1. 1
Functional Approach to Flow Assurance Applied to
Deepwater Field Development
Jean-François Saint-Marcoux, Brian F. Kennedy - Paragon Engineering Services
Abstract
Flow Assurance requirements are major drivers of Deepwater Field Architecture.
However, current methods of stipulating these requirements may not provide the
safeguards that are intended for the full range of operating conditions.
One example is the difference in thermal inertia of insulation systems. Specifying an
Overall Heat Transfer Coefficient does not impose a minimum cool-down time for the
system, and specifying a cool down time without a warm-up time may lead to increasing
thermal inertia, which is adverse for warm-up.
The paper presents a refined method that consists of a systematic review of all operating
conditions for the facilities under design. They include warm-up, well start-up, steady
state design conditions (early, mid and late life), shut down (planned and unplanned), and
blockage remediation.
Fluid properties are used to anticipate critical conditions (hydrate, wax formation and
asphaltene deposition) and to identify under which operating scenarios they are most
likely to occur. State-of-the-art multiphase transient analysis and Finite Element Thermal
Analysis can, within the frame of the proposed method, be used to better assess boundary
conditions to depict the behavior of the facilities.
Simulating critical functional conditions at an early stage allows selection of both a
CAPEX approach by modifying the architecture of the development and, in conjunction,
an OPEX approach by dedicating operating procedures (e.g. heating vs. hot oiling).
This method has already been used for a Deepwater field in West Africa. It is applicable
to passive insulation systems, as well as active heating systems. The method is also
applicable to the analysis of various artificial lift methods, such as multi-phase pumping
and riser gas lift, that have an effect on the whole production system.

2. 2
1. Introduction
The basic parameters that define a deepwater field development are fluid
characteristics and production data. It is common to study several fluid characteristics
and production profiles. This is treated by additional iterations.
1.1 Thermodynamic properties chart
It is convenient to present the properties of a particular fluid in the traditional
pressure temperature chart Ref. [12]. The following properties can be readily
obtained from commercially available PVT packages and process simulator:
- Phase envelope from the following laboratory data
o Chemical composition
o Pseudo component properties
o Tuned binary interaction coefficients for the Equation Of State (EOS)
o Liquid density at stock tank conditions
- Hydrate formation curve Ref. [4]
The hydrate formation curve depends on the salinity of the water with which
the gas phase may be in contact. Three cases are usually considered:
o Fresh water
o Sea water (applicable if sea water is used as injection water)
o Formation water
The salinity of formation water is usually larger than seawater and
therefore to remain on the safe side the hydrate formation curve with
seawater is retained, specifically when seawater is used at least
partially for water injection, see Fig.1.
- Wax Appearance Temperature (WAT)
This data is obtained experimentally. It is usually not very sensitive to
pressure and is often represented as a straight vertical line in the P, T plane.
WAT may be very different even for crudes found in adjacent locations1
.
- Asphaltene2
- Asphaltene deposition conditions do not benefit from existing
well-established correlations. However increased pressure is known to be
favorable to asphaltene deposition within a certain range. Wellfluid data
acquisition is nevertheless recommended Ref. [11], [13].
Fig. 2 shows a typical well fluid characteristics from a deepwater field in a P, T
diagram.
1.2 Effect of Deepwater and Ultra Deepwater
The energy equation Ref. [3] holds that under steady state,
QWgzVhgzVh +=++−++ )
2
1
()
2
1
( 1
2
1112
2
222 ρρ Eq. 1
1
Unlike hydrate curves that are usually in the same range (below 20o
C [68°F]) for most crudes.
2
ASTM D3279-97 provides the procedure to determine the asphaltene content of stock tank oil.

