Slug Catchers in Natural Gas Production - NTNU

Slug Catchers in Natural Gas
Production
Thereza Karam
Trondheim
December 2012

Karam – Slug Catchers in Natural Gas Production
ABSTRACT
Operations in deep, far and remote areas as well as cold environments have raised the problem of slug
formation. Irregular sea floor is the main concern and major reason behind the formation of these slugs. Their
presence in the pipelines has raised the flow assurance concerns. Several methods are used to inhibit such
occurrences as the use of MEG besides the erection of slug catchers at the receiving terminals. The design of
the latter challenges engineers due to the difficulty of predicting accurately slug length and volumes.
The project will focus on the design of slug catchers and then on four different field cases lying in the
Norwegian Continental Shelf. The analysis of a set of articles and theses made it possible to gather the needed
information. HYSYS was one tool in hand to calculate the gas, liquid and condensate fractions in the models.
Input data to the model were either assumed, found from previous literature work or calculated from several
correlations.
The project deliberates about two major parts. The first focuses on multiphase flow problems and slug
formation along with the different types of slug catchers available. As for the second part, the methods behind
the design of a slug catcher are brought into light. A HYSYS simulation was associated with the model to
verify the percentage of the different phases and check whether the size of the slug catcher is suitable.
As a result, the design of a slug catcher was dependent upon three major parameters. These are the length and
the inclination of the fingers of the multi-pipe catcher, the diameter of the pipeline heading to the inlet of the
slug catcher and the liquid accumulation volumes expected to be formed in the pipelines. The analysis showed
that the multi-pipe type is the mostly used especially for large slug volumes.
Regarding the simulations, HYSYS is not an accurate tool for multiphase flow analysis and estimation of
phase volumes due to the limitations of the program and the simplifications assumed. The MEG quantity
injected was smaller than what is actually used in the fields. Likewise, the volume or size of the slug catchers
should be smaller than their current size; this discrepancy is due to the larger amount of slug expected to be
formed and to the simplifications attributed to the model.
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ACKNOWLEDGMENT
The project was completed in partial fulfillment of the requirements for my Master’s degree in
Petroleum Production at NTNU. The project was completed under the supervision of Professor JÒn
Steinar Gudmundsson at the Department of Petroleum Engineering and Applied Geophysics at
NTNU.
I would like to thank Professor JÒn Steinar Gudmundsson for his continuous support and guidance
throughout the process and for the time he invested in reading and commenting my report. I am
grateful for the advices and help I got during our discussions.
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LIST OF CONTENT
ABSTRACT .......................................................................................................................................... ii
ACKNOWLEDGMENT...................................................................................................................... iii
LIST OF CONTENT ........................................................................................................................... iv
LIST OF TABLES ............................................................................................................................... vi
LIST OF FIGURES ............................................................................................................................ vii
CHAPTER 1 INTRODUCTION .......................................................................................................... 1
CHAPTER 2 MULTIPHASE FLOW AND SLUGS ........................................................................... 3
2.1 Multiphase flow and flow patterns .............................................................................................. 3
2.2 Slug Flow .................................................................................................................................... 4
CHAPTER 3 SLUG CATCHERS ........................................................................................................ 8
3.1 Slug Catcher types ....................................................................................................................... 8
3.2 Vessel slug catcher vs. Multi-pipe slug catcher .......................................................................... 9
CHAPTER 4 SLUG CATCHERS DESIGN GUIDELINES ............................................................. 11
4.1 Steps and calculation process .................................................................................................... 11
4.2 Close-up on the formulas behind the design ............................................................................. 12
4.3 Components and specifications ................................................................................................. 16
CHAPTER 5 NORWEGIAN FIELDS AND SLUG CATCHERS .................................................... 22
5.1 Troll and Kollsnes ..................................................................................................................... 22
5.2 Heidrun and Tjeldbergodden ..................................................................................................... 23
5.3 Snøhvit and Melkøya ................................................................................................................ 24
5.4 Ormen Lange and Nyhamna ..................................................................................................... 24
CHAPTER 6 HYSYS SIMULATIONS ............................................................................................. 26
6.1 Model Setup with a close up on the Ormen Lange case ........................................................... 26
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6.2 MEG Injection to the model ...................................................................................................... 28
CHAPTER 7 DISCUSSION ............................................................................................................... 29
CHAPTER 8 CONCLUSION............................................................................................................. 32
CHAPTER 9 NOMENCLATURE ..................................................................................................... 33
CHAPTER 10 WORKS CITED ........................................................................................................ 34
CHAPTER 11 TABLES ..................................................................................................................... 37
CHAPTER 12 FIGURES .................................................................................................................... 39
APPENDIX I - GENERAL INFORMATION ABOUT THE FIELDS USED FOR THE HYSYS
SIMULATION .................................................................................................................................... 52
I.A – Troll Field .............................................................................................................................. 52
I.B – Heidrun Field.......................................................................................................................... 54
I.C – Snøhvit Field .......................................................................................................................... 55
I.D – Ormen Lange Field ................................................................................................................ 56
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LIST OF TABLES
Table 1: The different slug catcher characteristics of both the finger type and the vessel type
(Contreras & Foucart, 2007) ................................................................................................ 37
Table 2: Data from the reservoir and the pipelines of the four different fields .................................. 38
Table 3: Data related to the wells and the slug catchers collected for the four different fields ......... 38
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LIST OF FIGURES
Figure 1: The six different flow patterns that form depending on the flow speed in the channel. (Aker
Solution, 2011) ......................................................................................................................... 39
Figure 2: The slug formation process in three steps starting with the Kelvin-Helmholtz Wave Growth,
then by a slug nose ingress and tail shedding to gas entrapment (Feesa, 2003) ...................... 40
Figure 3: The effect of pipeline inclination on slug formation (Feesa, 2003) ....................................... 40
Figure 4: Idealized slug unit showing all four different elements: the mixing zone, the slug body, the
film and the bubble (Scott et al., 1989) .................................................................................... 41
Figure 5: Representation of the slug unit and unit length with both the slug and film zones (Marquez et
al., 2009) ................................................................................................................................... 41
Figure 6: Flow map of a 20-in horizontal slug catcher showing the operational point (Sarica et al.,
1990) ......................................................................................................................................... 42
Figure 7: Flow map of a 26-in horizontal slug catcher showing the operational point (Sarica et al.,
1990) ......................................................................................................................................... 42
Figure 8: The appropriate design of a constrictor (Shell, 1998). ........................................................... 43
Figure 9: View of the inlet side of a multi-pipe slug catcher (Patel, 2007) ........................................... 44
Figure 10: View of the liquid header side of a multi-pipe slug catcher (Patel, 2007) ........................... 44
Figure 11: The bottle geometry of the slug catcher for Troll field in the Kollsnes processing plant
(Shell, 1998) ............................................................................................................................ 45
Figure 12: A general view of the two slug catchers at the Kollsnes Processing plant (Klemp, 2011) .. 45
Figure 13: The different components of the Hammerfest processing plant of the Snøhvit field
(Pettersen J. , 2011). ................................................................................................................ 46
Figure 14: Representation of the Storegga Slide (left) and the location of the field (right) (Bryna et al.,
2005) ....................................................................................................................................... 46
Figure 15: A general Overview of one of the two multi-pipe slug catchers at Ormen Lange (Gupta,
2012) ....................................................................................................................................... 47
Figure 16: Setup of the HYSYS model (MEG injection was not included in this setup) ...................... 47
Figure 17: Elevation profile of the Ormen Lange big bore well retrieved from the HYSYS model..... 48
Figure 18: Elevation Profile of the Ormen Lange flowline (Christiansen, 2012 from Biørnstad, 2006)
................................................................................................................................................. 48
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Figure 19: The digitized elevation profile of the Ormen Lange flowline in HYSYS ............................ 49
Figure 20: The slug tool results showing the position, length, frequency and velocity of slugs along
with different flow regimes in the Ormen Lange pipeline. ................................................... 49
Figure 21: The elevation profile of the Snøhvit flowline (Christiansen, 2012) ..................................... 50
Figure 22: The digitized elevation profile of the Snøhvit field as it is implemented in HYSYS .......... 50
Figure 23: The elevation profile of the Troll flowline. H=-350 m and L=67 km (Albrechtsen &
Sletfjerding, 2003) .................................................................................................................. 51
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CHAPTER 1 INTRODUCTION
Natural gas reserves around the world have shown a remarkable increase. As the population around
the world is growing, especially in underdeveloped countries, the oil/gas industry is forced to find
some additional sources of energy besides oil. Thus, researches for new fields and new alternatives
were carried on and intensified. Due to that, the approved reserves of natural gas, according to BP’s
statistical energy review 2011, have increased from 106.86 trillion cubic meters in 1987 to 208.4
trillion cubic meters in 2011. At the end of 2011, the world’s natural gas production, which is showing
an increasing trend, accounts for 3276.2 billion cubic meters.
Natural gas is essential and accounts for a great portion of the world’s energy supply. It constitutes up
to 24% of the worldwide supply of energy. It is currently used for electricity and power sectors which
feed, in turn, both residential and commercial sectors. The industrial sector and transportation are both
using natural gas for energy supply. It is considered as the cleanest source of energy implemented at
the present time in the industry, thus making the usage of it more popular. Its ability to produce a large
deal of energy with the least emission possible made of natural gas a highly demanded energy source
especially with the increasing environmental concerns.
The production of natural gas presents many challenges among which the transport of gas from the
templates up to the receiving facilities stand out. Many of the receiving terminals do not receive only
natural gas in the pipelines: gas is often associated with condensed hydrocarbons and condensed water.
Both the condensate and the water tend to form slugs in the pipelines leading to blocked pipes and to
irregular arrival to terminals with large volume rates. These rates cannot be handled by the facilities
without the presence of some buffer volumes known as slug catchers.
Slug catchers have been used in many of the receiving facilities in Norway. Troll, Heidrun, Ormen
Lange and Snøhvit are four different fields offshore Norway. The first three lie in the Norwegian Sea
whereas the last one is located in the Barents Sea. The four different fields are linked to the receiving
facilities through subsea pipelines. Slug catchers are the first facilities receiving the flow from the
pipelines. In order to determine the size of the slug catcher, the approximate volumes assumed to be
forming in the pipelines have to be estimated. To do so, HYSYS has been used to implement some
simulations, estimate the continuous amount of gas, condensate and liquid water and then discuss the
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suitability of the current design. However, it should be noticed that when simulating multiphase flow
in pipelines, results can be undependable due to the difficulty of an accurate representation.
