized by the alternating flow of liquid slugs and gas pockets along the pipeline
• Liquid slugs are regions of high liquid holdup that occupy most of the pipeline cross-section, while gas pockets are regions of high gas content with a stratified liquid layer at the bottom
• Slug flow can occur in both horizontal and inclined pipelines, and its behavior is influenced by factors such as the gas and liquid velocities, fluid properties, and pipeline inclination

Slug length and frequency

• Slug length refers to the distance between the front and tail of a liquid slug, and it can vary significantly depending on the flow conditions
• Slug frequency is the number of slugs passing a given point in the pipeline per unit time
• Predicting slug length and frequency is important for the design of slug catchers, separators, and other downstream equipment
• Empirical correlations and mechanistic models, such as the Dukler-Hubbard model and the Zhang model, are used to estimate slug length and frequency based on flow parameters

Slug velocity and holdup

• Slug velocity refers to the speed at which the liquid slugs travel along the pipeline
• Slug holdup is the fraction of the pipeline volume occupied by the liquid slugs
• The slug velocity is typically higher than the average velocity of the liquid phase, as the slugs are propelled by the expanding gas pockets behind them
• Slug holdup depends on factors such as the slug length, the liquid holdup in the film region, and the gas void fraction in the slug body
• Empirical correlations and mechanistic models are used to predict slug velocity and holdup based on flow conditions and fluid properties

Slug flow pressure gradient prediction

• Predicting the pressure gradient in slug flow is essential for the design and operation of multiphase pipelines
• The pressure gradient in slug flow is influenced by the gravitational, frictional, and accelerational components, as well as the characteristics of the liquid slugs and gas pockets
• Empirical correlations, such as the Beggs-Brill correlation and the Mukherjee-Brill correlation, can be used to estimate the pressure gradient in slug flow
• Mechanistic models, such as the unit cell model and the slug tracking model, provide a more detailed approach to predicting the pressure gradient by considering the dynamics of individual slugs and the interactions between the phases

Annular flow in multiphase pipelines

Annular flow characteristics and behavior

• Annular flow is characterized by the presence of a continuous gas core flowing in the center of the pipeline, with a liquid film flowing along the pipeline wall
• The liquid film can be smooth or wavy, depending on the gas and liquid velocities and the fluid properties
• Annular flow typically occurs at high gas velocities and is common in vertical and inclined pipelines, as well as in the later stages of horizontal pipeline flow

Liquid film thickness and distribution

• The thickness of the liquid film in annular flow varies along the pipeline circumference, with the film being thicker at the bottom due to gravitational effects
• The distribution of the liquid film is influenced by factors such as the gas velocity, liquid flow rate, and pipeline inclination
• Predicting the liquid film thickness and distribution is important for understanding the heat transfer, mass transfer, and corrosion behavior in annular flow
• Empirical correlations and mechanistic models, such as the Asali model and the Alves model, are used to estimate the liquid film thickness and distribution based on flow conditions and fluid properties

Entrainment in annular flow

• Entrainment refers to the process by which liquid droplets are torn from the liquid film and carried by the gas core in annular flow
• The degree of entrainment depends on factors such as the gas velocity, liquid film thickness, and fluid properties (surface tension and viscosity)
• Entrainment can have significant effects on the pressure gradient, heat transfer, and corrosion in annular flow
• Empirical correlations, such as the Ishii-Mishima correlation and the Sawant correlation, are used to predict the entrainment fraction based on flow conditions and fluid properties

Annular flow pressure gradient prediction

• Predicting the pressure gradient in annular flow is essential for the design and operation of multiphase pipelines
• The pressure gradient in annular flow is influenced by the gravitational, frictional, and accelerational components, as well as the characteristics of the liquid film and the gas core
• Empirical correlations, such as the Lockhart-Martinelli correlation and the Friedel correlation, can be used to estimate the pressure gradient in annular flow
• Mechanistic models, such as the two-fluid model and the film thickness model, provide a more detailed approach to predicting the pressure gradient by considering the interactions between the liquid film and the gas core

Stratified flow in multiphase pipelines

Stratified flow characteristics and behavior

• Stratified flow occurs when the gas and liquid phases flow separately, with the liquid flowing at the bottom of the pipeline and the gas flowing above it
• Stratified flow is common in horizontal and slightly inclined pipelines, particularly at low gas and liquid velocities
• The interface between the gas and liquid phases can be smooth (stratified smooth flow) or wavy (stratified wavy flow), depending on the relative velocities of the phases and the fluid properties

Liquid level and interface shape

• The liquid level in stratified flow refers to the height of the liquid phase in the pipeline cross-section
• The shape of the gas-liquid interface depends on factors such as the gas and liquid flow rates, the fluid properties, and the pipeline inclination
• Predicting the liquid level and interface shape is important for understanding the pressure gradient, flow stability, and heat transfer in stratified flow
• Empirical correlations and mechanistic models, such as the Taitel-Dukler model and the Shoham-Taitel model, are used to estimate the liquid level and interface shape based on flow conditions and fluid properties