3. 3
For a riser in which no work is done, W is zero. The velocity is usually limited by
erosional criterion to a low enough value (for example, Ref. [2]), and therefore the
velocity term in Eq. 1 may be neglected.
Consequently as per Ref [3]
Qgzhgzh =+−+ )()( 1122 Eq. 2
Where (h + gz) is the significant terms of total enthalpy. This shows the
equivalence of changing elevation and changing thermodynamic enthalpy.
In a first approximation neglecting the Joule-Thomson coefficient, and the phase
change, the enthalpy may be taken as Cp T. It is then possible to assess the
change of temperature equivalent to a change in elevation.
)()''( gzCpTgzCpT +=+ Eq. 3
)'(' zz
Cp
g
TT −−=− Eq.4
Numerically for a typical hydrocarbon this corresponds to about 1o
C per 200m of
change in vertical elevation1
. As a first approximation in a P, T diagram, Eq.4
establishes the decrease in temperature caused by the impact of water depth. This
temperature difference is sometimes referred to as the adiabatic temperature
difference. (See Fig.3.)
1.3 Production Facilities Constraints
The processing facilities require a minimum arrival pressure and temperature.
The inlet pressure is dictated by the optimum liquid recovery Ref [6] that is
usually in the range of 20 to 40 bar (300 to 600 psi).
The Wax Appearance Temperature dictates the arrival temperature if higher than
the ambient temperature at the floating facilities.
1.4 Summary of Allowable conditions
a) Steady state conditions
As a result, the well fluid, in steady state production, must remain within a
rectangle in the pressure, temperature plane limited by:
o The wellhead flowing temperature less the adiabatic temperature difference
derived above
o The wellhead flowing pressure
o The minimum processing temperature
o The wax appearance temperature (or ambient temperature)
1
1o
C per 200m is equivalent to 1o
F per 370’

4. 4
As shown on Fig.3, the impact of elevation change is significant. This explains
the high insulation level required by deep water lines. This requirement gets
more severe with increasing water depth and thus insulation levels get even
more stringent with ultra deepwater lines.
The steady state constraints are summarized in Fig.4.
The impact of the productivity index Ref. [10] is identified in Fig. 5. It does
not significantly affect the above statements especially in the case of high
productivity wells typical of the recent finds in deep water.
b) Non producing condition
As an example in the South Atlantic (Ref 7) the temperature varies between
2.5o
C at 3000m [36.5°F at 9850’] in Ultradeep conditions to 4o
C at 1000m
[39°F at 3300’] in Deepwater conditions at 30o
of South Latitude.1
At this temperature range, the hydrate formation pressure is typically above 10
bar and therefore depressurization to atmospheric pressure is effective.
Therefore, under non-producing conditions, the hydrate formation curve, the
sea floor isotherm, and the atmospheric pressure line limit the operating
envelope. The atmospheric pressure represents the limit of the lower pressure
achievable3
.
2. Functional Analysis Approach
Functional analysis may be seen as a comprehensive review of all phases of the
system whether operating at design conditions, during transient phases, or during
non-producing conditions. The purpose of flow assurance is to allow the fluid to
remain on the allowable range during start-up, steady state and shut down. Applying
functional analysis warrants a systematic and comprehensive flow assurance review.
The steady state is considered first, then shut down, cooldown, start up, and warm-up.
This is in reverse order of the actual operations but this corresponds to the usual
progression of the field architecture, and the flow assurance analysis.
The diagram “Flow Assurance Overall Review” represents the sequence of analysis
that is required to insure this systematic approach.
2.1 Steady State (See Fig. 3)
Several software are available on the market to perform multiphase flow analysis:
PIPESIM (steady state), OLGA, PLAQ and TACITE (transient conditions)
among others.
1
Lower temperatures down to –2o
C can be found in the Northern North Sea. Higher deep-water
temperature can be found in the Mediterranean Sea (12 to 13o
C).
3
The riser base lift gas line may also be used for depressurization, when available.