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CHAPTER 2 MULTIPHASE FLOW AND SLUGS
2.1 Multiphase flow and flow patterns
Multiphase flow is the mostly common and dominating flow in pipelines. A single phase flow is rarely
found in the oil industry as the high pressure in the reservoir will cause a portion of the gas from the
gas cap to get dissolved in the oil or water to be dissolved in the gas. As the pressure is reduced due to
production, the gas will come out of solution; similarly, water will come out of solution in the form of
water droplets. In a more general description, two different sets of simultaneous flows constitute the
multiphase flow. Simultaneous flow of materials of two different states such as liquid, solid or gas
occurring at the same time in the same mixture is classified as multiphase flow. On the other hand,
simultaneous flow of materials of different chemical properties belonging to the same state or phase
such as oil droplets in water is also considered as a multiphase flow (Bakker, 2005). As for the
nomenclature of the phases, the continuous one is considered primary while the second phase(s) is
considered secondary as it is dispersed in the first.
Several multiphase flow regimes take place in horizontal pipelines. The two-phase gas-liquid flow is
considered in the section below. Phase separation usually occurs when the gravity effect is
perpendicular to the pipe axis. Six different patterns can appear in the horizontal pipe and are
represented in Figure 1. The following flow regimes are mentioned as a function of increasing flow
rate velocities. Stratified smooth (SS) pattern is the flow regime that is taking place more frequently in
pipes as both gas and liquid streams are being separated and parallel due to gravity. The gas overlies
the liquid and the interface is smooth. Stratified wavy (SW) pattern occurs as the gas velocity
increases slightly and causes waves to form on the gas-liquid interface.
The considerable increase in gas velocity in the pipes leads to more complicated flow regimes.
Elongated bubble flow (EB), also known as plug flow, shows elongated gas bubbles that separate the
liquid plugs. The elongated bubbles have a large diameter so that the liquid phase is lying continuously
at the bottom of the pipe. The elongated bubbles will grow in size with increasing flow velocity until
they reach a diameter similar to that of the channel leaving behind some liquid slugs. This is known as
the slug flow (I). The latter bubbles are known as the Taylor bubbles which will be coated by a liquid
film. Dispersed bubble (DB) flow takes place where the gas phase is extensively distributed in the
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form of bubbles or droplets in the continuous liquid phase. Annular (wavy) flow (A-AW) arises when
the flow rate is the highest. Hence, the liquid will form an annular film around the tube; but the film is
thicker at the bottom than at the top of the tube. Some small amplitude waves disrupt the interface
between the liquid film and the gas; as well, some droplets may be found in the gaseous phase
(Walveribne Tube Inc, 2007, Azzopardi, 2010 and Bratland, 2010).
Counter-current flow represents one of the aspects encountered in multiphase flow. Counter-current
takes place normally as the flow is flowing in an upward direction. Hence, gravity plays a major role;
it pulls the heavier phase of the gas-liquid mixture downwards. Each layer drags the other one
oppositely to its flow direction. In such a flow type, double holdups are always expected. The bubble
instability leads to a difficulty in the prediction of the flow’s velocity. Counter-current flow limitation
takes place when the gas flow rate increases. This increase causes a decrease in the delivered liquid
flow rate.
Liquid fallback can be inhibited by a pressure difference applied on the fluids and an interfacial shear
between the two phases present in the pipe. In order to inhibit this occurrence, the interfacial shear
should be high. This is mainly implemented with an increase in the gas flow rate which should be able
to lift the liquid existing in the form of either a film or droplets. Furthermore, the pressure differential
should be high as well in order to overcome the liquid-wall stress and the gravity that pull the liquid in
the other direction. To simplify, the direction of the liquid-wall shear determines whether the flow is a
co-current or counter-current flow. A positive shear corresponds to a co-current flow while a negative
shear corresponds to a counter-current flow.
2.2 Slug Flow
Slug, which is a lump of liquid, has been one of the major concerns of the industry when it comes to
transport of flow in multiphase flowlines. The slug normally forms as a result of retrograde
condensation when the reservoir pressure drops below the dew point. The presence of a slug flow in
the flowlines leads to an unsteady hydrodynamic behavior. The latter is the consequence of an
alternating flow of liquid slugs and gas pockets. The liquid level in the inlet separator will be affected;
a good separation is inhibited and in the worst case scenario, a flooding of the separator will occur.
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The slug formation is a three step process that is represented in Figure 2. The first pipeline section
shows a stratified flow where the gas is overlying the liquid and usually flowing at a higher velocity.
The interface between these two phases is not a straight line but a wave-like boundary. As soon as the
gas hits the wave, a pressure drop will take place followed by a pressure recovery. The latter will
create a small force that will be sufficient to lift the wave upwards until it reaches the top of the pipe
forming the slug shape. This is mainly generated by the Kelvin-Helmholtz instability. The slug shape
formed consists of a nose and a tail. The first is shown on the right side of part 2 of Figure 2 extracted
from the Feesa case study; as for the second, it is located to the left side. The slug is mainly pushed by
the gas at a higher rate than the liquid. Hence, the presence of the tail can be explained and leads to a
liquid entrance in the slug nose. Jet formation is, then, the outcome of such an incident. The result is a
bubble formation which will, in turn, reduce the liquid holdup increasing thus the turbulence in the
slug due to interference with the liquid ingress process.
The amount of liquid to be formed in the pipelines depends upon several variables. The velocity
between the liquid and gas surface is one factor that determines the amount of the slug being formed; a
slip in velocity between the two phases will cause the liquid to accumulate. The length of the twophase
flow pipelines through which the liquid is transported under steady-state conditions affects also
the amount of liquid being deposited; the longer the distance of transport, the more liquid is deposited.
The slug that comes out from the pipeline under steady state condition is changed into operating
conditions when the volume flow might change. In other words, by a change of velocity which is
normally up to 12 m/s in gas pipelines or by pigging, the slug will come out of the pipeline. Pigging
produces the largest amount of slugs. It should be noticed that the slug flow characteristics are difficult
to predict and cause some challenges due to the varying slug length and frequency, liquid holdup and
pressure drop.
The size of the slug and its degree of persistence in the flowline depend mainly on the flow rate, the
liquid ingress and how it will affect the turbulence within the slug. The latter is also governed by
several parameters such as the fluid properties in the pipeline, the pipeline inclination and the local
flowing conditions as it was stated in the case study ‘Hydrodynamic Slug Size in Multiphase
Pipelines’ completed by Feesa. The inclination of the pipe is one of the most sensitive parameters that
affect the slug formation; an inclination of less than 1° can cause an unbalanced state in the pipe.
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The difference in the slug formation in both a horizontal and an undulant pipe is shown in Figure 3. In
the first case of a horizontal pipe, only slug flow regime is occurring while both slug and stratified
flow regime are encountered in the undulant pipe implying a varying range of slug sizes and pressure
drops. The turbulent region in the slug, which is also affected by the gas bubble formation, affects the
frictional pressure losses. It should be noticed that the horizontal pipes are rarely used due to different
topographies and bathymetries that require more or less undulating pipes. For the four different fields
in question in this paper, rough terrains and large slides formed huge challenges. Thus, horizontal
pipes were only small sections of the elevation profile for each of the fields.
Several types of slugs can form. The hydrodynamic slug, one of the mostly known slug types, forms in
near horizontal parts of the flowlines due to the small amount of liquids compared to the free volume
in the separator. The accumulated liquids must be handled as they come out from the pipelines without
any reduction in the pipeline flow velocity. On the other hand, riser’s slugging can cause some
problems for processing as gravity forces can develop riser slugs if the flowline has a low point in
front of the riser. The reasons behind the riser slug formation are mainly low flow rates and low
pressure in the flowline around the end of the field lifetime. The low rate can be increased by the use
of a static topside choke. Slug removal by flow stabilization has a great economic potential since it
reduces the shutdown periods and might improve the oil recovery. The hydrodynamic slug is the only
slug type to be handled by the inlet separator or slug catchers.
Slugs are more or less very complicated to model the 3D turbulent multiphase phenomena. They occur
in numbers in a pipeline, thus, this adds to the complexity of modeling. Slugs might be mostly
communicating whether directly or indirectly; therefore, each one cannot be treated separately or in
isolation which further complicates the situation. In order to somehow predict the behavior of the slug,
both the initial and the boundary conditions must be determined with precision as the chaotic behavior
of the slug is sensitive to the initial conditions.
The slug flow can be suppressed in different manners depending on the availability of the information
about slug formation. When slug formation is expected, it is possible to reduce it by changing the
design of the process equipment. On the other hand, if the slug flow forms unexpectedly, some
intervention methods should be implemented to reduce its effect on the processing part; thus, devices
handling the slug should be considered in the design. To solve the problem, a large inlet separator can
be built to avoid slug flooding during severe slugging but this method is quite expensive and requires a
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large space. This previously stated solution is mainly implemented for offshore slug formation. The
similar alternative for onshore operations is the use of a slug catcher which is a big tank located at the
receiving terminal. It is the first equipment to collect the flow from the pipelines.
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3.1 Slug Catcher types
CHAPTER 3 SLUG CATCHERS
A slug catcher, which is a part of the gas pipeline system, is an essential equipment at the receiving
terminal of a multiphase flow processing plant. The specific function of a slug catcher is the separation
of the gas and liquid phases as well as the storage of the liquids temporarily. The gas is then sent for
further treatment in the gas-treating facilities downstream the pipes. The slug catcher is mainly made
up of two different compartments: the first one includes the gas-liquid separator under steady flow
conditions while the second consists of the storage where the received liquid is accumulated under
operating conditions. The gas will be guaranteed to reach the downstream facilities as the accumulated
liquid will displace the existing gas in a relatively continuous pattern. The size of the slug catcher
should be determined by the size of the largest slug that is possible to form in the pipeline.
The appropriate design of the slug catcher accounts largely to avoid problems at the receiving
terminals. In order to prevent the acceleration of the gas/liquid mixture, the inlet diameter of the pipes
entering the slug catcher should be the same as that of the pipeline. Normally the slug catcher is made
up of a series of pipes that are parallel and inclined in order to give the hold-up volume for the liquid
(Shell, 1998). Each one of these pipes in the slug catcher is known as a finger. The upper end of the
pipes discharges the gas while the bottom end discharges the liquid. A strong structure and foundation
maintain the pipes so as to support the impact of the slug.
