Report_FAT1_Final

1
Development of Flow Assurance Tool (FAT1©
) for
Simulation of Flow through Subsea Pipelines
By
_______________
Ashwin A. Gadgil
Master of Engineering in Ocean Engineering ‘16
Texas A&M University
College Station, Texas
_______________
Advisor: Dr. Robert E. Randall
W. H. Bauer Professor in Dredging Engineering
Director, Center for Dredging Studies
Ocean Engineering Department
Texas A&M University
DATE: 12/14/15
OCEN 685

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ACKNOWLEDGEMENT
To begin with I would like to thank Dr. Robert Randall at Texas A&M University for presenting me with the
opportunity to work on this project. His help in sketching out the general direction and objective of the project was
vital to the timely and correct development of the project. He was always very responsive to any doubts I had and
always guided me in the right direction whenever I was stuck with any module of the project. He kept the objectives
realistic, practical and applicable. All his guidance not only helped me develop a tool which is very handy, accurate
and vital for the Subsea industry, but also allowed me an opportunity to convert all the concepts of fluid flow and
thermodynamics which I learned over the years into an industry specific tool. I will be indebted to him for
considering me worthy of working on this project.
Secondly, I would like to thank Mr. Dave Lucas, who introduced me to the world of Subsea Engineering and was
also my professor for the course of Fundamentals of Subsea Engineering. His guidance and advice from an industry
point of view, about design of Subsea tools and flow assurance was the cornerstone in ensuring the developed tool
was tailored to industry needs and standards.
My deepest gratitude to Dr. H. C. Chen and Dr. Jun Zhang for laying the foundation of my knowledge of fluid
dynamics. Also a heartfelt thanks to the IT support staff for installing PipeSIM at a very short notice.
Lastly, I would like to thank my parents and my sister for standing by me and continually giving me hope
throughout the duration of this project, my Masters’ degree and the ups and downs of the ever-so-challenging Oil &
Gas industry.

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Table of Contents
LIST OF FIGURES ......................................................................................................................................4
LIST OF TABLES........................................................................................................................................4
1. Literature Review .....................................................................................................................................5
1.1 The need for flow simulation tools (Single phase, two phase and Multiphase) for subsea pipelines.5
2. Current Commercial Tools: Overview & Background.............................................................................7
2.1 PIPESIM .............................................................................................................................................7
2.2 OLGA .................................................................................................................................................7
2.3 Simsci PIPEPHASE............................................................................................................................8
3. Objectives of the Proposed Tool...............................................................................................................8
3.1 Predict flow pattern, pressure and velocity patterns along the pipeline for single and two phase flow
(Including flow through valves, pumps and choke)..................................................................................8
3.2 Predict temperatures and heat losses along the pipeline for single and two phase flow.....................9
3.3 Predict cooldown time during a shutdown........................................................................................10
3.4 Evaluate well integration and its effects. ..........................................................................................11
4. Black Oil flow model development ........................................................................................................11
4.1 Single phase pipe flow......................................................................................................................11
4.2 Single phase flow through valves, chokes and pumps......................................................................13
4.3 Single phase heat transfer .................................................................................................................17
4.4 Estimation of cooldown time............................................................................................................19
5. Comparison of Results with PipeSIM.....................................................................................................20
Summary.....................................................................................................................................................24
References...................................................................................................................................................25
Appendix I: Tutorial for Using FAT1.........................................................................................................26
Appendix II: PipeSIM Result File ..............................................................................................................27

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LIST OF FIGURES
FIGURE 1: FLOW PHASES IN VERTICAL DIRECTION; (IMAGE COURTESY THERMOPEDIA.COM).......................................8
FIGURE 2: FLOW PHASES IN HORIZONTAL DIRECTION; (IMAGE COURTESY SUBSEA ENGINEERING HANDBOOK Y.BAI)9
FIGURE 3: TIME VS TEMPERATURE CONDITIONS; (IMAGE COURTESY SUBSEA ENGINEERING HANDBOOK Y.BAI) ......10
FIGURE 4: BLACK OIL FLOW ........................................................................................................................................12
FIGURE 5: DISCHARGE COEFFICIENTS FOR INLINE VALVES; (IMAGE COURTESY HYDRAULICS OF PIPELINES BY PAUL
TULLIS) ...............................................................................................................................................................13
FIGURE 6: VALVE & PUMP SHEET ................................................................................................................................14
FIGURE 7: CHOKE SHEET..............................................................................................................................................15
FIGURE 8(A)(B)(C): CV VALUES FOR DIFFERENT TYPES OF CHOKES; (COURTESY CAMERON)......................................16
FIGURE 9: TEMPERATURE DROP SIMULATION IN FAT1................................................................................................18
FIGURE 10: TEMPERATURE SIMULATION SHEET...........................................................................................................18
FIGURE 11: HYDRATE AND WAX FORMATION TEMPERATURES; (IMAGE COURTESY FUNDAMENTALS OF SUBSEA
ENGINEERING COURSEWORK TEXAS A&M UNIVERSITY) ...................................................................................19
FIGURE 12: PIPESIM MODEL FOR SIMULATION............................................................................................................20
FIGURE 13: PRESSURE DROP FROM RESERVOIR TO RISER BASE (PIPESIM)...................................................................21
FIGURE 14: PRESSURE DROP SIMULATED IN FAT1 .......................................................................................................21
FIGURE 15: TEMPERATURE DROP FROM RESERVOIR TO RISER BASE (PIPESIM) ............................................................22
FIGURE 16: TEMPERATURE SIMULATION IN FAT1........................................................................................................22
FIGURE 17: COOLDOWN SIMULATION AT THE WELLHEAD IN FAT1 .............................................................................23
FIGURE 18: PRESSURE VS TEMPERATURE (PIPESIM)...................................................................................................23
FIGURE 19: PRESSURE VS TEMPERATURE SIMULATION FAT1 .....................................................................................24
LIST OF TABLES
TABLE 1: MINOR LOSS COEFFICIENTS; (COURTESY ENGINEERINGTOOBOX.COM) ........................................................12
TABLE 2: INPUTS FOR SIMULATION IN FAT1................................................................................................................20
TABLE 3: ACCURACY COMPARISON OF FAT1 AGAINST PIPESIM.................................................................................24

