Severe slugging in the upstream industry: how to address this issue using ALFAsim (Part I)

Beginning today, ESSS O&G will publish a series of blog posts about issues most commonly found in the production area of the upstream industry. In covering topics like hydrodynamic and flow assurance problems, the main goal of these posts is to help the reader understand, identify, and address flow issues with the aid of ALFAsim, a 1D multiphase flow simulator developed by ESSS.

In this post, we discuss severe slugging, a very common flow assurance issue encountered particularly often in offshore fields due to the use of long risers fed by long lateral flowlines. Since this can be considered an extreme example of slug flow, let’s first introduce this specific flow pattern.

Slug Flow

Slug flow is characterized by the intermittent sequence of liquid slugs followed by longer gas bubbles flowing through a pipe. This flow pattern is frequently encountered in industrial applications, including in oil/gas production and transport lines and in boiler and heat exchanger tubes for energy production plants [7]. 

Classical flow maps indicate that the intermittent slug flow regime exists for a wide range of gas and liquid flow rates in a horizontal or nearly horizontal pipeline configuration, as illustrated in Figure 1. It can be generated from stratified flow by two main mechanisms: (i) liquid accumulation due to instantaneous imbalance between pressure and gravitational forces caused by pipe undulations, and (ii) natural growth of hydrodynamic instabilities. 

Figure 1: Slug flow in a horizontal pipe
Figure 1: Slug flow in a horizontal pipe [6]

The slug flow pattern in a vertical pipe is characterized by elongated bullet-shaped gas bubbles, known as Taylor bubbles, separated by liquid slugs which often contain small dispersed bubbles, as observed in Figure 2. 

Figure 2: Slug flow in a vertical pipe
Figure 2: Slug flow in a vertical pipe [9]

Due to its intrinsic transient nature, slug flow can cause severe problems in processing and transport equipment due to the intermittent loading that it imposes on these structures. Also, in hydrocarbon production lines, where the fluids transported may contain corrosive agents, slug flow can present safety risks due to damage imposed on pipe walls. It is believed that the large fluctuations in the wall shear stress generated by this flow pattern may remove protective coatings  from the pipe wall, thereby facilitating the corrosive-erosive attacks. Another characteristic resulting from this flow pattern is the pressure oscillations within the pipe.

An extreme example of this terrain-induced slug flow is called severe slugging, which happens when a slightly inclined pipeline meets a vertical riser. Severe slugging is considered a flow assurance issue and is described in further detail in the next section.

Severe Slugging

Recently, with the ever-increasing development of offshore fields, the number of long risers fed by horizontal flowlines has grown.  As a result, this type of configuration exposes the production system to an extreme case of terrain-induced slug flow, namely severe slugging. It happens particularly with a decline in reservoir pressure and, consequently, in flow rates.

Severe slugging occurs in two-phase flow through a downward-inclined flowline followed by a vertical riser at low flow rates.  In severe slugging, the liquid accumulates in the riser and curvature section of the flowline, blocking the passage of gas at the lowest point of the system.  As a result, the gas front penetrates the liquid blockage intermittently, causing extremely large slugs, severe fluctuations, and flooding of downstream equipment [1].  

The phenomenon is unstable, resulting in large pressure and flow rate fluctuations and, therefore, creating potential problems in the platform facilities, e.g. separators, pumps, and compressors. Severe slugging may cause flooding and overpressurization in the separator, pipe rupture, and increased backpressure at the wellhead. All of these issues may lead to a complete shutdown of the production facility. 

The first stage of severe slugging is  slug formation, in which a large liquid slug is formed as the liquid blocks the passage of the gas and increases its level into the riser section.  Consequently, the gas phase accumulates in the flow line and is compressed.  The liquid slug reaches the top of the riser, initiating the second stage: slug production.  In this stage, liquid is produced while the gas pocket is being pressurized for an eventual penetration into the liquid.  The third stage, or blowout, occurs once the gas pressure in the downward-inclined flow line overcomes the hydrostatic pressure of the liquid column.  In this stage, the gas pushes the liquid column violently out of the riser.  As the pressure declines in the pipeline, the fourth and last stage of the severe slugging phenomenon, liquid fallback, occurs.  At this stage, the remaining liquids fall back and accumulate at the riser base and curvature sections.  Figure 3 shows a schematic of the severe slugging phenomenon [2].

Figure 3: Severe slugging schematic
Figure 3: Severe slugging schematic [4]

To represent pressure and flow rate fluctuations in time for a typical severe slugging scenario, ESSS’s 1D multiphase flow simulator, ALFAsim, was used. For this case, the offshore system designed represented a well-flowline-riser as shown in Figure 4, which considers two-phase flow. 

Figure 4: Offshore system representation using ALFAsim
Figure 4: Offshore system representation using ALFAsim

The flowline-riser pipeline profile is designed as shown in Figure 5. It consists of a 4-km long downward-inclined horizontal flowline followed by a 2.7-km long riser. As previously mentioned, this type of configuration, combined with the reservoir pressure and flow rates’ consequent decline over time, can lead to the severe slugging phenomenon.

Figure 5: Flowline-riser profile
Figure 5: Flowline-riser profile

For this study, a fixed outlet pressure and varying inlet flow rates at a fixed GOR were considered. The goal of this simulation was to evaluate the effect of different inlet flow rates on  severe slugging behavior.

