FUNDAMENTALS OF FPSOs

MODULE 1

Introduction to Offshore Production and FPSOs

AUTHOR

John Preedy PhD

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CONTENTS

Page No.

INTRODUCTION TO THE COURSE 4

Welcome to the Course . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

COURSE STRUCTURE 5

STUDYING THE COURSE 8

LEARNING OUTCOMES 9

1. INTRODUCTION TO OFFSHORE PRODUCTION 10

1.1 Introduction to Offshore Production Systems . . . . . . . . . . . . . . . . . . . . . . . 10

1.2 Subsea Production Systems (SPS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

1.3 Floating Production Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

2. EXPLORATION, RESERVOIR ANALYSIS AND MARINE DRILLING 20

2.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2.2 Origin of Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2.2.1 Oil Traps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

2.3 Exploration Phase Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.4 Seismic Surveys . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.4.1 Marine Seismic Survey Methods . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.5 Reservoir Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

2.6 Introduction to Offshore Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

2.6.1 Mobile Drilling Rigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

2.6.2 Drilling the Well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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3. BASIC PRINCIPLES OF OFFSHORE PRODUCTION 34

3.1 Field Location/Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

3.1.1 Reservoir Factors Pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

3.1.2 Reservoir Factors Chemistry. . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.1.3 Reservoir Factors Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . 37

4. THE FUNDAMENTALS OF SUBSEA ENGINEERING 38

4.1 Subsea Engineering Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

4.1.1 Wellhead Functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

4.1.2 Xmas Tree Functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

4.1.3 Template Functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

4.1.4 Manifold Functions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

5. FLOATING PRODUCTION SYSTEMS 48

5.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

5.2 Floating Production, Storage and Of oading Monohull Vessels . . . . . . . . . . . 49

5.2.1 FPV and FPSO De nitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

5.2.2 FPSO Total System Building Blocks . . . . . . . . . . . . . . . . . . . . . . . . 50

5.3 Worldwide Operating Floaters and Current Development . . . . . . . . . . . . . . . 53

5.3.1 Regional Differences . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

5.3.2 Advantages of Floater Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

6. FPSO MARKET OVERVIEW 56

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APPENDIX 1 59

Table 1 Worldwide Distribution of FPSO Vessels . . . . . . . . . . . . . . . . . . . . . . . . . 59

APPENDIX 2 62

Web Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Copyright IIR Limited 2010. All rights reserved. These materials are protected by international copyright laws. This manual is only for the use of course participants

undertaking this course. Unauthorised use, distribution, reproduction or copying of these materials either in whole or in part, in any shape or form or by any means electronically, mechanically, by photocopying, recording or otherwise, including, without limitation, using the manual for any commercial purpose whatsoever is strictly forbidden without prior written consent of IIR Limited.

This manual shall not affect the legal relationship or liability of IIR Limited with, or to, any third-party and neither shall such third-party be entitled to rely upon it. All information and content in this manual is provided on an as is basis and you assume total responsibility and risk for your use of such information and content. IIR Limited shall have no liability for technical errors, editorial errors or omissions in this manual; nor any damage including but not limited to direct, punitive, incidental or consequential damages resulting from or arising out of its use.

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INTRODUCTION TO THE COURSE

Welcome to the course

Across the world, oil and gas production faces problems such as elds in ever-deeper water depths and very small reserves which are uneconomic to exploit by conventional xed platform approaches. Field size and location, water depth, ocean currents and harsh weather may all in uence the decision of which type of production installation to use. A xed installation may not be technically feasible in particularly challenging locations where a oating unit would offer the best solution.

The offshore oil and gas industry has been using oating production, storage and of oading systems, or FPSOs, since the mid 1970s. These facilities can offer signi cant advantages over xed production platforms particularly in remote deepwater locations or where export pipelines are dif cult to install or uneconomic to run. They can also be oated off at the end of a elds productive life and re-used elsewhere, which has economic bene ts, particularly for marginal elds where the production facilities may only be required for a few years.

This distance learning course examines the key components of FPSO technology and deployment, including FPSO design, systems development, subsea engineering, operations and economics for the development and management of FPSOs.

Offering the exibility of studying in your own time and location, this programme will bene t a broad range of people. If you are starting in a new role, this course will provide a comprehensive introduction to FPSO design and function. For those who work in a different part of the oil and gas industry it will provide a deeper understanding of the part played by FPSOs. Professionals in associated industries such as consultants, lawyers, bankers and accountants will gain an insight into the complexities of this increasingly crucial method of oil and gas production.

Whatever your motivation, the unique blend of downloadable and multimedia learning materials, expert tutorial support and peer interaction via a dedicated online forum will ensure a thorough, accurate and up-to-date knowledge of FPSO technology fundamentals, wherever you are in the world.

Welcome to Module 1.

John E. Preedy PhD

Course Director

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COURSE STRUCTURE

The course is divided into six modules. Modules will be made available for download at two-week intervals. Modules will cover the following:

Module 1

Introduction to Offshore Production and FPSOs

Background to offshore production systems

Global oil and gas reserves and elds

Introduction to offshore exploration and drilling

Fundamentals of oil and gas production

Oil and gas types

Field size and location

Flow assurance

Reservoir depletion plan

Subsea eld development equipment (subsea engineering)

Wellheads and Xmas trees

Manifolds and seabed structures

Pipelines and owlines

Rises

Subsea production control systems

Floating production hosts

FPSOs

Semi-submersibles

Spars

Tension Leg Platforms (TLPs)

FPSO markets overview

Module 2

Field and FPSO Development Decisions and Project Management

Government licence award and approvals for a eld development plan

Project development strategy and planning

Project management procedures

Contracting options

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Field project options development and selection procedures

FPSO considerations

New build vs. lease

New build vs. tanker conversion

Turret con gurations or spread moored

Storage capacity

Metocean (meteorological and oceanographic) parameters

Field development contracts

Module 3

FPSO Design

Hull hydrodynamics and model testing

Hull new construction or tanker conversion

Accommodation and helideck

Topsides plant layout

Mooring systems

Type: spread or turret moored

Components

Design

Installation

Turrets

External turrets

Internal turrets

Fluid swivel

Risers

Flexible dynamic risers

Hybrid riser towers

Steel catenary risers

Module 4

FPSO Production and Operations

Topsides process requirements

Main topsides functions

Oil separation

Gas compression

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Produced water treatment

Injection water treatment

Other topsides functions

Power generation

Topsides process utilities (e.g. heating and cooling medium, chemicals for injection and ares systems)

FPSO vessel cranes

Oil storage

Oil export

Trading or shuttle tankers

Tandem of oading or distant of oading station

Oil transfer metering

Gas export or re-injection

Module 5

Regulations, Safety and Environmental Issues

Regulatory requirements for FPSOs

Coastal states requirements and oil and gas processing host

Classi cation societies

Flag state requirements

Codes and regulations

Safety

Safety case approach (self goal setting by risk assessment process)

Rule-based safety approaches

Veri cation and audit

Safety main FPSO risks

Fire and blast

Damage by other vessels and helicopters

Safety accident examples

Environmental issues

Flared gas

Oil spills and leaks

Hydrocarbon emissions

FPSO eld environmental impact assessment

Environmental incident examples

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Module 6

Contractual and Economic Considerations, Field Development Case Studies

Steps in a eld development

Field partners

Capital costs (CAPEX)

Operational costs (OPEX)

Evaluating and managing risks

Examples of elds developed with FPSOs

Small North Sea elds (shallow water)

Large deepwater elds in West Africa

Large deepwater elds in Brazil

Fields in S.E. Asia and Australia

Other global elds

STUDYING THE COURSE

We all have our preferred learning styles and tackle reading and learning activities in our own unique way. As the author and tutor for this course it is my responsibility to keep you interested in the content and to try and help you remain motivated to learn. This will be achieved in part by the text, which will take you through a thorough introduction to the oil and gas industry, but you also have responsibility yourself. Your responsibility is to set aside suf cient time and a place where you can undertake your study of the modules, be it at home, whilst you are travelling, or during quiet periods at work. For optimal personal development though, you need to fully engage in the learning process part of this is to apply your responsibility to work diligently through the materials, thinking about what you read, re ecting on it, and no doubt at times challenging it.

