UTP Student Industrial Project Report

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STUDENT INDUSTRIAL PROJECT REPORT

JANUARY 2014 – APRIL 2014

MODELING AND SIMULATION OF STEADY STATE FLOW

ASSURANCE STUDY ON OFFSHORE PIPELINES USING

PIPESIM SOFTWARE

at

BERACHAH GROUP SDN. BHD.

by

MOHANA ROOPARN A/L KALAICHELVAN

15338

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II

VERIFICATION STATEMENT

I hereby verify that this report was written by Mohana Rooparn A/L Kalaichelvan,

15338 and all information regarding this company and the projects involved are NOT

confidential.

Host Company Supervisor’s Signature & Stamp

Name:

Designation: Host Company:

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III

ACKNOWLEDGEMENT

First and foremost, the author would like to express his utmost gratitude towards his parents, for it was them who had given the author the guidance and moral support required throughout the industrial training totalling up to 7 months at Berachah Group Sdn. Bhd. The author would also like to take this opportunity to extend his appreciation towards all other individuals, both family and friend that have cheered and supported the author during this internship period.

Many thanks the author bids to his host company Berachah Group Sdn. Bhd. for providing the opportunity to undertake the industrial training with them and also to the supervisors, Pipeline Engineer Mr. Krishna Kumar and Flow Assurance Engineers Ms. Prasana Seharan, for their vital encouragement, support and guidance in the author’s learning process throughout training period here.

The author also wishes to convey his deepest gratitude towards all members of staff and engineers of Berachah Group Sdn. Bhd., for all of their supports and training given to the author during the industrial training. Special thanks to Mr. Samuel John, Senior Project Manager for his valuable inputs and guidance throughout this project. The experiences shared with the engineers provided a much needed insight towards the working environment.

Last but not the least, the author wishes to thank his supervisor from Universiti Teknologi PETRONAS (UTP), Dr. Khor Cheng Seong, who was ever willing to spend his time providing support during the entire training period to ensure the author is able to achieve the objectives of the Student Industrial Internship Program.

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IV

LIST OF TABLES

Table 1: Horizontal Flow Regime Limits ...28

Table 2: Constants for Liquid Holdup Calculation...29

Table 3: Design and operating conditions ...39

Table 4: Pipeline design data ...40

Table 5: Riser design data ...40

Table 6: Environmental data ...41

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VII

LIST OF FIGURES

Figure 1: Company Logo ... 5

Figure 2: Some of the aspects of flow assurance. ... 6

Figure 3: Gas hydrates plug removal from pipeline. ... 6

Figure 4: European gas pipeline network. ... 8

Figure 5: Flow Regime Map Based on Superficial Velocities ...13

Figure 6: Flow Patterns for Vertical Two-Phase Flows...14

Figure 7: Flow Patterns for Horizontal Two-Phase Flows...15

Figure 8: Holdup Factor Correlation ...18

Figure 9: Correlation for Viscosity Number Correlation ...18

Figure 10: Correlation for Secondary Correction Factor ...19

Figure 11: Moody Diagram ...21

Figure 12: Lockhart& Martinelli Friction Correction ...24

Figure 13: Horizontal FlowPatterns of Beggs & Brill Correlation ...27

Figure 14: Simple molecular structure of methane hydrate ...32

Figure 15: Simplified schematic representation of CO2 corrosion mechanism ...35

Figure 16: Project Flowchart ...38

Figure 17: Sarawak offshore gas fields ...39

Figure 18: Seabed elevation profile ...41

Figure 19: PIPESIM interface ...43

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VIII

LIST OF GRAPHS

Graph 1: Horizontal flow correlation comparison ...47

Graph 2: Vertical flow correlation comparison ...48

Graph 3: Vertical flow correlation comparison - Riser F14 ...48

Graph 4: Vertical flow correlation comparison - Riser F23 ...49

Graph 5: Pressure drop for various pipe sizes ...50

Graph 6: Pressure drop for various pipe sizes, Outlet = 92 bara ...51

Graph 7: Fluid velocity for various pipe sizes, Outlet = 92 bara ...52

Graph 8: Phase envelope plot ...53

Graph 9: Phase envelope plot - operation line ...54

Graph 10: Phase envelope plot - 5 mm insulation ...54

Graph 11: Phase envelope plot - 10 mm insulation ...55

Graph 12: CO2 corrosion rate ...56

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CHAPTER 1: INTRODUCTION

This report is prepared to record all the relevant activities that contributed towards the completion of the author’s study on his industrial project throughout the internship period at Berachah Group Sdn. Bhd. This chapter gives a brief description on the host company, the purpose of the industrial project, followed by the objectives and training approach applied.

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1.1. PURPOSE OF STUDENT INDUSTRIAL PROJECT

The main purpose of the Student Industrial Project (SIP) is to provide exposure to Universiti Teknologi PETRONAS (UTP) students to the real working environment and in doing so they would be able to relate theoretical knowledge learned in the university with appropriate application in the industry. The SIP program will also aid the students in the development of their skills set such as in safety practices, work ethics, communication and management. UTP also aims to achieve closer relationships with the industry through the SIP program.

The SIP is an opportunity for UTP students to build a solid understanding of the fundamentals of business and organization performance such as economic models of business, competitive positioning and strategy execution. In this real life environment, students will be able to develop their ability to assess performance, interpret trends, explore the consequences of change and make better decisions as engineers.

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1.2. OBJECTIVES OF STUDENT INDUSTRIAL PROJECT

There are a number of learning outcomes of which the students doing the SIP are required to accomplish by the end of the training. These learning outcomes would become the main objectives of the SIP, which are:

a) Integrate theoretical knowledge in the industry.

The SIP provides students with the opportunity to implement the theoretical knowledge learnt in the university into real-world situations. Through this hands-on experience working with the industrial practitioners, the students will have better understanding of the knowledge learnt.

b) Analyse complex engineering/technical projects or problems.

During SIP, students will be assigned projects and tasks by their host company supervisors. This will expose them to the real engineering working environment where they would work with other engineers or independently to investigate and study the engineering/technical part of the projects and tasks assigned.

c) Evaluate and propose solutions for given complex project or problems.

Upon investigating the project or task assigned to them and identifying the problems involved, the student would then have to propose a solution for it. Working with other engineers of various engineering background, the students will gain valuable knowledge and experience on how to overcome such engineering problems.

d) Communicate effectively on complex engineering/technical activities.

During the SIP period in the host company, students will able to demonstrate their practical, communication and technical skills gained throughout the internship. The students will be able to present their findings to fellow engineers and professionals and with excellent performance and testimonies will even be able to secure placement at the host company and launch their career there upon graduation.