The slug catchers exist in three different types: the vessel type, the multi-pipe type and the parking
loop type. The vessel type can range from a simple to a more complicated knock-out vessel which is
mainly used for limited plot sizes such as offshore platforms due to its small size. For large volumes of
slugs which implies a volume exceeding 100 m 3 , the multi-pipe or parking loop slug catchers are
mainly used. The multi-pipe slug catcher is made up of a liquid and gas separation entry slot and a
series of parallel tilted bottles where the liquid is stored. The inflow of liquid gets first through the
splitter into the inlet manifold and then down to the bottles moving thus the existing gas up to the gas
outlet risers. As a consequence, a continuous gas flow is maintained to the downstream facilities.
Therefore, the advantage of this slug catcher category is the ease of operation due to a free flow
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control measure. The gas inlet side and the liquid inlet header are shown in Figures 9 and 10,
respectively.
The parking loop slug catcher is designed to handle liquid carry-over that can be easily formed in case
of counter-current gas/liquid flow. The separation and storage parts are practically separated but the
liquid and the gas from the incoming stream are separated in the container. A slug arrival into the
separator can be detected by an increase in the liquid volume in the vessel. For precautious measures,
the gas is controlled by forcing the liquid to get into the pipe-loop where a pig is present. The latter is
responsible for the separation of the liquid and gas. The other side of the loop is now open for the gas
to flow in a co-current mode to the downstream facilities. This slug catcher type is mainly used
offshore where the separator is located on the platform while the loop is mounted on the seabed. It can
also be used onshore to reduce the space used if the pipe-loop is placed parallel to the inlet pipe.
Multiphase surges can be classified into three different categories. The latters are hydrodynamic slugs,
terrain induced slugs and operationally induced surges. Hydrodynamic slugs, as mentioned previously,
form due to an instability in the waves at the gas-liquid interface in stratified flow regimes. On the
other hand, the terrain induced slugs form mostly at low flow rates after accumulation and intermittent
removal of liquids in dips along the flowline. The operationally induced surges occur usually as the
system is forced to change from one steady state to the other such as in pigging operations. In order to
say that a pipeline is being operated under slug flow regime, it should be then filled with a number of
hydrodynamic slugs. Under such regime, the liquid-gas flow shows a chaotic behavior.
3.2 Vessel slug catcher vs. Multi-pipe slug catcher
Multi-pipe slug catcher, also known as finger slug catcher, is preferably used compared to the vessel
slug catcher. In case of large volumes of slug handling, which is more frequently experienced in
operations, multi-pipe slug catcher is more cost effective. As well, less operational problems are
encountered when using the multi-pipe slug catcher. On the other hand, vessel slug catcher is more
size effective as it does not require a large space in the processing plant.
Several criteria and aspects are to be considered when deciding upon which type of slug catcher is
more feasible for the field in question. The performance as handling the incoming slug and the
transportation features differentiate the two types of slug catchers. The performance depends chiefly
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on the volume of the slug to be handled; this has been mentioned in the previous section. The
efficiency to remove the liquid is essential: the vessel type has a high efficiency in removing the small
particles. The weight of the two different catchers is also taken into consideration; the finger type
weighs much less than a vessel type. The fabrication of the walls of a smaller bottle does not require as
much material as that of the walls of a larger bottle (Mokhatab et al., 2006). The larger bottle should
sometimes handle a higher pressure; therefore, the walls should be thicker than those of a finger type
catcher. The lighter weight of the finger type and the smaller size of the pieces to be assembled later
on in the field make it easier for the finger type to be transported than the heavy and bulky vessel type.
The capital cost or CAPEX is also to be accounted for when deciding upon the appropriate slug
catcher type. The capital cost is the money invested in acquiring or upgrading a physical asset. It
depends on the pressure that should be handled by the catchers. The vessel type is expected to handle a
higher pressure but sometimes both types should handle approximately the same pressure. However,
the vessel type is more expensive if transportation and taxes are also included (Mokhatab et al., 2006).
The installation costs and the associated technological risk should be thought of in the choice of the
suitable slug catcher type. The installation costs are higher for a finger type than a vessel type. The
area required for installing the catcher, the crew responsible for installation, the field work and the
erecting time are, as well, all higher for a finger type slug catcher. The finger type is constructed in a
workshop but needs to be assembled in the field and then connected to the existing equipment.
However, the vessel type is also erected in a workshop but needs only to be installed in the field and
connected to the other equipment. This can explain the difference in the installation costs. Both have a
low risk associated to handling the operations then this is not a criterion that would affect much the
decision (Contreras & Foucart, 2007).
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CHAPTER 4 SLUG CATCHERS DESIGN GUIDELINES
4.1 Steps and calculation process
Slug catchers, as previously stated, are important equipment in the receiving terminals for multiphase
flow pipes. For that purpose, the accurate and appropriate design of these catchers is crucial. More
specifically, the size of the slug catcher and the diameter of either the vessel or the fingers should be
estimated. To do so, a series of steps should be followed (Bai & Bai, 2010).
1- Determining the functions of the slug catcher
2- Determining the location of the slug catcher
3- Selecting the primary configuration of the slug catcher
4- Compiling the design data
5- Establishing the design criteria
6- Estimating the size and the dimensions of the slug catcher
7- Reviewing of the feasibility of the overall design; reviewing if necessary
As for the calculation sequence, the preferable order of calculations according to Shell’s DEP is the
following (Shell, 1998)
1- Calculating the intercept volume
2- Calculating the buffer volume based on the process requirements downstream
3- Deciding the size of the bottle
4- Deciding the number of primary bottles
5- Calculating the distance between the end of the downcomer and the gas riser
6- Calculating the bottle ‘s storage length in a way to contain the volume of the slug catcher
7- Determining the slug catcher’s total width and length and deciding upon the necessity of
secondary bottles depending on the available length of the plot for the slug catcher
8- Determining with a sketch the configuration and the major dimensions of the slug catcher
9- Analyzing critically the volumes in a way to take the volume of the slug catcher calculated in
step 6 and adjusting accordingly the length and the number of bottles; the necessity for
secondary bottles should be checked again. Repeating the steps starting with number 4 in case
of adjustments
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10- Repeating the volume calculations after finalization of all dimensions
4.2 Close-up on the formulas behind the design
Slug flow behavior must be determined first in order to be able to design and size a slug catcher
whether it is a normal slug flow or induced by pigging. A number of calculations and a set of
equations should be available and used. The slug length, slug holdup, slug velocity and translational
velocity should all be determined according to Sarica et al. (1990). The slug velocity can be defined as
the velocity of the mixture in steady state flow whereas the translational velocity, , is determined by
the equation below:
(1)
where is the velocity of the mixture, is the drift velocity and c is a constant. The drift velocity,
which is the velocity of one phase relative to a surface moving at the mixture velocity, is expressed
- for normal slug flow in vertical pipes, as:
√
(2.a)
- for normal slug flow in horizontal pipes, as:
√
(2.b)
- for normal slug flow in inclined pipes based on the Bendiksen correlation (1984), as:
(2.c)
- for pigging, as:
The constant c depends on the flow type thus if the flow is laminar, c=2. If the flow is turbulent, then
c=1.2. Otherwise, the Taitel correlation (2000) is used; it is represented as follows,
(2.d)
( ) ( )
(3)
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The general slug liquid holdup, which is symbolized by or and affected by the liquid velocity,
is expressed by the Gregory et al. correlation (1978) for a liquid slug with a viscosity less than 500 cP
( ( ) )
(4.a)
If the viscosity of the liquid is greater than 500 cP, the correlation obtained at PDVSA Intevep is used,
The latter correlation can also be used to determine the holdup in the Taylor bubble,
(4.b)
(5)
The Beggs correlation (1991) is used to calculate the gas void fraction which is the fraction of a
volume element in the two-phase flow occupied by the gas phase in the slug zone.
(6)
According to Sarica et al. (1990), the average slug length for large diameter pipes up to 24 inches can
be determined by the Norris correlation which is based on the Prudhoe Bay experiment. It is
represented in the equations below.
̅
(7.a)
̅
(7.b)
Thus, the maximum anticipated slug length can be determined using the results of eq. (7.b),
̅ (8)
Equation (7.b) has some limitations; thus, it uses a limited set of data which fall within a small range
of flow rates. This will narrow the applicability of this correlation to other systems; hence, it is
inapplicable to pipe diameters larger than 24 inches.
An alternative correlation has been developed by Shoham (2000) to determine the slug length. The
latter requires a known film length of the slug. Thus, a film length of the slug, which is mainly the
length of the Taylor-bubble as it constitutes the majority of the film zone, was developed by PDVSA
Intevep and then, included in the general formula for the slug length calculation. A representation of
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the slug and film length and zone are shown in Figures 4 and 5. The film length of the slug and the
slug length for a hydrodynamic flow are represented, respectively, as follows,
( ) (9)
( )
(10)
The slug frequency denoting the rate of intermittence of the slug through the pipeline, is expressed as
(11)
with L U , the slug unit length, being the sum of the slug length L S and the film length L L .
The instantaneous inlet flow rates of both gas and liquid are important slug characterization features
and crucial for the design of the slug catchers. These rates have been calculated by using the Miyoshi
et al model (1988). The equations are as follow:
- for the liquid: (12.a)
- for the gas: (12.b)
The liquid accumulation in the slug catcher should be determined in order to define the size of the slug
catcher. According to Sarica et al. (1990), a mass balance between the inlet and outlet liquid rate of the
slug catcher can be used to calculate the accumulated liquid rate and thus the accumulated liquid
volume.
[ ] [ ] [ ]
To solve the mass balance, the different parts of the equation should be determined separately. As
expressed earlier, the liquid input mass rate can be calculated with the Miyoshi et al. (1998) model
similarly to equation (12.a). The liquid discharge mass rate represents the flow rate at the outlet of the
slug catcher which is, in turn, dependent upon the flow control valve (Marquez et al., 2009). The
liquid accumulation rate can be calculated from equation (13) with the assumption of a constant liquid
density in the slug catcher and no acceleration while slug production (Sarica et al., 1990). On the other
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hand, what counts more for the design and modeling of the slug catcher is the liquid accumulation
volume calculated from the mass balance as in equation (14). The minimum rate is preferably used in
case of fluctuation of the discharge rate.
(13)
[ ] (14)
The dimensions of the fingers of a multi-pipe slug catcher are very important in the overall design.
One of the parameters to be determined is the diameter of the fingers. It is required to ensure an inlet
stratified flow into the slug catcher instead of getting a slug flow. Two measures can be implemented
to satisfy the stated requirement. The first is to increase the diameter of the slug catcher while the
second is to have a downward inclination of the slug catcher. Therefore, the minimum diameter
required leading to a stratified flow can be calculated from the transition criterion given by Taitel et al
(2000) based on the inviscid Kelvin Helmholtz instability criterion. This is shown in equation (15).