5. 5
The available pressure difference provides the sizing criterion for the line. It is
then necessary to check for the occurrence of severe slugging. Internal studies
have shown that the local configuration of the risers, (SCR’s, Hybrid Riser
Towers, Flexibles) does not significantly affect the onset of severe slugging.
It is worth noting that riser base gas lift can be used for at least two purposes:
- driving the onset of severe slugging down to a lower flowrate threshold
- reduce the weight column under high water cut
In the former case the lift gas should be insulated to prevent the cooling of the
wellfluid. This is not required if lift gas is to be used for the latter only, as the
mass flowrate and therefore the thermal inertia of the gas lift flow is small
(typically 10%) in front of the mass flowrate of the well fluid.
Even moderate down slope before the riser increases the likelihood of severe
slugging. The location of the production facilities is often conditioned to avoid
negative slopes.
When a wide range of flow rates is anticipated, a loop with two different line sizes
can be beneficial. Some pigs can tolerate a change in diameter and therefore still
allow round trip pigging under those conditions.
In a summary, the available pressure differential determines the minimum line
size. The temperature differential determines the minimum flow rate, assuming
heavy slugging conditions are avoided, for example with riser base gaslift.
The minimum flowrate is of course, dependent on the selected insulation system.
The review of the insulation systems available on the market is beyond the scope
of this article, however the various systems may be divided into:
- Wet insulation4
(Polypropylene and derivative, Polyurethane and derivative,
epoxy)
- Pipe-In-Pipe (PIP) (Polyurethane Foam (PUF), Microporous under
atmospheric pressure, Microporous under partial vacuum)
Industry studies have indicated that below an OHTC valve of 2 W/m2
K [0.35
BTU/ft².hr.°F], pipe-in-pipe may be competitive and below 1W/m2
K [0.18
BTU/ft².hr.°F] pipe-in-pipe is currently widely used if not the only solution5
.
2.2 Shutdown
The shutdown issue is dominated by hydrate formation avoidance, as no
significant wax deposition will occur when the fluid is not circulating. It is
recognized Ref. [8] that hydrates do not form during the cooldown period but to
the contrary upon restart.
4
Manufacturing of wet insulation is limited to about 120 mm [6 inches] which correspond to an OHTC of
about 2 W/m².K [0.35 W/m².K].
5
Vacuum insulated lines are another solution provided large heat losses at field joint are handled and
possible hydrogen permeation is mitigated.

6. 6
a) Planned shutdown
Hydrate avoidance procedures that can be implemented include:
- in the case of passive insulation:
o methanol injection
o displacement by dead oil
o depressurization6
- in the case of active heating7
, maintaining the wellfluid temperature above
hydrate formation temperature.
The cost of active heating is to be weighed against the cost of dead oiling
facilities.
b) Unplanned shutdown
In the case of unplanned shutdown time should be allocated for
recognizing the issue and implementing the procedures. This usually
translates into a cooldown time composed of:
§ a no touch period during which the risk of hydrate formation is
recognized and acknowledged
§ a period required for intervention such as
• methanol injection
• dead oiling
The latter period increases with the length of the tieback, and the number
of loops to be treated simultaneously.
2.3 Cooldown
The steady state heat transfer limits the heat release in the regular section of the
line. The fastest temperature drop will occur on singular points such as:
- manifolds
- valves with unprotected actuators
- connectors
- bulkheads
- field joints
It has been recently observed that unprotected or incompletely protected
connectors or flange sets, especially when the pipe axis is in the vertical position
can generate high heat losses associated with the formation of a thermosiphon.
Care should be taken to properly design and implement convection mitigation
techniques.
A controversial issue is the minimum acceptable length of cold spot. In the case
of a horizontal line or nearly horizontal line, it can be shown that due to internal
convection inside of the fluid, the cold fluid region will be limited to the cold
6
Dedicated service lines to cluster manifolds may be used for depressurization
7
Electrical heating systems usually generate constant heat flux. In multiphase flow this may generate high
temperature in gas pockets. From this standpoint, hot fluid has advantages as, by principle, it limits the
temperature.