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1.3. TRAINING APPROACH

The training approach used for all tasks, assignments and projects undertaken at the host company applied the following topics:

 Hands-on training

 Real project-based assignments  Research-based activities  Team-work activities

 Leadership and management skills  Safety awareness

For SIP, the suggested training areas applicable for the students of the Chemical Engineering programme are, but not limited to:

 Research and Development  Health, Safety and Environment  Statistical Process Control  Process Design & Unit Operation  Process & Instrumentation Control  Plant Process/Maintenance

 Process Analysis  Thermal System Design  Management & Administration  Production Planning

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1.4. HOST COMPANY

1.4.1. Berachah Group Sdn. Bhd.

Figure 1: Company Logo

Berachah Group Sdn. Bhd. (BGSB), incorporated in 27th August 2007 offers engineering and project management services for the offshore and onshore oil and gas pipeline industry with a team of specialists and engineers spanning various disciplines. BGSB’s main office is located in the Wisma Goldhill office tower in Jalan Raja Chulan, which is part of the “Golden Triangle” business district in Kuala Lumpur.

BGSB currently has strength of 31 personnel with active plans for expansion in progress. The company’s staffs consists of professional engineers and specialists coming from various backgrounds with extensive skills in engineering design and project management with up to 25 years or so of experience in the offshore and onshore oil and gas industry. Due to their vast experience and knowledge of the industry, BGSB is able assemble its team of engineers to understand the uniqueness of each client and the associated projects; therefore adapting and providing tailored solutions to meet the clients’ needs.

BGSB has a standing reputation in the industry with a broad client base consisting of key players of the oil and gas industry in Malaysia and even in the South- East Asia region. Some of the clients BGSB frequently works with include:

 PETRONAS Carigali Sdn. Bhd.  Petrofac (Malaysia) Limited  Sarawak Shell Bhd.

 Brunei Shell Petroleum Company Sdn. Bhd.  Talisman Malaysia Limited

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1.4.2. Business & Expertise

BGSB’s expertise lies in providing a wide range of engineering and design solutions to cater for its clients in the oil and gas industry. The main expertises of BGSB are in offshore pipelines and risers, onshore pipelines and facilities, flow assurance and operability, marine terminals and subsea production. The scope of engineering, design and project management services provided include Conceptual Design, Front End Engineering Design (FEED), Detailed Engineering and Design, Construction and Installation Engineering and Construction Management and project Management.

1.4.2.1. Flow Assurance Team

As mentioned previously, one of BGSB’s expertise lies in the field of flow assurance. Flow assurance is the design, strategies and principles for ensuring that there is an uninterrupted hydrocarbon production flowing from the reservoir to the point of sale through the pipeline. A flow assurance study for a pipeline can mostly be performed with the aid flow simulations such as network modelling, multiphase steady state and transient modelling, but besides that it also involves tackling other complications of a pipeline flow such as gas hydrate deposits, wax, asphaltene and scaling.

Figure 2: Some of the aspects of flow assurance. Figure 3: Gas hydrates plug removal from pipeline.

Since flow assurance is based on fluid flow and its inherent properties, the BGSB Flow Assurance Team, is led by and comprised mainly of chemical engineers due to their specialisation in these topics. The author was also a member of this team and therefore this project is based upon the flow assurance studies undertaken during the author’s SIT in the previous semester.

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CHAPTER 2: PROJECT

INTRODUCTION

This chapter provides a simple introduction of the project by expressing the problem statement, highlighting the project’s objective followed by discussing the scope of study and finally defining the relevancy of the project.

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2.1. PROBLEM STATEMENT

In the present age, the global demand for energy is limitless and grows annually. Majority of this energy is generated via fossil fuel or petroleum. To maintain supply, energy companies worldwide actively search for new oil wells, be it onshore or offshore, or try to maximise production in an already existing ones. The raw petroleum or natural gas is then transported to onshore refineries and processing facilities via a network of pipelines. With the discoveries of new wells and production increases from already existing wells, newer pipelines are designed and constructed as part of the overall network to handle these higher production volumes.

Figure 4: European gas pipeline network.

However, the task of designing and constructing such pipelines are not to be taken lightly. One of the factors of the utmost importance to be taken into consideration when designing pipelines is flow assurance which are the design strategies implemented to achieve uninterrupted flow of product in the pipeline. Thus, to achieve this uninterrupted flow, various calculations and modelling have to be performed to

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study all major problems that might arise in the pipeline. Some of the factors that have to be considered include:  Pressure drops  Temperature variations  Corrosion  Hydrate formation  Slugging

Performing the required calculations and modelling is not an easy task either, mainly due to the vast length of the pipeline and the complex numerical methods employed in the modelling.

2.2. OBJECTIVES

Some of the main objectives identified for carrying out this project include the following:

a) To identify the important aspects of flow assurance.

b) To model steady state fluid flow conditions with the aid of computer software simulations using data obtained from the field.

c) To identify and analyse problem found in the end result of the simulations.

d) To suggest solutions designed to nullify the problems.

e) To propose a design for an offshore pipeline based on the findings of the steady state flow simulations and the solutions implemented.

2.3. SCOPE OF STUDY

The scopes of studies covered by the author in this particular project are as per following:

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b) Studying the different types of fluid flow such as liquid flow, gas flow and multiphase flow and flow regimes involved in such flows.

c) Studying the theories used in the modelling of steady state flow conditions such as flow correlations, assumptions and applicability of these correlations.

d) Understanding the application and capabilities of the steady state flow simulation software used in this project.

e) Providing design inputs for an overall design of an offshore pipeline based on findings.

2.4. RELEVANCY OF THE PROJECT

Designing and constructing a pipeline without properly considering these factors will pose serious risks such as clogging due to hydrate plugs, leaking from corroded joints and even explosions caused from excessive pressure. This will then lead to severe downtime for maintenance and repair works and the costs incurred will be too high.

Therefore, in this project, the author, with the aid of advanced software, will attempt to model and simulate the flow of well fluids using specific fluid compositional data and environmental data from the field. With the generated results, the author will then address the flow assurance factors and propose control methods and solutions to finalize a basic design input for the pipeline in study.

With these suggested modifications to the pipeline design, the pipeline would have a better chance of operating flawlessly under the simulated conditions and unnecessary damage and downtime can be avoided.

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CHAPTER 3: LITERATURE

REVIEW

In this chapter is mainly based upon the engineering and technical aspects of fluid flow simulations. The author discusses the themes addressed in this report such as multiphase flows, hydrates and etc. with available literature and past researches. The final study will be based upon the literature discussed in this chapter.