( ) √
(15)
The viscous Kelvin Helmholtz instability criterion according to Marquez et al (1990) is a better
representation of the transition between slug and stratified flows. The transition is applicable for a
wider range of viscosities (100-5000 cP). The transition can be then represented by:
√ ( ) (16)
K V is a correction factor calculated from the following equation:
√
(17)
Several indications would simplify the recognition of a stratified flow at the inlet of the catcher. The
stratified flow will take place when the actual gas velocity is lower than the transitional gas
velocity,
. Some flow pattern maps for specific diameters of slug catchers can be used to
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position the operational and the transitional points which will assist in determining if the flow is
stratified or not. Two flow pattern maps are shown in Figures 6 and 7; the first illustrates a map for a
20 inch diameter horizontal slug catcher while the second is for a 26 inch diameter horizontal slug
catcher. The two maps show that an increased diameter will provide a better stratification of the flow
in the catcher.
The volume needed to handle the entering liquid flow has to be decided upon after determining the
minimum diameter of the slug catcher. The latter has to be increased in order to accommodate the
accumulating liquid and avoid carryovers. The accumulating liquid will destabilize the flow in the
catcher and stratified flow is consequently not maintained with such a pre-determined minimum
diameter. The operational liquid holdup, H oper , can be calculated by solving the combined momentum
equation for the stratified flow conditions. It depends on the liquid and gas average flow rates. The
transition equation can be used to determine the maximum superficial liquid velocity knowing the
superficial gas velocity. Thus, the transitional liquid holdup, H tran , can be calculated. The available
volume to accommodate the liquid in the slug catcher is represented as the difference between the
operational and the transitional liquid holdup. Thus, the length of the slug catcher for a specific
diameter is calculated using equation (18).
[ ]
(18)
Larger slug catcher dimensions result from such calculations due to two assumptions considered. The
first consists of having a lower accumulated liquid volume than what is calculated in equation (14)
since the liquid continues to be under the gas bubbles in the liquid film during production. As for the
second, the liquid in the slug catcher is represented by H Loper before slug production while this amount
drops as gas pockets and film are produced. The overestimation of the dimensions of the slug catcher
can be considered as an advantage as it is a safety factor in production. The set of calculations is
applied to one finger, but is valid to more than one finger knowing the liquid distribution among the
fingers.
4.3 Components and specifications
The design of the slug catcher follows a series of computational steps using the equations stated
previously. As a first step, data from the field are required such as temperature, pressure, °API, inlet
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flow rates of the gas and the liquid, diameter and roughness of the pipes. Afterwards, the operational
point is to be plotted on the flow pattern map generated for the designated diameter of the inlet
pipeline to the slug catcher. The operational point should be in the slug flow region of the map
otherwise a slug catcher is not required.
The flow characteristics are also calculated using the equations stated previously in this paper. The
time difference in the slug arrival is mainly determined by the nature and the operating way of
handling the system. Pigging can affect greatly the regularity of the slug emergence to the slug catcher
aside from the natural slug flow. The slug catcher, in this case, should be designed based on the
interval of pigging, the volume of slug to be produced from each sphering phase and a contingency
volume. If pigging is not to be performed frequently, the maximum sphere-generated volume, SGV, of
liquid should be determined by a computer program to size the slug catcher. In normal flow, the size
of the catcher, according to Shell (1998), should be designed in a way to handle the difference between
the volumes of the steady-state holdup generated by the fluctuating liquid flow in case of no pigging.
Some complications should be accounted for in the sizing process. For long pipes, the pigging
activities should be controlled as to limit the size of the slug catcher since the slug-sphered volumes
(SGV) might be very large. There should be a comparison in the cost of having a more frequent
pigging activity and a smaller slug catcher and that of a large slug catcher with occasional pigging
(Mokhatab, Poe, & Speight, 2006). Sizing slug catchers with very rough elevation profiles of pipelines
needs a specific computer program to simulate the transient flow. This is due to the terrain slugs that
will form. By-pass pigging was also considered to cut the size of the slug catcher as it reduces the rate
of the slug arrival and extends the arrival period of the slug ahead of the pig (Shell, 1998).
The gas and liquid flow rates heading to the fingers’ inlet are considered in the design taking into
account an even distribution among the different fingers. An even distribution is retained by the use of
Tee-junction shaped splitters receiving the inlet flow perpendicularly. The splitters’ main function is to
divide and further divide the flow into 2, 4 and 8 equal and parallel streams going downwards through
the runs. The runs are constantly adjusted to keep the flow velocity constant and the flow distribution
equal through back pressure induction. The inlet manifold is located perpendicularly to the splitters
and should be of a large diameter so that the phases are evened before proceeding to the downcomers.
Each inlet manifold can take up to eight downcomers which will be mounted to a constrictor.
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A constrictor guarantees a good distribution of liquid in case of SGV thus it should be minutely
designed. The appropriate constrictor design is shown in Figure 8. It has to be positioned eccentrically
and close to the lower wall side of the downcomer. This will ensure a 40% reduction in the inlet
diameter maintaining, thus, an even distribution of flow and then any jetting effect, with the resulting
mist/foam formation, will be avoided as the liquid is moving along the wall. With the gas expansion
down the constrictor, segregation of gas and liquid takes place and will be enhanced in case of a 1:1
slope of the downcomer instead of a vertical downcomer. A 45° angle with the horizontal can be used
as an optimal solution for the stratified flow.
The diameter of the downcomer is usually smaller than that of the bottle so that D downcomer < 2/3 D bottle .
A peculiar conical expander is located at the downcomer and bottle joint. The expander can either
have the flat side up or the flat side down such as in the Troll field in the North Sea. A slight
preference for the second is observed as the slope of the bottle is continuous hence the stratified flow
would develop problem free. A further separation of gas and liquid will take place due to expansion.
(Shell, 1998)
The bottle section of the slug catcher, including primary and/or secondary bottles, an equalizer system
and a liquid outlet header, is designed with the consideration of several criteria. The first section of the
primary bottles encompasses the gas-liquid separation just upstream the first gas risers. The storage of
liquid takes place downstream the riser. Liquid droplets as small as 600 μm or less are removed from
the gas (Mokhatab et al., 2006). The distance between the riser and the conical expander should be
long enough to ensure more than 99% separation efficiency. Nevertheless, it should not be too large
implying a gas flow rate less than 2 m/s in the bottle. On the other hand, secondary bottles can only
store liquids. The equalizer is used mainly to ensure a unified pressure in the bottles. The use of an
equalizer should be very precautious as the system geometry is very sensitive. An equalizer can lead to
unwanted liquid carryovers.
The choice of the bottles number is very important in the design of the slug catcher. The gas flow rate
in the pipeline, the required volume of liquid storage and the length of the bottles are crucial for this
choice. It should be noticed that the number of bottles should not exceed eight for flow distribution
reasons but should be an even number to maintain symmetry. The design should also consider the
possibility for further expansion of the slug catcher along with increasing flow rate. The bottles have
to be inclined downwards to allow a smooth liquid filling due to gravity and gas migration to the gas
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outlet system. The most heavily loaded bottle can take an additional 20% compared to an even
distribution thus 120/n pb %. Stratified inflow of liquid should be maintained in the bottles in order to
avoid chocked bottles.
The slope of the bottles and the slope concept behind the slug catcher design should be decided upon
when choosing the bottles’ number. The bottles’ angle of inclination has to be determined with
precaution. As for the slope concepts, there are mainly two: the single and the dual slope concepts. In
the single slope concept, the minimum optimum slope for the bottles should be 1% and the maximum
can reach 3%. The latter will prevent the chocking effect of forming. On the other hand, for the dual
slope concept, the first part of the primary bottles is inclined at an optimal angle, around 2.5%, that
can ensure a filling flow rate with no chocking effect. A smaller inclination angle of 1% can be then
used for the other part of the primary bottles and the secondary bottles. This approach implemented in
the Kollsnes processing plant takes advantage of the liquid storage capacity of the bottles and uses it
efficiently; as well, high structural designs are avoided. (Shell, 1998)
The diameter of the fingers is also crucial for the number of bottles. It is determined by iterations as
the diameter is kept on being increased until the operating point lies in the stratified flow region. But
the minimum diameter can be accomplished when the operational point is superimposing on the
transition curve between the intermittent and stratified flow regions; this point is called the transition
point and is seen in figure 7. Equation (16) is used for this estimation.
A closer look on the method shows the following. The calculations start with a diameter similar to that
of the pipeline, then calculations are made to plot the operational point on the flow pattern map. As the
transition point is reached, the minimum diameter of the finger is increased to the next commercial
pipeline diameter to ensure a stratified flow during the operations. The number of fingers used is
determined based on the diameter; the latter should be large enough so that more than one finger is
used. The mostly used finger number is mainly four. Their length is calculated using equation (18).
The weight of the slug catcher is calculated in the final steps of the process as it has to consider the
overall components of the slug catcher. Among those are the inlet header, the separation zone and both
liquid and gas outlet headers. (Marquez et al., 2010)
The gas outlet section should be designed in a way to ensure the optimum separation. This section
includes the gas risers, the gas outlet headers and the gas outlets. Ensuring a flow of gas out of the unit
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is the main function of a gas riser along with the prevention from liquid carryovers in case of large
volumes of liquid passing through the lower region of the riser. The risers can sometimes be used as
liquid separators with high gas flow velocities. The capability of the riser in separation is based on the
load factor λ, which is expressed as,
√ (19)
The superficial gas volume generated can be calculated from the following equations,
( )
(20)
√ (21)
For large droplets with a size greater than 2 mm to setlle out of the stream, λ should be smaller or
equal to 0.2 m/s. This is applied in case of pigging-formed slugs and when the riser is mounted in the
primary bottles with a receiving capacity of 120/n pb %. A high gas flow should also be maintained to
avoid liquid flow from the heavily loaded bottles to the other bottles. The bottle has to be retained at a
minimum height where the liquid would settle; thus, its height should be at least 5 times or 5 meteres
bigger than its diameter depending on which value is lower. A second riser is mounted down the first
one to share 20 to 30% of the gas flow and the flow is equally distributed among the two risers by the
use of reducers at the top of the risers. This technique ensures a 100% carryover free and
uninterrupted production even when the slug catcher is half functioning due to maintenance. A
maximum of two risers per bottle is allowed for safe and optimal production.