7. 7
spot. Upon restart a mixing will occur and a short cold spot will vanish in the
surrounding hotter fluid. Averaging over the length of a pipe joint appears
legitimate, even though all operators do not yet generally accept this as a rule.
In the case of vertical cold spots, the cold fluid will not remain at its location but
will slowly migrate towards the deepest area of the line where it will mix with
surrounding fluid. Typical migration velocities are in the range of 10-2
m/s [0.4
inch/s].
Cooldown involves two phenomena:
- Fluid comes to rest; gas and liquid separate according to the profile of the line
- Heat is dissipated
The coming to rest of the fluid occurs within a short duration typically in less than
a half-hour, whereas the cooldown requirements can be in the range of 10 to 30
hours or more. Because those two phenomena happen on a different time scale, it
is possible to model them separately.
The coming to rest of the fluid can be analyzed with the same transient
mechanistic software so the cooldown interface of the gas and liquid can be
reliably identified. Under ordinary conditions cooldown occurs with a line full of
liquid (no depressurization).
Heat dissipation, even for simple geometry requires finite difference analysis and
for complex geometry finite element analyis1
. Several software are available for
this type of analysis (see Fig. 6)
- SYSTUS as used on Girassol
- ANSYS as used on Bonga
As heat is dissipated to the outside of the fluid, it is redistributed inside of the
fluid by internal convection. For relatively short flowlines and low GOR, the gas
liquid interface is located in the riser. The detailed behaviour of the fluid during
its cooldown may be modeled using Computational Fluid Dynamics package such
as FLUENT, Ref. [9]. At this stage, those types of studies are tedious:
improvement of these studies is currently underway in at least two JIP’s2
.
Using again a simplified approach, it is straight forward that for an insulated flat
plate the cooldown time is proportional to the thermal inertia of the system
(MCp), and inversely proportional to the Overall Heat Transfer Coefficient (U-
value)
U
MC p∑≅τ Eq.5
1
Only in the case of thin insulation with heat capacity negligible in front of the fluid and pressure holding
barrier, is a straightforward approach valid.
2
Deepstar in the US and CLAROM in France

8. 8
For a flat plate U = k/e and in the case of a gas filled line the thermal inertia is
essentially that of the carrier pipe for highly effective insulation. Therefore, the
cooldown time is proportional to:
k
et
≅τ Eq. 6
Where k is the conductivity of the insulating material, t is the thickness of the
carrier pipe and e is the thickness of the insulation. As a result, a way of
achieving a longer cooldown time is to increase the thickness of the carrier pipe,
the thickness of the insulation material, and/or using a very low conductivity
insulating material.
Long cooldown time may be obtained by only increasing the thermal inertia of the
system by such means as:
- line burial
- phase change material
However this will have an adverse impact on warm-up.
Hot oil can be simulated using mechanistic transient analysis with the appropriate
calculation module. It can also be analyzed with a time-step method. See Fig. 7.
2.4 Start-up
Start-up is performed in accordance with carefully planned procedures that
include:
- methanol injection
- injection of hydrate inhibitors (kinetic or now-preferred anti-agglomerates
agents)
- Hot oil circulation
Methanol volume should be enough to lower the hydrate formation temperature
until enough well fluid has flowed to warm-up the line above regular hydrate
formation temperature.
2.5 Warm-up
Unless hot oiling, hot water circulation, or electrical heating is used to maintain
the temperature of the line above the hydrate formation temperature, the line will
eventually return to seafloor temperature.
The goal is to restore the line to its steady state operating temperature. The first
step is to escape the hydrate formation region. Methanol injection displaces the
hydrate formation curve so that hydrate formation conditions can be avoided
without heat addition.
It may be noted that the heat input requirement for maintaining the welfluid
outside of the hydrate formation temperature (without methanol injection) is fairly
modest for highly insulated lines (typically 100 W/m [104 BTU/hr.ft]).