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3.1. MULTIPHASE FLOW

Multiphase flow is commonly referred to as any fluid flow consisting of more than one phase or component. In many cases, the two main phases are vapour and liquid. Many other combinations are possible too, such as solid-gas, solid-liquid and two immiscible liquids. In this context however, a 3-phase fluid flow is considered which consists of gas, water and oil. To this date, multiple methods have been applied for the studying and modelling of the multiphase flow regime. The true predictions of fluid flow are only available for single-phase laminar flows and very low Reynolds number flows in simplified geometries. When there is an increase in the Reynolds number however, to values of real applications, the true predictions can no longer be valid and therefore the only practical means is by applying empiricism. This proves that multiphase flows with deformable interfaces take upon virtually an infinite number of flow configurations which present an intractable problem. For example, laminar flow over a basic geometric shape such as an isolated spherical particle, bubble or droplet, yield analytical solutions to the conservation equations. This is particularly true given that in the vast majority of cases multiphase flows are turbulent in nature. This goes to show that the study and modelling of multiphase flow regimes put upon a heavy emphasis on empirical methods and the predictions resulting from it can only be as reliable as the empirical relationships which they are based upon (Brill & Mukherjee, Multiphase Flow in Wells, Monograph Volume 17, 1999).

From the numerous observations and experiments performed over past years, it was found necessary for the flow patterns or flow regimes observed to be defined and categorized accordingly. Pickering, Hewitt, Watson, & Hale, 1992 provide an introductory discussion of flow patterns and states that these can themselves be categorized into three main types which are dispersed flow, separated flow and intermittent flow. In dispersed flows, flow regimes are characterized as one phase is distributed uniformly in another continuous phase as rough spherical elements (Beggs & Brill, 1973). For example, bubble flow in which small gas bubbles are dispersed through a continuous liquid phase and mist flow where small droplets of liquid are carried along in a vapour stream. Separated flows consist of immiscible phases. One of it stratified flow where the heavier liquid phase flows at the base of the pipe and the lighter gas phase on the above. Another variant is annular flow where the liquid flows

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around the periphery of the pipe as a thin film with a gas core flowing internally. Finally, there is the intermittent flow made up of non-uniformly distributed phases. An example of intermittent flow is the slug flow. This flow regime creates massive amounts of turbulence at the front of the slug. The slug flow exerts a high sheer stress on the walls of the pipe due to the constant impact and collapse of the slug upon the pipe wall which in turn leads to corrosion.

Figure 5: Flow Regime Map Based on Superficial Velocities

The figure above classifies some of the main flow regimes based on the superficial velocities of the liquid and gas phases involved. The fluid mean velocity for a single phase flow regime can be obtained by dividing the volumetric flow rate with the cross sectional area. However, when multiphase flow is involved, a better way to define the velocities would be through superficial velocities using the volumetric flow rates of the liquid phase and gas phase respectively. For a simple 2-phase flow consisting of a single liquid phase and single gas phase, the corresponding superficial velocities are:

= ( /4) =

( /4)

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It can be seen, at very low superficial velocities, the flow is rather laminar or stratified. As the superficial velocities of both phases increase, the flow becomes wavy and finally at very high superficial velocities it develops into an annular flow. At lower gas superficial velocities, the flow transitions from the wavy-stratified flow into a slug flow and upon reaching high liquid superficial velocities compared fairly lower gas superficial velocities the flow becomes a bubble flow with gas bubbles entrained within a continuous liquid phase. For the opposite conditions, where the gas superficial velocities are fairly higher compared to the liquid superficial velocities, the flow becomes a mist flow containing liquid droplets in carried in a gas phase. Although very useful, it is important to note that the superficial velocities do not represent the actual velocity of which the phase is moving as it is based on the relative flow rates and cross sectional areas of the flowing phase.

Figure 6: Flow Patterns for Vertical Two-Phase Flows

Even though the identification and classification of flow regimes into specific flow patterns is subjective, it has become a rather useful method in the modelling of multiphase flows. This is mainly due to the significant differences in the pressure drops and phase hold-ups of one flow pattern compared with another and therefore the predictions of the multiphase flow will benefit from the knowledge of the flow pattern and an appropriate model which is unique to the flow pattern being studied. The models which offer the best predictions for such multiphase flows rather accurately are the phenomenological models. These models function by first indentifying the flow pattern being studied and then applying a very specific and unique model for the flow pattern in study. For example, considering a slug flow, the traditional Eulerian solution of a two-phase model which specifies a stationary spatial grid over which the partial

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differential equations are discretised, presents certain difficulties associated with the unphysical dispersion of discontinuities, for example, the noses and tails of slugs. These problems can be partly alleviated using complex adaptive grid techniques which allow the spatial nodes to bunch in order to ‘resolve’ discontinuities. However, perhaps the only robust solution will come from a Langrangian phenomenological model where individual slugs are followed throughout the system and appropriate correlations are employed for entrainment of bubbles at the nose and shedding of liquid from the tail (Date, 2005).

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3.2. FLOW CORRELATIONS

A general and simplified equation used to calculate the pressure gradient can be written as:

= + +

This equation takes into account three main factors that cause the pressure drop, which are the elevation, friction factor and fluid acceleration. The pressure drop arising from the elevation variations is mainly due to the changing density of the two-phase fluid. This would be usually calculated using a liquid holdup value. This component also causes the main pressure drop in vertical flows unless for conditions of high flow velocities. The second component is the pressure drop due to frictional losses and this is obtained through the computation of a two-phase fluid friction factor. Finally, there is the pressure loss caused by the acceleration of the fluids. This is neglected in most cases unless it involves high flow velocities.

Over the past years, many semi-empirical flow correlations have been developed for the purpose of predicting the pressure gradients in two-phase flows. All these flow correlations differ in the sense of their approach used to calculate the three components of the total pressure gradient mentioned previously. Certain correlations assume a no-slip condition where the velocities of both the liquid phase and gas phase are the same for evaluating the mixture density and evaluate only a friction factor empirically. Unfortunately, this approach is rather inaccurate. Other developed methods calculate both liquid holdup and friction factor of the flow and even divide the flow conditions into patterns and regimes and apply different correlations for different flow regimes (Brill & Beggs, 1991).

3.2.1. Hagedorn & Brown Correlation

The Hagedorn & Brown flow correlation was developed using data obtained from a 1500 ft. experimental well with pipe sizes ranging from 1 in. to 4 in., applicable for vertical flows only. This correlation takes into account slippage between the phases due to velocity differences but not the different flow regimes that may occur in the pipe. However, the liquid holdup calculated using this correlation is not actually the

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true measure of the portion of the pipe retained with liquid but is rather a correlating parameter to satisfy the measured pressure gradient arising from friction losses and fluid acceleration.

3.2.1.1. Elevation Pressure Drop

For calculating pressure losses due to elevation variations, a value liquid holdup must be established. Several dimensionless parameters need to be used in order to obtain the liquid holdup value. The parameters are:

= 1.938 ∙ ∙ Liquid Velocity Number

= 1.938 ∙ ∙ Gas Velocity Number

= 120.872 ∙ ∙ Pipe Diameter Number

= 0.15726 ∙ ∙ 1

∙ Liquid Viscosity Number

The units used for the given equations are rather specific and commonly referred to as “oil field” units, which are:

vsL = liquid superficial velocity, ft/s

vsg = gas superficial velocity, ft/s

ρL = liquid density, lbm/ft3

σL = interfacial tension, dynes/cm

μL = liquid viscosity, cp

d = pipe internal diameter, ft

For a liquid stream made up of an oil-water mixture, the properties of the fluid can be represented as:

=

+ = 1 − = +

= ∙ + ∙

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= ∙ + ∙

With the dimensionless parameters calculated, the liquid holdup can now be obtained with the aid of the following correlations, shown in the figures below.