We aim to thoroughly cover the subjects addressed in the course, but you may at times wish to consult other sources on the internet, or maybe in a library, in order to delve deeper into an issue that particularly interests you. Your responsibility for your learning also extends to making use of the online course forum. Here you can post a question if there is something you dont understand, you can read what others are asking or saying, you can add your comments in order to allow others to bene t from particular knowledge you have, or you can share your own experiences of a particular issue. However the course forum is what you make it. If you just enter it to read other peoples posts and do not contribute yourself, it will be a lonely place. Please start by checking out the forum and introducing yourself. You could post your name, where you are, who you work for and the reason you are interested in the subject of this course. Have a go and try it out!

I do hope you have taken the above onboard. The worst thing you could do with this course is to just read the content of each module, learn it parrot fashion and then move on, without further thought or discussion with others.

A large degree of thought has gone into the chronology of the modules and their sections the running order. The sections in these modules are akin to the chapters in a book or a story, in that they build upon one another. We would respectfully encourage you to read them in order, to put you in the strongest position to address and absorb the key messages. Naturally you will have your preferred pace and you may choose to dip in and out of the text, which is your prerogative.

As a nal note, a great idea that suits many people when studying by distance learning is to consider writing their own brief summary of the key learning points being taken away at the end of each major section which is sometimes called an Elevator Pitch. Where does the term Elevator Pitch come from? Imagine you are travelling a few oors in an elevator with your boss and he/she asked you what did you learn from that last chapter of your course I saw you reading? Youve got the time the elevator travels those few

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oors to succinctly tell them the main points you drew from the text. Have a go at drafting one. Remember that whatever you produce will probably vary from someone else this is not a problem as you will probably have a different priority or focus on what is important to you in the section. Additionally, the disciplines of summarising and prioritising are very important for people to practice.

Enough of the preparation and guidance for this course, lets turn our focus to the rst module.

LEARNING OUTCOMES

On completing this module you will have an understanding of:

The background factors that led to the development of oating production systems.

How and where oil and gas can form in the Earth and how it is located.

The importance of the geological information to predict how the oil will ow.

How a well is drilled.

The factors that will make oil ow from the source to the production facility.

The effect of weather, sea conditions, economic and political factors on the development of a oating production system.

You will also have an overview of:

The elements and equipment of subsea engineering.

The different oating production systems.

A global view of the use of oating production systems and the global FPSO market.

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1. INTRODUCTION TO OFFSHORE PRODUCTION

1.1 Introduction to Offshore Production Systems

The exploration for offshore oil and gas resources began in the late 1800s. In 1896, an offshore well was drilled off the coast of California. These were drilled from piers generally 100 to 150 m long, some producing from as deep as 200 m of water. The 1938 discovery of the Creole eld 2 km from the Louisiana coast in the Gulf of Mexico marked the rst venture into open, unprotected waters. The discovery well was drilled from a 20 by 90 m drilling platform secured to a foundation of timber piles set in 4 m of water.

In the search for oil and gas in offshore areas, the oil industry has continually extended and improved drilling and production technology. The early schemes utilising xed structures tied to the sea bed evolved into the use of large steel jacket reinforced concrete production platforms standing in more than 300 m water depth. The driving necessities of cost reduction and the need to develop elds at ever increasing water depths has led to other concepts including:

Floating Production Vessels (FPV)

Tension Leg Platforms (TLP)

Floating Storage Units (FSU)

Floating Production, Storage and Of oading Vessels (FPSO)

SPARS and DDCS vessels

Over the last decade offshore oil production continued to increase in all global areas with oil and gas amounting to some 66% of the worlds energy needs. While the onshore areas of the world provide the largest amounts of oil and gas, the offshore industry is increasingly important and by 2015 offshore oil and gas will account for 40% of the total production. Oil production is currently some 85 million barrels per day. This will peak sometime between 2015 and 2030, but it is expected to hold at its peak for many years after (but with new mixes of hydrocarbon sources).

The worldwide offshore expenditure is massive. Background information from Douglas-Westwood Ltd is shown in Figures 1.1(a)(d).

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Figure 1.1(a)

Global Energy Requirements (Oil at about 85 Million Barrels/Day) with Oil and Gas Accounting for Some 66%.

Figure 1.1(b)

Regional Oil and Gas Reserves.

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Figure 1.1(c)

Is Peak Oil on the Way?

Figure 1.1(d)

The Importance of Offshore Oil Production with some 40% of all Oil and Gas coming from Offshore Activities by 2015.

Source Douglas-Westwood Ltd.

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Directed Learning: Visit the Douglas-Westwood Ltd web site (www.dw-1.com). Enter Downloads by providing your email address and nd a range of their most recent Conference Presentations. This will update and extend the information as in Figure 1.1

From this new information prepare your thoughts on the following:

Developments and expenditures in your geographical location.i.

Your thoughts on when and how oil will peak and eventually run out.ii.

The costs of oil and gas in say 1, 3, 10 years time.iii.

Once you have done this, publish your ndings and reasons on the module forum on the Learning Management System so we can share your thoughts and read what other participants say.

In the early stages of offshore oil and gas exploration and production, both in the Gulf of Mexico and the North Sea, xed platforms dominated production development concepts. The xed structure, either as a tubular steel jacket or reinforced concrete construction, provided the location for the topsides facilities including the drilling rig, processing equipment, controls and export systems. With the concrete structures additional oil storage is often available.

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1.2 Subsea Production Systems (SPS)

The rst subsea well was completed by Shell Oil in 1960 in the Gulf of Mexico. It came on stream in early January 1961, marking both the successful culmination of more than ve years intense research and development, and the beginning of an identi able subsea production industry.

During the rst decade of the 21st century the total number of subsea wells is estimated to be over 5,000 worldwide. Such subsea wells and the development of subsea production systems have been extensively used in full eld developments and as satellite wells or tie-backs to host platforms. These are illustrated in Figure 1.2.

Figure 1.2

Satellite Field Tied-Back to Host Platform with Central Manifold and Cluster of Wells.

Reservoir A accessed direct from the platform. Reservoir uids move up the production tubing, passing through the seabed to the platform wellhead deck. The well control valve pack (Xmas Tree) is in the dry.

Reservoir B is accessed via a subsea tie-back with the wells completed on the seabed, i.e. wet trees. The reservoir uids ow through the manifold, along the owlines and up the platform risers to the process deck.