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1. Literature Review
1.1 The need for flow simulation tools (Single phase, two phase and Multiphase)
for subsea pipelines
To ensure system deliverability of hydrocarbon products from one point in the flowline to another, the accurate
prediction of the hydraulic behavior in the flowline is essential. From the reservoir to the end user, the hydrocarbon
flow is impacted by the thermal behavior of the heat transfer and phase changes of the fluid in the system. The
hydraulic analysis method used and its results are different for different fluid phases and flow patterns. To solve a
hydrocarbon hydraulic problem with heat transfer and phase changes, adequate knowledge of fluid mechanics,
thermodynamics, heat transfer, vapor/liquid equilibrium, and fluid physical properties for multicomponent
hydrocarbon systems is needed.
Successful production system design and operations requires a detailed understanding of multiphase flow behavior.
Flow modeling and simulation provides valuable insights into flow behavior, including the physics describing flow
through the entire production systems, from reservoir pore to process facility.
The flow assurance tools offer the following application
 Size pipelines to minimize backpressure while maintaining stable flow within the maximum allowable
operating pressure (MAOP)
 Size pumps, compressors, and multiphase boosters to meet target rates
 Examine system-design layout options and operating parameters for a range of inputs
 Size separation equipment and slug catchers to manage liquids associated with pigging, ramp-up surges,
and hydrodynamic slugging volumes
 Design and optimize pipelines and equipment such as pumps, compressors, and multiphase boosters to
maximize production and capital investment
 Perform nodal analysis and diagnose liquid loading or lift requirements
 Design artificial lift systems (e.g., rod pumps, progressing cavity pumps, ESPs, and gas lift) and compare
their relative benefits
 Optimize production through intelligent completions by modeling downhole flow control valves or other
downhole equipment, such as chokes, subsurface safety valves, separators, and chemical injectors
 Optimize the completion design by considering skin effects on horizontal well length and tubing or casing
size
 Model multilaterals or wells with multiple layers and crossflow
 Identify the risk for severe riser slugging
 Account for emulsion formation
 Assess the operational risk from the deposition of wax along flowlines over time
 Identify locations prone to corrosion and predict CO2 corrosion rates
 Model erosion using the API 14E and Salama methods
 Manage pipeline integrity with erosion and corrosion prediction
 Accurately characterize fluid behavior with a wide variety of black-oil and compositional fluid models
 Identify the risks of potential solids formation including wax, hydrates, asphaltenes, and scales
 Assess the risk from deposition of wax along flowlines over time
 Determine the amount of methanol to inject to avoid hydrate formation
 Calculate optimal burial depth and insulation requirements for pipelines
A lot of the above targets can be achieved with a high degree of reliability with this proposed tool with a fraction of
the computing resource. Although it would take a significantly larger work input from the operator.

