Severe slugging in the upstream industry: how to address this issue using ALFAsim (Part II)
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Published on: 08/04/2021
In the previous blog post, we discussed the severe slugging phenomenon, which occurs especially in mature two-phase flow offshore fields, as reservoir pressure and, consequently, the flow rates decline. It happens at a particular pipeline configuration where a downward-inclined flowline is followed by a vertical riser. At this configuration, liquid accumulates at the flowline’s curvature section, resulting in blockage of the gas passage. As pressure builds up, the gas front penetrates the liquid blockage intermittently, causing extremely large slugs, severe fluctuations, and flooding of downstream equipment [1].
To further explore this issue, we’ll introduce the reader to the main severe slugging mitigation methods and how to use commercially available software, such as ALFAsim, to design them. These flow assurance methods are the result of a simple analysis, so let’s begin by exploring the physics behind severe slugging mitigation methods.
Severe Slugging Mitigation
Based on the balance of pipeline and riser forces, Bøe [2] developed a criterion to determine the occurrence of the severe slugging phenomenon. The ratio between the rate of gas pressure increase in the flowline and the rate of hydrostatic pressure increase in the riser leads to the following equation:
where Wg and WL are the mass flow rates of gas and liquid, and HLF is the liquid holdup in the pipeline upstream of the liquid blockage. For the cases where the ΠSS value is less than 1, severe slugging is expected to occur based on this criterion.
The Bøe criterion is still widely used in the industry, and from this equation, the principles of severe slugging suppression can be determined. Based on the equation above, to eliminate the problem, the pipeline’s pressure gradient should increase and/or the riser’s pressure gradient should decrease.
In order to increase the pressure gradient in the pipeline, methods that will increase the mass flow rate of gas, reduce pipeline diameter, and increase back pressure (increase HLF) are expected to be used. To reduce the riser’s pressure gradient riser, gas lift (reduce ρRiser), foaming (reduce ρRiser), reducing mass flow rate of liquid, and increasing riser diameter should be considered.
Several elimination methods have 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 production capacity reduction. Hassanein and Fairhurst [3] suggest foaming as another mitigation method. This method requires foaming agents (surfactants) and a foam generation method, which together will lower the liquid surface tension, allowing the gas to disperse and consequently decrease the liquid density in the riser.
Another method, gas lift, consists of injecting gas into the riser to reduce hydrostatic pressure and increase the gas flow rate in the pipeline. This method requires large amounts of gas to accomplish the elimination and comes at a high operational cost. Tengesdal et al. [4] tested a new approach, named 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.
Using ALFAsim to Mitigate Severe Slugging
ESSS’s 1D multiphase flow simulator, ALFAsim, demonstrates how a choke valve and gas lift can be designed as severe slugging mitigation methods. To illustrate this, the same system used in Blog Post #1 (Severe slugging in the upstream industry: how to address this issue using ALFAsim, Part I) was utilized , as shown in Figure 1, below. A more detailed description of the system profile can be found in the previous post.
Figure 1: Offshore system representation in ALFAsim
The initial goal of this simulation was to obtain a good representation of severe slugging behavior. Trends for the absolute pressure at the riser base and the outlet total oil volumetric flow rate STD (representing, in this case, the liquid flow rate arriving at the process facility) at a fixed reservoir pressure of 335 bar, productivity index of 20 m3/bar.d, GOR of 150 sm3/sm3, were obtained, as shown in Figure 2.
Figure 2: Absolute pressure (riser base) and total oil volumetric flow rate STD (outlet) trend plots
The cyclic pressure increase (slug accumulation) until it reaches a plateau (slug production), followed by a sudden drop (blowout and liquid fallback), indicates typical severe slugging behavior. This behavior can also be inferred from the oil volumetric flow rate (sm³/d) trend plot as a large amount of liquid is produced intermittently.
Considering this result as the base case for our study, let’s examine the choke valve and gas lift simulations.