The gas outlet header and the gas outlet are to be designed accurately. Their diameter shouldn’t be too
small as it will lead to a high pressure drop in the system. Such a pressure drop can cause an increase
in the liquid level closest to the gas outlet system compared to the other bottles. This is known as the
manometer effect. Thus, it is advisable to keep a balanced pressure distribution in the system.
Allowing the gas to be released from both ends of the header or using a reducer for each riser may
ensure such a distribution.
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As for the liquid outlet, it should be of the same diameter as the bottles or minimum 75% of it in order
to be able to handle the large liquid volumes without blocking the passage. The gas carry-under is to
be taken care of or avoided by having the liquid outlet header lower than the lower end of the bottle.
The liquid accumulation in the system should be kept as low as possible in the manifold. To do so, the
two liquid drains are added to the system under the lower end of the bottle. Three liquid outlets per
manifold should exist in the system. These have to be evenly distributed and positioned at a 45° angle
from the vertical to keep a minimum liquid accumulation. (Shell, 1998).
Last of all, the control of the liquid in the slug catcher is given a great importance especially from a
safety side. The presence of water and glycol, the blockage of the bottles due to sludges and the
accumulation of condensed liquid can all affect the liquid level in the catcher. Pressure tappings are
used as control devices mounted in the liquid outlet headers to supress any interruption caused by the
sludge. The maximum allowable operating pressure (MAOP) in the slug catcher should be at least
equal to that of the inlet pipeline. In case the MAOP of the slug catcher is decided to be lower than
that of the pipeline, an overpressure protection is then included in the design. A pressure test is
implemented; during this test all the loads in the catcher are considered. Such loads, according to Shell
(1998), can be the pressure, the thermal expansion, the passage of slugs, the settelment, the
environmental loads and the foundation and support reaction. (Shell, 1998)
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CHAPTER 5 NORWEGIAN FIELDS AND SLUG CATCHERS
This chapter will describe four different slug catchers from four different fields lying in the Norwegian
continental shelf. The Troll field is linked to an onshore processing plant known as Kollsnes whereas
the Heidrun field has its gas processing activity in Tjeldbergodden methanol processing plant. The
Melkøya plant receives the gas from the Snøhvit field while the Nyhamna plant receives the gas
streams from the Ormen Lange field. Following that, relevant data are collected and organized in two
tables, Tables 2 and 3, to allow a HYSYS simulation of the amount of liquid to be expected in the slug
catcher and discuss the design.
5.1 Troll and Kollsnes
Statoil-owned processing plant, Kollsnes, located 67 km west of Bergen started operations in October
1996. The location of the plant made it possible to build a simpler platform than what was originally
planned. The gas from the Troll field is transported to the Kollsnes plant. In 2005, the gas from both
Kvitebjørn and Visund fields started coming also to the Kollsnes processing plant. The original
capacity of the plant was 120 million standard cubic meters per day with the presence of 5
compressors; it is now raised up to 143 million standard cubic meters per day due to the installation of
a sixth compressor. It can also handle 69 000 barrels of Natural Gas Liquids (NGL) per day
(Hydrocarbons Technology, 2012). The new plant, which can handle 26 million standard cubic meters
of gas, is now able to process gas from further field developments.
Natural Gas Liquid is separated from the rich gas at the Kollsnes gas plant and then sent to Mongstad
refinery through the Vestprosess pipeline in order to fractionate gas into propane, butanes and naphtha.
Pressurized dry gas is driven by the large compressors and transported to customers through gas
trunklines. There are four trunklines: Statpipe, Zeepipe, Europipe I and Franpipe transporting the gas
to 7 continental European countries: France, Netherlands, Belgium, Germany, Czech Republic,
Austria and Spain. It should be noticed that the previously listed trunklines do not all originate from
the Kollsnes plant. Along with the Kårstø processing plant, they constitute 70% of the gas transported
from Norway to Europe.
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The Troll oil and gas field is located in the 31/2, 31,3, 31/5 and 31/6 blocks in the North Sea. The Troll
gas is sent from the Troll A wellhead platform to the Kollsnes plant through two 36’’ gas-condensate
pipelines as a multiphase flow is being transported. The receiving terminal consists of a dual-slope
multi-pipe slug catcher. The design of this slug catcher is shown in Figure 11. A general view of the
two slug catchers at the Kollsnes plant are shown in Figure 12. There are two slug catcher sets which
are 575 feet or 175.26 meters long. They consist of four pipe sections each with a 48 inch diameter
(Thaule & Postvoll, 1996).
5.2 Heidrun and Tjeldbergodden
The Heidrun field, an oil field associated with a gas cap, is located 175 km offshore the Norwegian
coast. It is located at a 345 meters water depth. It is located mainly on the south end of the SW-NW
trending Norland ridge and extending towards the less faulted Halten terrace (Mitcha et al., 1996). It is
the first field where the first Tension Leg Platform (TLP) has ever been used. The gas is transported
through a 250 km long 16 inches pipeline known as the Haltenpipe to a methanol plant,
Tjeldbergodden.
The Tjeldbergodden complex is located in mid-Norway, in the Aure commune between Kristiansund
and Trondheim. It occupies an area of 150 hectares and is designed to handle up to 900,000 tons of
methanol per year. It is mainly composed of four constituents: a receiving terminal for gas, a methanol
plant, an air separation plant and a gas liquefaction plant (Statoil, 2011). It is known as the most
environmentally friendly petrochemical plant. Two combined techniques in handling and treating
methanol were chosen with precaution; therefore, the production of carbon dioxide and nitrogen
oxides per ton of methanol will be very minimal and the energy consumption is set as the lowest in the
world (Hansen, 1997).
The Tjeldbergodden plant has some limitations and specifications. The plant production is limited due
to a restricted production capacity of 6.3 MSm 3 /d (Gustavsen & Tøndel). The gas reaches the
receiving terminal with an inlet pressure of 50 bars compared to the normal operating pressure in the
pipeline which ranges between 120 and 170 bars. As for the temperature, it is increased by 40 °C at the
inlet of the slug catcher.
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5.3 Snøhvit and Melkøya
The Snøhvit field is located in the 7120 and 7121 blocks of the Barents Sea at a 140 km distance from
shore. The development of this field was the first in the Barents Sea. Several challenges were faced
throughout the process especially regarding the operation in a remote area. The reservoir, which is at a
2400 meters depth, is underlying a water depth ranging from 250 to 340 meters. No platform of any
kind was used for operations and production, a subsea production facility was used instead (Statoil,
2012).
The gas is transported from the reservoir to Melkøya through a 143 km long, 26.8 inches pipeline. The
route followed by the pipeline is quite rough which will cause numerous production problems such as
slug formation. The elevation profile versus the length of the pipe should be determined. The cold
water of the Barents Sea and low temperatures at the sea floor can cause some flow assurance
problems as well. Therefore, these specifics have to be accounted for in the design. Inhibitors such as
MEG are also be added to the system to reduce the effect of these two previously stated factors.
The Melkøya island, represented in Figure 13 with all its components, receives the gas from two other
different fields, the Albatross and the Askeladd fields also located in the Barents Sea. The products
generated are LNG, LPG and condensate. This made of Hammerfest the first land based LNG plant.
The gas produced is then shipped to some further treating terminal facilities in Bilboa, Huelva and
Cove point before being distributed to the European and American markets. LNG tankers are used to
transport the gas instead of the pipelines due to the location of the field and the processing plant with
respect to the targeted markets (Pettersen J. , 2006).
5.4 Ormen Lange and Nyhamna
The Ormen Lange field located in the blocks 6305/4, 5, 7 and 8, 121 km north-west of the Møre coast
in mid-Norway, is the second largest gas field in the Norwegian Sea (Statoil, 2012). Some
geographical patterns of the area such as the well-known Storegga Slide made the transport of gas to
shore challenging, especially that the field is lying within this area and close to the steep upper
headwall. The latter has a slope ranging from 25 to 30 degrees and goes from 250 meters of water
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depth at the upper end of the wall down to 500 meters at the foot (Bryna et al., 2005). The Storegga
Slide is represented in Figure 14.
The reservoir is located at a depth of 2013 meters and has an initial pressure of 290 bara and an initial
temperature of 96 °C. The Ormen Lange field has a total gas flow rate of 70 MSm 3 /d and it is
producing from 8 different wells which are located at the same distance from the PLEM. It should be
mentioned that the big-bore wells of this field represent the largest wells drilled in 900 meters deep
waters; they have a 9 5/8’’ tubing size and production liner (Biørnstad, 2006).
The Ormen Lange field is tied to the Nyhamna processing plant through two 30’’, 121 km long pipes.
The pipes are not lying on a flat and horizontal area but they should go through the Storegga Slide
area. The latter has caused many problems and additional work such as adding around 3 million tons
of rock boulders at some points in order to flatten the area and provide a smoother path for the pipes.
The Nyhamna plant is then exporting the gas produced to the UK through Langeled, the longest
pipeline in the world with a length of 1200 km. Energy efficiency and reduced energy emission were
the basis on which the whole project has been erected.
Flow assurance is one of the concerns for gas transport to the Nyhamna processing plant. When
passing through such a rugged seafloor with different elevations, the angles of inclinations of the pipes
will vary greatly and thus will enhance the possibility of water accumulation and slug formation
through the transport since all 3 conditions of hydrate formations are present in the field in question.
The Hydrate inhibition in the pipeline is then essential; therefore, a 5/8’’ MEG injection was included
in the design. 97% of the gas production accessibility of the plant is thus ensured. In addition, two
symmetrical multi-pipe slug catchers of a capacity of 1500 m3 are mounted at the end of the two
pipelines. Each of the two-multi-pipe catchers is also divided into two for maintenance reason. One of
the two multi-pipe slug catchers is represented in Figure 15.
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CHAPTER 6 HYSYS SIMULATIONS
6.1 Model Setup with a close up on the Ormen Lange case
Aspen HYSYS V7.3 has been used to determine the continuous amount of gas, liquid and condensate.
The simulations have been implemented for the four different fields in question. Therefore, data from
all the fields had to be colleted and used as input for the simulation cases. The basis environment is
built separately for every field, it includes all the fluid properties of that field. Afterwards, the
flowsheet is built in order to connect the streams and the input data together. Many simplifications
have been assumed due to the lack of accurate information.
Ormen Lange is one of the fields to be investigated. As a first step, the composition of the field has to
be determined in order to provide the simulator with the make up of the gas being investigated. The
Peng-Robinson fluid package was chosen for the analysis. The model is attributed to a steady-state
model which also reflects a simplified aspect of the model. For further simplifications, all wells and
templates are also assumed to be symmetric in position and capacity.
