offshore production
TRANSCRIPT
Abstract
IPTC 15287
Hydraulic Evaluation of Transport Gas Pipeline on Offshore Production Zhaira Nava, PDVSA Producción Costa Afuera; Marisela Rojas, PDVSA Intevep; Nelson Martínez, Ministerio del Poder Popular para la Energía y Petróleo; Jorge Trujillo, Yobiris Rigual and Camilo González, PDVSA Intevep
Copyright 2011, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Bangkok, Thailand, 7–9 February 2012. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is res tricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435
Gas production has increased due to increasing in demand of energy worldwide. Flow assurance studies in transport systems
related to offshore pipelines must be performed since the design in order to reduce operational costs and failures. This paper
presents the flow assurance study of a hydrocarbon pipeline of 120 km, which transports 650 MMscfd of gas production from
offshore fields to onshore facilities. Fluidynamics parameters were studied in order to optimize internal diameter and process
equipment required for handling of liquids present in the transport systems.
Design parameters were evaluated, such as: fluid, gas superficial velocity and liquid erosion rate, pressure drop and
temperature. The selection of the optimal diameter pipe from the point of hydraulic and thermal focused on one export system
that meets the most technical aspects of flow assurance established for the study, with the 28" internal diameter pipe that
presented those operational conditions.
The designed and applied methodology in this paper was aimed to optimize the transport scheme of offshore gas
production based on a compositional and thermodynamic analysis of the feed gas and liquids streams flowing throught the
system as well as a compilation and analysis of information required to define the numerical simulation model in steady and
transient states. In this sense, a sensitivity analysis was conducted at operating conditions: gas and liquid flow, pressure,
temperature, pipe diameters, and the hydrate formation curve to establish safe operating limits in order to minimize potential
flow restriction problems, plugging and damage to the pipeline and process equipment, thus ensuring reliability in the desing
of the pipeline.
Introduction Transportation of natural gas through subsea pipelines could be affected by problems of flow blockage. Low temperature, long
transport distances, fluid composition bathymetry at offshore environments influences multiphase flow behaviour. . The
economic viability of an offshore project is mainly subject to the costs of drilling and pipelines. The subsea pipelines represent
at least 25% of the total project cost and this is one of the reasons for the flow assurance studies.
Prediction and mitigation of flow blockage in pipelines is part of a flow assurance philosophy and should be applied on
from the beggining phase of a project in order to minimize operational problems, increasing guarantee of having a continuous
transport of a multiphase flow throughout the productive life of wells.
Flow assurance is a thermodynamic and hydraulic analysis used to develop control strategies to avoid flow stoppage by
solid formations such as hydrates, asphaltenes, scale, paraffin, and corrosion problems. Furthermore, this analysis allows
establishing operational strategies, based on thermal behavior of the system, at different stages of production: startup, restart,
shutdown, warm up, cooldown, etc.
In this study, flow assurance philosophy is applied in an export pipeline of gas and liquid with the aim of selecting the
internal diameter that optimize hydraulic and thermal fluid behaviour allowing achieve maximum recovery of gas and liquid as
possible by maximizing the energy reservoir. The analysis takes into account the accumulation of liquid, the erosion ratio,
superficial gas velocity, superficial liquid velocity, pressure drop and temperature. Sensitivities are also performed with the
production profile (gas / water / condensates) of fields and different pipe diameters.
Flow assurance philosophy applied to offshore natural gas pipelines The development of offshore infrastructure begins with reservoir studies when a production plan for the reserves is proposed.
This plan considers the location of wells, fluid production per well and different scenarios for the exploitation of
hydrocarbons. The scenario will be selected taking into account flow assurance analysis and field architecture: production or
2 IPTC 15287
service platforms, floating production storage and offloading systems, flowlines, field architectures (single well tieback,
cluster well manifold, daisy chain tieback or multi well template), export pipeline, transport of single or multiphase flow.
Steady state flow assurance
The steady state flowline model can be generated with the use of software such as PipeSim and Pipephase. The steady state
flow assurance study has the following objectives:
Determine flowline size based on the maximum and the minimum allowable flow rates and pressure drop.
Reduce the risk of hydrate formation during operation. This requires evaluating temperature and pressure distributions
along flowline in steady state condition.