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1.2 Basic principles and phenomenon of flow through subsea pipelines
The complex mixture of hydrocarbon compounds or components can exist as a single-phase liquid, a single-phase
gas, or as a multiphase mixture, depending on its pressure, temperature, and the composition of the mixture. The
fluid flow in pipelines is divided into three categories based on the fluid phase condition:
• Single-phase condition: black oil or dry gas transport pipeline, export pipeline, gas or water injection pipeline, and
chemical inhibitors service pipelines such as methanol and glycol lines;
This is the simplest to model as the hydraulic theory underlying single-phase flow is well understood and analytical
models may be used with confidence.
• Two-phase condition: oil + released gas flowline, gas + produced oil (condensate) flowline:
Of the four type of Two-Phase Flow (Gas-Liquid, Gas-Solid, Liquid-Liquid and Liquid-Solid), gas-liquid
flows are the most complex, since they combine the characteristics of a deformable interface and the
compressibility of one of the phases. For given flows of the two phases in a given channel, the gas-liquid
interfacial distribution can take any of an infinite number of possible forms. However, these forms can be
classified into types of interfacial distribution, commonly called flow regimes or flow patterns. Detailed
discussions of these patterns are given by Hewitt (1982), Whalley (1987) and Dukler and Taitel (1986).
The regimes encountered in vertical include Bubble Flow, where the liquid is continuous, and there is a
dispersion of bubbles within the liquid; Slug or Plug Flow where the bubbles have coalesced to make larger
bubbles which approach the diameter of the tube; Churn Flow where the slug flow bubbles have broken
down to give oscillating churn regime; Annular Flow where the liquid flows on the wall of the tube as a
film (with some liquid entrained in the core) and the gas flows in the center; and Wispy Annular Flow
where, as the liquid flow rate is increased, the concentration of drops in the gas core increases, leading to
the formation of large lumps or streaks (wisps) of liquid.
Another important factor is liquid holdup, which is defined as the ratio of the volume of a pipe segment
occupied by liquid to the volume of the pipe segment. Liquid holdup is a fraction, which varies from zero
for pure gas flow to one for pure liquid flow.
• Three-phase condition: water + oil + gas (typical production flowline):
Multiphase transport is currently receiving much attention throughout the oil and gas industry, because the
combined transport of hydrocarbon liquids and gases, immiscible water, and sand can offer significant
economic savings over the conventional, local, platform-based separation facilities. However, the
possibility of hydrate formation, the increasing water content of the produced fluids, erosion, heat loss, and
other considerations create many challenges to this hydraulic design procedure.
The pipelines after oil/gas separation equipment, such as transport pipelines and export pipelines, generally
flow single-phase hydrocarbon fluid while in most cases, the production flowlines from reservoirs have
two- or three-phase fluids, simultaneously, and the fluid flow is then called multiphase flow. In a
hydrocarbon flow, the water should be considered as a sole liquid phase or in combination with oils or
condensates, since these liquids basically are insoluble in each other. If the water amount is small enough
that it has little effect on flow performance, it may be acceptable to assume a single liquid phase.

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2. Current Commercial Tools: Overview &
Background
2.1 PIPESIM
The PIPESIM simulator incorporates a wide variety of industry-standard multiphase flow correlations, as well as
advanced 3-phase mechanistic models, including OLGAS, Kongsberg LedaFlow Point Model, and the TUFFP
unified model. These allow calculation of flow regimes, liquid holdup, slug characteristics, and pressure loss for all
nodes along production paths of all deviations—vital information for designing and operating production gathering
and distribution systems. The PIPESIM simulator produces detailed flow regime maps at points of interest.
The design of pipelines and processing facilities can be optimized by predicting hydrodynamic slugs, including size
and frequency, as a function of length traversed. Additionally, the PIPESIM simulator predicts the risk of severe
slugging in risers.
The PIPESIM simulator includes a calibration feature for flow correlation, which can automatically adjust the
holdup factor, friction factor, and U-value multiplier to match measured pressures and temperatures. Additionally,
the comparison operation can quickly sensitize to flow correlations and help selecting the most appropriate model.
High-resolution flow regime maps can also be produced for any point in the system. The PIPESIM simulator
includes code templates that can assist in compiling a user-generated 2- or 3-phase flow correlation via a plug-in
DLL.
The PIPESIM simulator performs comprehensive energy balance calculations that account for a variety of heat
transfer mechanisms, including the following:
 Convection (free and forced)
 Conduction
 Elevation
 Joule-Thompson cooling and heating
 Frictional heating
Heat transfer models supported by the PIPESIM simulator include a flow regime dependent model for inside film
coefficient, plus an analytical model for convection in buried and partially buried pipes—shown to closely match
more complex finite-element methods. The PIPESIM simulator can also model internal natural convection using a
proprietary methodology shared with OLGA.
The PIPESIM steady-state multiphase flow simulator offers workflows for both front-end system design and
production operations. The PIPESIM simulator is frequently used to identify situations that require more detailed
transient simulation using the OLGA multiphase flow simulator. Such situations may include shut-in, startup, ramp-
up, terrain-induced slugging, severe slugging, slug tracking, hydrate kinetics and wellbore cleanup. Together, the
PIPESIM and OLGA simulators offer the most rigorous modeling solution for multiphase flow systems.
2.2 OLGA
The OLGA dynamic multiphase flow simulator models time-dependent behaviors, or transient flow, to maximize
production potential. Transient modeling is an essential component for feasibility studies and field development
design. Dynamic simulation is essential in deepwater and is used extensively in both offshore and onshore
developments to investigate transient behavior in pipelines and wellbores.
Transient simulation with the OLGA simulator provides an added dimension to steady-state analyses by predicting
system dynamics such as time-varying changes in flow rates, fluid compositions, temperature, solids deposition and
operational changes.