Wet gas has to be ensured in the reservoir and in its representation in the model. To do so, the
reservoir gas stream has to be associated with a stream of water. These two are led to a simple vertical
separation to extract the vapor phase which is used as the main reservoir stream. The initial reservoir
conditions were specified in both the reservoir stream and the water stream. The reservoir temperature
is 96 °C and the reservoir pressure is 290 bars. The setup of the field model is shown in Figure 16.
The water flow rate has to be determined with precision. This is calculated by the water solubility r sw
which is given in Kg/MSm 3 . A VBA has been prepared for that purpose where water mole fraction in
methane and the water mole fraction in gas are calculated to get to the water solubility. The inputs to
the VBA are the initial pressure and temperature, the gas gravity and the water salinity. The gas
gravity in the case of the Ormen Lange is 0.6 as for the salinity, it is assumed to be zero ppm. The
water mass rate, which is 1441 Kg/h, is obtained from the water solubility and the gas flow rate. It
should be noticed that no formation water is produced at the early stages of production.
The flow rate is one of the main and essential parameters to be included in the model as it affects the
model’s performance to a great extent. The total gas flow rate of the field is 70 MSm 3 /d that are
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produced from 8 different wells positioned symmetrically away from the PLEM. Two 30’’ pipelines
transport the gas from the PLEM to the receiving terminals onshore.
To simplify and due to symmetry, halving the wells and the pipelines can be used as a simplification
according to Christiansen (2012) and Heskestad (2004). One well was enough to represent the flow
through the wells. Therefore, the flow rate is divided by the number of wells which is thus 8.75
MSm 3 /d. The pressure drop in the reservoir, which is around 30 bars, was accounted for through a
graph shown by Christiansen (2004). This pressure drop can be represented in the model through a
valve.
The Ormen Lange well is known as the Big Bore Well. It is a 9 5/8’’ tubing well with 8.5’’ inner
diameter. It is not a vertical well. On the contrary, it has four different sections that are represented in
a well elevation profile shown in the Figure 17. It can handle the largest production rates in the world
and then can reduce the need for wells for the same production.
As a next step, the flow will enter the pipeline passing first through a wellhead choke. The two 30’’
pipelines are 121 km long each with an inner diameter of 27.17’’. They are lying on the irregular and
rough seafloor; therefore, a pipeline elevation profile is needed. It was taken from Christiansen’s paper
(2012) and then digitized in HYSYS. The elevation profile to be digitized is represented in Figures
18while the digitized profile is shown in Figures 19. The wellhead choke should handle a pressure
drop that will ensure the operational inlet pressure to the pipeline which is around 150 bars.
The next spot to which the flow is heading to is located at the receiving terminal. The slug catcher is
the first equipment to handle the arriving flow. It is represented by a simple separator in the model. It
has a specific inlet pressure of 90 bars. A choke will be responsible for ensuring a pressure drop
corresponding to the appropriate inlet pressure. As operations are carried on, the inlet pressure will be
reduced to75 bars as production rate will decline to 60 MSm 3 /d (Gupta, 2012).
An expected problem in the pipeline system is the formation of slugs. HYSYS allows the detection of
such a hindrance; the slug detection should be activated in the model. This is done simply by ticking
the ‘Do Slug Calculations’ option. The results are then displayed showing the slug position, the status,
slug length, the bubble length, the film holdup, the slug frequency, the velocity and the pressure
gradient. A sample of the results is shown in Figure 20.
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Karam – Slug Catchers in Natural Gas Production
6.2 MEG Injection to the model
Slug formation in the pipelines needs to be inhibited. To do so, slug or hydrate inhibitors are used. The
most common inhibitors used in the industry are Mono-Ethylene Glycol also known as MEG and
Methanol also known as MeOH. For the Ormen Lange field, the inhibitor applied is the MEG as it is
easier to regenerate and re-inject. It is injected at the wellhead through two 6’’umbilicals. Only one of
the two umbilicals is used for injection while the second is a spare one.
The amount of MEG to be injected has to be determined beforehand. In his book Hydrate Engineering,
Sloan has enclosed a CD that helps in the calculation of the amount of MEG or MeOH needed by
simply entering a couple of parameters. By doing so, the amount of MEG needed in this particular
case is 746.7 Kg/h; the MEG is injected with water at a 49 wt.%.
The MEG’s use is intended for the inhibition of slugs in the pipelines. This effect can be tested by the
analysis of the data provided by the slug option present in the simulator. The results have shown that
the MEG is reducing the length of the slug and the bubble as well as the film holdup and the pressure
gradient. On the other hand, the velocity and the length ratio S/B are both increased due to the smaller
length of the slugs.
The same analysis was applied for the Snøhvit field for both cases. Many simplifications were made
due to the lack of all the needed information to build the model. The elevation profile of the pipeline
was available along with the gas composition. The elevation profile and the digitized elevation profile
of the flowline are shown in Figures 21 and 22, respectively. The well elevation profile was not found,
thus a similar profile of the Ormen Lange was used with a smaller ID (assuming 5 ½’’ production
tubing). The wells in Snøhvit are not equally distant from the PLEM, but for simplification, all the
wells are assumed to be at an equal distance. The elevation profile of the Troll flowline was also
available and is shown in Figure 23. As for the wells, they are equally spaced and were assumed to be
similar in profile to that of the Ormen Lange except for the smaller ID.
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Karam – Slug Catchers in Natural Gas Production
CHAPTER 7 DISCUSSION
Slug formation constitutes one of the major concerns for gas transport from offshore to onshore
facilities. Several conditions induce their formation. High velocity in pipelinees would cause a
turbulence and a plug or slug flow regime, increasing thus the tendency of slugs to form. Irregular
bathymetry challenges the engineer as the pipelines would be following the sea floor elevations. Slug
formation is very sensitive to the angle of inclination: a change of less than 1° would induce slug
formation in significant amounts. The reservoir gas is usually saturated with water; this is another
aspect that enhances slugs in horizontal conduits.
Suppression of slug formation is one of the main flow assurance duties. The injection of inhibitors as
MEG and the erection of buffer volumes at the receiving terminals reduce the intensity of slugs. The
buffer volumes also known as slug catchers should be sized in a way to handle the largest slug
expected to be formed. Therefore, they should be designed as accurately as possible. Counter-current
flow forms another challenge to be delt with in multiphase flow; gravity pulls the heavier component
of the two-phase flow downwards in an upward conduit which makes it difficult to predict velocities.
The latter has a great influence in the calculations behind the slug catcher design.
The slug catchers are found in three different types. The vessel type and the multi-pipe type are the
mostly common in the industry. For the fields in question, multi-pipe type was chosen due to the
feasibility of the model along with its capacity to handle the slugs with a volume greater than 100 m 3 .
Since the fields apply to the latter condition, this type of catcher was selected regardless of the ability
of the vessel type to separate particles as small as 10 microns.
Moreover, the finger type catcher can be designed with either a single slope or a dual slope concept.
The latter uses two different inclination angles of the bottles which prevent choking effets and makes
efficient use of its liquid storage capacity. Symmetrical systems are essential for the design as they
might reduce the liquid load when it comes to more than one pipeline and/or slug catcher; similarily, it
ensures continuous production in case of maintenance or pigging activities.
Liquid accumulation volume and fingers’ length constitute two important parameters to be determined
with precision when it comes to the design of the slug catcher. The difficulty faced in the design is
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Karam – Slug Catchers in Natural Gas Production
mainly due to the inability to determine minutely the velocity and the flow regime under which the
pipe is operating especially as counter-current flow is frequent and unpredictable in mltiphase flow.
The diameter of the fingers is determined at a minimum to ensure a stratified flow and then increased
to maintain the same flow regime at the inlet of the buffer. Similarily, a downward inclination of the
fingers ensure a stratified flow.
The dimensions of the slug catcher, based on the method stated in this paper, might be larger than
needed. This is due the volume of accumulated liquid assumed to be lower than the calculated volume
as the liquid keeps on being under the gas bubbles in the liquid film during production. The
operational liquid holdup used is the one prior to production while in reality this value is lower due to
gas pockets and film production. Nevertheless, an overestimation of the slug catcher can be considered
as a safety factor for production. The calculations are also flexible and can be applied to more than one
finger as long as symmetry is maintained.
HYSYS simulator has been used to generate models reflecting the amount of gas, water and
condensates. The models are not reliable due to the numerous simplifications assumed and the
difficulty in simulating multiphase flow. Multiphase flow is accurately represented by the OLGA
simulator which was not available in the HYSYS package I have been using due to a limited license.
The simplified HTFS homogeneous flow correlation has been used for pipe and well calculations.
Many of the input data were also assumed due to the lack of information which makes it difficult to
create a model operating as the real field. The steady state flow is assumed throughout the entire
production.
Ormen Lange model is the most accurate model among the four fields due to the availability of data
and due to symmetry in the field design which makes its modeling precise. As for the rest, either some
of the main input data such as the elevation profiles were missing or the wells are not located
symmetrically or at the same distance from the PLEM. Further assumptions regarding those two
matters made it hard to rely on the HYSYS outcome.
The slug option provided by the HYSYS has shown that some of the results have been affected by the
injection of the MEG and the length of the bubbles as well as that of the slug were reduced. The
amount of MEG injected based on the sheet provided by the Hydrate Engineering book was 49 wt%
which is lower than what is currently used in the field (~ 60 wt%). This is mainly due to the inputs to
the sheet which are taken from the HYSYS simulator. Furthermore, the volume of water expected to
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Karam – Slug Catchers in Natural Gas Production
form in th field is higher, hence a higher percentage of MEG is required. Similarily, the volume of the
liquid to be expected at the slug catcher was estimated by HSYSYS as around 1300 bbl/d which is
way smaller than the size of the slug catcher at the receiving terminal.
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Karam – Slug Catchers in Natural Gas Production
CHAPTER 8 CONCLUSION
Slug formation has raised the concern of engineers when it comes to gas transport from remote and
deep sea templates to shore facilities. Slug tends to form as the flow velocity is increased and the flow
is lying in the slug flow regime region. A small pipeline diameter would lead to the same problem.
The irregular and rough sea bed causes some low lying areas in the pipelines where the liquid might
accumulate; additionally, a small variation in the angle of inclination would lead to a change in the
flow regime dominating the pipes.
Slug catchers are facilities used for handling the slug formed from the production of a multiphase
pipeline along with the use of the MEG inhibitor. Multi-pipe slug catchers are frequently used in the
industry due to the ease of manipulation of the fingers and to the ability to handle large volumes of
slugs which is the case for all the fields under investigation. Single and dual slope concept can be
applied to this type of the catchers; thus, the choice of the concept will be costumed to every field.