Some of the subsea wells could be for water injection, where water is sent from the platform into the reservoir for pressure maintenance.

Source Azur Offshore Ltd.

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1.3 Floating Production Systems

There is a range of oating production systems. In the broadest sense such categorisation may include:

Semi-submersible Floating Production Vessels (FPV). With or without Storage.

Ship-based Floating Production, Storage and Of oading vessels (FPSO).

SPAR buoys.

Tension Leg Platforms (TLP).

Floating production facilities (semi-sub and monohull) have gained more and more acceptability over the past 35 years. These involve the extensive use of subsea production systems. Some of the key steps are noted below:

Argyll Field FPV (Hamilton Brothers) was the rst oater to be used in the UK sector of the North Sea. Converted Transworld drilling rig (without storage) and after the end of the eld life it was decommissioned. It was refurbished for use in the Far East.

The rst FPSO monohull concept was offshore Spain in 1976/7 by Shell, a converted tanker for the Castallon Field. A second equivalent FPSO was Tazerka in Tunisian water in the Med.

Balmoral FPV (Sun Oil/Agip) was the rst purpose-built semi-submersible production vessel, without storage, a GVA 5,000, moored by an eight-chain catenary anchor system equipped with four azimuthing thrusters of 2,400 KW each which has been in operation since November 1986. This was the rst oater in the North Sea to employ exible dynamic risers.

Gryphon FPSO (Kerr McGee) Gryphon A (the rst new build Tentech 850 design) was on location 1993 producing through eight risers and with six additional risers for injection. The Gryphon A FPSO is designed to stay on location for 20 years.

Directed Learning: The above ve Floaters (two production semi-submersibles and three FPSOs) were important landmarks in the oil industry. Search through the web and try to nd good record photographs or pictures of them and further information about the developments. Post website links on the forum for other participants to share.

The gain in popularity of FPSOs and other oaters, compared to xed structures, is primarily due to the economic bene t and reversibility in utilising such facilities. In many cases it has been the only economic means to develop an offshore oil eld as companies explore in remote and deepwater areas with no existing infrastructure, and as smaller marginal elds are developed in mature areas. Secondly, technology in the areas of mooring design and subsea production systems has reached an advanced stage where both increased feasibility, reliability and unit cost reduction have had a favourable impact.

A key factor in elds developed with oating production systems (FPV and FPSO monohull) is the relatively high degree of movement of the oater (i.e. + or 25 m in the horizontal plane and + or 8 m in the vertical plane) which means the wells cannot be completed topsides (as in a xed platform), but must be completed subsea with the exible dynamic risers providing the link between. Other forms of oater (TLPs and SPARs) do not have such massive movements and wells can be completed in the dry topsides.

Several eld development schemes are given as illustrations in Figures 1.31.7.

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Figure 1.3

Marginal/Small Field with a Floating Production Vessel (FPV Semi-Submersible). FPV above an Integrated Template Manifold System.

FPV is sited above the wells system. The reservoir uids ow up to the wells in the template manifold. Because the FPV has high horizontal and vertical motions the steel production tubing cannot continue directly up

to the oater.

The link between the seabed and the FPV is a exible dynamic riser. Because the wells are completed with trees on the seabed this is a wet tree system. Thus the commingled ow from the manifold goes along a short owline to the riser base and then up the exible dynamic riser. At the FPV main deck the ow arrives at the

riser porch and on the topsides process units.

If all the reservoir locations cannot be accessed from the central template manifold then the eld may incorporate satellite wells accessing the outer parts of the reservoir, tied-back to the template manifold.

Source Azur Offshore Ltd.

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Figure 1.4

Small Field with FPSO and an Integrated Template Manifold.

FPSO is sited away from the wells system (often with a spacing of 1 to 2 km). The FPSO is permanently moored by a turret mooring system. Because the FPSO has high horizontal and vertical motions the steel production

tubing cannot continue directly up to the oater. As in Figure 1.2 the wells are completed on the seabed. The reservoir uids travel via short owlines to the riser base and up the exible dynamic risers, through the

turret system to the process deck.

The separation of the permanently moored FPSO and the subsea well systems is required because at some future date the wells may need to be accessed from a drilling semi to carry out well maintenance activities.

There has to be room in the eld for the permanently moored FPSO and the temporary moored drilling semi.

Source Azur Offshore Ltd.

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Figure 1.5

Floating Production Hosts.

These comprise: Floating Production, Storage and Of oading Vessels (FPSO) Asgard FPSO (source Statoil)

Floating Production Semi-submersible Vessels (FPV) Thunder House Production Semi (source BP plc)

Source Drawings J E & P Associates.

Figure 1.6

Floating Production Hosts.

These comprise: Production SPARs Devils Tower (Source Wikipedia Common)

Tension Leg Platforms (TLP) Not a true oater Mars TLP (Source Shell plc)

Source Drawings J E & P Associates.

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Figure 1.7

Snorre Field Norway.

Field comprising the Snorre B Semi-submersible and Snorre TLP with subsea eld facilities.

Source Statoil.

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2. EXPLORATION, RESERVOIR ANALYSIS AND MARINE DRILLING

2.1 Introduction

The petroleum industry has always been required to characterise the formations below the surface to identify the locations of oil and gas reserves and to use further information to de ne the drilling and production strategies for recovering these reserves. Over many years this skill has involved the best inputs from geologists, geophysicists, petroleum engineers, drilling engineers and production engineers. In addition to the very important human skills involved, nowadays we have the tremendous capabilities of physical methods combined with very extensive computing powers.

The stages in this acquisition and evaluation using the above are:

Exploration Phase

Appraisal and Reservoir De nition Phase

Drilling and Well Testing Phase

Production Phase

2.2 Origin of Oil

The origin of oil dates back to the time when vast oceans covered much of the worlds surface. Countless millions of marine animals and plants died and were buried in the mud of those early ocean beds, the silt entombing them before they were fully decomposed. As thousands of centuries passed, increasing pressure from the subsequent deposits changed the underlying mud into shale, a ne grained rock, while heating transformed part of the modi ed organic matter into hydrocarbons. Further pressure then forced out the oil into porous rocks, through which it slowly percolated towards the earths surface. Sometimes it succeeded in reaching the surface itself, but often its passage was nally halted by some barrier of impervious rock through which it could not lter. At such points it accumulated in what are called reservoir rocks. Exploration for oil begins with the search for such rocks, though there is no guarantee, even when they are found, that oil will be there. A trap is a geological feature in which oil might have accumulated in commercial quantities.

2.2.1 Oil Traps

All oil traps have two basic requirements. There must be a porous and permeable rock strata in which oil or gas could have accumulated. This rock must be covered by an impervious layer cap rock through which the oil cannot travel. Such traps may be either structural, namely formed by the distortion of the rocks (either as anticlines or faults), or stratigraphic, due to changes in the actual nature of the rocks.

Common oil trapping Mechanisms include:

Fold Traps

Slip Traps

Salt Dome Traps

Old River Valleys

Most traps contain a gas cap, an oil layer and underlying water.

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See Figure 1.8 below.

Figure 1.8

Geological Oil Traps Oil & Gas Reservoirs.