9. 9
Significantly higher heating power is required to elevate the temperature of the
fluid at rest within a specified time reasonable for production
After methanol has been injected in the well bore, warm-up may be conducted in
two phases
- line warm-up by hot oil circulation
- well start-up
If it is not possible to warm-up the line before start-up, the well start-up should
take place at the maximum sustainable flowrate. The lines should have the
minimum acceptable thermal inertia1
in order to minimize the duration during
which the fluid may be exposed to hydrate formation conditions.
Transient mechanistic software such as OLGA allows warm-up simulation.
Similarly, as they can be analyzed for cooldown, cold spots can be analyzed for
warm-up using Finite Element Thermal Analysis;
3. Conclusion
The attached diagram depicts the logic sequence of the flow assurance analysis, as
recommended by the authors, that need to be followed in order to insure a complete
overview of the relevant flow assurance issues of a particular field development.
Furthermore based on the foregoing, a qualitative screening of the field architecture
options and operations can be offered.
3.1 Passive Insulation
Most Deepwater field architectures are based on passive insulation systems. The
table below summarizes the findings of the functional analysis.
Warm-Up Steady State Cooldown
Wet Insulation No impact Beneficial8
No impact
Burial Adverse Beneficial9
Beneficial
Phase Change Material Adverse No impact Beneficial
Pipe-in-Pipe10
Beneficial Beneficial Beneficial
Vacuum11
Beneficial Beneficial Beneficial
1
The addition of anti-agglomerate and kinetic inhibitors is also generally included.
8
Limited to above 2 W/m².K [0.35 BTU/ft².hr.°F]
9
Limited to above 1.5 W/m².K [0.26 BTU/ft².hr.°F] when used in conjunction with wet insulation
10
A prototype with an OHTC of 0.1 W/m².K [0.02 BTU/ft².hr.°F], excluding the negative effect of field
joints.
11
Hydrogen permeation may be an issue

10. 10
3.2 Active Heating
Only a limited number of active heating systems have been implemented: Shell,
Serrano Oregano and Statoil Asgard
- Warm-up – the active heating system is designed to maintain the temperature of
the line with the fluid above the hydrate formation temperature, so that no
warm-up is needed
- Steady State – in the existing facilities the heating system is shut-off during
normal production
- Cooldown – as for warm-up
It can be seen that as the drive towards ultra-deepwater continues, the loss of
potential energy restrains the temperature differential available to exchange heat
with the outside. There will eventually be a requirement for heating high WAT
wellfluid in order to be able to produce them.
Active heating can be used to counterbalance the loss of potential energy, which
by definition occurs in the riser. Hybrid Riser Towers are particularly suitable to
transfer heat either electrically or with hot fluid because
- easy access is provided at the top
- the heating section is limited to the riser section and does not extend up to the
touch down point area
3.3 Processing Conditions
Processing pressure is a driver in term of deliverability and should be considered
as part of the flow assurance loop through their impact on arrival temperature and
pressure.
The production of the field can also be improved through multiphase pumping
which can be part of the above simulation.
4. Acknowledgements
The authors gratefully acknowledge both Paragon Engineering Services and Stolt
Offshore for allowing publishing this article. Mark Utgard’s assistance is also
appreciated.