Choose an insulation combination that prevents the temperature at riser base of a tieback subsea system to fall below
the minimum value for cooldown at the whole range of production rates. Riser base temperature is determined as a
function of flow rate and the combined well bore/flowline insulation system.
Determine the maximum flow rate in the system to assure the arrival temperatures do not exceed any upper limits set by
the separation and dehydration processes or the equipment design (Bai 2005).
Metodology was carried out in an export pipeline (multiphase flow) begining with a steady state analysis using multiphase
flow simulation tools.
Field and production environment data were collected: fluids composition, production profiles, pressure and temperature
during field lifetime, bathymetric profile, field architectures and processing schemes viewed as part of the business plan, etc.
Fluid consists of non-associated natural gas, coming from two fields located offshore (fields A and B). These fluids contain
condensable liquid hydrocarbons with an amount of 0.3 GPM for field "A" and 5.3 GPM for field "B". Figure 1 and Figure 2
shows phase envelopes of each fluid and Figure 3 the hydrate formation curve.
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Figure 1. Phase Envelope of field A
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Temperature (°F)
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Figure 2. Phase Envelope of field B
Hidrate curves. One of the purposes of this study is to identify the hydrate formation tendency of the system for different
operating scenarios and to establish operating conditions of pressure and temperature in order to prevent hydrate formation.
In offshore projects there are several ways to prevent the formation of gas hydrates which are: reducing pressure below the
pressure of hydrate formation for a given temperature, maintaining the temperature of the gas flow above the temperature of
IPTC 15287 3
hydrates formation for a given pressure, removing the water by reducing the dew point of water vapor in the gas flow below
the operating temperature, using inhibitors (chemicals) which decrease the risk of hydrate formation.
A study with various inhibitors was performed to compare the operating temperatures with the hydrate formation
temperatures. Several hydrate inhibitors were evaluated such as: methanol (MeOH), monoethylene glycol (MEG) and
triethylene glycol (TEG).
Different simulation runs were conducted using PIPESIM to generate hydrate pressure and temperature curves varying
hydrate inhibitor content. Based on these curves (Figura 4) there isa certain risk of hydrate formation considering the lowest
seabed temperature (63 °F).
For this study is prefered the injection of TEG as a hydrate formation inhibitor with a TEG/water ratio greater than 1:10.
Figure 4 shows an acceptable safety margin to operate the system with a temperature differential near to ∆T = 20 °F and
without risk of hydrate formation for seabed temperature conditions. However, for future stages of engineering a more
rigorous study is required for evaluating and selecting the inhibitor that satisfies other parameters such as economic factors,
storage, reliability, volumes required and others.
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0 10 20 30 40 50 60 70 80 90 100
Temperature (°F)
Pre
ssu
re (
psi
a)
Field "A" Field "B" Field "A + B"
Figure 3. Hydrate formation curve
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)
Unhibited
MEOH/water 1:20
MEG/water 1:20
TEG/water 1:20
MEOH/water 1:10
MEG/water 1:10
TEG/water 1:10
MEOH/water 1:5
MEG/water 1:5
TEG/water 1:5
MEOH/water 1:4
MEG/water 1:4
TEG/water 1:4
MEOH/water 1:3
MEG/water 1:3
MEOH/water 1:2
MEG/water 1:2
Seabed temperature
Figure 4. Hydrate curve with different inhibitors
The export pipeline route starts from a production platform located offshore and ends at the onshore processing facilities
(1100 psig), with an approximate length of 120 km. Bathymetry has water column of 130 m in the deepest point, with a
temperature about 63° F. Onshore air temperature is close to 80 °F.
Two options were evaluated: a multiphase flow export pipeline and single-phase flow pipeline. For the evaluation of
single-phase flow gas and liquids separation was assumed.
Then, thermal and hydraulic behaviors as a function of internal diameter were evaluated over the productive life of the
fields for selecting optimal diameter. Technical criteria were as follows:
Minimal pressure drop in the pipelines: < 400 psi
Management inventory liquid holdup
Superficial gas velocity between 10 and 25 ft/s (Su 2003).
