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OTC 23694

Marlim 3 Phase Subsea Separation System Challenges and Innovative

Solutions for Flow Assurance and Hydrate Prevention Strategy

Daniel Greco Duarte, Alysson Vincius de Melo, Carlos Bandeira Cardoso, Flvio Luiz Vaz Vianna, Petrobras; and
Tine Irmann-Jacobsen, Ole Thomas McClimans, Paulo Machado, Pavel Barta, Zabia Marie Furre Elamin, Randi
Moe, FMC Technologies
Copyright 2012, Offshore Technology Conference
This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 30 April3 May 2012.
This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

This paper presents hydrate design premises established to reach the final design and operational philosophy for the 3
phase subsea separation system, also known as Marlim SSAO. The main purpose of this pilot station is to separate the
produced water and reinject it into reservoir for pressure support while routing the oil and gas to topside.
Since the subsea process station handles multiphase flow where gas and free water are present, and the system is exposed
to low temperatures by the ambient cold sea water, a good strategy to avoid hydrate formation is necessary. The hydrate
strategy must be incorporated as a part of the total system design and shall handle all critical operational scenarios as shutdown and start-ups. The hydrate strategy is closely linked to the temperature control and the evaluation of need for thermal
insulation of the system. Temperature control is also important in the system because of high sensitivity in fluid properties.
General thermal insulation verification analysis and detailed studies of cold spots are required. Real fluid testing was included
in order to better evaluate the hydrate potential.
The Marlim SSAO, as an integrated part of a field system from subsea wells to topside, is divided into several parts for the
facilitation of the flow assurance and the hydrate prevention strategy: Multiphase lines, water lines and water injection system.
The hydrate prevention is very challenging because of several open connections between the multiphase lines and the water
lines. Hence, usual means as MEG inhibition and thermal insulation have not been enough to ensure the hydrate prevention
strategy and new strategies have been developed. It has been necessary to challenge the strategies in every part of the system.
The results of the work methodology and the analysis executed indicated that Marlim SSAO is a safe system to operate
from a flow assurance and hydrate prevention point of view. The material presented in here intends to establish a key reference
for preservation design of 3 phase subsea separation systems. It applies for future generations of these kinds of equipments.
The Marlim SSAO is a subsea processing pilot station which has been installed in the Campos Basin off the coast of
Brazil. The objective is to separate most of the water from the production stream and re-inject it into the reservoir for pressure
support while transporting the oil and gas to topside. The SSAO is installed at a water depth of 876 m, 341 m from the
production wellhead and 2100 m from the injection wellhead. The hydrocarbons will be sent to the topside facilities 2400 m
(riser and flowline length) from the SSAO.
This paper describes the challenges and innovative solutions on flow assurance and hydrate prevention strategy for the
Marlim SSAO. This includes the main philosophy, the preservation of the station in different operational modes, evaluations
of identified risks, and calculations and analysis performed to support the strategy.

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System description
Schematic drawing of the SSAO processing system is presented in Figure 1. The production fluid from the well flows first
through a multiphase inline desander that removes most of the sand. This equipment aims to reduce the solid accumulation, as
well as decreasing the required flushing frequency of the downstream equipment. The free gas is separated in a harp and the
liquid stream (oil and water) goes through the Pipe Separator.
Downstream the separator the water is led to the polishing line while the oil and gas is recombined before entering the
multiphase flowline for transportation to topside. The polishing line consists of another inline desander and two hydrocyclones
to ensure the water meets the strict quality requirements before being boosted and injected into the reservoir.
The desanders and hydrocyclones have reject lines entering the multiphase flowline downstream the separator. There is
also a water crossover line going from the pump outlet to the multiphase flowline that is required for some operational
scenarios. In addition there are several water lines to be used for periodic flushing of the equipment.
In other words there are several connections between the water lines and the multiphase lines which is challenging when
considering flow assurance management. Some of the connection points are in use during normal operation while others will
function as dead legs.
The use of vertical connectors and strict limitations of weight and size for all retrievable modules have resulted in a
challenging mechanical design for subsea station from a flow assurance point of view.
The SSAO system has been divided into several parts for the facilitation of the discussions of the hydrate prevention
Multiphase lines
Inlet multiphase line
Equipment modules (bypass module, multiphase desander, harp, pipeseparator, outlet vessel)
Outlet multiphase line (downstream separator)
Low pressure water lines
Water system downstream separator and upstream water injection pump
Equipment modules (water desander, hydrocyclones)
High pressure water lines
Water injection system (WI) downstream WI pump and to the water injection well
Water flushing system
Mulitphase flowlines upstream and downstream the SSAO





