Gas-liquid two-phase flow occurs in both onshore and offshore crude oil and natural gas production and transportation facilities. In an offshore oil and gas production facility, pipeline-riser systems are required to transport two-phase hydrocarbons from subsurface oil and gas wells to a central production platform. Severe slugging reaching several thousands pipe diameters may occur when transporting gas and liquid in these pipeline-riser systems.

Severe slugging creates potential problems in the platform facilities, e.g. separators, pumps and compressors. Severe slugging may cause overpressurization of the separator, rupture of the pipe, and an increased back pressure at the wellhead. All of these might lead to the complete shutdown of the production facility. Therefore, the accurate predictions of severe slugging characteristics, e.g. slug length, oscillatory period, are essential for the proper design and operation of two-phase flow in the pipeline-riser systems.

LedaFlow is a new dynamic multiphase flow simulator for wells and flowlines. Based on models that are closer to the actual physics of multiphase flow, LedaFlow provides a step change in fidelity, quality, accuracy and flexibility over current generation multiphase flow simulation technology. This increase in model definition provides the engineer with much greater understanding of the flow in wells and pipelines.

First of all, the experimental data acquired at IMFT published by J.Fabre and L.L. Peresson was used to validate Ledaflow 1.3 software. The same experimental results were obtained using the numerical simulation by Ledaflow.

A full updated tutorial (12/03/2013) of the new version 1.3 of Ledaflow has been created.

Then, the focus was on three points with small gas and liquid flow rates referring to J.Fabre and L.L Peresson article. Three Turndown curves were traced for each point with the same gas and liquid mass fraction but with different gas and liquid flow rate.

Using these curves and transient simulations by Ledaflow, a flow map was created to distinguish the stable zone, the transient zone and the unstable zone (severe slugging).

Studies were made to compare the geometry effect on the results already found, once by doubling the length of the pipe by two and another time by doubling the height of riser by two. 

The next Video was filmed at LISBP, INSA Toulouse for an experimental installation to capture the severe slugging phenomena.



Flow Assurance

Why Flow Assurance is needed?

Flow assurance is an engineering analysis process that is used to ensure that hydrocarbon fluids are transmitted economically from the reservoir to the end user. Because of the high pressures and low temperature in deep water, flow assurance is the most critical task during the transport of hydrocarbon fluids. It focuses mainly on the prevention and the control of concern, such as hydrates, wax, and asphaltenes, sometimes scale and sand are also included. For a given hydrocarbon fluid, these solids appear at certain combinations of pressure and temperature and they deposit on the walls of the production equipment and flowlines. 

Figure 1-1 shows the hydrate and wax depositions formed in hydrocarbons flowlines, which ultimately may cause plugging and flow stoppage.

Figure 1-1 Solid Depositions Formed in Hydrocarbon Flowline

Types of Flow Pattern

Two-Phase Vertical Flow Patterns

The most familiar two-phase flows in petroleum production are gas-water flow and oil-water flow. In our study, we focus on the gas-water vertical flow patterns.

Two-phase flow in vertical pipelines may be categorized into five different flow patterns, as shown in figure 1-2 and listed here: Bubble flow, Slug flow, Churn flow, Froth flow and Annular flow.

This plot is helpful for understanding the phenomena, several flow regimes are identified on the map such as annular flow at very high gas rates and very low liquid rates & bubble flow at very low gas rates. Also note the large zone of intermittent/slug/churn flow in the center of the plot.


            Figure 1-2 Flow regime transition criterion for upward two-phase flow in vertical tube

            Source :


                                           Figure 1-3 Slug flow pattern in vertical pipes


In our study, we are interested in the slug flow pattern in vertical pipes and risers, figure 1-3. In vertical flow, the bubble is an axially symmetrical bullet shape that occupies almost the entire cross-sectional area of the tubing. The velocity of the gas bubbles is greater than that of the liquid slug, thereby resulting in a liquid holdup that not only affects well and riser friction losses but also flowing density.



Severe Slugging

What is Severe Slugging?

At low gas and liquid flow rates, unsteady state flow may occur in such two-phase pipeline-riser systems. The cyclic unsteady state flow characterised by large-amplitude, relatively long-period pressure and flow rate fluctuations is know as severe slugging.

At relatively low flow rates, liquid accumulates at the bottom of the riser, blocking the gas, until sufficient upstream pressure has been built up to surge the liquid slug out of the riser followed by gas surge. After fluid and gas surge, part of the liquid in the riser falls back to the riser base to create a new blockage and the cycle repeats. This transient cyclic phenomenon causes period of no liquid and gas production at the riser top followed by very high liquid and gas surges, and is called severe slugging.

Figure 1 shows the different stages of a cycle of severe slugging 

Fig. 1 : Stages of Severe Slugging

Types of Severe slugging

Severe Slugging of type 1

To highlight the differences between all types of severe slugging, we can better describe a cycle of SS1 in five stages: (1) Blockage of the riser base ; (2) slug growth; (3) liquid production; (4) fast liquid production; (5) gas blowdown. In Fig. 2 these five stages are illustrated.

Fig. 2: Stages for severe slugging of type 1 (a) a graphical illustration (b) marked on a cycle of an experimental riser $\Delta\:P$ trace (USL​=0.2 m/s & USG0​ =1 m/s)

Severe Slugging of type 2

The transitional severe slugging of type 2 is qualitatively similar to SS1, but the slug length is shorter than the height of the riser and it often has intermittent unstable oscillations. In Fig. 3 four stages of SS2 are illustrated. 

Fig. 3: Stages for severe slugging of type 2 (a) a graphical illustration (b) marked on a cycle of an experimental riser $\Delta\; P$ trace (USL= 0.10 m/s & USG​=2.00 m/s)

Severe Slugging of type 3

We describe a cycle of SS3 in four stages: (1) transient slugs; (2) aerated slug growth; (3) fast aerated liquid production; (4) gas blowdown. In Fig. 4 these four stages are illustrated.

Fig. 4: Stages for severe slugging of type 3 (a) a graphical illustration (b) marked on a cycle of an experimental riser $\Delta P$ trace (USL= 0.39 m/s & USG​=2.33 m/s)


Severe Slugging Risks

Severe slugging creates potential problems in the platform facilities downstream of the riser top which have been designed to operate under steady state conditions, e.g. separators, pumps and compressors. During the liquid and gas surges, the peak flow rates might cause overpressurization of the separator, which consequently might lead to the complete shutdown of a production facility. Moreover, an increased back pressure at the wellhead may lead to the end of the production and abandonment of the well. These repeating impacts provoke a faster mechanical fatigue and can eventually lead to a rupture.

Therefore, the accurate prediction of severe slugging characteristics is essential for the proper design and operation of two-phase flow in these systems