Figure 8: Holdup Factor Correlation

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Figure 10: Correlation for Secondary Correction Factor

The steps taken to calculate the liquid holdup and the final pressure drop due to elevation are:

1. Obtain viscosity number, CNL and secondary correction factor, ψ from the

graphs in Figure 9 and Figure 10 respectively using dimensionless parameters NLv, Ngv, Nd and NL calculated earlier.

2. Use obtained CNL value to calculate for holdup factor, is from Figure 8.

3. Multiply by ψ to obtain liquid holdup, HL.

4. Input HL and the other relevant values in the following equation to obtain the

elevation pressure drop component:

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20 3.2.1.2. Frictional Pressure Drop

The pressure drop due to friction between the fluid and the pipe wall can be computed using the following equation:

= ∙ ∙

2 ∙ ∙

However, the expression derived by Hagedorn and Brown, which incorporates mass flow rate is given as:

= ∙

2.9652 × 10 ∙ ∙

Where:

w = mass flow rate, lbm/day ρs = liquid holdup density, lbm/ft3

= ∙ + ∙ , = 1 − d = internal diameter of pipe, ft f = friction factor

The fluid Reynolds number is calculated to obtain the friction factor either from the Moody Diagram in Figure 11, or using an equation as mentioned below.

= ∙ ∙ Reynolds number

= + Mixture velocity

= × Mixture viscosity

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3.2.1.3. Acceleration Pressure Drop

The pressure gradient arising from acceleration of the fluids in the pipe is neglected in most cases unless there are high flow velocities involved. The governing equation of this pressure gradient is:

= ∙ ∆( )

2 ∙ ∙

Where:

∆( ) = ∙ ( , ) − ∙ ( , )

And Ek is defined as:

= ∙ = ∙ ∆( )

2 ∙ ∙

Therefore, the total pressure drop arising from elevation variations, friction between fluid and pipe wall and fluid acceleration can be calculated from the following equation:

=

+ 1 −

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3.2.2. Lockhart& Martinelli Correlation

The Lockhart& Martinelli correlation applies for fluid flow along horizontal pipes, therefore pressure loss due to elevation variations are disregarded. This correlation does not follow the usual friction factor analogy but takes it into account the two-phase flow as a single phase with a correction factor. The pressure gradient due to acceleration is also ignored in this flow correlation.

The general pressure drop equation for horizontal flows is:

= + or = ∙ ∙ 2 ∙ ∙ + ∙ ∙ ∙

Note the absence of the elevation pressure drop component from the equation. However, since the Lockhart& Martinelli disregards the acceleration component, the equation is reduced to:

= ∙ = ∙ = ∙ ∙ 2 ∙ ∙ = ∙ ∙ 2 ∙ ∙ Where: Subscripts: f = friction factor vs = superficial velocity ρ = density

gc = gravitational constant (for conversion of lbm to

lbf)

g = gas L = liquid

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24 d = pipe internal diameter

The friction factors can be determined from the Moody diagram or the equation by calculating the Reynolds number of the flow as mentioned previously.

The two-phase correction factors used are correlated with a parameter defined as following:

=

.

This correlation is shown in the graph in Figure 12, where different curves are used for each ϕ depending on the Reynolds number of each phase. Laminar flow is considered for phases with Reynolds number less than 1000.

Figure 12: Lockhart& Martinelli Friction Correction

The lower case subscripts t and v represent either turbulent or laminar flow with the first one designated for the liquid phase and the second one for the gas phase. For example, the factor ϕGvt is the correction factor applied to the single phase gas

pressure gradient when the liquid phase is in laminar flow and the gas phase is in turbulent flow.

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The steps taken to calculate the pressure drop using the Lockhart& Martinelli correlation are:

1. Calculate Reynolds number for gas phase, NReg and liquid phase, NReL and

obtain the corresponding friction factor values, fg and fL.

2. Determine the pressure gradients for the liquid phase, and gas phase, .

3. Calculate for parameter X.

4. Use the obtained X value to determine the correction factors for the liquid phase, ϕL and gas phase, ϕg, based on the Reynolds number calculated earlier.

5. Multiply the correction factors with their respective pressure gradients to obtain the final pressure drop.

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3.2.3. Beggs & Brill Correlation

The Beggs & Brill correlation was developed from small scale test facility experiments consisting of 1 in. and 1.5 in. acrylic pipes with a length of 90 ft. which could be inclined at any angle. The parameters studied for the development of this correlation include:

 gas flow rate (0-300 MMSCFD)  liquid flow rate (0-30 gal/min)  average system pressure (35-95 psia)  pipe diameter (1-1.5 in.)

 liquid holdup (0-0.87)

 pressure gradient (0-0.8 psi/ft)  inclination angle (-90o to +90o)

 horizontal flow patterns (segregated, intermittent and distributed, Figure 13)

This flow correlation is one of the most widely used in the industry due to versatility where it can be applied to both horizontal and vertical flows. The liquid holdup and pressure gradient was measured at angles of 0o (horizontal) and varied up to plus minus 5o_{, 10}o_{, 15}o_{, 20}o_{, 35}o_{, 55}o_{, 75}o_{and 90}o_{. A total of 584 tests were}

conducted to develop this correlation and therefore it has a high degree of accuracy (Brill & Beggs, Two-phase flow in pipes, 1991).

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28 3.2.3.1. Flow Regime

To determine the flow regime of the fluid inside the pipe, first, the following parameters are calculated:

= ∙ = = 316 ∙ . = 0.0009252 ∙ . = 0.10 ∙ . = 0.5 ∙ .

The parameters are then compared with the limits mentioned below to identify the flow patterns involved:

Flow Patterns Limits

Segregated λL< 0.01 and NFR< L1 or λL≥ 0.01 and NFR< L2 Transition λL≥ 0.01 and L2≤ NFR≤ L3 Intermittent 0.01 ≤ λL< 0.4 and L3< NFR≤ L1 or λL≥ 0.4 and L3< NFR≤ L4 Distributed λL< 0.4 and NFR≥ L1 or λL≥ 0.4 and NFR> L4

Table 1: Horizontal Flow Regime Limits

3.2.3.2. Elevation Pressure Drop

As mentioned previously, to calculate for pressure drop caused by elevation, the liquid holdup must be calculated.