High pressure lines


Figure 1: Schematic of the SSAO, definition of the low pressure parts of the system

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Main premises for the hydrate prevention strategy

The main philosophy of the production system is to operate above hydrate formation conditions during normal production.
For a planned shutdown of the processing station MEG shall be available for preservation of critical components. In case of
unplanned shutdown the system shall allow for 2 hours no-touch time and 4 hours preservation time giving a total cool down
time of 6 hours. To meet the cool down time requirement the system is thermally insulated.
The ultimate system safeguard is a full depressurization in case of hydrate plugging.
Due to the numerous connections between water and multiphase lines and the layout limitations it was found that designing a
system with no risk of hydrates would require many MEG injection points. Including more MEG injection points would have a
large cost impact. The main premise for the hydrate prevention strategy has therefore been to design a system with low risk but
with a limited number of MEG injection points.
The hydrate prevention strategy of the production and gas lift flowlines upstream and downstream the separator station,
will be through depressurization and fluid substitution by diesel. This concept is according to the existing philosophy for this
Hydrate curve
Two hydrate curves are shown in Figure 2, one for the Marlim reservoir fluid (well fluid) and another for the same fluid
but added gas lift. The curve has similar form both for the multiphase and the dissolved gas because the relative fraction of
components that impacts the curve is kept the same. The curve show that for temperatures and pressures in the operational
envelope from 50-60C and 50-60 bara the station is operating outside the hydrate formation region. The critical hydrate
formation temperature used as a basis for the evaluations was set to 15C.
The ambient sea water temperature is 4C hence the requirement for depressurization would be approximately 10 bar for
the separator station.



Pressure [kgf/cm!]



Wellfluid with gaslift





T = 4C


Temperature [C]




Figure 2: Hydrate curve, the dissolved gas and potential free gas will have similar hydrate curve as the well stream
Kinectic tests of actual fluid
In order to verify the hydrate formation kinetics tests were performed where samples of the produced water were placed in
contact with gas under hydrate formation conditions. The test of hydrate kinetics for the production fluid showed that the fluid
is not hyper sensitive to hydrate formation.
1. The test fluid form hydrates under shaking, with induced times ranging from 30 minutes to 7 hours.
2. Without shaking, the same test fluid did not form hydrate for up to 16 hours of experiment.
The tests have shown approximate times for hydrates formation under hydrate formation conditions regarding pressure and
temperatures. Although the test showed no hydrate formation for stagnant fluid, the operation of the production system will
always cause mixing (shaking) of the gas and water. MEG is therefore necessary in order to avoid hydrates in the system when
the system is inside the hydrate formation envelope (e.g. during cold start up).

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Depressurization as method for hydrate removal

