Slugging Flows
3.4.1 Normal or Hydrodynamic Slugging
It was discussed in section 3.3 that normal slug flow occurs at moderate gas and liquid flowrates and hence is commonly encountered in multiphase pipelines. The intermittent nature of this type of flow means that the separation plant at the downstream end of a slugging phase line will experience variations in liquid and gas flow.
In order to be able to design reception facilities to accommodate slug flow, and to design pipe supports to handle the forces associated with slug flow, it is necessary to predict both of the following:
l Slug volume (slug length and liquid content)
l Slug velocity
(a) Slug Volume (Slug Length and Hold-up)
A considerable amount of R&D work has been carried out world-wide to improve the under-standing of slug flow. It was apparent from early experimental work that slug lengths observed in small scale laboratory rigs could not be scaled up to field conditions.
In the late 1970s the operators of the Prudhoe Bay Field, Alaska, (PBU) were faced with the problem of designing numerous large diameter multiphase flowlines (24” in diameter) and the separators into which the fluids pass. They commissioned fluid flow specialists at Tulsa University (Dr. J.P. Brill) to carry out a large programme of work which included the collection of slug flow data from existing lines at PBU. The largest of these was a 16” 3-mile pipeline. From the data collected at PBU, together with some information on smaller flowlines, and laboratory scale multiphase systems, a correlation was developed to predict mean and maximum slug length. This correlation was published by Brill et al in 1979 :
= -2.663 + 5.441 + 0.059
where:
= mean slug length (ft) d = pipe diameter (in)
= mixture velocity
The PBU data suggested that slug lengths follow a log normal distribution, i.e. slugs distributed about the mean length through the following relationship:
+
where:
= slug length observation
Section 3. Gas Pipeline Design BP Multiphase Design Manual
= standard deviation (approximately 0.5)
zp = standard normal distribution function (3.08 for 0.1% probability)
Based on the 16” PBU data, et al claimed that the longest slug likely to be observed equates approximately to the 0.1% probability slug. The calculated 0.1% probability slug is approximately 4.7 times longer than the calculated mean slug.
The above slug length correlation has become the industry standard design method and has been used extensively by oil companies and contractors since 1979.
In the Tulsa University workers returned to PBU to gather data on a new 24” line that ran parallel to the 16” line that had been monitored previously. They found that in general slugs were not as large as had been predicted using their original correlation. BP revised the original slug length correlation to take account of the new 24” data. It is this modified correlation which is available in It is referred to as the Brill method as the correlation was kept in the same form as Brill’s original equation:
-3.579 + 7.075 + 0.059 [In 0.7712 [In(d)]
The above correlation is heavily biased by the PBU data. Most of this data was collected on a 16” and 24” line which run parallel to one another and hence have the same length and geom-etry. The correlation thus shows no dependence on line geometry or fluid type, and only a very weak dependence on flowrate. It was widely felt that the correlation could prove unreliable when applied to other types of systems. Consequently, under BPX, XTC, sponsorship the Multiphase Flow Group commenced a programme of work aimed at gathering slug flow data on a wide range of multiphase systems.
Since 1985 the Multiphase Flow Group have collected data from the following sites.
Wytch Farm
A summary of the data collected on all these tests, apart from the last 2, is available in (8).
The data collected by BP covers a wide range of pipe sizes, lengths, geometries, fluid proper-ties, and water cuts. The data has been compiled into a database vastly greater than anything previously available. Using this database, the Multiphase Flow Group have developed a mechanistic correlation for slug frequency. By applying one of the available slug flow models, knowledge of slug frequency yields the mean slug length. This is discussed in Appendix 3A.
No data has yet been collected from slugging hilly terrain pipelines. A new slug model has recently been developed by the Multiphase Flow Group to track slug sizes throughout a hilly terrain pipeline system. This model was referred to in Section 3.1.3, and is discussed further in Appendix 3D. It is intended to gather data from the Cusiana in-field system. The data collected from this hilly terrain system will be used to validate and develop the new model.