Choke Valve
The choke valve at the riser top will impose back pressure to the system that can mitigate severe slugging , depending on the valve’s opening percentage. The increased back pressure will push back the penetrated gas, allowing for control of both flow rate and pressure.
One of ALFAsim’s main features, Parametric Runs, can perform multiple simulations changing one or more parameters and show results simultaneously on the same plot. In this case, the valve opening percentage variation will be analyzed (Figure 3).
Figure 3: Parametric runs in ALFAsim (choke valve opening)
The results in Figure 4 show that as the valve closes, the pressure amplitude starts to decrease and the number of slug cycles increases over time until the absolute pressure becomes stable at 100 bar, indicating that severe slugging has been mitigated.
Figure 4: Absolute pressure at riser base (choke valve opening)
The same behavior can be observed for the outlet oil flow rate STD. A cyclic process results in which a period of no liquid production into the separator occurs, followed by a period of very high liquid production. As the valve closes, the production cycle increases, but the amount of liquid produced decreases, avoiding flooding and damage to process equipment. At a specific valve opening,the flow rate will stabilize, indicating that severe slugging has been mitigated (Figure 5).
Choking was found to effectively eliminate the severity of the slugging at a valve opening of 80%.
Gas Lift
Gas injection at the riser base will reduce the hydrostatic pressure by decreasing the liquid density and increasing the gas flow rate at the pipeline, helping mitigate severe slugging.
Using ALFAsim’s Parametric Runs feature, multiple simulations were performed by varying the gas flow rate at a Mass Source equipment located at the riser base (Figure 6).
Figure 6: Parametric runs in ALFAsim (gas lift)
As is the case with the choking results, as the gas injection rate increases, the pressure amplitude decreases, and the number of slug cycles increases over time until the pressure becomes stable at 90 bar, indicating that severe slugging has been mitigated (Figure 7).
Figure 7: Absolute pressure at riser base (gas lift)
Regarding oil being produced, although the number of slug cycles increases, the produced oil volume will be smaller as gas is injected. As previously mentioned, this will avoid process equipment flooding and damage. The outlet flow rate will stabilize when a specific amount of gas is injected, indicating that severe slugging was mitigated (Figure 8).
The results of the study presented above show that gas lift can also eliminate severe slugging effectively. This simulation demonstrated that a relatively large amount of gas (80.000 m3/d) was needed before gas injection would completely stabilize the flow through the riser.
Final remarks
The simulation results presented in this post showed that both mitigation methods investigated are effective for eliminating severe slugging. However, production engineers should also keep in mind that the the choke valve could lead to an excessive back pressure increase due to choke setting changes, leading to severe reduction in production capacity. Also, although gas lifts lead to more continuous production and lower system pressure, this method depends on the availability of injection gas, has higher CAPEX and OPEX, and can require injection gas heating n in order not to cool down the production fluids.
By keeping these considerations in mind and using numerical simulations, severe slugging mitigation can be successfully achieved.
Stay tuned for the next blog posts exploring how simulation tools can design elimination methods.
References:
[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] Bøe, A. 1981. Severe Slugging Characteristics; Part 1: Flow Regime for Severe Slugging; Part 2: Point Model Simulation Study. Presented at Selected Topics in Two-Phase Flow, Trondheim, Norway, March 1981.
[3] Hassanein, T., and Fairhurst, P. Challenges in the Mechanical and Hydraulical Aspects of Riser Design for Deep Water Developments. IBC UK Conf. Ltd. Offshore Pipeline Technology Conference, Oslo, Norway, 1998. .
[4] Tengesdal, J. Ø., Sarica, C., & Thompson, L. Severe slugging attenuation for deepwater multiphase pipeline and riser systems. In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers,2002.
[5] Jansen, F. E., Shoham, O., & Taitel, Y. (1996). The elimination of severe slugging—experiments and modeling. International Journal of Multiphase Flow, 22(6), 1055-1072.
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.