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From wellbore dynamics for any well completion to pipeline systems with all types of process equipment, the
OLGA simulator provides an accurate prediction of key operational conditions involving transient flow.
The OLGA simulator enables key flow simulation applications, including:
 liquids handling
 sizing separators and slug catchers
 managing solids (e.g., hydrates and wax)
 simulating key operational procedures including start-up, shut-down, and pigging
 modeling for contingency planning (kill mud density and kill flow rates for blowout control)
 Assessing environmental risk in complex deep water drilling environments.
From early conceptual and planning phases to full field production operations and contingency planning, the OLGA
simulator helps you to determine the best design, operational procedures, optimization, and risk mitigation strategy.
2.3 Simsci PIPEPHASE
PIPEPHASE simulation software rigorously models steady-state multiphase flow in oil and gas networks and
pipeline systems with the power and flexibility to model applications ranging from the sensitivity analysis of key
parameters in a single well, to multi-year facilities planning studies for an entire field. PIPEPHASE covers the
complete range of fluids encountered in the petroleum industry, including single phase, black oil, and compositional
mixtures. The program may also be applied to single component stream or CO2 injection networks.
There are many similar and prominent software which offer similar capabilities like Sluggit or AsperHYSYS etc.
3. Objectives of the Proposed Tool
3.1 Predict flow pattern, pressure and velocity patterns along the pipeline for
single and two phase flow (Including flow through valves, pumps and choke)
A single phase flow has well defined equations to guide its development, viz. Bernoulli’s eqn. energy eqn. etc. The
portrayal of these equations in the excel sheet for the entire pipeline broken up into parts of 1m length or less as per
the accuracy desired by the user will give a fairly accurate prediction of flow velocities and pressures in the pipeline.
Similar to flow conditions in the single phase flow prediction, the single phase flow through valves has standard data
sheets published for different types of valves, pumps and the choke is nothing but a specialized type of control
valve. The user has to select the desired value of CD /CV corresponding to the percentage of closing of the valve or
choke and enter the value, the rest of the calculations are carried out based on the energy equation as is explained in
section 4.
For a two-phase flow, most analyses and simulations solve mass, momentum, and energy balance equations based
Figure 1: Flow Phases in Vertical Direction; (Image Courtesy Thermopedia.com)

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on one-dimensional behavior for each phase. Such equations, for the most part, are used as a framework in which to
interpret experimental data. Reliable prediction of multiphase flow behavior generally requires use of data or
experimental correlations. Two-fluid modeling is a developing technique made possible by improved computational
methods. In fluid modeling, the full three dimensional partial differential equations of motion are written for each
phase, treating each as a continuum and occupying a volume fraction that is a continuous function of position, this is
the “separated flow model”.
Another popular model is the drift flux model, we use the void fraction, the quality of the product and the slip ratio
primarily amongst other things to correlate the gas and liquid velocities and combine the mass, momentum and
energy equations for gas and liquid into a single equation which accounts for the difference in velocities between the
gas and liquid. This method reduces the computational requirements, but is inaccurate at low speeds of flow.
The objective of any user while designing a system is to ensure that the void fraction of flow within the pipe is such
that the flow stays out of the “SLUG” zones which are depicted in Figure 1 (Thermopedia.com, 2015) & Figure 2
(Yong Bai, 2008). This can be achieved by appropriately manipulating the flow speeds of oil via valves and chokes.
In cases where it is absolutely inevitable to avoid a slug flow, slug catchers have to be designed and pipelines have
to be reinforced at appropriate locations, these topics are beyond the scope of this project.
3.2 Predict temperatures and heat losses along the pipeline for single and two
phase flow
In long flow lines, steady state heat loss drives the design of the thermal insulation to prevent hydrate formation and
wax deposition. In subsea production equipment, such as trees, manifolds, and jumpers, transient cooling caused by
an interruption in well flow drives the design and thickness of the insulation system. Thermal insulation is necessary
in these systems to keep the produced fluid above the hydrate formation temperature long enough for the operator to
either introduce hydrate inhibitors or until flow can be reestablished. Typically operators require eight to twelve
hours above the hydrate formation temperature. Trees and other subsea production equipment are of complex
shapes, and therefore, require complex analysis to predict cool down time, and determine the thickness of insulation
required to meet cool down requirements.
Figure 2: Flow Phases in Horizontal Direction; (Image Courtesy Subsea Engineering Handbook Y.Bai)