BP Multiphase Design Manual Section 3. Oil Gas Pipeline Design
i
In parallel with this data gathering exercise, the Multiphase Flow Group have carried out an extensive programme of work to determine how slug lengths are distributed about the mean.
This work has involved analysis of data collected on experimental rigs at as well as data collected from other experimental facilities. Using the limited PBU data Brill et al had concluded that slug lengths follow a log-normal distribution. Hence the Brill correlation always calculates the maximum slug length to be 4.7 times the mean. The Multiphase Group have found that the distribution of slug lengths actually varies with the location of the pipeline oper-ating point on the As a consequence the ratio of maximum to mean slug length varies with flowing conditions. Near the stratified wavy boundary the maximum slug length may be ca. 4-5 times the mean. However, near the elongated bubble transition maximum slug lengths are only ca. 2 times the mean. Work on quantifying slug length distribution is contin-uing at
The combination of a method for determining slug frequency, a slug flow model, and a slug length distribution model provides a means of predicting mean and maximum slug lengths.
This new approach is available in as the “RCS Mechanistic Model”.
A more detailed explanation of the slug model is given in Appendix 3A.
Prediction of the liquid volume associated with slug flow requires knowledge of the liquid content of the slugs (slug hold-up), as well as the slug length. The slug hold-up method currently used within the RCS slugging model is that due to Gregory. The Gregory model is based on laboratory scale experiments and predicts slug hold-up as a function of mixture velocity only. BP has found that in practice slug hold-up is strongly dependent on water cut as well as mixture velocity. Hence at Prudhoe Bay slug hold-ups have increased from ca. 0.3 to 0.9 as water cuts have risen from 0 to 50%. Similar significant increases in slug hold-up have been observed on the FE-FA 6” test line when running wells of different water cuts. Further work is being conducted in this area in order to develop a more reliable design method.
Slug Velocity and Forces due to Slugging Horizontal
When slug flow occurs in an essentially horizontal line the mean velocity of the liquid in the body of the slug is equal to the mixture velocity, V,, hence :
mean slug velocity
It is this velocity, V,, which should be used when evaluating the forces imposed by a slug as it travels through a bend.
A detailed discussion of how to calculate loads associated with slug flow is given in Section 11 of this manual.
Pipeline Risers
It was mentioned in Section 3.3 that although a slug will progress through a riser at the down-stream end of a pipeline, it will tend to decelerate as the line updown-stream of the slug packs up to provide the pressure to overcome the increasing hydrostatic head in the riser.
Section 3. Oil Gas Pipeline Design BP Multiphase Design Manual
As the slug leaves the riser the hydrostatic head loss in the riser reduces so that the upstream gas bubble expands and accelerates the slug into the process plant. This phenomenon is shown schematically in Figure 3.
Velocity of slug
Time
Figure 3. Normal slugging in riser
Press
In order to model the effect of slug flow in a pipeline- riser, BPX has developed a dynamic program known as NORMSL. This can be used to determine the velocity of the slugs as they pass through the riser and into the pipework. In order to assess the effect of slugging on the process plant the output file from NORMSL can be used as the input to a dynamic simulation model of the plant.
Process dynamic simulation work in BPX is often performed using the SPEED-UP program.
(This type of work is performed by the Process Simulation Group of ESS, Sunbury). NORMSL and SPEED-UP have now been directly linked so that pressure changes in the process plant arising from the production of slugs or gas bubbles are fed back directly into the pipeline-riser model. This feedback effect becomes more significant as the height of the riser increases, i.e.
for deep water developments.
BP Multiphase Design Manual Section 3. Gas Pipeline Design
3.4.2 Dependent Slugging
(a) Hilly Terrain Pipelines
It was explained in Section 3.3 that when stratified flow occurs in a pipeline liquid may accumu-late at low points to form a temporary blockage. Gas pressure builds up behind the blockage causing the liquid to be expelled as a slug. Such slugging is clearly dependent on the geometry of the pipeline as well as the flowing conditions.