Several parameters contribute to the design of the slug catcher. The diameter of the pipeline should be
designed first at the minimal diameter size and then increased to maintain a stratified flow at the inlet
of the buffer. The liquid accumulation volume along with the length of the fingers and their inclination
are essential for determining an accurate and optimal size and design of the slug catcher. The
calculations might lead to a larger size of the slug catcher which may be considered as a safety margin.
Gas, liquid and condensate volumes were estimated by the HYSYS simulator. The model for the
Ormen Lange is the most accurate among the four fields in question due to the availability of input
data. Regardless that, the numbers estimated were too low compared to the real data because of the
simplified model where a steady state flow was presumed throughout the production. A homogeneous
flow was assumed as well since the license that was in hand does not support the OLGA multiphase
simulator which gives a more detailed and accurate analysis.
The suitability of the current designs of the slug catchers is hard to be critically discussed due to the
inaccuracy in the modeling of the fields in HYSYS. Similarly, the data available regarding the sizes of
the slug length entering the slug catcher was scarce or unavailable. But most of the slug catchers were
designed based on the multi-pipe model with complete symmetry. This is favored due to the reasons
stated earlier.
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CHAPTER 9 NOMENCLATURE
Karam – Slug Catchers in Natural Gas Production
Nomenclature
A = Cross-sectional area, m 2
c = Bubble velocity proportionality constant
C = Wave velocity
D = Diameter
f s = Slug frequency, slugs/s
g = Gravitational acceleration, m/s 2
h = Height, m
Subscripts
accum = Accumulation
CL = Constant Liquid
d = Drift
dis = Discharge
F = Film zone
G = Gas
Gtran = Gas transition
H LLS or E S = Liquid holdup in the slug zone
hor = Horizontal
H LTB = Liquid holdup in the film (Taylor-Bubble) zone
ins = Instantaneous
K V = Coefficient of stability
IV = Invicid
̅ Average length, m L = Liquid
L = Length, m
m = Mixture
m = Number of risers per bottle
max = Maximum
n = Number of bottles
oper = Operational
q = Flow rate, m 3 /s
Re = Reynolds number
t = time, s
v = Velocity, m/s
V = Volume, m 3
Greek Letters
α = Gas void fraction
θ = Inclination angle, degree
ρ = Density, Kg/m 3
λ = Load factor or volumetric fraction of liquid in
two-phase flow , m/s
p = Pipe
pb = Primary bottle
S = Slug zone
SG = Superficial gas
SL = Superficial liquid
t = Translational
U = Slug Unit
ver = Vertical
V = Viscous
Page 33 of 56

Karam – Slug Catchers in Natural Gas Production
CHAPTER 10 WORKS CITED
Hydrocarbons Technology. (2012). Retrieved from Kollsnes Gas Processing Plant, Norway:
http://www.hydrocarbons-technology.com/projects/kollsnes-gas/
Actis, S., Smith, K., & Chenier, D. N. (1993). Planning and Start-Up of the Heidrun TLP Predrilling Program.
Society of Petroleum Engineers.
Albrechtsen, R., & Sletfjerding, E. (2003). Full-scale Multiphase Flow Tests In the Troll Pipelines. PSIG Annual
Meeting, Bern, Switzerland.
Azzopardi, B. (2010). Multiphase Flow-Vol 1. Chemical Engineering And Chemical Process Technology.
Bai, Y., & Bai, Q. (2010). In Subsea Structural Engineering Handbook (pp. 389-390).
Bakker, A. (2005). Lecture 14 - Multiphase Flows: Applied Computational Fluid Dynamics.
Barnea, D., & Taitel, Y. (1993). A Model for Slug Length Distribution in Gas-Liquid Slug Flow. International
Journal of Multiphase Flow, 19, 829-838.
Biørnstad, C. (2006). Ormen Lange og Langeled. Naturgassfaget på NTNU.
Bolle, L. (n.d.). Troll Field-Norway's Giant Offshore Gas Field.
Bratland, O. (2010). Introduction. Retrieved from The Flow Assurance Site.
Bryna, P., Berga, K., Forsbergb, C. F., Solheimb, A., & Kvalstada, T. J. (2005). Explaining the Storegga Slide.
Marine and Petroleum Geology.
Christiansen, H. E. (2012). Rate of Hydrate Inhibitor in Long Subsea Pipelines.
ConocoPhillips. (n.d.). Norway. Retrieved from ConocoPhillips:
http://www.conocophillips.com/EN/about/worldwide_ops/europe/Pages/Norway.aspx
Contreras, M. A., & Foucart, N. (2007). Selection Slug Catcher Type. SPE.
Cook, M., & Behnia, M. (1999). Slug length prediction in near horizontal gas-liquid intermittent flow. School of
Mechanical and Manufacturing Engineering, University of New South Wales, Australia.
Corradini, M. L. (1997, August 4). Wisconsin Institute of Nuclear Systems. Retrieved from Fundamentals of
Multiphase Flow: http://wins.engr.wisc.edu/teaching/mpfBook/main.html
Feesa. (2003). Hydrodynamic Slug Size in Multiphase Pipelines. Feesa Ltd Case Study.
Page 34 of 56

Karam – Slug Catchers in Natural Gas Production
Golan, M. (2012). Exercise Set 6-Field Processing. TPG4230-Field Development . Retrieved from
https://files.itslearning.com/File/Download/GetFile.aspx?FileName=Ex+set+6-
2012.pdf&Path=kKg0zGiHdYtVzUwAHgoFdhz7ABu7nTWQFGwBaqTL1jl3D1WoVbezcdEGcngkzMYE%2b
U2VhDLUTQNJWs9%2bgribGInewMaaKvhsyZ0TfwEF9IkxdrLtkJ%2fehwy10UtQih4J4YMsg%2ff3rqL529
obw4%2bhPThZuSV8
Gustavsen, Ø., & Tøndel, P. (n.d.). Production Optimization using Automatic Control at Heidrun. StatoilHydro.
Hansen, R. (1997). Combined Reforming For Methanol Production. 15th World Petroleum Congress.
Madsen, T. (1997). The Troll Oil Development: One Billion Barrels of Oil Reserves Created Through Advanced
Well Technology. 15th World Petroleum Congress.
Marquez, J., Manzanilla, C., & Trujillo, J. (2009). Slug Catcher Conceptual Design as Separator for Heavy Oil.
SPE.
Marquez, J., Manzanilla, C., & Trujillo, J. (2010). A conceptual Study of Finger-Type Slug Catcher for Heavy Oil
Fields. SPE.
Mitcha, J. J., Morrison, C., & De Oliveira, J. (1996). The Heidrun Field - Development Overview. OTC.
Miyoshi, M., Doty, D., & Schmidt, Z. (1988). Slug-Catcher Design for Dynamic Slugging in an Offshore
Production Facility. SPE Prod Eng 3.
Mokhatab, S., Poe, W. A., & Speight, J. G. (2006). In Handbook of Natural Gas Transmission and Processing (pp.
221-223).
NaturalGas.org. (2011). Background. Retrieved from NaturalGas.org:
http://www.naturalgas.org/overview/background.asp
Patel, R. J. (2007). Slug Catcher Inspection Using The Large Structure Inspection. 4th Middle East NDT
Conference and Exhibition, Kingdom of Bahrain,.
Pettersen, J. (2006). Hammerfest LNG (Snøhvit).
Pettersen, J. (2011). Snøhvit Field Development.
Sarica, C., Shoham, O., & Brill, J. (1990). A New Approach for Finger Storage Slug Catcher Design. OTC.
Scott, S. L., Shoham, O., & Brill, J. P. (1989). Prediction of Slug Length in Horizontal, Large-Diameter Pipes.
Shell. (1998). Design of Multiple-Pipe Slug Catchers (Manual).
Shell. (2012). Shell. Retrieved from Ormen Lange - Facts and figures:
http://www.shell.no/home/content/nor/products_services/ep/ormenlange/en/facts/
Shoham, O. (2000). Two-Phase Flow Modeling. Thesis. Department of Petroleum Engineering, University of
Tulsa, Oklahoma.
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Karam – Slug Catchers in Natural Gas Production
Statoil. (2007, September 18). Statoil. Retrieved from Kollsnes gas processing plant:
http://www.statoil.com/en/OurOperations/TerminalsRefining/ProcessComplexKollsnes/Pages/default
.aspx
Statoil. (2007, September 29). Statoil. Retrieved from Troll Gass :
http://www.statoil.com/no/OurOperations/ExplorationProd/ncs/troll/Pages/TrollGas.aspx
Statoil. (2011, August 10). Tjeldbergodden industrial complex. Retrieved from Statoil:
http://www.statoil.com/en/OurOperations/TerminalsRefining/Tjeldbergodden/Pages/default.aspx
Statoil. (2012, March 27). Ormen Lange. Retrieved from Statoil:
http://www.statoil.com/en/OurOperations/ExplorationProd/partneroperatedfields/OrmenLange/Pag
es/default.aspx
Statoil. (2012, August 10). Snøhvit. Retrieved from Statoil:
http://www.statoil.com/en/OurOperations/ExplorationProd/ncs/snoehvit/Pages/default.aspx
Taitel, Y., & Barnea, D. (1990). Two Phase Slug Flow. In Advances in Heat Transfer (pp. Vol 20, 83-132).
Academic Press.
Thaule, S. B., & Postvoll, W. (1996). Experience with Computational Analyses of the Norwegian Gas Transport
Network. PSIG.
Time, R. (2011). Flow Assurance and Multiphase Flow. Seminar at Aker Solutions.
Valberg, T. (2005). Temperature Calculations in Production and Injection Wells.
Walveribne Tube Inc. (2007). Chapter 12 Two-Phase Flow Patterns. In Engineering Data Book III (pp. 3-4).