4 IPTC 15287
Erosion ratio less than 1 (API 1991)
Onshore delivery Pressure: 1100 psig
Maximum operating pressure: 1500 psig
Onshore liquid slug catcher capacity: 4700 bbl
The internal diameters evaluated in the transport systems were: 26", 28", 30", 32" and 34" for multiphase flow. For
pipelines of single phase: 24", 26", 28", 30", 32"and 34" for gas and 75/ 8”, 83/ 4”, 93/4”, 113/4”, 12” y 13” for the liquid.
Transient flow assurance
In an offshore project, one of the purposes of evaluating the transient condition of hydrocarbon transportation systems is to
define operational strategies for mitigating and controlling flow fluids obstruction caused by the precipitation of solids such as
hydrates and scale and avoiding corrosion.
The transient regime is related to the changes in the system over time. Transient flow modeling in pipes can be obtained by
software packages such as OLGA (SPT Group), LEDA (SINTEF), IMPLIED (Invensys) and others. The transient analysis
includes the following scenarios:
Start-up and shut-down
Shutdown
Blowdown and warm up
Pigging operations
Pipeline packing and blowdown
Liquids sweeping
At transient conditions, fluid temperatures and pressure must exceed the hydrate dissociation limit. Then, in this case, it
will be necessary to propose a control treatment like pipeline insulation or hydrate inhibitor injection, or both.
Transient hydraulic analysis performed for pipeline multiphase flow is based on determining hold up growing in the
transport system and the time it reaches the equilibrium condition, in order to optimize design.
Flow assurance study for export pipeline
Steady state numeric simulation model
The steady state model was developed using the simulation tool PIPESIM®, and was built in detail considering the
bathymetry existing from the field located offshore (inlet) to the installations onshore (delivery). Figure 5 shows the seabed
profile along the export pipeline route.
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Distance (m)
Ele
va
tio
n (
m)
Bathymetry Sea level
Figure 5. Water depth profile of the export pipeline
Hydraulic analysis considers Xiao mechanistic model and Eaton Holdup correlation to estimate the friction losses and the
liquid holdup, respectively.
The steady state model assumes that operational conditions (flow rate, temperature and composition) are constant over
time, as well as external conditions (ambient temperature, bathymetry, currents)
Multiphase transport system. In the case study, all the wells are produced simultaneously, and gathered through a daisy
chain arrangement in the field A and B trunk line to a platform and then sent to the onshore reception facilities through a
120 km export line. Both gas fields are mixed at the initial point of the export pipeline (offshore platform).
Behavior of the multiphase pipeline for each of the studied variables is discussed bellow:
Figure 6 shows that gas temperature is highly dependent on seabed temperature due to the low heat capacity of gas, so that
fluid reaches thermal equilibrium quickly.
IPTC 15287 5
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78
80
0 10 000 20 000 30 000 40 000 50 000 60 000 70 000 80 000 90 000 100 000 110 000 120 000 130 000
Distance (m)
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mp
era
ture
(°F
)
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-60
-40
-20
0
20
40
60
Ele
va
tio
n (
m)
Temperature Bathymetry
Figure 6. Temperature profile in multiphase transport system
Analysis of the temperature profile along the export pipeline, shown in Figure 6, identifies the sections in which the heat
exchange with the environment can reach operating temperatures which can promote the appearance of hydrates. According to
the results obtained, the fluid heat exchange with the environment on the seabed occurs rapidly, reaching a temperature of
63 °F in the underwater section. Once the pipeline starts the climb in the area of higher elevation, the temperature of the
product stream is rapidly approaching 77 °F and after the passage of the slope, the stream reaches again the seabed
temperature (73 °F). When pipeline arrives to shore, then equalizes environmental temperature (78 °F).
Figure 7 shows the results of the pressure drop in the export pipeline for different gas flow rates (between 50 and
1000 MMsfcd) and internal diameters of pipe 26", 28", 30", 32" and 34". All curves show an inflection point: on the left side
there is a decreasing in pressure drop with increasing gas flow and an increase in pressure drop when increases the diameter of
the pipe. On the right side of the inflection point, the pressure drop is directly proportional to the gas flow and is inversely
proportional to the diameter of the pipe. At low gas flow rates, the dominant factor is the accumulation of liquid and at high
gas flow rates (right of the inflection point), the friction factor predominates, as in the case of line 26" internal diameter
(Figure 8).