As the available design methods for this phenomenon were inadequate and known to signifi-cantly overpredict slug size, the Multiphase Flow Group carried out physical and theoretical modelling studies to gain a better understanding of the terrain slugging process. These studies have led to the development of a mechanistic model for slug production from dips. The model has been validated with data obtained from the experimental facilities. The new model is discussed in detail in Appendix 3B.
The two most important aspects of the model with regard to pipeline design are:
(al) Critical Gas Velocity
The critical gas velocity above which no liquid accumulates in a dip is evaluated by considering the gas velocity for total liquid removal by the co-current liquid film process.
(a2) Slug Size and Frequency
At gas velocities below the critical value liquid can accumulate in a dip and eventually this leads to the production of a slug. As a slug moves through the uphill section, liquid is shed from its rear and runs back down the slope. If insufficient liquid is available in the preceding film for the slug to up and replace that lost by shedding, then the slug will collapse before reaching the brow of the hill. For a system with a steady liquid inflow, liquid will build up in the dip so that eventually slugs will emerge to pass into the downstream pipework. The model evaluates the frequency of slug production for a particular geometry. With knowledge of the slug frequency, the slug size is determined by calculating the volume of liquid entering the system during the inter-slugging period.
Pipeline-Riser Systems
When a pipeline terminates in a riser a particular type of terrain slugging may occur which has been variously termed riser and severe slugging. The conditions giving rise to the occurrence of severe slugging have been outlined in Section 3.3.
A diagrammatic representation of severe slugging is given in Figure 4. A detailed description of the severe slugging phenomenon plus details of the BP test rig studies is given in Appendix 3C.
A brief description of severe slugging is given below:
When a stratified flow occurs in a pipeline and the ratio of gas to liquid is below some critical value, a liquid blockage will form at the base of the riser. When such a blockage occurs liquid accumulates at the base of the riser while gas is trapped within the flowline. The liquid slug now formed at the junction between the and the riser will continue to grow if the
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rate of hydrostatic head increase in the riser, corresponding to the rate at which liquid arrives from the flowline, is greater than the rate of gas pressure increase in the flowline. Liquid accu-mulation continues until the riser is full of liquid (slug generation).
Stage 1
Slug generation Start of Stage 1
Blockage occurs
Figure 4. Severe slugging in riser
BP Multiphase Design Manual Section 3. Oil Gas Pipeline Design
At this point the hydrostatic head loss over the riser reaches a maximum value and the slug begins to be pushed slowly from the (slug production).
Once the gas slug interface enters the riser the hydrostatic head decreases rapidly while the expanding gas bubble accelerates the bulk of the liquid from the system (bubble penetration).
This stage continues until the gas bubble enters the separator. Gas production rapidly rises to a maximum value and then declines steadily as the line depressures (gas blowdown).
As the gas reduces, any liquid held up in the riser falls back and accumulates together with liquid arriving from the flowline, to form a blockage at the base of the riser. The cycle is then repeated.
The occurrence of severe slugging is generally associated with flowlines which slope down-wards to the base of the riser. However, a similar surging cycle can be produced in horizontal and slightly upwardly inclined pipelines.
Extensive physical modelling has been carried out by the Multiphase Flow Group to investigate and confirm previous descriptions of severe slugging and to investigate means of eliminating the phenomenon, see Appendix 3C. Much of this work was sponsored by the SE Forties project.
Of particular interest to the SE Forties Project was the use of riser gas injection to eliminate severe slugging both at low throughputs and at start-up. Tests showed that gas injection would reduce the severity of the severe slugging cycle and that in sufficient quantity it would completely eliminate the phenomenon.
A computer of severe slugging was purchased from the Tulsa University Fluid flow Projects (TUFFP). This program evaluates liquid and gas production rates throughout the severe slugging cycle and so by feeding the results directly into a dynamic model of the
plant, the effects of slugging on the process facilities can be evaluated. The TUFFP model was modified at to include pipework. The program could then be used to evaluate the forces exerted on the riser and pipework. The program was further modified to include the effect of riser gas injection. The predicted quantities of gas required to eliminate severe slugging were found to be in good agreement with the data collected from the BPX experimental facility.