Stability of stratified flow

• Stratified flow can become unstable and transition to other flow regimes, such as slug flow or annular flow, under certain conditions
• The stability of stratified flow depends on factors such as the gas and liquid velocities, the fluid properties, and the pipeline geometry
• Instability in stratified flow can be caused by the growth of interfacial waves, leading to the formation of slugs or the entrainment of liquid in the gas phase
• Stability criteria, such as the Kelvin-Helmholtz criterion and the Taitel-Dukler criterion, are used to predict the conditions under which stratified flow becomes unstable

Stratified flow pressure gradient prediction

• Predicting the pressure gradient in stratified flow is essential for the design and operation of multiphase pipelines
• The pressure gradient in stratified flow is influenced by the gravitational and frictional components, as well as the characteristics of the gas and liquid phases
• Empirical correlations, such as the Lockhart-Martinelli correlation and the Chisholm correlation, can be used to estimate the pressure gradient in stratified flow
• Mechanistic models, such as the two-fluid model and the interface friction model, provide a more detailed approach to predicting the pressure gradient by considering the interactions between the gas and liquid phases

Dispersed bubble flow in multiphase pipelines

Dispersed bubble flow characteristics

• Dispersed bubble flow occurs when small gas bubbles are uniformly distributed in a continuous liquid phase
• This flow regime is common in vertical and inclined pipelines, particularly at high liquid velocities and low gas velocities
• The behavior of dispersed bubble flow is influenced by factors such as the bubble size distribution, bubble velocity, and fluid properties

Bubble size distribution and coalescence

• The size distribution of bubbles in dispersed bubble flow can vary depending on the flow conditions and fluid properties
• Bubble coalescence, which is the merging of smaller bubbles into larger ones, can occur due to factors such as turbulence, bubble collisions, and wake interactions
• Predicting the bubble size distribution and coalescence is important for understanding the mass transfer, heat transfer, and flow behavior in dispersed bubble flow
• Empirical correlations and population balance models are used to estimate the bubble size distribution and coalescence rates based on flow conditions and fluid properties

Bubble velocity and holdup

• Bubble velocity refers to the speed at which the gas bubbles travel in the liquid phase
• Bubble holdup is the fraction of the pipeline volume occupied by the gas bubbles
• The bubble velocity is influenced by factors such as the liquid velocity, bubble size, and fluid properties (density and viscosity)
• Bubble holdup depends on the gas flow rate, bubble velocity, and bubble size distribution
• Empirical correlations and mechanistic models, such as the drift-flux model and the two-fluid model, are used to predict bubble velocity and holdup based on flow conditions and fluid properties

Dispersed bubble flow pressure gradient

• Predicting the pressure gradient in dispersed bubble flow is essential for the design and operation of multiphase pipelines
• The pressure gradient in dispersed bubble flow is influenced by the gravitational, frictional, and accelerational components, as well as the characteristics of the gas bubbles and the liquid phase
• Empirical correlations, such as the Lockhart-Martinelli correlation and the Friedel correlation, can be used to estimate the pressure gradient in dispersed bubble flow
• Mechanistic models, such as the homogeneous flow model and the drift-flux model, provide a more detailed approach to predicting the pressure gradient by considering the interactions between the gas bubbles and the liquid phase

Modeling multiphase flow in pipelines

Empirical correlations for multiphase flow

• Empirical correlations are based on experimental data and provide simple, quick estimates of multiphase flow parameters such as pressure gradient, liquid holdup, and flow pattern transitions
• Common empirical correlations for multiphase flow include the Lockhart-Martinelli correlation, the Beggs-Brill correlation, and the Mukherjee-Brill correlation
• These correlations are often limited to the range of conditions under which the experimental data were obtained and may not accurately capture the complex physics of multiphase flow

Mechanistic models for multiphase flow

• Mechanistic models are based on the fundamental physical principles governing multiphase flow, such as conservation of mass, momentum, and energy
• These models provide a more rigorous and accurate approach to predicting multiphase flow behavior compared to empirical correlations
• Examples of mechanistic models include the two-fluid model, the drift-flux model, and the slug flow model
• Mechanistic models require a deeper understanding of the underlying physics and may involve more complex mathematical formulations and computational requirements

Computational fluid dynamics for multiphase flow

• Computational fluid dynamics (CFD) is a powerful tool for simulating multiphase flow in pipelines, providing detailed information on flow patterns, phase distributions, and local flow parameters
• CFD models solve the governing equations of fluid flow, such as the Navier-Stokes equations, using numerical methods like the finite volume or finite element method
• Multiphase CFD models can capture complex flow phenomena, such as phase interactions, turbulence, and heat transfer, and can handle complex pipeline geometries and flow conditions
• However, CFD simulations can be computationally expensive and require significant expertise in model setup, validation, and interpretation

Comparison of modeling approaches

• The