Simulations were performed to verify if it is possible to depressurize the SSAO. The simulations showed that it is possible to
depressurize the SSAO to approximately 5 bar, which is sufficient to dissolve any hydrates. The depressurization can be
performed within 4 hours and requires depressurization of both the production flowline and the gas lift line.
To depressurize the system it is necessary to shut down the production well as both the production and gas lift flowlines are
used to depressurize the separation system.
Hydrate formation risk analysis at SSAO
The operating envelope of the SSAO is with a water cut of approximately 70-90% off the incoming multiphase fluid. This
means that the amount of gas present in the multiphase system is relatively low (actual gas/liquid ratio is 0.5-1).
When the system is shut down and the fluid is still (after transient), the only hydrates that might form is on the interface
between the water and the gas. To form rapid hydrate blockage the hydrates formed needs to be of a type which stick together
and builds up in blocks or on walls. In general there needs to be a constant feeding of new gas into a place in the system to
build blockages of hydrates. This happens usually when the system is in dynamic flow, mixing and moving or if there is an
enclosed volume which is constantly fed by gas.
The complexity of multiphase and water lines at the processing station results in intersections or dead legs that could be
exposed to hydrates.
The insulated part of the SSAO includes multiphase lines (Figure 1green and brown) and the low pressure water lines
(Figure 1blue and orange). The insulation is designed with respect to the cool down criteria i.e. a period of 6 hours and
hydrate formation temperature of 15C.
The risk for hydrates due to oil and gas carryover from the separator has been evaluated together with the requirement for
MEG injection.
The hydrate strategy and design of the SSAO have aimed to minimize the number of scenarios that might lead to hydrate
Each part of the SSAO was examined in detail to identify and evaluate the risk for hydrate formation.
Low pressure water lines
Evaluations have been performed to check whether there is a risk for hydrate formation in the water lines from the outlet
section of the separator to the water injection well. To form hydrates free gas and free water need to be present. The critical
question is to identify if this condition can manifest itself in the water lines. The fluid in these lines is mainly water. Three
possibilities of presence of free gas have been identified.
Open connection points
Flashing of gas in water lines
Backflow from multiphase lines
Open connection points
An open connection point is defined as an open intersection between water lines and multiphase production line at the
SSAO. In these intersections the flow direction will be from high pressure to lower pressure, i.e. from water line into the
multiphase line during normal operation. In addition it is necessary to evaluate the impact of other operational scenarios; both
planned and unplanned. The main flow assurance challenges in these water lines are:
prevent gas ingress
prevent sand accumulation
The strategy to solve the open connection point challenges has been to arrive at a design that prevents both gas ingress and
sand accumulation, while taking into account the process requirements and layout limitations. As each open connection point
differs in size and process requirements the design has had to be tailor-made for each individual point.
CFD analyses have been performed to arrive at an appropriate pipe layout design; both by investigating multiphase flow
patterns and cool down.
Intersection between water crossover line and multiphase line
The connection point between the water crossover into the multiphase line is an open connection point. The diameter of the
water line is the same as the multiphase line. The water line is usually not in use and will be cooled to the ambient seawater
temperature. Hydrate risk would be from gas fed into line over time. Several designs have been investigated and the design
indicated in Figure 3 has been evaluated as the optimum design to prevent gas ingress and sand accumulation from the
multiphase flow. CFD simulations have been used to verify the design and as can be seen in Figure 4 the gas ingress is
marginal and the risk of hydrate blockage has been evaluated to be low. MEG will not be required for this water line dead leg
to mitigate hydrates.

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As short as possible

Main multiphase
line with flow

Insulation scope

As long as possible

Gas/water interface

Water line with

stationary water

Figure 3: Schematic view of an intersection between multiphase and water lines with same diameter

Figure 4: Gas volume fraction for connection point between lines of same diameter, from CFD simulations. In the
multiphase line the fluid is flowing, while in the angled deadleg the water is stationary.
Intersection between reject lines and multiphase line
The water desander reject line transports sand from the water desander into the multiphase production line. As the main
function of the line is to transport sand the inclination cannot be too steep. For the hydrocyclone reject lines the main function
is to transport oily water and no sand will be present in normal use. The inclination can therefore be steeper. The reject lines
are much smaller in diameter than the multiphase line. The lines are normally in use, except when the water system is
bypassed. If the water system is bypassed the design should prevents gas ingress and sand accumulation into the reject lines.
CFD analysis have been performed and used as a design tool for the pipe geometry. A schematic is shown in Figure 5 and the
result from the CFD analysis is shown in Figure 6. The risk of hydrate blockage due to ingress of gas into the reject line is
considered to be low and no hydrate measures are required when these lines are not in use.

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Insulation scope

Main multiphase
line with flow

Gas/water interface

As short as possible

Reject line
Flow direction

Figure 5: Schematic view of intersection of reject line of smaller diameter reject into multiphase line