It was found that the Taitel-Dukler-Barnea criterion for the onset of annular flow provided a good estimate of the quantity of gas required to eliminate severe slugging. This method predicts that the transition to annular flow occurs at superficial gas velocities in excess of a crit-ical value given by:
3.1
where:
s = surface tension (N/m) g = 9.81
Section 3. Oil Gas Pipeline Design BP Multiphase Design Manual
= liquid density = gas density
The modelling work showed that partial closure of a choke positioned near the top of the riser would also eliminate severe slugging.
The choke adds sufficient frictional pressure drop so that the system pressure loss becomes dominated by friction, rather than by hydrostatic head loss as is the case for the
pipeline-riser. In order to establish a stable, friction dominated system, the choke needs to provide a pressure drop comparable to the hydrostatic head loss over the riser when full of liquid.
Operational Experience
(b3.1) General
The SE Forties field is the principal BP-operated site where severe slugging was considered in the design stage. A number of the satellite wells may also have exhibited severe slug-ging had their maximum production rates been reduced to low values (their arrangement is different to SE Forties in that the chokes are at the top of the riser severe slugging would not occur unless the riser- top chokes were almost fully open).
There is one 12” line and one 6” line between Forties Echo minimum facilities platform and Forties Alpha. There are eleven wells on Forties Echo, now mainly assisted by electric submersible pump. They have chokes on Forties Echo. Therefore once the flows from the wells are co-mingled into the 12” line (or flowing individually or co-mingled through the 6” line), there is the possibility of severe slugging at low flowrate.
Low considerations obviously may also include start-up, when one or more severe slugging cycles may be experienced before a higher steady-state is reached.
In April 1988 a major field test was undertaken on the Forties Alpha platform mainly to investi-gate the behaviour of the 6” line over a range of flowrates, and from different wells that had a range of water cut. The aim was to keep reducing the from one well at a time through the 6” line until the onset of severe slugging. However, due to a fear that choking back the wells too far might kill them, it was not possible to reduce the production rates sufficiently to reach genuine severe slugging during the tests. Despite this limitation, there was a marked change in the character of the flow pattern, from steady low liquid hold-up slugging to a regular surging, as the flowrates were reduced.
Experience with the 12” line is limited to start-ups. Operators present at first oil through the line reported heavy surging. During the 1988 tests three start-ups were monitored, with several large surges during each. However, because of the steadily increasing input flowrates it was not possible to assess the accuracy of the predictive tools, either for the occurrence of severe slugging, or for the cycle time.
(b3.2) Elimination of Severe Slugging
The Forties Echo-Forties Alpha line has two methods for ameliorating the effects of severe slug-ging riser-base gas injection, and riser-top choking. The theory behind these 2 methods is discussed in Appendix 3C.
BP Multiphase Design Manual Section 3. Oil Gas Pipeline Design
The design intention for SE Forties was that riser gas injection would be the principal means of eliminating or ameliorating severe slugging at low production rates and at start-up.
Gas is re-cycled after NGL extraction through a 3” line down to the base of the 12” riser, and a 2” line for the 6” riser. The gas injection system capacity is sufficient to put the risers into annular-mist flow at the highest gas rates.
As mentioned above it was not possible to undertake any ‘steady-state’ severe slugging tests during the 1988 field work. However, the use of gas injection to ameliorate the low
period of a line start-up was demonstrated on both diameter lines.
The full gas injection procedure was used during the third of the 1988 test sequence of three start-ups of the 12” line, with the maximum recommended gas injection rate (180,000
into the 12” line flowing before the first production fluids were introduced at the Echo platform. Whilst there was still an initial surging the gas injection did serve to reduce the dura-tion of the main surge, and also the number of cycles.
This benefit of gas injection during start-up was also demonstrated whilst trying to bring on a weak well through the 6” test line. The well began to flow, but as liquid reached the base of the
This benefit of gas injection during start-up was also demonstrated whilst trying to bring on a weak well through the 6” test line. The well began to flow, but as liquid reached the base of the