Slugging and Liquid Handling
Contents
Slugging Flow
The occurrence of slug flow in a transportation pipeline can cause many problems in design and operation processes, which include kinetic force on fittings and vessels, pressure cycling, control instability, and inadequate phase separation. Slugging greatly affects the design of receiving facilities. In gascondensate systems, larger lines result in more liquid being retained in the pipeline at low rates. When the flow rate is increased, much of the liquid can be swept out, potentially overwhelming the liquid handling capability of the receiving facilities. The facilities can be flooded and damaged if the slugs are larger than the slug catcher capacity. Therefore, quantifying the slug size, frequency, and velocity is necessary prior to equipment design.
The pressure at the bottom of the riser can vary if the holdup in the riser is not about the same as that in the line feeding it. If the riser holdup is too large and the gas velocity is too small to provide continuous liquid lift, too much of the liquid reverses and flows downward. Liquid accumulates at the base, causing an unstable pressure situation. This is relieved
by large liquid slugs periodically leaving the riser at a high velocity. The changes in liquid amount and the corresponding pressure changes can be dramatic. A large slug catcher installation can be provided onshore, but it is not economical to place it on the platform. This is one of the practical reasons why a pipeline section immediately ahead of the riser should be horizontal or have a slightly upward slope of 2 to 5.
The riser may have to handle far more liquid than awell because the flowline can feed it liquid surges that far exceed those possible by gas-lift or reservoir mechanisms. In many oil and gas developments that incorporate multiphase flowlines, the possibility of slugs or surges is one of the most important flow assurance concerns due to the excessive demands large changes in oil/gas flow rates place on the processing facilities. Multiphase surges come in three forms:
1. Hydrodynamic slugs: formed from the stratified flow regime due to instability of waves at certain flow rates.
2. Terrain-induced slugs: caused by accumulation and periodic purging of liquid in elevation changes along the flowline, particularly at low flow rates.
3. Operationally induced surges: formed in the system during operation transfer between a steady state and a transient state; for example, during start-up or pigging operations.
Hydrodynamic Slugging
Hydrodynamic slugs are initiated by the instability of waves on the gas/liquid interface in stratified flow under certain flowing conditions.
A main part of the frictional pressure drop in multiphase flow is thought to be due to the turbulent region within the slug. Thus, the size of the turbulent region can have a significant effect on the frictional pressure losses in a pipeline. Two-phase flow pattern maps indicate hydrodynamic slugging, but slug length correlations are quite uncertain. Tracking of the
development of the individual slugs along the pipeline is necessary to estimate the volume of the liquid surges out of the pipeline. Slugging simulations need to be performed over the flow rates, water cuts, and GORs for the field life. The effects of any artificial lift should be included in the simulations. In general, simulation results are presented as liquid and gas flow rates at the separator, slug lengths at the base and top of the riser, and pressure at key locations as a function of time.
The key locations in a well are upstream of the well flow control devices and bottomhole. If processing equipment is included in the model, the separator pressure, separator levels, and outlet gas and liquid rates from the separator as a function of time are presented. In cases where the predicted slugging causes liquid or gas handling problems, the effects of additional choking upstream of the separator should be determined. The evolution of slugs is very sensitive to the pipe inclination and changing the inclination by less than a degree can be sufficient to change the balance, causing a flow regime transition. Thus, peaks and troughs along the pipeline profile of relatively small elevation change may have a very significant effect.
Flowlines switches between the stratified and slug flow regimes, implying that not only could the slug sizes differ markedly, but the pressure drops could be very different too. Few pipelines have constant inclinations; most undulate following the natural terrain. When modeling multiphase flow in lower flow rates, it is important to represent these undulations as faithfully as possible. At higher flow rates, undulations may not have much impact on predictions.
Terrain Slugging
Liquid accumulates at the base of the riser, blocking the flow of gas phase. This liquid packet builds up until the gas pressure is sufficiently high to overcome the hydrostatic head and blow the liquid slug from the riser. Slug lengths can be two to three times the riser height.Terrain slugs can be very severe, causing large pressure variations and liquid surges out of a pipeline. Terrain slugging is a transient situation that requires a dynamic model to predict and describe. When the minimum flow rate is defined as the terrain slugging boundary, a region without severe slugging should be determined as a function of the water cut and including gas lift. In cases where the predicted slugging causes liquid or gas handling problems, the effect of additional choking upstream of the separator should be determined. It may be difficult to design a slug catcher to cope with the magnitude of terrain slugs. If the transportation system terminates in a vertical riser onto a receiving platform, the passage of the slug from the horizontal pipeline to the vertical riser results in cyclic flow effects. As the slug decelerates into the vertical riser, the following gas bubble is compressed.
Compression continues until sufficient energy is generated to accelerate the slug from the riser. When the wellhead pressure is limited, the vertical riser from the seabed into the platform may form a backpressure due to slugs, and it will limit well production. In such circumstances the vertical pressure loss can be reduced if a slug catcher is located on the seabed, and the gas and liquid phases are separated. The liquid is pumped to the surface with the gas free flowing to the platform through a separate riser. An alternative is to inject gas at the base of the riser, which will lighten the fluid column and minimize vertical pressure losses.
Start-Up and Blowdown Slugging
Slugs form in the start-up operation process because of transformation from a steady state to a transient process. The start-up simulations should be performed starting from shutdown conditions to different representative operating conditions throughout the field life. A range of start-up rates, consistent with reservoir management constraints, should be evaluated. If necessary, artificial lifting to mitigate start-up slugs should be evaluated. For gas lifting, the required gas-lift rate should be determined. If lift gas is unavailable until it is obtained from the production, this operating constraint should be included in the simulations.