Oil was formed many millions of years ago by organic material collecting and then being covered by layers of sedimentary rock. Over time the organic material was converted to oil and gas by the temperature and

pressures conditions. Oil and gas tend to migrate upwards. Most of such oil has already migrated upwards and been lost. Some of the oil could not progress upwards, being blocked by various trapping mechanisms.

These are: fold traps, slip traps, salt domes, capture in old river valleys

These traps can be seen by seismic exploration. Eventually the traps must be drilled (exploration drilling) to determine whether oil and gas are present.

Source J E & P Associates.

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2.3 Exploration Phase Methods

Land-based exploration techniques involve both geological surveying and the collection and examination of rock samples as well as various geophysical survey methods. For offshore exploration it is the latter that are employed, either from the air or more commonly from surface vessels. Geophysical surveys can be divided into two broad categories: reconnaissance surveys to outline possible areas of interest, where there are thick sediments and the possibility of structural traps, and detailed surveys, to de ne well locations to test speci c structures. Gravity and magnetic surveys are generally regarded as reconnaissance methods.

Directed Learning: Visit the Fugro web site (www.fugro.com) to learn more on geotechnical and survey methods. To access the site look at APPENDIX 2 FIGURE A at the end of this module. The site has a detailed hand book on Geophysical & Geotechnical Techniques for non-specialists. The site has other information on the Fugro survey vessels and what they do. Report what you learn from this site.

There have been a number of advances in non-seismic methods such as gravity and magnetic surveys. When recorded in conjunction with a 3D seismic program, these methods offer the bene t of an independently measured geophysical property which can be effectively used to verify, re ne and constrain a 3D velocity model and/or seismic interpretations

Seismic surveys can be used for reconnaissance purposes and are almost invariably used for the detailed surveys.

2.4 Seismic Surveys

The acquisition of seismic data involves the transmission of controlled acoustic energy into the Earth, and recording the energy that is re ected back from geological boundaries in the subsurface. Information regarding the structure and nature of the re ecting strata can be derived from the two-way travel time, and other attributes, of the returning energy. Processing these re ections produces a synthetic image of the Earths subsurface geologic structure

During 1975 and 1995 signi cant progress occurred, especially in seismic imaging. In addition, the cost of acquiring, processing and interpreting a unit amount of data decreased, as did the time required for all these steps. This progress resulted from four technologies:

Seismic data acquisition;1.

3D seismic data processing;2.

Computer hardware technology;3.

Interpretation and display.4.

More recently 4D seismic methods have become important, the additional dimension being time lapse, in assisting the operational management of the depletion of the reservoir in the production phase.

2.4.1 Marine Seismic Survey Methods

The method involves the use of purpose-equipped vessels both deploying the activating source of energy and the means to receive the returned signals. The vessel has large computer capabilities both to store and to process offshore the signals, and nowadays the means to transmit over satellite links the signals direct to land-based locations. All vessels use GPS to de ne the working location.

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Figure 1.9

Marine Seismic Survey Methods.

The seismic exploration method involves sending a shock wave down through the earth and recording the return signals which bounce back from the various subsurface layers. The collected data is processed to build a picture

of the subsurface structures.

For offshore exploration the marine survey method involves the activity from a survey vessel. The shock source is from a compressed air gun and the recording hydrophones are on streamers towed by the vessel.

Source J E & P Associates.

Thus the ve key ingredients to acquire useful seismic data are:

Positioning/Surveying

Seismic Energy Source

Data Recording

Data Processing

Data Interpretation

POSITIONING

The Global Positioning System (GPS) is used to provide positional accuracy of between 30 cm and 2 m. At sea the vessel and all its towed equipment is constantly in motion. An integrated combination of multiple reference site Differential GPS (DGPS), Relative GPS (RGPS), laser measurements of range and angles, underwater acoustics ranging and digital compasses along the streamers are used to determine the accurate position of all the components in real time as the vessel continuously moves along.

24

SEISMIC SOURCE Air Guns

An individual air gun generally consists of a system of two high-pressure chambers connected and sealed by a double-ended piston. During the charging cycle, air at high pressure (say 200 psi) is fed into the upper chamber and bleeds through the hollow piston into the lower chamber. To re the gun, an electrical pulse opens the solenoid valve and a slug of high-pressure air is delivered to the underside of the trigger piston. The piston shoots upwards under the pressure exerted on the ring piston releasing the air in the lower chamber into the water. Pressure in the upper chamber then drives the piston back to its initial position and the charging cycle recommences.

An alternative to air guns is the use of an implosion source fuelled by superheated steam.

HYDROPHONE RECORDERS

The receiving hydrophones are mounted on a line (streamers). The vessel will have many individual lines (often 12 but can nowadays be up to 20 or more) which are towed from arm arrangements on the vessel. Each streamer line may be many kilometres in length, with the total streamer lines making up many tens of kilometres in length. There are a number of different hydrophone types including the newer solid state ones.

DATA COLLECTION/PROCESSING

The vessel has large computers both to collect/store and to process the data. Nowadays the data is usually transmitted directly (in real time) back to the land-based organisation via satellite links for further processing and supply to the client. See Figures 1.10 and 1.11 for examples of survey vessels and survey data.

Figure 1.10

Marine Seismic Vessel.

Geo Challenger Vessel with seismic lines. Source CGGVeritas

Atlantic Explorer Vessel with seismic lines. Source PGS Petroleum Geo-Services

25

Figure 1.11

Geological Reservoir Model.

The end product of the seismic exploration process is a computer-generated graphic 3D model of the subsurface. Based on this and other information exploration companies will decide if and where to drill for oil and gas.

Source CGG Veritas.

The aim of the exploration activity is to identify potential trap structures to be the target for exploration drilling (often called wildcat drilling).

Directed Learning: Visit the CGGVeritas web site (www.cggveritas.com) to learn more on seismic exploration methods. To access the site look at APPENDIX 2 FIGURE B at the end of this module. View the 40-slide-set show and other information provided. You may wish to add them to your notes.

26

Figure 1.12

Types of Drilling.

The rst drilling is exploration drilling called wildcat drilling. This is to identify if the potential reservoir trap does in fact contain oil and gas. If successful this information is added to the reservoir model. Further drilling, called

appraisal well drilling, is carried out around the reservoir to con rm its size and extent. If the reservoir is con rmed as being exploitable then a plan for producing it will be developed, and the reservoir drilled to bring

the hydrocarbons to a production host. This activity is part of the eld development plan.

Source J E & P Associates.

Many exploration wells are not successful and prove to be dry. However if the exploration drilling does nd oil and/or gas then further appraisal well drilling may be commenced to support the evolution of the reservoir model by reservoir and petroleum engineers.

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2.5 Reservoir Engineering

The principal functions of reservoir engineers are:

To predict the future performance of a reservoir under the various producing mechanisms which are, or may become, available.

And in conjunction with other disciplines (geology and geophysics (G&G), facilities, drilling, production/operations, commercial), develop optimum eld development and depletion strategies.

The primary sources of rock properties are well tests, conventional and special core analysis, and logs.

In order to predict future performance of the well, reservoir engineers estimate which reservoir drive mechanisms are in effect. These drive mechanisms are:

uid expansion

solution gas drive

water drive

gas cap drive

gravity drainage

combination

For new eld developments, the assessment relies on the geological description of the reservoir and on the pressure, volume, and temperature (PVT) behaviour of the reservoir uids. For producing elds, production rate and reservoir pressure data provide valuable information for assessing mechanisms for driving the oil to the surface.