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( )=

∙

Where:

ψ = correction factor to account for inclination HL(0) = liquid holdup for horizontal pipe

Flow Regime a b c

Segregated 0.98 0.4846 0.0868

Intermittent 0.845 0.5351 0.0173

Distributed 1.065 0.5824 0.0609

Table 2: Constants for Liquid Holdup Calculation

The inclination correction factor, ψ is calculated from:

= 1 + [sin(1.8 ∙ ) − 0.333 ∙ sin (1.8 ∙ )] = (1 − ) ∙ ln ( ′ ∙ ∙ ∙ ) Where: θ = angle of inclination Flow Regime d' e f g Segregated uphill 0.011 -3.768 3.539 -1.614 Intermittent uphill 2.96 0.305 -0.4473 0.0978

Distributed uphill No correction necessary

Downhill (all flow patterns)

4.70 -0.3692 0.1244 -0.5056

However, when a transition flow patterns is involved, its liquid holdup is calculated via interpolation of the liquid holdups of segregated and intermittent flow:

( ) = −

− × ( ) + 1 −

−

− × ( )

Once the liquid holdup is obtained, the elevation pressure drop can then be calculated via:

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= ∙ ∙ + ∙ (1 − )

3.2.3.3. Frictional Pressure Drop

Equation used to calculate the frictional pressure drop:

= ∙ ∙ 2 ∙ ∙ where: = ∙ + ∙ and = ×

The friction factor fn, is obtained from the Moody diagram or the given equation, using

the Reynolds number of the flow, calculated via:

, =

∙ ∙

where:

= ∙ + ∙

The correction factor, s, applied to the normal friction factor to obtain the two-phase friction factor can be obtained from:

= ln ( ) −0.0523 + 3.182 ∙ ln( ) − 0.8725 ∙ [ln ( )] + 0.01853 ∙ [ln ( )] = ln(2.2 ∙ − 1.2), for 1 < x < 1.2 where: = (∅)

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31 3.2.3.4. Acceleration Pressure Drop

The pressure drop due acceleration of the fluids is very small unless for high velocity flows though it can be included in the calculation for better accuracy. The governing equation is:

= ∙ ∙

∙ ×

The acceleration term is defined as:

= ∙ ∙

∙

Therefore, the total pressure loss is represented as:

=

+ 1 −

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3.3. HYDRATES

Hydrate formation is a major hindrance in the transportation of oil and gas through offshore pipelines. The multiphase mixture consisting of oil, gas and water produced at the wellhead will normally be of high pressure and temperatures. The mixture, as it is flowing through the offshore pipelines cools down gradually and at certain points sometimes even rapid cooling occurs. With this, the mixture enters the hydrate formation region which will eventually lead to flow restriction or even blockage.

Gas hydrates or better known as clathrate hydrates are crystalline water-based solids which physically resemble ice and are formed when small non-polar molecules, typically gases are trapped within "cages" of water molecules which are hydrogen bonded. Clathrates and ice share rather similar properties with the main difference being the formation of the clathrates occurring at temperatures above the freezing point of water at elevated pressure conditions. Water molecules through hydrogen bonding can form a lattice-like structure which becomes stable when filled with suitable size gas molecules known as ‘hydrate former’. Some of the common hydrate formers include natural gases such as, methane, ethane, propane, isobutene, nitrogen, hydrogen sulphide and carbon dioxide. These gas hydrates can be formed at temperature well above the triple point of water (Sloan, 1998).

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As mentioned previously, conditions favouring gas hydrates formation are low temperatures and high pressures. As temperature falls, the rapid movement and vibrations of liquids and gas tend to slow down and since this vibration causes fluids to flow and take the shape of the container. This removal of thermal energy allows most fluids to freeze into solid crystalline structure and at higher pressures warmer fluids can freeze due to the tendency of the pressure to ‘push’ molecules into the crystalline structure (Masoudi, Tohidi, Anderson, Burgass, & Yang, 2004).

Other phenomena that induce formation of hydrates are such as turbulence, nucleation sites and free-water. Hydrate formation is favoured in high fluid flow velocity regions. Therefore, choke valves are particularly susceptible to hydrate formation. When natural gas undergoes compression through a valve, there is usually a significant temperature drop in accordance with the Joule-Thomson effect leading to hydrate formation and the velocity is also increased when it flows through the narrowing in the valve. Nucleation site is also favoured since it is a point where phase transition occurs from a fluid phase to solid phase. These nucleation sites generally include imperfections along the pipeline such as a weld spot or a fitting.

In order to prevent the formation of hydrates and the problems that may follow in subsea production systems, several methods can be used. Firstly, the freezing point of the water phase or the formation conditions of the hydrates can be altered by injecting large volumes of chemicals such as methanol. Small volumes of additives can also be injected into the pipeline to inhibit the formation of bigger hydrate plugs occurring through agglomeration of hydrate crystals. Finally, the pipeline can be insulated or under demanding conditions, even heated to maintain the flowing mixture outside the hydrate formation region. In the petroleum industry, methods have been developed to determine the volume of freezing point depressant required, the volume of additive required, and the insulation and degree of heating required (Masoudi, Tohidi, Anderson, Burgass, & Yang, 2004).

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3.4. CO

2

CORROSION

CO2 corrosion or sweet corrosion as it is widely called is recognized as a major

problem in production and transportation of petroleum over the years. It is a major source of concern in the application of carbon steel in the industry. This result from the fact that an aqueous phase is normally associated with the oil and gas production systems which promote an electrochemical reaction between carbon steel and the contacting aqueous phase. CO2 is very soluble in water but has a greater solubility in hydrocarbon fluids produced in the oil and gas production systems. Although it does not cause the catastrophic failure mode of cracking associated with H2S or sour

corrosion, its presence can nevertheless result in very high corrosion rate particularly localized corrosion.

3.4.1. Mechanism of CO2 Corrosion

Dry carbon dioxide gas by itself is not corrosive. It has to be dissolved in an aqueous phase through which it can promote an electrochemical reaction between steel and the aqueous phase. Various mechanisms have been proposed for the sweet corrosion process, all of which involve either carbonic acid, H2CO3 or the bicarbonate

ion, HCO3ˉ formed on dissolution of carbon dioxide in water. The basic reaction for

sweet corrosion occurs as follows: CO2(g)+ H2O →CO2(aq)

CO2(aq) + H2O ↔ H2CO3 ↔ H+ + HCO3ˉ

The corrosion mechanism: H2CO3 + e-→ H + HCO3ˉ 2H → H2 Reaction of steel: Fe → Fe2+ + 2e -Overall reaction: CO2 + H2O + Fe → FeCO3 + H2

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The significance of FeCO3 formation is that it drops out of the solution as a

precipitate due to its limited solubility. This precipitate has the potential to form passive films or scale on the surfaces of carbon steel which hinders further corrosion.