Rate Change Slugging
When the flow rate is increased, the liquid holdup in the line decreases. This change in holdup can either exit the line as a steady flow with increased liquid production, or it can come out in the form of a slug, depending on the flow rate change. The rate change slugs can occur in gas/condensate flowlines when the rates are increased. The flowline may be in a steady flow pattern, such as stratified flow, at both the initial and final flow rates but will slug during the transition period until the line reequilibrates at the higher rate. As with start-up slugs, it is impossible to predict whether slugs will occur when rates are changed using steady-state or hand methods. The flowline must be dynamically simulated using a transient flow program.
Pigging
Pigs are run through pipelines for a variety of reasons, including:
- Liquid inventory control;
- Maintenance and data logging;
- Pipeline cleaning and dewaxing;
- Inhibitor application.
Slugging Prediction
The slugging prediction can be carried out using PIPESIM (Schlumberger), OLGA (Scandpower Petroleum Technology), ProFES (Aspentech), or TACITE (Simulation Science). Steady-state multiphase simulation software such as PIPESIM can predict hydrodynamic slug distributions along the flowline and riser slugs. However, only OLGA 2000 (standard version), the OLGA 2000 slug tracking module, and ProFES are good at simulating transient multiphase flow and predicting the liquid holdup variations along the flowlines, terrain slugs and start-up/shutdown transient slugs. Ramp-up slugs are of primary importance for gas/condensate systems where the increased flow rate can sweep out large volumes of liquid.
Simulations of flow rate ramps should be performed from turndown rates to intermediate and full production rates over the life of the field. OLGA 2000 slug tracking is generally not required for ramp-ups in gas/condensate systems except in cases with hilly terrain or high liquid loadings (>50 bbl/ mmscf). Results may be presented as outlet liquid and gas rates as a function of time. The production system should be modeled starting at the reservoir using inflow performance relationships provided by reservoir modeling. At the outlet, pressure control is recommended.
If this is not possible, a sensitivity study should be performed to ensure that random fluctuations in the outlet pressure do not significantly alter the slugging. The artificial boundary conditions of a constant pressure tend to dampen slugging and should be avoided whenever possible for slugging simulations. True boundary conditions on the flowline/riser can be obtained using a transient pipeline model coupled to a dynamic process model. Integrated dynamic pipeline and process simulation is rarely necessary for the design of wells, flowlines, and risers. However, in certain instances, integrated modeling is advisable for the design and control of the process facilities.
Parameters for Slug Characteristics
The key parameters required for the assessment of the performance of separation and associated downstream facilities are the average slug volume and frequency, and the greatest likely slug volume and its frequency of occurrence. The combination of slug velocity, frequency and liquid holdup is important for the design of pipeline supports. These are the control parameters: Vsg (gas superficial velocity), Vsl (liquid superficial velocity), D (pipeline diameter), L (pipeline length), f (pipeline inclination), rg (gas density), rl (liquid density), mg (gas viscosity), ml (liquid viscosity), and sl (surface tension).
Slug Detection and Control Systems
Although slug control is very important to avoid facility damage and upsets, control options are limited. The potential impact of slugging on the topside system operation must be addressed and then analyses of the subsea system carried out to assess the effects. Usually a trade-off results between the design of slug catchers and the optimization of the flowline to reduce slugging.
Slugs have been successfully detected using gamma densitometers located on the riser, acoustical measurements, and measurements of pressure at the base of the riser. Slug detection systems should be considered when predicted slugging is expected to give operational difficulties and/or when an advanced control system is to be used for slug mitigation. In this case, the slugging simulations should include advanced controls to test the control algorithm. Flow assurance and process disciplines should demonstrate advanced controls to critically dampen predicted slug volumes and frequency.
Equipment Design for Slug Flow
The design of slug catchers, separators, and control systems in downstream pipelines is based on the presence and severity of slug flow in the system. The parameter estimations of slug volumes, liquid and gas rates exiting the pipeline as a function of time, etc., must be factored into the equipment design for slug flow. These parameters should be calculated for steady-state operation and for a series of transient operation cases: turndown rates, pigging, shutdown and start-up, rate changes, etc. Transient modeling gives the best estimations of transient slug flow behavior. Some of the transient simulators include separators and control systems as part of the run. In general, the size of slug catching equipment for gas/condensate pipelines will be governed by pigging considerations. For oil-dominated systems, the size of the slug catcher is usually governed by the maximum slug length due to either hydrodynamic or terrain slugs.
Slug Catcher Sizing
Slug catchers should be sized to dampen surges to a level that can be handled by downstream processing equipment. Before dynamic models of the topside facilities are available, the level of acceptable surging is unknown and designers are often forced to make assumptions vis-a`-vis surge volumes, such as designing for the “one-in-a-thousand” slug.
The surge volume for gas/condensate requirements is determined from the outlet liquid rates predicted in the ramp-up, start-up, and pigging cases. The required slug catcher size is dependent on liquid handling rate, pigging frequency, and ramp-up rates. An iterative process may be required to identify optimum slug catcher size, pigging frequency, liquid handling rate, and acceptable ramp-up rates. For this optimization, the results of the simulations should be presented as surge volume requirements as a function of liquid handling rate for representative ramp-up rates and pigging frequencies.
Separator volumes for black-oil systems are typically set by separation requirements rather than liquid slug handling capacity. Consequently, the ability of the separator to accommodate slugs from all operations should be confirmed based on the results of the slugging simulations.
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