Criteria designs suggest a low liquid holdup and friction losses to maintain the pipeline integrity and have a good hydraulic
performance. Figure 7 show that pipes between 28" and 32" ID achieve both conditions. Futhermore, in these diameters the
system can be operated in a wider range of gas flowrates, which increase operating flexibility. However, optimal diameter
selection considers other parameters of flow assurance.
Figure 8 shows the inlet pressure required in the export pipeline for different gas flow rates and diameters of pipe. The
minimum inlet pressure is reached at 26” ID pipeline with a gas production of 200 MMscfd maximum inlet pressure for this
export line has been defined to be 1500 psig.
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0 100 200 300 400 500 600 700 800 900 1000
Gas flowrate (MMscfd)
Pre
ss
ure
dro
p (
ps
i)
26" 28" 30" 32" 34" Inside diameter Maximum pressure drop
Figure 7. Pressure drop in multiphase transport system
6 IPTC 15287
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0 100 200 300 400 500 600 700 800 900 1000
Gas flowrate (MMscfd)
Pre
ss
ure
at
inle
t (p
sig
)
26" 28" 30" 32" 34" Inside diameter Maximun operating pressure
Figure 8. Inlet pressure in multiphase transport system
Another parameter evaluated is the superficial gas velocity, shown in Figure 9. Superficial gas velocity shows a behavior
directly proportional to gas flow and inversely proportional to the diameter of the pipe. The shaded area establishes that pipe
diameter selected must be inside 10 and 25 ft/s gas velocity limits where a stable operation is achieved promoting a low
holdup. Between 7 and 10 ft/s average operation is stable but with small liquid accumulation. For speeds below 7 ft/s, the
operation becomes unstable (Su 2003).
For the case 26" ID, this condition is reached when gas flow rate is about 360 MMscfd. For pipeline between 28" and 34"
ID, stable operation begins from 400 and 600 MMscfd respectively. Then, smaller internal diameters allow handling lower gas
flow rates.
System becomes unstable when gas flow rate is less than 230 and 400 MMscfd for 26 and 34” ID respectively.
It is important to note that the selection of the optimum diameter for hydrocarbon transport systems should consider gas
production profile of fields along the productive life, as well as the decrease in pressure from the reservoir.
0
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15
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25
30
0 100 200 300 400 500 600 700 800 900 1000
Gas flowrate (MMscfd)
Su
pe
rfic
ial G
as
ve
loc
ity
(ft
/s)
26" 28" 30" 32" 34" Inside diameter
Figure 9. Superficial gas velocity in the multiphase pipeline
To avoid erosion condition, API RP 14 E recommends that erosion ratio (gas and erosion velocity) remains below 1.
Moreover, the Engineering Design Manual of PDVSA recommends an erosion ratio between 50 and 60 %, when the limitation
of noise is an important consideration. For all cases, both erosion ratio conditions are met (Figure 10).
IPTC 15287 7
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0.9
1.0
0 100 200 300 400 500 600 700 800 900 1000
Gas flowrate (MMscfd)
Ero
sio
n r
ati
o (
-)
26" 28" 30" 32" 34" Inside diameter
Figure 10. Erosional ratio in multiphase transport system
Figure 11 shows the results of holdup in the transport system for different gas flow rates and internal pipe diameters. Large
liquid holdup or inventory is accumulated in the export pipeline. The larger the ID the higher is liquid inventory as gas
velocity is lower.
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40 000
60 000
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100 000
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140 000
160 000
0 100 200 300 400 500 600 700 800 900 1000
Gas flow rate (MMscfd)
To
tal liq
uid
co
nte
nt
(bb
l)
26" 28" 30" 32" 34" Inside diameter Onshore slug catcher capacity
Figure 11. Liquid inventory in multiphase transport system
Bathymetry influences the holdup in areas along export pipeline. In deepest and steepest sections of the pipeline route,
liquid accumulation can reach the maximun holdup. Figure 12 shows 650 MMscfd case, where holdup reaches about 40 % in
the first half of the route.
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Pip
elin
e e
lev
ati
on
(m
)
26" 28" 30" 32" 34" Inside diameter Bathymetry
Figure 12. Liquid holdup along the export pipeline for 650 MMscfd
8 IPTC 15287
Figure 13 to Figure 17 present the results of varying the delivery pressure onshore and internal diameter, from values of
700 psig to 1300 psig, maintaining gas flowrate at 650 MMscfd.