11. 11
5. References:
[1] WANG, J., Predicting Asphaltene Flocculation in Crude Oils, PhD Thesis New
Mexico Institute of Mining & Technology, 2000.
[2] ISO 13703 Design and Installation of Piping Systems on Offshore Production
Platforms, 2000 (API 14E)
[3] KLING, R., Thermodynamique Générale et Applications, Editions Technip, 1980
(p.5)
[4] MAKOGON, Y. F., Hydrates of Natural Gas, Penn Well Publishing, Tulsa, 1981
(p.10)
[5] McCAIN, W.D., The Properties of Petroleum Fluids, Penn Well Publishing,
Tulsa, 1973 (p.72)
[6] ARNOLD, K., STEWART, M., Surface Production Operations, Gulf Publishing,
Houston, 1986 (p.31)
[7] PEDLOVSKI, J., Ocean Circulation Theory, Springer Verlag, Berlin, 1998
(p.383)
[8] SLOAN E.D., Hydrate Engineering, SPE, Richardson 2000
[9] XIA C., MURTHY J.Y., Buoyancy-Driven Flow Transitions in Deep Cavities
Heated from Below, Journal of Heat Transfer, ASME, 2002
[10] AMYX, J.W., BASS, D.M., WHITING, R.L., Petroleum Reservoir Engineering,
McGraw-Hill, 1960, p.493
[11] JAMALUDDIN, A.K.M., NIGHSWANDER, J., JOSHI, N., CALDER, D.,
ROSS, B. Asphaltene Characterization: A Key to Deepwater Developments, SPE
77936, 2002
[12] JAMALUDDIN, A.K.M., NIGHSWANDER, J., JOSHI, N., A systematic
Approach in deepwater Flow Assurance Characterization, SPE 71546, 2001
[13] JAMALUDDIN, A.K.M., JOSHI, N., IWERE, F., GURNIPAR, D., An
investigation of Asphaltene Instability under Nitrogen Injection, SPE 74393, 2001

12. 12
Fig-1: Hydrate Formation Curves
Sea-water
Formation -water
Water

13. 13
Fig-2: Well Fluid Characteristics (Typical low shrinkage oil)
Hydrate
Formation
Curve
WAT
Phase
Envelope
Asphaltene
Deposition
Dew Point
Line
Bubble
Point Line
50%
25%

14. 14
Fig-3: Determination of available pressure and temperature
under steady state production
Fig-4: Allowable zone in non-producing conditions
HYDRATE
FORMATION
SEAWATER
TEMPERATURE
ATMOSPHERIC PRESSURE
SEE FIG-3
STEADY STATE
WHFT
P
T
MINIMUM
PROCESSING
PRESSURE
WHFP
WAT
ADIABATIC TEMPERATURE DIFFERENCE
(IMPACT OF POTENTIAL ENERGY CHANGE)
AVAILABLE ∆ T
AVAILABLE ∆P
P
T

15. C:WorkConferencesDOT2002 Functional Approach to Flow Assurance- Text of Paper.doc 155/18/2006
Fig-5: Impact of productivity index
IMPACT OF
PRODUCTIVITY
INDEX
WHFP
High Flow
WHFT
P
T
MINIMUM FPSO
PROCESSING
PRESSURE
WHFP
Low Flow
WAT WHFT

16. C:WorkConferencesDOT2002 Functional Approach to Flow Assurance- Text of Paper.doc 165/18/2006
Hot line temperature profile
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
0 500 1000 1500 2000 2500 3000 3500
Length (m)
Temperature(°C)
Fig. 6 Cooldown on a bundle bulkhead
Fig. 7 Hot Oiling Analysis

17. C:WorkConferencesDOT2002 Functional Approach to Flow Assurance- Text of Paper.doc 175/18/2006
Well Completion Data
CSG, TBG, Fluids
Well Fluid Conditions
WHFT, WHFP, IP
Flow Rate (Min. Max.)
Well Fluid Data Processing Conditions
Develop PVT Analysis
Line ProfileDetermine Steady-State
Pressure Temperature
Range ? P, ? T
Determine Depressurizing
Conditions at Sea Floor
Temperature
Select a Line Size
Determine Steady-State Flow
Regime, Limit of Heavy
Slugging and Gas Lift Requirements
Select an OHTC
Verify the Minimum Flow Rate
Conditions Matching the Available ?
T
Geometry of Cold Spots
Initial Cool-down
Conditions
Specified Cool-down Time
Finite Element Thermal Analysis
Hot Oiling
Analysis
Chemical Injection Volume Estimation
Warm-up Thermal Analysis
Methanol Injection Requirements
Compare Deliverability with Requirements
Iterate on Next Well Fluid Data
w
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-
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a
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-
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a
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Diagram: Flow Assurance Overall Review