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Gas hydrates are ice-like solids that form from gas and water under combinations of high pressure and moderately
low temperatures. Alkane hydrates in the form of crystalline methane hydrate can form at temperatures as high as 21
°C (70 °F) at pressures of 300 bars.
Hydrates can form at conditions to the left of the curve shown in Figure 3 (Bai, 2010) for illustration purpose. At
conditions to the right of this curve, hydrates will not form. Hydrate formation conditions depend on gas
composition, primarily the presence of low-molecular weight hydrocarbons such as methane, ethane, propane, iso-
butane and normal butane and the water salinity. The risk of forming hydrates is greatest when the well is cold. This
condition usually occurs during a production start-up or while the well is shut down following a period of flow.
Hydrates can also form while the well is flowing if the well temperature and pressure present the right conditions.
3.3 Predict cooldown time during a shutdown.
The Cooldown Time which is defined as a number of hours that the operator has before having to start up a
preservation scheme, for example to replace the hydrate-prone fluids inside the flowlines with inert (“dead”) oil. It is
also called the “no-touch” time. The prediction of heat losses in case of a shutdown should be able to indicate with a
reasonable certainty the cooldown time of the pipeline. Transient heat transfer occurs in subsea pipelines during
shutdown (cooldown) and start-up scenarios. In shutdown scenarios, the energy, kept in the system at the moment
the fluid flow stops, goes to the surrounding environment through the pipe wall. This is no longer a steady-state
system and the rate at which the temperature drops with time becomes important to hydrate control of the pipeline.
Pipeline systems are required to be designed for hydrate control in the cooldown time, which is defined as the period
before the pipeline temperature reaches the hydrate temperature at the pipeline operating pressure. This period
provides the operators with a decision time in which to commence hydrate inhibition or pipeline depressurization. In
the case of an emergency shutdown or cooldown, it also allows for sufficient time to carryout whatever remedial
action is required before the temperature reaches the hydrate formation temperature. Therefore, it is of interest to be
able to predict how long the fluid will take to cool down to any hydrate formation temperature with a reasonable
accuracy. When a pipeline is shut down for an extended period of time, generally it is flushed (blown down) or
vented to remove the hydrocarbon fluid, because the temperature of the system will eventually come to equilibrium
with the surroundings.
The software OLGA is widely used for numerical simulation of this process. However, OLGA software generally
takes several hours to do these simulations. In many preliminary design cases, an analytic transient heat transfer
analysis of the pipeline, for example, the lumped capacitance method is fast and provides reasonable accuracy.
Figure 3: Time vs Temperature Conditions; (Image Courtesy Subsea Engineering Handbook Y.Bai)
T (DegF)

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3.4 Evaluate well integration and its effects.
Finally, once the above objectives are achieved, the final challenge is to integrate more than one well into the same
pipeline and ensure that the changes that the new inlet makes are successfully reflected in the spreadsheets.
4. Black Oil flow model development
The development of this tool is planned in a drawn out but elemental method making this tool easily operable for
any one from an undergraduate student to a moderate startup. All the above planned objectives will be broken into
different spreadsheets and finally integrated into a main worksheet (SHEET1) within the same Excel file. This
worksheet would display all results, conclusions and readings for the simulated pipeline This could be accomplished
a lot faster with a MATLAB code but that would make the tool unalterable by the user for every project without
formal knowledge of MATLAB, which is a disadvantage we avoid by keeping the code in excel format.
4.1 Single phase pipe flow
The primary equation used to model the flow through the pipe only is the basic energy equation (1) given below.
𝑃1
𝜌𝑔
+ 𝑧1 +
𝑉1
2
2𝑔
=
𝑃2
𝜌𝑔
+ 𝑧2 +
𝑉2
2
2𝑔
− 𝐻 𝑝 + 𝐻𝑓 + 𝐻𝐿
(1)
Where the first 3 terms on both sides are pressure head, elevation head and velocity head respectively. HP is the head
added due to a pump, although pumps are considered in a separate spreadsheet and hence are not included in the
flow sheet. Hf is the friction loss and HL is the minor head loss.
Hf is given by
𝑓𝐿𝑉2
2𝐷𝑔
HL is given by 𝐾𝑉2
/2𝑔
Figure 4 shows the excel sheet in which the above equation is modeled. Table 1 below gives the values for the minor
loss coefficients for various parts in the pipe.
If the pipe has a constant diameter the velocity will be the same at all the sections though out the length of the pipe
and hence gets cancelled out. Note that we are considering a steady flowrate of 10-20 fps which is the recommended
velocity bracket for gas removal as well as for avoiding cavitation and erosion. The cells in the excel sheets which
are colored green are the inputs which the user has to enter.