Figure 6: Design intersection of reject line of smaller diameter into multiphase line
Flashing of gas in low pressure water lines
Due to oil carryover into the waterline downstream the separator there could be a risk of hydrate build up. The oily water
flow passes through a desander and two hydrocyclones causing pressure drop. When saturated water and oil is subject to
pressure drop, the solubility of gas decreases and some gas will be released from the liquid phase. This results in small
amounts of free gas that will be present in the stream. To investigate the risk of hydrates formation due to the free gas a set of
worst case operational scenarios were defined with respect to oil carry over, pressures and temperatures. The actual volume of
gas has been calculated. The geometry of the piping has been scrutinized for possible locations where gas could accumulate
and form hydrates, especially all possible deadlegs.
There is only one identified potential area for gas accumulation between the outlet section and water injection pump. Any
gas in this point, which is a dead leg, will be removed when the first hydrocyclone is bypassed during the hydrocyclone
backflushing sequence every second week. The gas will then enter the second hydrocyclone and be removed through the reject
line. The backflushing is meant to be a preventive measure and the likelihood of all the reject holes in the second hydrocyclone
being blocked is low. This imposes that the probability of hydrates formation caused by gas accumulation due to gas flashing
is very small.
Backflow from multiphase lines
Dynamic process simulations have been performed for the subsea production system including the separation and water
reinjection systems. The dynamic simulations identified some scenarios that can cause a limited backflow from the multiphase
line into the water inject line. The risks were evaluated and it was found a minor increased risk for hydrate formation in the
water inject line.
The backflow scenario will have a very low frequency. Analysis show that the exact volume of potential hydrate formation
(between 5 and 10 vol%) due to hydrocarbon ingress is not important as long as it is limited. It is the kinetics in the startup and
eventual accumulation that will give the premises for the hydrate formation to occur. If the gas ingress is equally distributed in

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the line it will make no potential hydrate risk. Agitation of flow in a startup after a backflow occurrence is difficult to avoid.
To prevent blockage in this situation an operational priming procedure shall be executed immediately before startup. This will
increase the temperature in the system and secure the reject lines from potential hydrate formation. This imposes that the
probability of hydrate formation caused by backflow is very small. If it happens it is still possible to depressurize the system to
remove hydrates.
High pressure water lines
During normal production the water in the injection line downstream the pump is undersaturated since the pressure is much
higher than the separator equilibrium pressure. The temperature is also higher than the hydrate formation temperature at the
operating pressure. Hence, there is no risk of hydrate formation during normal production.
At shut-down, the maximum shut-in pressure is much higher than the separator equilibrium pressure and the temperature is
ambient after cool-down. The system is far into the hydrate zone, but there is no free gas available as long as the system is
pressurized at a higher pressure than the separator pressure. The solubility increases both due to increased pressure and
reduced temperature and the system is undersaturated.
In conclusion no hydrate risk has been identified for the high pressure water lines and no hydrate prevention measures have
been included.
Multiphase lines and production lines
The multiphase lines will be insulated to ensure that the temperature during normal operation is above hydrate formation
temperature and to keep the requirement of a no-touch time of 2 hours and a total cool-down time of 6 hours.
Dead legs have been carefully evaluated to reduce the hydrate formation risk and the design of the piping has been
optimized to reduce the risk further. In some cases it was not possible to keep the dead legs warm during normal operation and
MEG injection points are required to avoid hydrates. For these dead legs the piping layout has been optimized to ensure
retention of MEG, the piping will be located at low points to ensure that the MEG is kept in place.
Chemical injection lines
The requirements for the design of chemical injection points are based on discussions with internal control experts, flow
assurance evaluations and thermal FEA analysis.
Ideally the pipe between the injection point and injection shut off valve should be kept above hydrate formation
temperature during normal production. The pipe is drained to avoid accumulation of sand or other contamination. Thermal
insulation have been verified for each injection point, however not all injection point will meet the requirement of temperature
above hydrate temperature. Operational procedures which include regular opening of the injection valve to flush valve and
downstream piping have been established for these injection points.
Discussion and conclusion
A thorough evaluation has been performed to identify hydrate risks for the Marlim 3 phase subsea separation system. Due to
the operational requirements of sand removal and water polishing this forms a complex system with interfaces between water
pipes and multiphase pipes and many dead legs.
All possible operational scenarios of this system have been evaluated with respect to hydrate formation in any part of the
system. Mitigation measures have been implemented in design and operational procedures. This paper has presented piping
designs that reduces risks for hydrate formation in dead legs. Instead of the conservative approach of flushing all parts of the
system with MEG during a shut down, some parts have been identified as low or no hydrate risk and MEG injection can be
omitted. Reduction of the number of MEG injection points make the operation less complex and reduce cost.
CFD Computational Fluid Dynamics
FEA Finite Element Analysis
MEG Mono Ethylene Glycol
SSAO Separaco Submarina gua-leo (Subsea separation of water and oil)
WI Water Injection