By running this computer model to simulate reservoir performance over eld life, reservoir engineers can provide various data for drilling and well design, facilities design, and commercial decisions. Typical data is listed below.

reservoir uid compositions and properties

rock properties

oil, gas, and water production and design rates

reservoir, bottom hole, and wellhead pressures and temperatures

well counts

In addition the reservoir engineers and drilling teams will de ne the required drilling programme for the eld development. See Figure 1.13 for an example.

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Figure 1.13

Developing the Production Drilling Plan.

The petroleum/reservoir engineers and the drilling teams will de ne the drilling programmes for the eld development. This will lead to the de nition of where the drill paths should enter the reservoir for maximising

the drainage of the hydrocarbons and to provide the locations for any water injection requirements.

The gure is an illustration of the drilling plan for the Britannia Gas Field in the North Sea. In the reservoir picture the points of entry into the reservoir are indicated. In this eld development the wells located in the

circle to the right are drilled from a xed platform set in the eld. The wells located in the circle to the left are accessed from a subsea completion with a tie-back owline to the main platform.

Source Chevron UK Ltd.

2.6 Introduction to Offshore Drilling

Despite the great strides made in geological and geophysical exploration methods there is, as yet, no means of forecasting positively the presence or absence of hydrocarbons in any prospective horizon until a physical connection has been established and this means drilling.

For offshore drilling the choice of rig and drilling platform not only depends on drilling requirements and depth of water, weather prospects and seabed conditions must also be considered. Although there is a wide range of design in the various platform structures for offshore rigs, the structures themselves fall into three general categories, all of which must accommodate a complete drilling crew and a helicopter deck; these are:

Self-contained Platforms

Drilling Tenders

Mobile Units

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Figure 1.14

Offshore Drilling Rigs.

These are: Jack-up drill rigs for drilling in shallow water depths usually up to 120 m. The rig is oated to the drilling location with its legs up. At the site the legs are jacked down to land on the sea bed.

Semi-submersible drilling rigs. These operate in both shallow water depths (a few 100 metres) and deepwater depths (over 2,000 m). They can be operated by being moored to the seabed or held by dynamic positioning

(DP) thrusters.

Drillships. These are mainly a deepwater rig and usually operate on DP.

Source J E & P Associates.

Figure 1.15

Offshore Drilling Rigs at Work.

Jack-up drill rig On the move.

Semi-submersible drilling rig. Drilling in the North Sea Moored.

Drillships. Jack Ryan Drillship working in the GoM. Source BP plc.

Source Wikipedia Common and BP plc.

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2.6.1 Mobile Drilling Rigs

Jack-ups

These are self-contained hulls generally resembling a simple at-bottomed barge with three, four or multiple legs positioned on the periphery of the hull and up (or down) which the hull can be jacked. When under tow to or from location, the barge is at the bottom of the legs, which then have most of their length exposed above sea level. When over the well location the legs are jacked down until they reach the seabed. As jacking continues the legs will rst start to penetrate the sea bed but eventually the platform will climb up the legs until it is high enough to be out of the maximum wave area. At this position the legs are locked and drilling can start.

Such platforms are useable to moderate water depths.

Semi-submersibles

These are a development of the submersible structures and oat on two pontoons fully submersed in the water. The pontoons are such that the vessel can easily be towed from one location to another. The semi-sub can be held on location by a series of anchors or, in more advanced systems by dynamic positioning (DP). Anchored systems can operate up to quite deep waters, the DP vessels can operate in extreme water depths.

Drill Ships

Because of its conventionally shaped hull, drill ships suffer more from wind and wave movements than the semi-sub. In calm water areas (i.e. W. Africa and parts of the Far East) this is no problem. They do have the advantage of better (faster) mobility between locations and very large working deck space (both for working and for stores and equipment). Drill ships may be moored by anchors or have DP capabilities. Drillships are use in extreme water depths.

Directed Learning: Search on the web for Marine Drilling Companies. Collect information on their Drilling Fleets

Which type is the most numerous?

Where are some of the current areas of the world with big drilling programme activities?

What are the typical water depths in these areas?

Collate your ndings and publish them to share with other participants. Comment on which are the best web sites for Drilling Fleets.

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2.6.2 Drilling the Well

Figure 1.16

A Typical Subsea Well Casing Design (North Sea).

The drilling process involves drilling a number of hole sizes, starting with the largest 36 hole. Following the drilling, the casing is set in the hole and cemented in. Further smaller sizes of holes are drilled and casings set

and cemented until the drilling reaches the reservoir location. This is illustrated by a typical North Sea well system. Ultimately the 5 production tubing will be set in the well and provide the owpath of the reservoir

hydrocarbons to the surface.

Source J E & P Associates.

Temporary Guide Base

The temporary guide base is a frame which serves as the foundation for the other subsea equipment. It is lowered to the seabed on the end of a string of drill pipe. The string is tted with a special running tool that releases the guide base when it is in position. The base may need to be levelled. When this has been done the four guide lines are tensioned up from the rig.

Spudding-In

A 36-diameter bit (called a hole opener) is lowered to the seabed inside a guide frame that runs down the four guide lines. A relatively short section of hole is drilled to a depth of around 100 m. Sea water is often used as the circulating uid and cuttings are brought to the seabed. It is important that this portion of the hole is vertical and checks are made as the drilling proceeds. While the hole is open it may be temporarily lled with a gel-water uid or bentonite to stop it sloughing (when the sides fall in).

Outer Conductor Casing and Permanent Guide Base

30 conductor casing is run into the hole. Centralisers are used to keep the casing string in the middle of the hole. These are tted round the joints as they are run. Before the last joint of 30 casing is run, the permanent guide base (PGB) is attached to its top, leaving about 1.5 m of casing protruding above it. This provides anchorage for the next string of casing (20).

The PGB, with the casing suspended from its aperture, is lowered on a special running tool to the seabed. The guide lines running through the four posts on the PGB guide it into position and it slots into the PGBs aperture with a funnel-shaped bottom projection that guarantees an accurate t.

Cementing the Conductor Casing

The casing is anchored to the hole wall by cementing. A drill string is run into the conductor casing, through which cement will be pumped extending it into the shoe at the bottom of the casing. Cement is pumped through the bottom of the casing, displacing the sea water and rising up into the space between the outer

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diameter of the steel casing and the hole wall. This continues until cement is seen to be emerging at the seabed level. The cement is allowed to harden over a period of a few hours.

Drilling 26 Hole

A 26 hole is now drilled to a depth of some 500 m. Sea water again is used as the drilling uid and the cuttings are discharged to the seabed. Measures to prevent sloughing may be required.

Running and Cementing 20 Casing and Running the Wellhead

The shoe at the bottom of the 20 casing is guided into the aperture in the PGB and the casing run to the bottom of the hole. A welhead is attached to the top of this casing. The wellhead is a device with internal ttings called casing hangers that suspend the various sizes of casing and tubing strings that will be run during the remainder of the well programme. The upper end of the wellhead, which has an internal hole diameter of 18, is designed to closely latch onto the 18 Blow Out Preventer (BOP) stack when this is run. The wellhead is run with the last joint of the inner 20 conductor casing, after which the casing is cemented as for the 30 conductor casing.