Figure 15: Simplified schematic representation of CO2 corrosion mechanism

3.4.2. Parameters Affecting CO2 Corrosion

There are several parameters that affect the rate at which the corrosion due to carbon dioxide occurs. Some of the main parameters which have a significant effect on the corrosion rate include:

a) CO2 Partial Pressure

CO2 corrosion occurs when the steel surface of the pipe reacts with carbonic

acid formed via the solution of CO2 in an aqueous phase. The CO2aqueous

phase concentration is directly related to the partial pressure of CO2 in the gas

in equilibrium with the aqueous phase. Thus, in CO2 corrosion, estimates of

corrosion rate are primarily based on the partial pressure of CO2 in the gas

phase.

b) Temperature

The rate of corrosion of carbon steel via aqueous CO2increases with

temperature and this leads to the formation of iron carbonate as a reaction product. However, at significantly high temperatures, around 80°C, the solubility iron carbonate falls and it begins to precipitate and form a protective

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FeCO3 film. This scale as it is commonly referred to hinder further corrosion

of the pipe wall.

c) pH

The pH value is an important parameter in corrosion of carbon steel. The pH affects both the electrochemical reactions and the precipitation of corrosion products. Under certain production conditions the associated aqueous phase can contain salts which will buffer the pH. This tends to decrease the corrosion rate and lead to conditions under which the precipitation of protective FeCO3 film layers is more likely.

d) Scaling

Scaling occurs when the product of the sweet corrosion, FeCO3 is not able to dissolve any further as it has reached saturated levels. This leads to the precipitation of the FeCO3 and this precipitate builds up and forms a layer of scale on the pipe wall. This scale hinders corrosion by blocking the wall from further attack by the ions. However, at high flow velocities, the scale begins to break away from wall and corrosion progresses (de Waard, Lotz, & Dugstad, Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model, 1995).

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CHAPTER 4: METHODOLOGY

This chapter discusses the methods and procedures taken in carrying out this project. In this chapter, the author also introduces the tools used in this project and provides descriptions on the functionality of the mentioned tools. Finally, a Gantt chart highlighting the progress of the project is given at the end of the chapter.

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4.1. PROJECT FLOW

The flow chart below represents the general procedures taken in carrying out this project:

Analyse and discuss upon the collected results Gather and compile results of all performed simulations

Perform further simulation for sensitivity analyses and optimisation of results Collect results from simulation

Perform preliminary simulation in PIPESIM Build model based on data on hand

Gather and compile pipeline design and operating data Selection of an appropriate case study

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4.2. CASE STUDY

The selected case study is a design for a20 in. 30 km pipeline connecting the F14 gas field and the F23 production facilities offshore of Sarawak. The pipeline is part of an overall development project of the mentioned gas field and therefore is fairly recent. The approximate location of the pipeline is shown in the figure below.

Figure 17: Sarawak offshore gas fields

4.2.1. Design and Operating Data

PARAMETER UNIT VALUE

Operating Pressure bara 100

Design Pressure bara 153

Operating Temperature °C 86

Design Temperature °C Max: 96, Min: -20

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DESIGN PARAMETER UNIT VALUE

Nominal Pipe Size in 20

Outer Diameter mm 508 Inner Diameter mm 476 Wall Thickness mm 16 Absolute Roughness mm 0.045 Approximate Length km 30 Concrete Coating mm 60

Table 4: Pipeline design data

DESIGN PARAMETER UNIT VALUE

Nominal Pipe Size in 20

Outer Diameter mm 508 Inner Diameter mm 457.2 Wall Thickness mm 25.4 Absolute Roughness mm 0.045 Height Profile Dry Zone m 12 Splash Zone 12.2 Submerged Zone F14 101.1 F23 87.7 External Corrosion Coating

Dry Zone (GFE)

mm

0.5

Splash Zone (EPDM) 12.7

Submerged Zone

(3LPP) 10

Table 5: Riser design data

Tables 3, 4 and 5 show the operating and design conditions, design data for the pipeline and the design data for riser respectively. The concrete coating on the pipeline is necessary for ensuring the stability on the pipeline on the sea floor whereas the coatings on the riser are to prevent the riser from corroding externally.

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4.2.2. Environmental Data

Environmental data input is required for PIPESIM simulations. Therefore, recent data has been collected at the time of the project from meteorological and oceanographic surveys as shown in the following page.

PARAMETER UNIT VALUE

Average Water Depth

F14

m 105.3

F23 91.9

Average Air Temperature °C 27.2

Seawater Surface Temperature °C 27.2

Seabed Temperature °C 19.1

Underwater Current Velocity m/s 1.31

Air Velocity m/s 43.4

Table 6: Environmental data

Figure 18: Seabed elevation profile

4.2.3. Simulation Parameters

ITEM PARAMETER

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Thermodynamic Package Multiphase

Equation of State Peng-Robinson

Table 7: Simulation parameters used

To perform a simulation in the PIPESIM environment, a model of the pipeline system has to be built first. It is built using the pipeline and riser and the environmental input data provided above. It then requires simulation parameter which will provide the basis for the PIPESIM engine to simulate the model. The table above shows a summary of the parameters used to run this PIPESIM simulation.

The fluid model is required to identify the properties of the fluid being simulated. For general purposes, the black oil model is can be used. This model uses bulk properties such as watercut, specific gravity, API gravity and gas-to-oil ratio to simulate the flow. The results generated using the black oil can be less accurate due to the fact that these bulk properties are based on averages. For more accurate results, compositional models can be used where the user inputs the molar fraction of all the species found in the fluid being modelled. PIPESIM’s compositional modelling engine can also generate and model pseudo-components which are used for heavy petroleum fractions.

To generate the properties of the species in the composition, the software uses a thermodynamic package which is a form of database and calculation engine for the thermodynamic properties. The thermodynamic package used in this simulation is the MULTIFLASH package developed by Infochem. MULTIFLASH is able to carry out multiphase equilibrium calculations using the selected equation of state to model the phase envelope, PVT behaviour, entropy, enthalpy and internal energy of the fluid mixture. It is also required for modelling hydrate formations.

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4.3. TOOLS & SOFTWARE

In BGSB, the primary simulation software available for pipeline flow assurance study is the PIPESIM software developed by Schlumberger. PIPESIM is a very applicable tool capable of modelling single phase and multiphase flows from the reservoir through the production facilities to the final delivery point. In facilities modelling, PIPESIM can also be used to design systems by varying key system parameters, thus enabling optimal pipeline and equipment sizes to be determined.

Some of the typical applications of PIPESIM include:  Multiphase flow in flowline and pipelines.

 Point by point generation of pressure and temperature profiles.  Transportation pipeline design and flow rate calculation.

 Flowline & equipment performance modelling (system analysis).  Hydrate modelling.

 Sweet corrosion & erosional corrosion modelling.  Wax deposition modelling.