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Figure 4: Black Oil Flow
Table 1: Minor loss coefficients; (Courtesy EngineeringToobox.com)

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4.2 Single phase flow through valves, chokes and pumps
Let us first consider flow through a valve. As for any one phase steady flow, even the flow through a valve is
governed by the energy equation given above but the representation is slightly different (2).
∆𝐸 𝑚𝑒𝑎𝑠𝑢𝑟𝑒𝑑 = ∆𝐸 𝑛𝑒𝑡 + 𝐻𝑓 + 𝐻𝐿
(2)
The term on the left hand side is the measureable change in energy due to flow through the valve which includes the
elevation change, friction losses and change in energy due to drop in velocity.
∆𝐸net is given by 𝐾𝑙 ∗ 𝑉2
/2𝑔
Where 𝐾𝑙 =
1
𝐶 𝐷
2 − 1
The values for CD are given in literature for different types of valves. Figure 5 (Tullis, 1989) shows a few of them.
Figure 5: Discharge coefficients for inline valves; (Image Courtesy Hydraulics of Pipelines by Paul Tullis)
So we calculate the ∆𝐸measured for 100% open valve as we know the velocity through the pipeline. Once that is done,
we calculate the velocity for a certain percentage of closing by keeping the ∆𝐸measured same and matching it with the
right hand side of the equation by iterating the velocity as the CD value changes. Note that as the velocity changes so
does the Reynolds number and thus the frictional losses, but the change is negligible and hence the ∆𝐸measured can be
assumed to be the same. Figure 6 below shows the excel sheet for flow through valves and pumps. Note that pump
design and selection is beyond the scope of this project but any desired pump head can be added to the net head in
the sheet shown below.

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Figure 6: Valve & Pump Sheet
The flow through chokes is exactly as flow through valves but with a much better and accurate control over the
flow. Figure 8 below shows the CV values for standard industry chokes by Cameron.
CV relates to CD by the following formula.
𝐶 𝑉 = [
890𝐷4
𝐶 𝐷
2
1 − 𝐶 𝐷
2 ]
1
2
(𝐷 𝑖𝑠 𝑖𝑛 𝑖𝑛𝑐ℎ𝑒𝑠)
(3)
And the rest of the calculation proceeds exactly as for the valves as shown in Figure 7.

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Figure 8(a)(b)(c): Cv Values for different types of Chokes; (Courtesy Cameron)

17
4.3 Single phase heat transfer
Conventionally these predictions are made using FEM software. In the developed tool we would be applying the
same principles that are programmed into the software but we would be entering them manually into the spreadsheet
and evaluate heat losses on elemental lengths of pipe and do a cumulative integration on the values.
The heat transfer through the pipe is governed by the equation (4) given below:
𝑄𝑟 = 𝑈 ∗ 𝐴 ∗ (𝑇𝑖 − 𝑇𝑜)
(4)
U: Overall heat transfer coefficient based on external or internal surface area (W/sq.m.K)
A: Area of heat transfer surface, Ai or Ao (sq.m)
To: Ambient Temperature of pipe surroundings (K)
Ti: Average temperature of fluid inside the pipe (K)
𝑈 =
1
[(
1
ℎ𝑖
)+𝑟𝑖∗
ln(
𝑟1
𝑟𝑖
)
𝑘1
+𝑟𝑖∗
ln(
𝑟𝑜
1
)
𝑘2
+
𝑟𝑖
𝑟𝑜∗ℎ𝑜
]
; (5)
k is thermal conductivity (W/m.K), h is Heat transfer coefficient (W/sq.m.K) both of these values are readily
available in literature. For buried or semi-buried pipelines the following formula is to be used for ho.
ℎ𝑠𝑜𝑖𝑙 =
𝑘𝑠𝑜𝑖𝑙
(
𝐷
2
) cosh−1(
2𝑍
𝐷
)
; Z: distance between top of soil and center of pipe (m)
ho= (1-f)ho buried + f*ho exposed
f: percentage of burial, ri: Internal diameter, r1: Intermediate diameter, ro: Outer diameter.
Insulation manufacturers typically use a U value based on the outer area while pipe line designers use U value based
on internal area, for the purposes of this project we have used the internal area.
Qnet= M. CP. (Ti-To) (6)
CP= Specific heat of fluid (kJ/kg K),
M= Fluid mass in the pipe segment (kg)

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We calculate the net heat at a location along the pipe in a finite segment and remove the heat transferred from it in
the amount of time the control volume is within that segment. Then we find the internal temperature based on the
new value of Qnet obtained. The smaller the segments the more accurate your solution will be. Figure 9 given below
shows the temperature drop for a reservoir at 15000 psi and initial temperature 215o
F.
Figure 10: Temperature Simulation Sheet
Figure 9: Temperature Drop Simulation in FAT1