Running the BOP Stack and the Marine Riser

The BOP stack is run attached to the lower end of the 21 bore marine riser. The riser acts as a conduit for tools and for drilling uid and cuttings returning from the well. By this means all further operations are organised from the drill deck on the surface installation.

Drilling 17 Hole

The cement lled shoe of the 20 casing is next drilled out with a 17 bit to a depth of about 2,000 m. Drilling mud is circulated from the drilling facilities through the drill string with the circulation continuing up the hole (now containing cuttings) and marine riser onto the mud deck where it is passed over a shale shaker which removes the cuttings and allows the mud to be re-circulated. When the hole has been completed it is logged with electric and sonic wireline logging devices to determine the conditions in the hole before running the casing. Such logging is often carried out by specialist personnel brought out to the drilling platform to perform such functions.

Running and Cementing 13 Casing

The 13 casing is run to the bottom of the hole. Cementing requires a very large quantity of material for this length of hole. The cement will be prepared in the mixing and pumping equipment on the drill facilities. The amount of cement is carefully calculated from the knowledge of the hole diameter along its length. The amount required is to ll the annulus and to leave a certain amount of cement inside the bottom of the casing above the shoe, this being drilled out at the start of the next hole section.

The cement is forced down the casing and back up the outer portion of the hole. It is important to displace all the mud which previously occupied this space. Separation of the mud and the cement interface is assisted by a plug which travels ahead of the cement. Once the calculated amount of cement has been pumped into the well another plug is used and mud is then used to provide the driving force to force the cement all the way to the top of the casing annulus.

The well may be surveyed using wire line instruments to check inclination and direction.

Drilling 12 Hole

The cement shoe of the 13 casing is then drilled out with a 12, and drilled to 3.5 km.

Logging, Running and Cementing 9 Casing

The hole is rst cleaned by mud circulation. Logs are run. The casing is run and cemented similar to the 13 casing.

Drilling 8 Hole to Total Depth

The hole drilled to the nal depth (and hence into the oil pay zone) may require a different mud system. If so the new mud system has to be prepared and used to displace the other mud system from the hole.

33

The hole is drilled to its nal Target Depth (TD) with an 8 bit. As it nears its target more and more measurements are taken with various instruments. When TD is reached the pay zone should have been penetrated. The new mud controls the well by providing weight to balance the pressures.

Coring and Logging

When at the pay zone a coring drill will be used to cut a core sample which is brought back to the surface for examination and testing. The coring drill has a hollow section with the cutters only around the edge. Logging operations follow the coring operation.

Running and Cementing the 7 Liner

The 7 liner may run to the wellhead or it may be suspended from the bottom of the deepest string in the casing run (9) by means of a liner hanger. The liner is cemented in at the same time as it is run, and a packer or plug is set at its top to isolate the test zones inside it from the cased hole above. If a string of narrow tubing is now run down through this packer with special valves that allow the controlled entry of well uids, it is now possible to channel pressurised well uids to surface under control. To allow uids access to the inside of the liner requires that it is perforated using a perforating gun which produces a series of holes in the liner.

Well Testing and Well Stimulation

When the well system has been completed it is necessary to test the ow characteristics from the reservoir. These tests involve measurement of the owrate of the oil as well as various physical and chemical tests on the produced hydrocarbons. This data will be use to determine whether the well ( eld) can go into production.

Directed Learning: For further information on Drilling Wells visit www.world-petroleum.org/education/offdrill. On the web there are many sites of Drilling Companies and others that have video presentations. Search for some of these and report what they show to other course participants.

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3. BASIC PRINCIPLES OF OFFSHORE PRODUCTION

There are many different eld development concepts involving bottom founded platforms, often in shallow water, and oating production hosts which can be deployed in both shallow and deep water.

Figure 1.17

Field Development Options.

There are many options for a eld development. All the options should be considered in the concept phase. Each should be evaluated for technical merit and cost.

For the production host there are a range of bottom founded hosts appropriate to shallow water developments, and a range of oating production hosts appropriate to shallow and deepwater developments. Some of these will have dry well systems direct to the host without subsea completions. Others will require wet tree solutions involving subsea completions. At the seabed level there is the choice of individual wells, or manifolded ow.

Source Azur Offshore Ltd.

The basic principles of subsea production are illustrated showing the reservoir, the well, the wellhead and Xmas tree at the seabed with the owline to the base of the riser, onto the production host and processing system. The Figure 1.18 may be used to represent the key reservoir factors which in uence the production. These are all important factors in the crucial component of FLOW ASSURANCE which is the continued ability of the production well to produce under all future conditions.

35

Figure 1.18

Basic Principles of Offshore Production.

The Figure gives a simple representation of the ow of reservoir uids up the production tubing, through the subsea Xmas tree, along the seabed owline and up the riser system to the production host. Factors which could

cause problems to such a scheme operating successfully are known as FLOW ASSURANCE ISSUES.

These include: System Hydraulics In the reservoir the uids may be at 250 bar pressure. Some of this pressure is lost as the uids ow up the well, through the seabed equipment, along the owline and up the

risers. Hydraulic studies must evaluate if there is suf cient energy to allow this to operate. Reservoir pressure maintenance may be achieved by injecting water at the edges of the eld (water injection).

Corrosive compounds in the reservoir uids. Levels of H2S and CO2 can cause corrosion of simple steels. Protection against corrosion may be by continuous injection of an inhibitor into the owline.

The oil in the reservoir may contain wax which could precipitate out as the oil cools in the owline causing blocking of the line. This may be treated by injection of wax inhibitors or maintaining the heat in the owline by

insulation.

The presence of gas and water can lead to ice-like crystals of hydrates which could block the lines.

The design of the overall offshore production system must incorporate defences against all such potential Flow Assurance problems.

Source J E & P Associates.

The factors are:

The Field Location/Size

The Reservoir (Reservoir Engineering)

Reservoir Factors Affecting the Production System

Pressure

36

Temperature

Chemistry

Long Term Operation

3.1 Field Location/Size

The overall development will be in uenced by:

Geographic Location (i.e. stable mature areas distant, remote areas).

Water Depth (i.e. shallow waters of a few m up to very deep water more than 2,000 m).

Field Size (i.e. a few tens of million barrels of oil with two or three wells up to elds with one or two billion barrels of oil with 40 or 50 wells).

The presence of large quantities of gas.

The environmental weather conditions (i.e. benign in W. Africa and severe in W. of Shetlands)

3.1.1 Reservoir Factors Pressure

Initially the oil (and dissolved gas known as associated gas) is in the reservoir at relatively high pressure (at say 3,000 psi). This pressure forms the natural drive which forces the oil to ow from the reservoir into the production tube and up the well.

The vertical lift in the well system will depend on the reservoir depth. By the time the oil ow has reached the seabed it will have used up much of the natural pressure (and will be at say 1,000 psi).

At the seabed the oil ow will be through the wellhead, the Xmas tree and manifold systems. These involve valves, chokes, pipe runs and bends. All these will cause some pressure loss.