Page 36 of 56

CHAPTER 11 TABLES
Karam – Slug Catchers in Natural Gas Production
Table 1: The different slug catcher characteristics of both the finger type and the vessel type (Contreras & Foucart,
2007)
Slug Catcher Characteristics
Finger Type
Economical way to catch large slugs
Gives predictable particle separation in the 50
micron and up sizes
Predictable separation up to tens of thousands of
barrels slug size
Shipping in pieces for field assembly with line
pipe
When slug size is large enough to justify the
logistics of field assembly, and B31.8 type
construction allowed, the harp type
separator/slug catcher will be considerably
cheaper than vessels
Vessel Type
Can give small particle separation (10 microns)
where there is liquid and lower gas flow
It is possible to be used as a three-phase
separator
Becomes expensive and heavy when large sizes
are required
When the slug size is up to 5-700 bbl., the
separation performance is good
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Karam – Slug Catchers in Natural Gas Production
Table 2: Data from the reservoir and the pipelines of the four different fields
Processing
Plant
Field
Starting
Production
date
Water
Depth
Reservoir
depth
Distance
to the
field
Pipeline
number
Pipeline
OD
Pipeline
OD
Pipeline
ID
Pipeline
ID
[-] [-] [-] [m] [m] [km] [-] [in] [mm] [in] [mm]
Kollsnes Troll 19/09/1995 350 1400 67 2 36 914.4 35.5 901.7
Heidrun 18/10/1995 345 2300 250 1 16 406.4 14.95 379.8
Melkøya Snøhvit 21/08/2007 250-340 2400 143 1 26.8 680.7 25.80 655.3
Nyhamna
Ormen
Lange
13/09/2007 800-1100 2013 121 2 30 762.0 27.17 690.0
Processing
Plant
Table 3: Data related to the wells and the slug catchers collected for the four different fields (* numbers close to real data)
Field
Field
Flow
Rate
Number
of Wells
Well
Flow
Rate
Slug
Catcher
Capacity
Slug
Catcher
Capacity
Page 38 of 56
Number
of Slug
Catcher
Slug
Catcher
Total
Capacity
Slug
Catcher
Total
Capacity
Pipeline
Outlet
Pressure
Pressure
Inlet to
Slug
catcher
Temperature
Inlet to Slug
catcher
[-] [-] [MSm 3 /d] [-] [MSm 3 /d] [m 3 ] [ft 3 ] [-] [m 3 ] [ft 3 ] [bar] [bar] [°C]
Kollsnes Troll 100 39 2.56 1250 44150 2 2500 88300 90 ~120 5 – 8*
Tjeldbergodden
Tjeldbergodden
Heidrun 11 10 1.10 2300* 81236 1 2300 81236 120-170
Melkøya Snøhvit 20.8 9 2.31 2800 98896 1 2800 98896 120-90*
Nyhamna
Ormen
Lange
50 (30-
50)
75 (70-
90)
increase of 40
(-5) - (4)
70 8 8.75 1500 52980 2 3000 105960 110-95* 90 2 – 4

Karam – Slug Catchers in Natural Gas Production
CHAPTER 12 FIGURES
Figure 1: The six different flow patterns that form depending on the flow speed in the channel. (Aker Solution,
2011)
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Karam – Slug Catchers in Natural Gas Production
Figure 2: The slug formation process in three steps starting with the Kelvin-Helmholtz Wave Growth, then by a
slug nose ingress and tail shedding to gas entrapment (Feesa, 2003)
Figure 3: The effect of pipeline inclination on slug formation (Feesa, 2003)
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Karam – Slug Catchers in Natural Gas Production
Figure 4: Idealized slug unit showing all four different elements: the mixing zone, the slug body, the film and the
bubble (Scott et al., 1989)
Figure 5: Representation of the slug unit and unit length with both the slug and film zones (Marquez et al., 2009)
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Karam – Slug Catchers in Natural Gas Production
Figure 6: Flow map of a 20-in horizontal slug catcher showing the operational point (Sarica et al., 1990)
Figure 7: Flow map of a 26-in horizontal slug catcher showing the operational point (Sarica et al., 1990)
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Karam – Slug Catchers in Natural Gas Production
Figure 8: The appropriate design of a constrictor (Shell, 1998).
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Karam – Slug Catchers in Natural Gas Production
Figure 9: View of the inlet side of a multi-pipe slug catcher (Patel, 2007)
Figure 10: View of the liquid header side of a multi-pipe slug catcher (Patel, 2007)
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Karam – Slug Catchers in Natural Gas Production
Figure 11: The bottle geometry of the slug catcher for Troll field in the Kollsnes processing plant (Shell, 1998)
Figure 12: A general view of the two slug catchers at the Kollsnes Processing plant (Klemp, 2011)
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Karam – Slug Catchers in Natural Gas Production
Figure 13: The different components of the Hammerfest processing plant of the Snøhvit field (Pettersen J. , 2011).
Figure 14: Representation of the Storegga Slide (left) and the location of the field (right) (Bryna et al., 2005)
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Karam – Slug Catchers in Natural Gas Production
Figure 15: A general Overview of one of the two multi-pipe slug catchers at Ormen Lange (Gupta, 2012)
Figure 16: Setup of the HYSYS model (MEG injection was not included in this setup)
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Karam – Slug Catchers in Natural Gas Production
Figure 17: Elevation profile of the Ormen Lange big bore well retrieved from the HYSYS model
Figure 18: Elevation Profile of the Ormen Lange flowline (Christiansen, 2012 from Biørnstad, 2006)
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Karam – Slug Catchers in Natural Gas Production
Figure 19: The digitized elevation profile of the Ormen Lange flowline in HYSYS
Figure 20: The slug tool results showing the position, length, frequency and velocity of slugs along with different
flow regimes in the Ormen Lange pipeline.
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Karam – Slug Catchers in Natural Gas Production
Figure 21: The elevation profile of the Snøhvit flowline (Christiansen, 2012)
Figure 22: The digitized elevation profile of the Snøhvit field as it is implemented in HYSYS
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Karam – Slug Catchers in Natural Gas Production
Figure 23: The elevation profile of the Troll flowline. H=-350 m and L=67 km (Albrechtsen & Sletfjerding, 2003)
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Karam – Slug Catchers in Natural Gas Production
APPENDIX I - GENERAL INFORMATION ABOUT THE FIELDS
USED FOR THE HYSYS SIMULATION
I.A – Troll Field
The gas composition of the Troll field is represented in the table below along with the corresponding
densities for C6 components and above (Madsen, 1997 and Bolle).
Component
Troll Gas Composition
Mole
Composition
weight
(mol %)
(g/mole)
N 2 1.749 28.01
Density
(Kg/m3)
CO 2 0.226 44.01
C1 92.815 16.04
C2 3.265 30.07
C3 0.585 44.10
iC4 0.331 58.12
nC4 0.090 58.12
iC5 0.081 72.15
nC5 0.330 72.15
C6 0.110 86.18 664.0
C7 0.185 96.00 738.0
C8 0.118 107.00 765.0
C9 0.051 121.00 781.0
C10+ 0.064 160.13 811.5
Since the gas arriving to the Kollsnes plant comes from three different platforms, then the respective
flow rate and the MEG injection rate varies and is represented in the table below (Madsen, 1997).
Field/
Platform
Typical Gas
Rate
(MSm 3 /d)
Typical
MEG
Injection
(m 3 /d)
Troll (ABC) 119 200
Kvitebjørn 20 10
Visund 6 4
Total 145 214
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Karam – Slug Catchers in Natural Gas Production
The reservoir and fluid properties are also essential for developing a HYSYS simulation. The data
required are shown in the following table (Bolle).
Reservoir and Fluid Properties
Reservoir pressure at 1547m MSL
158 bar
Reservoir temperature 68 °C
Gas gravity 0.61
Gas quality Sweet, dry, lean 24-29 ° API
Gas viscosity
0.018 cP
Gas density (at standard conditions) 0.75 Kg/m 3
Oil gravity
0.908 g/cm3
Oil quality
Slightly waxy
Condensate/gas ratio 29 Sm 3 /MSm 3
Condensate gravity
0.802-
0.825
g/cm 3
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Karam – Slug Catchers in Natural Gas Production
I.B – Heidrun Field
The gas composition of the Heidrun field can be found in the table below (Hansen, 1997).
Component
N2-C1
CO2
C2
C3
C4
C5
C6
C7
C8-C9
C10-C11
C12-C13
C14-C15
C16-C17
C18-C19
C20-C21
C22-C23
C24-C25
C26-C29
C30-C33
C34-C38
C39-C44
C4-C54
C55-C80
Mole
Composition
(%)
8.62E-01
1.23E-02
5.24E-02
2.03E-02
2.27E-02
1.12E-02
3.40E-02
4.12E-03
6.21E-03
2.53E-03
1.60E-03
9.19E-04
4.18E-04
1.69E-04
4.95E-05
2.28E-05
1.08E-05
6.60E-06
9.43E-07
2.06E-07
3.42E-08
5.43E-09
1.36E-09
The basic reservoir properties of the Heidrun field are represented in the table below (Actis, Smith,
& Chenier, 1993 and Norway).
Reservoir Properties - Heidrun
Reservoir pressure
267 bar
Reservoir temperature 85 °C
Gas in Place 50 BSm 3
Oil Gravity 851 Kg/m 3
Gas flow rate 11 MSm 3 /d
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Karam – Slug Catchers in Natural Gas Production
I.C – Snøhvit Field
The gas composition of the Snøhvit field can be found in the table below (Golan, 2012).
Component
Mole Fraction
Nitrogen 0.02525
Carbon dioxide 0.05262
Methane 0.81006
Ethane 0.05027
Propane 0.02534
i-Butane 0.004
n-Butane 0.0083
i-Pentane 0.00281
n-Pentane 0.00308
Hexanes 0.00352
Heptanes 0.00469
Octanes 0.00407
Nonanes 0.00203
Decanes plus 0.00397
Proprieties C 10+ fraction_
Molecular weight (g/gmol) 172
Density (kg/m3) 814
The basic reservoir properties of the Snøhvit field are represented in the table below (Christiansen,
2012)
Reservoir Properties - Snøhvit
Reservoir pressure
267 bar
Reservoir temperature 92 °C
Gas flow rate 20.8 MSm 3 /d
Gas In Place 317 GSm 3
Condensate 34 MSm 3
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Karam – Slug Catchers in Natural Gas Production
I.D – Ormen Lange Field
The gas composition of the Ormen Lange field can be found in the table below (Valberg, 2005).
Component Mole fraction
N2 0.003411
CO2 0.00408
H2O 0.005931
Methane 0.930927
Ethane 0.034719
Propane 0.012177
i-Butane 0.002717
n-Butane 0.00322
i-Pentane 0.00151
n-Pentane 0.001308
The basic reservoir properties of the Ormen Lange field are represented in the table below
(Biørnstad, 2006).
Reservoir Properties - Ormen Lange
Reservoir pressure
290 bar
Reservoir temperature 96 °C
Gas flow rate 70 MSm 3 /d
Condensate Production Rate 6000-8500 GSm 3
Gas Molecular weight 17.443
Gas Specific Gravity 0.6
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