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4.4 Estimation of cooldown time
The strategies for solving the transient heat transfer problems of subsea pipeline systems include analytical methods
(e.g., lumped capacitance method), the finite difference method (FDM), and the finite element method (FEM). The
method chosen depends on the complexity of the problem. Analytical methods are used in many simple cooldown or
transient heat conduction problems. The FDM is relatively fast and gives reasonable accuracy. The FEM is more
versatile and better for complex geometries; however, it is also more demanding to implement. A pipe has a very
simple geometry; hence, obtaining a solution to the cooldown rate question does not require the versatility of the
FEM. For such systems, the FDM is convenient and has adequate accuracy, which is why the cooldown sheet is
modeled using FDM. The calculations remain exactly the same as Section 4.3 but, instead of calculating
instantaneous heat loss, we calculate heat loss over extended periods of time at the same location with intervals at
every half an hour, the intervals can be reduced for higher accuracy. The ultimate aim of this exercise is to design a
pipeline thickness and insulation which allows for a 8-12 hour cooldown period. The final temperature at any point
in the pipe at the end of the time period has to be on the right of the blue lines shown in Figure 11, preferably to the
right of the red lines. The temperature simulation spreadsheet is shown in Figure 10.
Figure 11: Hydrate and wax formation Temperatures; (Image Courtesy Fundamentals of Subsea Engineering
Coursework Texas A&M University)

20
5. Comparison of Results with PipeSIM
For the purpose of comparing results with PipeSIM software, a simulation was run for a generic oil field, the details
of which are presented below. The reader is advised that the results presents are only meant to showcase the
software capabilities and are not to be confused with a verified engineering design as the structural requirements and
other strength constraints are not taken into consideration.
Table 2: Inputs for Simulation in FAT1
Depth of reservoir from seabed 9900 ft
Temperature inside reservoir 215 F
Pressure inside reservoir 15000 psi
Horizontal distance of flowline on seabed 10000 ft
Inner Diameter of Tubing 5 inches
Inner Diameter of flowline 5 inches
Thickness of tubing and flowline 0.5 inches
Production Rate 31400 STB/Day
Insulation thickness on flowline 0.5 inches
Velocity of Flow 15 ft/s
Oil API Index 26
The comparison was run using PipeSIM 2012 version the model of which is shown in Figure 12 below. The pressure
and temperature results are presented.
Figure 12: PipeSIM Model for Simulation

21
 Pressure variation in PipeSIM:
 Pressure variation as simulated in FAT1:
Figure 13: Pressure Drop from reservoir to riser base (PipeSIM)
Figure 14: Pressure drop simulated in FAT1

22
 Temperature variation in PipeSIM:
 Temperature variation as simulated in FAT1:
Figure 15: Temperature drop from reservoir to riser base (PipeSIM)
Figure 16: Temperature simulation in FAT1

23
Note that the above cooldown simulation is performed with the insulation thicknesses mentioned at the beginning of
section 4.5. To increase the cooldown time the insulation can be increased also reduction of time interval for the
simulation will allow it to be a lot more accurate and might actually increase the cooldown time without any
alteration of insulation.
 Pressure VS Temperature simulation in PipeSIM:
Figure 17: Cooldown simulation at the Wellhead in FAT1
Figure 18: Pressure VS Temperature (PipeSIM)

24
 Pressure VS Temperature simulation in FAT1:
Accuracy of the developed Flow Assurance Tool-(FAT1):
Table 3: Accuracy Comparison of FAT1 against PipeSIM
PipeSIM FAT1 Percentage
Difference
Temperature at
Riser Base (F)
191.0 190.7 0.18
Pressure at Riser
Base(Psi)
9466.0 9652.0 -1.96
Temperature at
Wellhead (F)
197.7 198.9 -0.58
Pressure at
Wellhead(Psi)
10289.5 10485.0 -1.9
Summary
Looking at the results presented in Table 3, we can conclude that the developed tool is fairly accurate and due to its
almost inexpensive nature in terms of money and computing requirements, it makes a very viable option for small to
midsized companies wishing to have an initial idea of the flow assurance parameters of their selected fields. This
tool in its current state is the first step towards building a more all-encompassing and more autonomous. The future
developments looks at incorporating drift flux models for two phase flows, three phase flows and optimizing
cooldown sheet to allow for shorter time intervals.
Figure 19: Pressure VS Temperature simulation FAT1