From the seabed wellhead/manifold systems the oil will ow along the seabed to the riser below the production host in a owline. The length of the owline could be a few tens of metres or up to several tens of kilometres. The seabed is not absolutely at. Overall there will be pressure loss of the ow along the seabed section.

From the riser base below the production host ( xed platform or oater) the oil has to rise to the sea surface and then some additional 50 metres to the point where it enters the process plant separator. The level of pressure lost on this nal lift depends on the water depth which can be from less than 100 m to up to 2,000 m. The oil has to arrive at the separator inlet at some 200 psi.

An hydraulics study is required to check that the proposed production system does allow the oil to ow from the reservoir to the process plant. This needs examination of the hydraulics for ow at day one, at the end of eld life (5, 10, 20 years or more) and for start-up after shut-down conditions. Such studies will provide information on pressure maintenance requirements (water or gas injection), downhole pumping or well gas lift and seabed pressure boosting or riser lift.

Additionally, as the pressure is reduced the associated gas will bubble out of the oil such that when the oil reaches the seabed it will be a mixture of oil and gas (probably together with some water). This is called multi-phase ow. The production process will have to take this into account in its design and operation.

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3.1.2 Reservoir Factors Chemistry

The hydrocarbon (and other materials) in each reservoir are unique to that reservoir. It is important to understand the chemistry of each reservoir. Key factors are:

The presence of H 2S and/or CO2

Levels of H2S at a few parts per million could lead to sour corrosion in steel and CO2 at more than a few % level could lead to sweet corrosion. Potential corrosion problems could be solved with expensive steels but normal steels with a chemical injection package of corrosion inhibitors is more commonly chosen.

Wax and Asphaltenes

Under low temperature conditions these can precipitate out and cause blocking of the owlines.

Chemicals which cause emulsion formation

Chemicals which cause scale

These may require chemical injection.

It must be noted that over the eld life the reservoir chemistry may change.

3.1.3 Reservoir Factors Temperature

In most areas of the world the seabed bottoms are at just over zero degrees C. Thus oil in steel lines will be subject to cooling. Cooling may cause:

Wax and Asphaltene deposition

Hydrate formation (if gas and water are present).

These and other effects may be mitigated by chemical injection and insulation of the lines.

Directed Learning: Visit the UK Oil & Gas web site (www.oilandgas.org.uk). Visit the Education section which has many sections on offshore production systems. To access the site look at APPENDIX 2 FIGURE C at the end of this module. Review the information provided to add to this eLearning course. Report what you have learnt from this information and in particular which sections were the most useful.

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4. THE FUNDAMENTALS OF SUBSEA ENGINEERING

4.1 Subsea Engineering Overview

The total view of subsea engineering is illustrated in Figure 1.19. The main building blocks are given in the outer part of the diagram, with the necessary interfacing activities towards the centre. Additionally subsea engineering should not be confused with underwater engineering a point illustrated in the Figure 1.19. The main areas of subsea engineering are:

AREA 1 WELL SYSTEM

AREA 2 SEABED STRUCTURES & PIPING SYSTEMS

AREA 3 PIPELINES, FLOWLINES & RISERS

AREA 4 SUBSEA CONTROL SYSTEMS

AREAS 5 & 6 OFFSHORE OPERATIONS/UNDERWATER ENGINEERING

Also, other key topics are:

RESERVOIR ENGINEERING

FIELD OPERATIONS AND PROJECT MANAGEMENT

NEW TECHNOLOGIES

39

Figure 1.19

Fundamentals of Subsea Engineering.

The various components of subsea engineering systems are represented in the circular diagram.

The main areas include: Area 1. Subsea wellheads and Xmas Trees.

Area 2. Templates and Manifolds Seabed Piping Structures.

Area 3. Flowlines (in eld lines), Pipelines (export product lines) and Risers (lines connecting ow between the seabed and above surface production host).

Subsea Control Systems.

Source J E & P Associates.

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AREA 1

Figure 1.20

Subsea Wellhead.

The subsea wellhead

Source Lasmo plc.

4.1.1 Wellhead Functions

To support BOP and seal with well casing during drilling

To support and seal the subsea production tree

To support and seal the well casing

To support and seal the production tubing hanger

41

Figure 1.21

Xmas Trees.

Dual Bore Xmas Tree. Picture shows the Tree inside a protective frame. The Valve actuators come out from the basic block. The Subsea Control system is mounted to the side (in orange). Small steel lines carry the hydraulic

uids to the appropriate valve when commanded.

Source Lasmo plc.

4.1.2 Xmas Tree Functions

Basically a stack of valves installed on a subsea wellhead to provide a controllable interface between the well and the production facilities.

Speci c functions of a subsea Christmas tree:

Sealing the wellhead from the environment by means of the tree connector

Sealing the production bore and annulus from the environment

Providing a controlled ow path from the production tubing, through the tree to the production ow line. Well ow control by means of tree valves and/or a tree-mounted choke valve.

Providing access to the well bore via tree caps and/or swab valves.

Providing access to the annulus for well control, pressure monitoring, gas lift, etc.

Providing a hydraulic interface for the downhole safety valve.

Providing an electrical interface for downhole instrumentation, electric submersible pumps etc.

Providing structural support for ow line and control umbilical interface.

42

AREA 2

Figure 1.22

Seabed Structures & Piping Systems (Manifolds).

Three options are illustrated.

i). Each well has its own owline back to the host platform with a 6 line.

ii). The wells are clustered about a manifold. In the manifold the ows from each well are commingled and sent to the platform in a 10 to 14 line.

iii). The wells and manifold are located in the same structure. This is called a Template Manifold.

Source J E & P Associates.

4.1.3 Template Functions

The primary function of a subsea template is to provide guidance for positioning wells and controlling their positions relative to one another.

Some speci c functions of a subsea template are:

To provide a guide for positioning the well conductor and guiding the conductor during installation.

To control spacing between adjacent well conductors.

To provide guidance and support for the BOP in some cases.

To provide guidance and support for well completion equipment (e.g. trees) in some cases.

43

To accommodate pre-installation of well owline piping and facilitate interface of the production trees with their owlines.

To accommodate pre-installation of tree control hardware and facilitate interface of the production trees with their controls.

4.1.4 Manifold Functions

The general function of a subsea manifold is to gather and distribute production through an arrangement of piping and valves. Some speci c functions are:

To collect the ow from individual satellite wells into a production header and control the delivery of the commingled ow to a eld production gathering owline

To collect the ow from several eld production gathering owlines and deliver that ow to a larger production export pipeline.

To isolate the production from individual wells and deliver it to a well test header or a well test owline.

To segregate high pressure and low pressure production into separate high pressure and low pressure headers and owlines.

To control the ow from individual wells by means of subsea chokes. Wells may be choked at the trees or at the manifold.

To distribute injection water or gas from a common supply header to individual injection wells (water injection or gas injection manifolds).

To distribute lift gas from a common lift gas header to individual wells (lift gas manifold).

To facilitate pigging of subsea pipelines by provision of pig isolation valves, tees and pig detector instrumentation mounted on the manifold structure.

To provide structural support of the piping and owline connector at the owline connection interface.

To provide ROV or installation tool interfaces for installation of owlines, chokes, pig launchers, pig receivers and other components.

44

AREA 3

Figure 1.23

Flowlines and Pipelines.

