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Multiphase Flow in Pipes

In pipeline transportation, multiphase flow commonly occurs due to pressure and temperature variations, especially gathering and transmission pipeline systems where the phase separation is not complete.  Multiphase flow refers to the phenomenon when more than one phase flow together in a pipeline system.  It can be gas-liquid (gas-oil or gas-water) two-phase flow, oil-water two-phase flow, gas-oil-water three-phase flow, or gas-oil-water-solid four-phase flow.  When multiple phases flow together in a pipeline, it may establish different flow behavior, which can be explained by flow patterns.  Flow pattern refers to the liquid phase distribution over the cross-sectional area of a pipe.  It depends on the flow rates, pipeline inclination angle and diameter, and also fluid properties.  

A typical two-phase (gas-liquid) flow pattern map for a horizontal and near-horizontal pipeline is shown in the figure below.  The typical flow patterns are:

  • Dispersed bubbles
  • Intermittent flow (can be subdivided into plug flow, slug flow, and pseudo-slug flow)
  • Segregated flow (can be subdivided into stratified flow and annular flow)
A classic flow pattern map in horizontal pipes

Dispersed bubble flow occurs at high liquid flow rates but low gas flow rates, in which the gas is dispersed as bubbles in the liquid phase.  In segregated flow, gas and liquid phases flow separately.  Segregated flow can be divided into stratified flow and annular flow. Stratified flow occurs at low gas and liquid flow rate conditions, where liquid mostly settles at the bottom of the pipe because of gravity.  Annular flow occurs at high gas flow rate conditions, where the liquid phase is flowing surrounding the entire pipe wall.  Intermittent flow is characterized by an alternate flow of liquid and gas.  The liquid plugs (without any gas bubbles) or slugs (with entrained gas bubbles) fill the entire cross-sectional area of the pipe and are separated by large gas pockets. Pseudo-slug flow occurs near the transition between the slug and segregated flows, in which the liquid slugs cannot fully fill the entire cross-sectional area of the pipe. 

The flow patterns in vertical pipes are mainly bubble, slug, churn, and annular flows.  Since the pipeline systems are mainly small inclination angle dominated, we will not explain them in this section. The pressure loss for multiphase flow is largely dependent on the flow pattern.  Therefore, the understanding of flow patterns is of great importance to accurately predict pressure drop in pipeline systems.

Multiphase flow can induce several flow assurance problems, such as liquid accumulation, severe slugging in a pipeline-riser system, and rheological problems. 

Liquid accumulation

Liquid accumulation can occur at the lower spots in a pipeline system when the gas flow rate is not high enough (Figure 1).  The accumulated water can cause pipeline internal corrosion, which is one of the major causes of pipeline failure.  Besides, liquid accumulation can also induce intermittent flow, resulting in pressure fluctuations that can promote pipeline fatigue failures, and increase the risk of downstream facility flooding.

Figure 1. Possible location for water accumulation at a lower spot

Terrain and severe slugging

Terrain slugging occurs at low gas flow rate conditions which is induced by undulating or hilly-terrain pipeline configurations.  It is a cyclical phenomenon characterized by the production of a large amount of liquid, followed by a large volume of gas blowout. Severe slugging is an extreme case that occurs in a pipeline-riser system.  Figure 2 explains a typical severe slugging cycle. It starts with slug formation at the riser base, followed by a slug growth and liquid production period after the liquid phase reaches the surface separator. During this period, the gas pressure at the riser base increases.  When the pressure is sufficient to enable gas to penetrate into the riser, rapid liquid production occurs, which is also called gas blowout.  Since it happens very fast, there is a high risk of surface separator flooding if the slug body is larger than the separator capacity.  After gas blowout, liquid starts to fall back and accumulates at the riser base. Another cycle starts.  Severe slugging occurs in a certain range in a flow pattern map.  It is crucial to ensure that the operating condition is outside of severe slugging conditions to minimize the risk of surface separator flooding.

Figure 2. Severe slugging

Rheological problems

Water-in-oil emulsion can increase the mixture viscosity significantly, which raises energy or pump power required to pump it for a long distance. Figure 3 shows the variation of emulsion viscosity as a function of water fraction.  The pike at around 53% of water content represents the inversion point, where the emulsion changes from water-in-oil to oil-in-water from left to right.  For water-in-oil emulsion, the viscosity of the mixture increases with increasing water fraction.  Oil-in-water emulsion has a much smaller viscosity compared with water-in-oil viscosity because the continuous phase, water, is less viscous.  Emulsion transportation is one of the problems in heavy crude oils because it has more natural surfactants (such as asphaltene, wax, resin, etc., as aforementioned) that stabilize the emulsion.  Heavy oil transportation may require special technologies to reduce the pump power requirement.  Some example technologies are dilution using light oil, heating which can reduce viscosity, or adding drag reducing additives that reduce friction losses.

Figure 3. Variation of emulsion viscosity with water content percentage