Figure 13 and Figure 14 show the mixture velocities reached in the export pipeline. The maximum mixture velocity at the
inlet is reached in smaller diameter pipes. It is important to mention that in pipe 34" the limit of velocity is reached for oulet
pressure over 1200 psig. None cases exceeds maximum velocity of 25 ft/s, however outlet gas velocity is over this limit in
much cases, which limits operational conditions. For example, pipe 26" ID reaches the maximum threshold set velocity
(25 ft/s), if gas is delivered at a pressure of 700, 800, 900 and 1000 psig. Importantly for the delivery pressure of 1100 psig, all
pipe diameters evaluated have acceptable velocity for normal operation.
5
10
15
20
25
600 700 800 900 1000 1100 1200 1300 1400
Onshore delivery pressure (psig)
Mix
ture
v
elo
cit
y
at
in
let
(ft/
s)
26" 28" 30" 32" 34" Inside diameter
Figure 13. Inlet velocity of the mixture to the export system
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15
20
25
30
35
40
45
50
600 700 800 900 1000 1100 1200 1300 1400
26" 28" 30" 32" 34" Inside diameter
Figure 14. Oulet velocity of the mixture the export system
Figure 15 and Figure 16 shows the inlet pressure to the pipe and the pressure drop obtained for the different diameters
evaluated considering the variation in oulet pressure at onshore. The analysis of these figures allows selecting pipe taking into
account energy balance in order to choose optimal pipe. According to PDVSA standards, maximum allowable pressure drop in
the export line should Figure 16. This condition is satisfied by ID of 28”.
Figure 17 shows total liquid inventory in the pipeline and allows to visualize how large should be the slugcatcher located
onshore in case of no rampup strategies are implemented.
Just as small diameter pipes generate the highest gas velocities and pressure drop, also have the lowest accumulation of
fluid, as speeds of gas generate an excellent sweep inside the pipe. For a nominal pipe diameter of 28" values of gas velocity
are above the threshold of 10 ft/s and there is an acceptable pressure drop, which indicates compliance with the premises
established for the design of transport system.
IPTC 15287 9
800.0
900.0
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1200.0
1300.0
1400.0
1500.0
1600.0
1700.0
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600 700 800 900 1000 1100 1200 1300 1400
Onshore delivery pressure (psig)
Pre
ss
ure
a
t i
nle
t (p
sig
)
26" 28" 30" 32" 34" Inside diameter Maximum operating pressure
Figure 15. Inlet pressure in the export system
100.0
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500.0
550.0
600.0
650.0
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600 700 800 900 1000 1100 1200 1300 1400
Pre
ss
ure
dro
p (
ps
i)
Figure 16. Pressure drop in the export system
10 000
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14 000
16 000
18 000
20 000
22 000
24 000
26 000
28 000
600 700 800 900 1000 1100 1200 1300 1400
Onshore delivery pressure (psig)
To
tal
liq
uid
in
ve
nto
ry (
bb
l)
26" 28" 30" 32" 34" Inside diameter
Figure 17. Total liquid inventory in the export system
Single phase transport system.
Evaluation of gas transport system. The results obtained in the analysis of flow assurance variables showed a pattern
similar to the study of multiphase transport system.
28” ID exposed an acceptable thermal and hydraulic behavior for export pipeline of single phase flow where pressure drop
in the system is less than 400 psi for gas flow rates less than 600 MMscfd. Superficial gas velocity is between 10 and 25 ft/s
(stable behavior) for a wide range of gas flow rates (350 – 850 MMscfd). Erosion ratio less than 1 for all diameters and gas
flow rates studied and the greatest liquid accumulation occurs for a gas flow of 50 MMsfcd with a total liquid holdup of 60000
bbl.
10 IPTC 15287
Evaluation of liquid transport system. The behavior of the transport system of liquid (water and condensate) is shown in
this section. The analysis includes the variation of internal diameters of pipeline between 75/8” and 13” and liquid flow rates
between 5 MBPD and 30 MBPD.
The variables analyzed to evaluate the hydraulic behavior of the liquid are the same that were studied for gas: pressure
drop, superficial velocity (in this case for liquid).