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4.4. GANTT CHART

No. Activities Category Week

1 2 3 4 5 6 7 8 9 10 11 12 13 14

1 Determine problem statement and objectives.

Planning

2 Identifying a proper case study.

3 Research on literature related to project.

Research

4 Determine methods to test case study.

5 Prepare model and run simulations. Execution

6 Collect and analyse the generated results. Results

7 Prepare report.

Reporting

8 Conduct presentation on project.

9 Submission of SIP report.

10 Submission of logbook summary.

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CHAPTER 5: RESULTS &

DISCUSSION

This chapter compiles the collected data from the simulations conducted and the subsequent analysis of the data. This followed by the findings regarding the project based on the engineering and technical review done on the second chapter.

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5.1. PIPESIM MODEL

The above diagram shows the basic model built using the pipeline and riser data provided. This model is then subjected to various inputs based on the parameter being studied and simulated to obtain the desired data.

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5.2. PRESSURE VARIATION AMONG FLOW CORRELATION

The following simulation was carried out to compare between the different pressure drops arising from the use of different flow correlations. This study is generally done to observe the accuracy of the flow correlations being studied. The inputs used for this simulation are as follows:

 Inlet pressure : 100 bara  Inlet temperature : 86 °C

 Gas flowrate : 200 MMSCFD

 Nominal Pipe Diameter : 20 inch

There are two outputs generated of this simulation, which are for the comparison of horizontal flow correlations followed by the comparison of vertical flow correlations. The following is the output for the horizontal flow correlations comparison:

Graph 1: Horizontal flow correlation comparison

The graph shows the pressure drop variation between the Lockhart & Martinelli, Beggs & Brill Original and the Beggs & Brill Revised horizontal flow correlations. Note the pressure drop variation only happens along the main line and not at the edges. This is because the correlations being varied are for horizontal flow and not vertical flow as in with the riser sections at the edges. It can be also seen that the pressure drops for the Lockhart & Martinelli and Beggs & Brill Original correlations are rather similar whereas for the Beggs & Brill Revised correlation it is much steeper. This is mainly due to the fact that the Lockhart & Martinelli and Beggs

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& Brill Original were developed without taking pipe surface roughness into consideration. When the Beggs & Brill correlation was originally formulated, it only considered for smooth pipe flow with an absolute roughness of 0.0015 mm. It was later on revised and formulated into the Beggs & Brill Revised correlation which has a provision for surface roughness and therefore a carbon steel pipe with an absolute roughness of 0.045 mm exhibits a larger pressure drop compared to the other two.

Graph 2: Vertical flow correlation comparison

This graph shows the pressure drop variation between the Hagedorn & Brown, Beggs & Brill Original and the Beggs & Brill Revised vertical flow correlations. The variation cannot be seen clearly here because it only occurs in sections involving vertical flow, in this case the risers. Therefore, zooming in towards the riser sections, the different pressure gradients are more visible.

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Graph 4: Vertical flow correlation comparison - Riser F23

These two graphs also highlight the effect of the surface roughness on the overall pressure drop. It is also observed that the pressure gradients of both the original and revised Beggs & Brill overlap. This is due to the liquid holdup calculation which is similar for both and the elevation pressure drop contributed by it.

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5.3. PIPELINE SIZE OPTIMISATION

This study is performed to obtain an optimum pipe size or diameter for the main flowline connecting the F14 and F23 risers. The main factors considered for sizing a pipeline are the pressure requirements, the fluid flow velocity and the pipeline design pressure. This is a sensitivity study where fluid flow is simulated against the various pipe sizes available and compared against one another. The inputs used in this simulation are:

 Nominal Pipe Diameter : - 20 inch - 18 inch - 16 inch - 14 inch - 12 inch - 10 inch

The pressure drop profile obtained for the current simulation with the given pipe sizes are as follows:

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Based on the graph, it is observed that the light blue, red and green lines representing the 10 inch, 12 inch and 14 inch pipes are cut off before travelling the total pipeline distance of 30 km. This shows clearly that an inlet pressure of 100 bara is insufficient to deliver the required flowrate of 200 MMSCFD of gas across the pipeline at mentioned diameters.

The input of the simulation is altered slightly with the outlet pressure being fixed now at 92 bara which would be the required topside pressure. The output generated is:

Graph 6: Pressure drop for various pipe sizes, Outlet = 92 bara

From this graph, it can be seen that the required inlet pressures for the 10 inch pipe and the 12 inch pipe are 225 bara and 160 bara respectively. However, these two pressures are higher than the given design pressure for the pipeline, thus cannot be implemented. Therefore, this leads to the 14 inch pipe to be the optimum size with an inlet pressure of 135 bara.

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Graph 7: Fluid velocity for various pipe sizes, Outlet = 92 bara

Another graph is plotted to observe the variations in the velocity of the fluid flowing in the pipes of differing sizes. The reason behind this being the possibility of erosion occurring at velocities higher than 20 m/s for a gas flowline. From the graph, it can be seen that the maximum velocity exhibited is at an excess of 10 m/s for the 10 inch pipe which is still within limits. Therefore, the initial optimum pipe size selection of 14 inch is still maintained for its required inlet pressure is within the design pressure and the fluid velocity is within the erosional velocity limit.

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5.4. HYDRATE CONTROL

Hydrates as mentioned in the previous chapters, pose a serious threat for gas pipelines operating in low temperatures. Although operating in a tropical region, the pipeline studied here still faces the risk as minimum sea water temperatures can drop up 19°C. This study is done to identify the possibility of hydrates forming in the pipeline and providing sufficient control if necessary. This simulation uses the following inputs:

 Nominal Pipe Diameter : 20 inch

Graph 8: Phase envelope plot

The graph above shows the phase envelope plot which is specific to the composition of the gas used. The red and green lines on the phase envelope plot are the hydrate curves which represent the phase boundary to the hydrate formation region. The region towards the left of the green line is the stable hydrate region where the formation of hydrates is inevitable and the region between the red and green lines is the meta-stable region where hydrates form and dissolve spontaneously. To prevent hydrate formation, the operating conditions must be in the region towards the right of the red hydrate line.

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Graph 9: Phase envelope plot - operation line

This graph shows the same phase envelope plot but with the added operation line which traces pressure and temperature operating conditions along the pipeline. It can be clearly seen that the operation line intersects the first hydrate curve and enters the meta-stable region. This shows that along the pipeline, conditions exist for the formation of hydrate crystals. To avoid this, the operation line needs to be shifted to the right towards temperatures higher than 20 °C. This can be done by applying insulation to the pipeline to prevent heat loss and subsequent temperature drop.

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Graph 11: Phase envelope plot - 10 mm insulation

By applying an insulation of 3 Layer Poly-Propylene (3LPP) of 5 mm thickness, it can be seen that the operation line is slightly nudged towards higher temperatures but still falls in the meta-stable region. Increasing the 3LPP insulation thickness to 10 mm effectively moves the operation line completely out of the meta-stable region and thus blocking the hydrate formation completely.

Therefore, an insulation of 3LPP of 10 mm thickness is required input in the overall design of the pipeline to prevent excess heat lose and temperature drop which will lead to hydrate formation.