25
References
 J. Paul Tullis, Hydraulics of pipelines, John Wiley & Sons. 1989.
 Yong Bai & Qiang Bai, Subsea Engineering Handbook.
 Ovadia Shoham, Mechanistic modeling of gas-liquid two phase flow in pipes.
 Randall, R. Underwater and Moored Systems Design, OCEN 408 Course Notes, Department of Ocean
Engineering, Texas A&M University, College Station, TX, August 2015.
 Lucas, D. Fundamentals of Subsea Engineering, ENGR 689 Course Notes, Texas A&M University,
College Station, TX, August 2015.
 Barnea, D. (1987) A unified model for predicting flow-pattern transitions for the whole range of pipe
inclinations, Int. J. Multiphase Flow, 13, 1-12. DOI: 10.1016/0301-9322(87)90002-4
 Biesheuvel, A. and Gorissen, W. C. M. (1990) Void fraction disturbances in a uniform bubbly fluid, Int. J.
Multiphase Flow, 16, 211-231. DOI: 10.1016/0301-9322(90)90055-N
 Dukler, A. E. and Taitel, W. (1986) Flow Pattern Transitions in Gas-Liquid Systems: Measurement and
Modelling, Chapter 1 of Multiphase Science and Technology, Vol. 2 (Ed. G. F. Hewitt, J. M. Delhaye and
N. Zuber), Hemisphere Publishing Corporation.
 Govan, A. H., Hewitt, G. F., Richter, H. J. and Scott, A. (1991) Flooding and churn flow in vertical pipes,
Int. J. Multiphase Flow, 17, 27-44. DOI: 10.1016/0301-9322(91)90068-E
 Hewitt, G. F. (1982) Chapter 2, Handbook of Multiphase Systems (Ed. G. Hetsroni), Hemisphere
Publishing Corporation, New York.
 Hewitt, G. F., Martin, C. J. and Wilkes, N. S. (1985) Experimental and modelling studies of annular flow in
the region between flow reversal and the pressure drop minimum, Physico-Chemical Hydrodynamics, 6,
43-50.
 Lin, P. Y. and Hanratty, T. J. (1986) Prediction of the initiation of slugs with linear stability theory, Int. J.
Multiphase Flow, 12, 79-98. DOI: 10.1016/0301-9322(86)90005-4
 Taitel, Y., Barnea, D. and Dukler, A. E. (1980) Modelling flow pattern transitions for steady upward gas-
liquid flow in vertical tubes, AIChE J, 26, 345-354. DOI: 10.1002/aic.690260304
 Whalley, P. B. (1987) Boiling and Condensation and Gas-Liquid Flow, Clarendon Press, Oxford. DOI:
10.1017/S0022112088211739
 www.Thermopedia.com
 Schlumberger (PipeSIM, OLGA). 2015.
 Cameron Subsea. 2009.
 Schneider Electric (PipePhase). 2007.

26
Appendix I: Tutorial for Using FAT1
1. On sheet no. 1 named “B.O.Flow” fill out all the sections which are highlighted in green. These include the
basic parameters of the oil or gas field that the user is running the simulation for.
2. The length segments can be decided by the user is column A. Although a segment smaller than 0.5m is
generally not recommended. The user also has to enter the diameter and any minor loss coefficient is the
segment is that of a valve or a bend in the pipe. Finally the user has to enter the elevation of the particular
segment of pipe. Depending on if it is lying flat in which case all elevation values will be 0 or if it has a
steady slope the user can incorporate that into the sheet.
3. Once all the initial parameters are input the user just has to drag the row down keeping the segment
distance same until one of the parameters changes i.e the elevation, minor loss coefficient or diameter.
4. Once the required changes are made to the parameters, the user can continue to drag the row until he wants
to incorporate a valve, choke or pump in which case the user has to go to step 5.
5. As in the previous sheet the “Valve & Pump patch” sheet also has green cells which need to be filled in by
the user. The pressure to be input here is the pressure at the point in the pipeline where the valve is located
and can be copied from the previous sheet.
6. The CD value for the valve has to be entered at the 100% open condition. This value will depend on the
type of valve selected and that is available widely in literature. The initial velocity, diameter and other
parameters are to be copied from the previous sheet as well.
7. Then the CD value for the partially open condition for the valve has to be input depending on what
percentage of the valve is open.
8. If a pump head is to be added it can directly be input in cell B20.
9. Finally once all inputs are correctly entered the entire row 26 from cell A to O can be copied back into the
main sheet and the user can go to step 4. Note that for a different percentage of opening for the same valve
or addition of a new valve at a different location the user has to repeat steps 5 through 9.
10. When a choke is to be entered into the system the same steps 5 through 9 have to be repeated but instead of
entering CD the user has to enter CV value for the choke. And then a Goal Seek is to be run in cell C3 to
match with the entered CV value to obtain the corresponding CD value. The rest of the calculation proceeds
just as described in step 5 through 9.
11. The row C27 has to be copied back into the original sheet and the user has to go to step 4.
12. The temperature simulation is broken down into two sheets the first one “Temp SIM” deals with
temperature simulation all along the length of the pipeline and the cooldown times along the length of the
pipeline. As in the previous sheets the green cells have to be filled in by the user. And the solution row can
be dragged down as far as the user wants to simulate the temperature condition during the operating case.
13. The current sheet is configured at 0.5m length intervals and 0.5 hr time intervals to simulate the cooldown
conditions. As mentioned earlier the accuracy can be improved substantially by reducing the time interval
even further. The user only has to change the number in row 18 to change the time interval and column A
to change the length interval.
14. The sheet “Temp SIM Local” deals with cooldown with 1 second intervals for a period of 12 hours at any
one single spot that the user wants to simulate, which might be of particular interest. The user only has to
copy all the inputs for the required location on the pipeline from the “Temp SIM” sheet along with the
other pipeline inputs to this sheet and the sheet automatically runs a simulation for that location for
cooldown time.

27
Appendix II: PipeSIM Result File

Report_FAT1_Final

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