93/4 inch and 103/4 inch internal diameter showed a good hydraulic behavior for liquid export pipeline where pressure drop
in the system is less than 2000 psi for all liquid flow rates and diameters evaluated (Figure 18). Superficial liquid velocity at
the inlet and at the outlet of pipeline between 2 ft/s and 6 ft/s for a wide range of liquid flow rates: 9000 bbl/d - 27000 bbl/d
(Figure 19 and Figure 20).
0
500
1 000
1 500
2 000
2 500
3 000
3 500
4 000
0 5 000 10 000 15 000 20 000 25 000 30 000 35 000
Liquid flowrate (bbl/d)
Pre
ss
ure
dro
p (
ps
i)
7,625" 8,75" 9,75" 10,75" 11,75" 12" 13" Inside diameter
Figure 18. Pressure drop for single phase export pipeline
0
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5
6
7
8
9
10
11
12
0 5000 10000 15000 20000 25000 30000 35000
Liquid flowrate (bbl/d)
Ve
loc
ity
a
t i
nle
t (f
t/s
)
7,625" 8,75" 9,75" 10,75" 11,75" 12" 13" Inside diameter
Figure 19. Liquid velocity at inlet for single phase export pipeline
0
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5
6
7
8
9
10
11
12
0 5000 10000 15000 20000 25000 30000 35000
Liquid flowrate (bbl/d)
Ve
loc
ity
a
t o
utl
et
(ft/
s)
7,625" 8,75" 9,75" 10,75" 11,75" 12" 13" Inside diameter
Figure 20. Liquid velocity at outlet for single phase export pipeline
IPTC 15287 11
Transient numeric simulation model
The study of flow assurance in transient state is applied in the design of flowlines and pipelines of multiphase flow in
offshore environments. This analysis establishes the operational strategies of the transport system throughout the productive
life of fields. Additionally, this analysis optimizes the design of process equipment required to transport production fluids, in a
safe and continuos manner.
The hydraulic transient analysis developed in this study for the pipeline multiphase flow is based on determining the rate of
accumulation of fluid in the transport system and the time to achieve a equilibrium condition. The study considers the export
pipeline multiphase flow 28" ID which showed a good hydraulic performance for flow assurance philosophy evaluated at
steady state.
The results of this evaluation are shown below:
Figure 21 shows that steady state condition is reached in approximately 49500 s (14 h) with an accumulation of liquid in
the export pipeline of 40800 bbl. This value is used to establish the operational strategy of liquid management upstream and
downstream of the system, for example, sweep liquids and pigging frequency, equipment required for separation and their
capacity.
Field B has a higher amount of liquid hydrocarbon than Field A. The analysis of the results of total liquid content in the
export pipeline allows to define strategies for liquid and gas separation offshore like an option for the recovery of condensates.
Applying offshore strategies, the size of process equipment required onshore could be minimized as well as the problems
associated with subsea multiphase transport systems. Additionally, the recovery of liquid hydrocarbons represents a business
oportunity.
Sensitivities were performed with 50% and 100% of the maximum gas flow in order to consider the production profile.
The results are shown in Table 1.
0
10 000
20 000
30 000
40 000
50 000
0 20 000 40 000 60 000 80 000 100 000 120 000 140 000
To
tal
liq
uid
co
nte
nt
in b
ran
ch
(b
bl)
Time (s)
50% 100% Field production
Figure 21. Liquid holdup in the export pipeline
Table 1. Total liquid holdup as a function of production profile
Field production
(%)
Required
pressure (psig)
Total liquid
holdup (bbl)
50 1295 47014
100 1500 40800
Figure 22 to Figure 24 display the results of the transient hydraulic evaluation for the variables of pressure drop, fluid
temperature and gas velocity. Pressure required at inlet of the pipeline is 1500 psia with a pressure drop of 400 psi
(3.3 psi/km).
Performing a thermal analysis in gas transport systems temperature profile of fluid is obtained. Heat transfer takes into
account environment condition to predict any problems that may affect the flow. In this study, the fluid reaches 63 °F in the
subsea sections increasing up to 80 °F above sea level.