After successfully simulating the aforementioned case, it was possible to analyze the riser base absolute pressure trend plot at different inlet flow rates, as shown in Figure 6. 

Figure 6: Absolute pressure trend plot (riser base)
Figure 6: Absolute pressure trend plot (riser base)

 Flow rates of 800 and 400 m3/d represent the typical cyclic severe slugging behavior. The pressure initially increases due to the slug accumulation stage until it reaches a plateau indicating the slug production phase. This plateau is followed by a sudden pressure drop associated with the blowout and liquid fallback phases. This plot also reveals that as the flow rate decreases, the number of severe slugging cycles also decreases, while the amplitude of pressure increases for each cycle. The amplitude and sudden pressure drop may cause severe damage to processing and transport equipment and to the pipelines.

The pressure behavior at the flow rate of 1500 m3/d does not represent the severe slugging phenomenon. The steady pressure fluctuation at lower amplitude, compared to the other cases, represents regular slug flow.

From the same simulation, the outlet oil flow rate trend (representing, in this case, the liquid flow rate arriving at the process facility), was obtained (Figure 7). The intermittent outlet liquid flow rate trend shows that a severe slugging phenomenon occurs. This sudden and large amount of liquid produced could lead to process equipment flooding and damage. 

Figure 7: Total oil volumetric flow rate STD trend - severe slugging
Figure 7: Total oil volumetric flow rate STD trend – severe slugging

Due to the complexity and potentially negative outcomes of the scenario described above, accurate predictions of severe slugging characteristics (e.g. slug length, oscillatory period, etc.) are essential for the proper design and operation of two-phase flow in the pipeline-riser systems. Commercially available simulators such as ALFAsim can be used successfully for that purpose. 

To mitigate the severe slugging problem, several elimination methods have also been proposed in the literature. The first method eliminates severe slugging by increasing the system back pressure with the use of a choke valve, which leads to a reduction in the production capacity. Hassanein and Fairhurs [3] suggest foaming as another mitigation method. This method requires foaming agents (surfactants) and a foam generation method, which together will drecrease the surface tension of the liquid, allowing the gas to disperse.

Another method, gas lift, consists of injecting gas into the riser to reduce the hydrostatic column and increase the gas flow rate in the pipeline.  This method requires large amounts of gas  and has a high operational cost. Tengesdal et al. [5] tested a new approach, called self-gas lifting, to attenuate severe slugging in pipeline-riser systems by transferring the pipeline gas (in-situ gas) to the riser at a point above the riser base.  The transferring process reduces both the hydrostatic head in the riser and the pressure in the pipeline with no additional gas injection required from the platform.  The proposed method is proven very effective for severe slugging attenuation in pipeline-riser systems.

Stay tuned for the next blog posts about using ALFAsim to design severe slugging  elimination methods. 


[1] Barreto, C. V., Pimenta, A., Karami, H., Pereyra, E., & Sarica, C. 2017, May. Experimental Investigation of Severe Slugging Control by Surfactant Injection. In Offshore Technology Conference. Offshore Technology Conference.

[2] Barreto, C.V. 2016. Effect of Foamer Delivery Location on Horizontal Wells Deliquification (Master of Science Thesis, The University of Tulsa)

[3] Hassanein, T., and Fairhurst, P. 1998. Challenges in the Mechanical and Hydraulical Aspects of Riser Design for Deep Water Developments.Presented at IBC UK Conf. Ltd. Offshore Pipeline Technology Conference, Oslo, Norway.

[4] Malekzadeh, R., and Mudde, R. F. 2012. A Modelling Study of Severe Slugging in Wellbore. Presented at North Africa Technical Conference and Exhibition. Society of Petroleum Engineers.

[5] Tengesdal, J. Ø., Sarica, C., & Thompson, L. 2002. Severe Slugging Attenuation for Deepwater Multiphase Pipeline and Riser Systems. Presented at SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers.

[6] Thaker, J., & Banerjee, J. 2015. Characterization of Two-Phase Slug Flow Sub-Regimes Using Flow Visualization. Journal of Petroleum Science and Engineering, 135, 561-576.

[7] Carneiro, J. N. E., Fonseca Jr, R., Ortega, A. J., Chucuya, R. C., Nieckele, A. O., & Azevedo, L. F. A. 2011. Statistical Characterization of Two-Phase Slug Flow in a Horizontal Pipe. Journal of the Brazilian Society of Mechanical Sciences and Engineering, 33(SPE1), 251-258.

[8] Yan, K., & Che, D. 2011. Hydrodynamic and Mass Transfer Characteristics of Slug Flow in a Vertical Pipe with and without Dispersed Small Bubbles. International Journal of Multiphase Flow, 37(4), 299-325.

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Carolina Barreto

Business Development, ESSS O&G

Carolina Barreto has a Bachelor’s Degree in Chemical Engineering, from the Federal University of Rio de Janeiro, and a Master’s Degree in Petroleum Engineering, from the University of Tulsa. Spanning over 10 years of professional experience in O&G, Carolina initially worked as a process engineer to later focus on petroleum production, in which the use of simulation for engineering applications became indispensable. Carolina has been working at ESSS since 2018 and is one of the responsible for fostering partnerships between Oil & Gas companies, Universities, Research institutions and ESSS, in order to develop R&D projects related to simulation and new software technologies.

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