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5.5. CORROSION STUDY

Another major problem occurring in pipelines is corrosion, not just external corrosion due to seawater but also in the internals. Two main forms of corrosion are the CO2 or sweet corrosion and the H2S or sour corrosion depending on the type of

service. This pipeline is a sweet service pipeline carrying natural gas mixed predominantly with CO2. To predict the corrosion rate along the pipeline in PIPESIM,

the following inputs were used:

 Nominal Pipe Diameter : 20 inch  Amount of CO2 : 1.8811 mol%

 Amount of H2O : 19.938 mol%

Graph 12: CO2 corrosion rate

The graph above shows the corrosion rate predicted by the deWaard-Milliam model along the entire length of the pipeline. The corrosion rate values fluctuate due to the many factors involved in the calculation but mainly varying pressures, densities and temperatures, however it averages at approximately 3.1 mm/year. This corrosion rate is still considered high and control methods have to be implemented to reduce it such as injection of corrosion inhibitors into the gas stream, dehydration and CO2

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The composition of the gas stream is now altered slightly to simulate a dehydrated and CO2 removed gas. The corrosion rate predicated is as follows:

Graph 13: CO2 corrosion rate - adjusted composition

It is observed now that the corrosion rate is significantly lower compared to the previous with an average rate of around 1.3 mm/year. By removing water an CO2 from

the gas stream, the concentration of the HCO3- ion which attacks metal surface of the

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CHAPTER 6: CONCLUSION &

RECOMMENDATION

With this chapter, the author finally draws a conclusion on the project based on the objectives laid out and the reported findings. The author also suggested a few recommendations to further improve upon the findings of the project for better understanding.

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UTP Student Industrial Project (SIP) is an effective medium designed to allow engineering students to make use of their knowledge obtained in the classroom and during the initial training and apply them in real world project to gain vital insight and experiences. With the exposure during the 14-weeks of project undertaking period, the author was able to fulfil the objectives set for the SIP, which are:

a) Integrate theoretical knowledge in the industry.

b) Analyse complex engineering/technical projects or problems.

c) Evaluate and propose solutions for given complex project or problems. d) Communicate effectively on complex engineering/technical activities.

It can be also brought to conclusion that the objectives and the corresponding scope of study for the undertaken project have been also fulfilled. The objectives laid out for the project were:

a) To identify the important aspects of flow assurance.

Some of the major aspects of flow assurance studied were the multiphase flow conditions, natural gas hydrates and sweet corrosion.

b) To model steady state fluid flow conditions with the aid of computer software simulations using data obtained from the field.

A case study on a proposed pipeline project was selected and its design data was used to build a model in the PIPESIM and simulated under steady state conditions.

c) To identify and analyse problem found in the end result of the simulations.

Simulation was performed in PIPESIM and the output generated was analysed to identify the problem associated with it.

d) To suggest solutions designed to nullify the problems.

Several control methods were proposed to overcome the problems identified in the preliminary simulations.

e) To propose a design for an offshore pipeline based on the findings of the steady state flow simulations and the solutions implemented.

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The control methods were implemented into the model as design modifications to the pipeline and simulated to achieve the desired results.

This project could be improved upon further. Some of the recommendations for improving this project would include:

 a transient or dynamic study of fluid flow in the pipeline.

 further optimisation to the design of the pipeline such as in pipeline sizing using varying wall thicknesses.

 alternative control methods study and implementation to address the hydrate and corrosion problems.

 costing analysis of the overall pipeline and the suggested design modifications.

With these suggested recommendations and improvements, much accurate and in depth results can be achieved leading to a more efficient and sustainable design.

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REFERENCES

1. Bai, Y., & Bai, Q. (2005). Subsea Pipelines and Risers. Elsevier Science Ltd.

2. Beggs, D. H., & Brill, J. P. (1973). A Study of Two-Phase Flow in Inclined

Pipes. Trans. AIME, 255, p. 607.

3. Brill, J. P., & Beggs, H. D. (1991). Two-phase flow in pipes (6th ed.).

4. Brill, J. P., & Mukherjee, H. (1999). Multiphase Flow in Wells, Monograph

Volume 17. SPE, Henry L.Doherty Series.

5. Date, A. W. (2005). Introduction to Computational Fluid Dynamics. New York: Cambridge University Press.

6. de Waard, C., & Milliams, D. E. (1975). Carbonic Acid Corrosion of Steel.

Corrosion .

7. de Waard, C., Lotz, U., & Dugstad, A. (1995). Influence of Liquid Flow Velocity on CO2 Corrosion: A Semi-Empirical Model. Corrosion .

8. Lyons, W. C. (1996). Standard Handbook Petroleum & Natural Gas

Engineering. Woburn: Butterworth-Heinemann.

9. Masoudi, R., Tohidi, B., Anderson, R., Burgass, R. W., & Yang, J. (2004). Experimental measurement and thermodynamic modelling of clathrate hydrate equilibria and salt solubility in aqueous ethylene glycol and electrolyte solutions. Fluid Phase Equilibria , 219 (2), 157-163.

UTP Student Industrial Project Report

STUDENT INDUSTRIAL PROJECT REPORT

JANUARY 2014 – APRIL 2014

MODELING AND SIMULATION OF STEADY STATE FLOW

ASSURANCE STUDY ON OFFSHORE PIPELINES USING

PIPESIM SOFTWARE

at

BERACHAH GROUP SDN. BHD.

by

MOHANA ROOPARN A/L KALAICHELVAN

15338

VERIFICATION STATEMENT

ACKNOWLEDGEMENT

TABLE OF CONTENTS

LIST OF TABLES

LIST OF FIGURES

LIST OF GRAPHS

CHAPTER 1: INTRODUCTION

1.1. PURPOSE OF STUDENT INDUSTRIAL PROJECT

1.2. OBJECTIVES OF STUDENT INDUSTRIAL PROJECT

1.3. TRAINING APPROACH

1.4. HOST COMPANY

CHAPTER 2: PROJECT

INTRODUCTION

2.1. PROBLEM STATEMENT

2.2. OBJECTIVES

2.3. SCOPE OF STUDY

2.4. RELEVANCY OF THE PROJECT

CHAPTER 3: LITERATURE

REVIEW

3.1. MULTIPHASE FLOW

3.2. FLOW CORRELATIONS

3.3. HYDRATES

3.4. CO

CORROSION

CHAPTER 4: METHODOLOGY

4.1. PROJECT FLOW

4.2. CASE STUDY

4.3. TOOLS & SOFTWARE

4.4. GANTT CHART

CHAPTER 5: RESULTS &

DISCUSSION

5.1. PIPESIM MODEL

5.2. PRESSURE VARIATION AMONG FLOW CORRELATION

5.3. PIPELINE SIZE OPTIMISATION

5.4. HYDRATE CONTROL

5.5. CORROSION STUDY

CHAPTER 6: CONCLUSION &

RECOMMENDATION

REFERENCES