Figure 24 shows how superficial gas velocity (SGV) remains within limits to assure stable operation (10 ft / s – 25 ft/s) and
supporting the optimal internal diameter selection. At gas flowrate over 600 MMscfd in 28" ID export pipeline will not present
problems of erosion velocity.
Table 2 summarizes the main results obtained in modeling steady and transient states: flow assurance studies at steady state
allow to determine the optimal diameter of flowlines and pipelines at early stage of the project and these studies are
complemented with the transient evaluation to establish safe operating limits minimizing the flow blockages or damages on
pipelines and process equipment downstream.
12 IPTC 15287
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Distance (m)
Pre
ss
ure
(p
sig
)
-140
-120
-100
-80
-60
-40
-20
0
20
40
60
80
Pip
eli
ne
ele
va
tio
n (
m)
50 100 200 300 400 500 650 700 800 900 1000 Gas flowrate (MMscfd) Bathymetry
Figure 22. Pressure profile in the export pipeline (28" ID)
50
52
54
56
58
60
62
64
66
68
70
72
74
76
78
80
82
84
86
88
90
0 10000 20000 30000 40000 50000 60000 70000 80000 90000 100000 110000 120000 130000
Distance (m)
Te
mp
era
ture
(°
F)
-140
-120
-100
-80
-60
-40
-20
0
20
40
60
80
Pip
eli
ne
ele
va
tio
n (
m)
50 100 200 300 400 500 650 700 800 900 1000 Gas flowrate (MMscfd) Bathymetry
Figure 23. Temperature profile in the export pipeline (28" ID)
10
11
12
13
14
15
16
17
18
19
20
0 10 000 20 000 30 000 40 000 50 000 60 000 70 000 80 000 90 000 100 000 110 000 120 000 130 000
Distance (m)
Su
pe
rfic
ial
ve
loc
ity
ga
s (
ft/s
)
-140
-120
-100
-80
-60
-40
-20
0
20
40
60
80
Pip
eli
ne
ele
va
tio
n (
m)
Superficial velocity gas Bathymetry
Figure 24. Superficial velocity gas in the export pipeline (28” ID)
IPTC 15287 13
Table 2. Summary of results at steady state and transient conditions for a gas flowrate of 650 MMscfd and 28” ID pipeline
Variables Steady State Transient
State
Internal diameter (in) 28 28
Pressure (psig) 1502 1500
Pressure drop (psi) 403 400
Ranges of VSG (ft/s) 12 - 19 12 - 16
Total liquid holdup (bbl) 20405 40800
Minimum liquid holdup (%) 2 5
Maximum liquid holdup (%) 34 26
Erosion ratio 0.28 - 0.41 0.20 - 0.38
Inlet temperature (°F) 80 79
Liquid rate (bbl/d) 57555 59208
Conclusions Flow assurance analysis was applied to optimize the internal diameter of an export pipeline in a multiphase offshore transport
system. Main conclusions are listed below:
1. Thermal evaluation shows risk of hydrate formation. Therefore, a study was carried out to select type and dosage of
hydrate formation inhibitor. TEG at a 1:10 injection ratio has been selected on a preliminary basis.
2. 26” ID pipeline pressure drop is higher than acceptable limits. On the other hand, 32” and 34” ID pipelines allow and
important liquid holdup or inventory which can impose contraints on transient operations (pigging frecuency) and slug
catcher sizing.
3. 28” ID pipeline pressure drop, liquid inventory and superficial gas velocities are acceptable according to pre-
established design criterias.
4. It is not expected erosion to be an issue as erosion ratio (gas velocity to erosion velocity ratio) is far bellows accepted
limits.
5. Flow assurance studies should be approached from the initial phases of the project and the analysis must be developed
during the whole life of the fields.
Note: This paper presents results applied in a pre-feed stage. Detailed analysis should be carried out in futures engineering
phases.
Nomenclature
” Inch
°F Fahrenheit grade
bbl Barrel
FPSO Floating Production Storage and Offloading
ft/s Foot per second
GPM Gallons per Mcf
h Hours
ID Inside diameter
in Inch
km Kilometer
m Meter
MBPD Thousand Barrel Per Day
MMscfd Million standard cubic feet per day
PDVSA Petróleos de Venezuela
psia Pounds per square inch absolute
psig Pounds per square inch relative
s Second
SGV Superficial gas velocity
14 IPTC 15287
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