In eld lines are called Flowlines. They carry the well uids to the host for processing separation into oil and gas. These are often smallish in size 6 to 14. They have to be buried for security. The lines which carry the separated oil and gas for export are termed Pipelines. If these are over 16 they may not need to be buried.

Source J E & P Associates.

Flowlines carry the uids from the wells, direct or via manifolds along the sea bed to the production host. These produced uids are multiphase and are combinations of hydrocarbon gas and liquids together with water.

These lines are often smaller in size 6 to 14 diameter.

Pipelines are the larger export lines carrying the processed separate oil and gas to shore or offshore loading facilities. They may be up to 40 and above.

45

Figure 1.24

Flexible Dynamic Risers.

Risers carry the liquids from the seabed to the intake to the Process plant on the production host. With dynamic hosts (i.e. FPSOs and FPVs) the motions are beyond the capabilities of steel pipe. In this case they are often

Flexible Dynamic Risers made of combinations of steel and plastic layers.

They have a tension length up to a mid-water arch shape and then a catenary hanging section up to the oater.

Source J E & P Associates.

Risers carry the liquids from the seabed to the intake to the process plant on the production host. With jacket platforms and other stable hosts they are steel tubes. With dynamic hosts (i.e. FPSOs and FPVs) the motions are beyond the capabilities of steel pipe. In this case they are often exible dynamic risers made of combinations of steel and plastic layers.

46

AREA 4

Figure 1.25

Subsea Control Systems and Umbilicals.

The subsea wells are controlled from the production host. The main features are:

Topsides Control Station (Computers, Hydraulics and Chemicals Skids)

Umbilical carrying signal cores, hydraulic lines and chemicals lines to seabed equipment.

Subsea Distribution and Subsea Control Modules.

Source Azur Offshore Ltd.

The subsea wells are controlled from the production host. The main features are:

Topsides control station (computers, hydraulics and chemicals skids)

Umbilical carrying signal cores, hydraulic lines and chemicals lines to seabed equipment.

Subsea distribution and subsea control modules.

47

Directed Learning: There are no good websites on the general topic of SUBSEA ENGINEERING. However there are ve main companies which provide Subsea Production Equipment. They are:

CAMERON www.c-a-m-.com

FMC www.fmctechnologies.com

AKER SOLUTIONS www.akersolutions.com

VETCO GREY gepower.com

DRIL-QUIP www.dril-quip.com

Visit their websites and view pictures and information on their products. From these prepare your own best set of the subsea equipment items and report them back.

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5. FLOATING PRODUCTION SYSTEMS

5.1 Introduction

The oil and gas industries utilise a range of oating vessels. These are de ned as:

FLOATING PRODUCTION, STORAGE AND OFFLOADING VESSEL (FPSO)

Floating production, storage and of oading vessel which includes, in addition to its storage and of oading capability, facilities for receiving crude oil from producing wells and processing it for export by separating water and gas.

FLOATING PRODUCTION VESSEL (FPV)

Floating production system: a general term to describe any oating facility designed to receive crude oil from producing wells and process it. It does not have facilities for storage, in which case export would be by pipeline to shore or to a nearby FSO.

FLOATING STORAGE AND OFFLOADING (FSO or FSU)

Floating storage and of oading system, often a ship or barge-shaped oating hull incorporating tanks for storage of produced oil, and a method of loading the oil into offtake tankers. These installations do not have any production or processing facilities.

Production in shallow and deep water (below 500 m) utilises a range of oating production hosts. The possible production oaters include:

FPSO MONOHULLS

Floating production, storage, and of oading systems receive crude oil from shallow or deepwater wells, process the oil into a dead crude and store it in their hull tanks until the crude can be pumped into shuttle or trading tankers for transport to shore. The topsides processing systems also separate gas (which can be exported by pipeline or disposed of by re-injection), separates produced water (for disposal) and prepares seawater for injection purposes to maintain reservoir pressure. FPSOs are commonly deployed with a eld development using subsea completions (i.e. wet trees).

This production host can operate in shallow and deepwater locations.

SEMI-SUBMERSIBLES

Semi-submersible marine structures are well known in the oil and gas industries for drilling and production. These semi-submersibles have a relatively low transit draught that allows them to be oated to a stationing location, where they can add ballast, usually by taking on seawater, to assume a deeper draught or semi-submerged condition for operation. Semi-submersible production vessels have the principal characteristic of remaining in a substantially stable position (spread moored), but presenting signi cant movements when they suffer the action of environmental forces such as the wind, waves and currents. Semi-submersibles are commonly deployed with a eld development using subsea completions (i.e. wet trees).

This production host can operate in shallow and deepwater locations.

DEEP-DRAUGHT SEMI-SUBMERSIBLES

Deep-draught Semi-submersible production vessels are similar to the above but with the bottom pontoon located in deeper water. This reduces the vessels motions and the resulting vessel stability allows the possible use of dry trees set at main deck level. The initial design concept envisaged the bottom pontoon to be located at minus 100 metres or so. No such units of this type were produced. The concept now refers to Semi-Submersibles vessels with the bottom pontoon extended by about 12 to 15 metres only. This still gives a signi cant reduction to the vessels motions and is becoming a requirement for hurricane resistance in the Gulf of Mexico.

This production host is designed to essentially operate in deepwater locations.

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SPAR

A spar is a deep-draught oating caisson, which is a hollow cylindrical structure similar to a very large buoy. Its four major systems are hull, moorings, topsides, and risers. The spar relies on a traditional mooring system (i.e. anchor-spread mooring) to maintain its position. About 90% of the structure is underwater. The spar design can be used for drilling, production, or both. The distinguishing feature of a spar is its deep-draught hull, which produces very favourable motion characteristics compared to other oating concepts. Low motions and a protected centrewell also provide an excellent con guration for deepwater operations. The resulting vessel stability allows the use of dry trees set at main deck level.

This production host is designed to operate in deepwater locations.

TENSION LEG PLATFORM (TLP) Not a true oater

A Tension Leg Platform (TLP) is a buoyant platform held in place by a mooring system. The TLPs are similar to conventional xed platforms except that the platform is maintained on location through the use of moorings held in tension by the buoyancy of the hull. The mooring system is a set of tension legs or tendons attached to the platform and connected to a template or foundation on the sea oor. The template is held in place by piles driven into the sea oor. This method dampens the vertical motions of the platform, but allows for some small horizontal movements. The topside facilities (processing facilities, pipelines, and surface trees) of the TLP and most of the daily operations are the same as for a conventional platform.

This production host can operate in shallow and deepwater locations

View again Figures 1.5 and 1.6.

5.2 Floating Production, Storage and Of oading Monohull Vessels

FPSOs generally are an amalgam of marine and petroleum functions, and therefore, present many specialised challenges for those involved in their creation. Their turret structures are designed to anchor the vessel, allow weather vaning of the units to accommodate environmental conditions, permit the constant ow of oil and production uids from vessel to undersea eld, all the time being a structure capable of quick disconnect in the event of emergency.

An FPSO system is an offshore production facility that is typically ship-shaped and stores crude oil in tanks located in the hull of the vessel. The crude oil is periodically of oaded to shuttle tankers or ocean-going barges for transport to shore. FPSOs may be used as production facilities to develop marginal oil elds or elds in deepwater areas remote from the existing pipeline infrastructure. FPSOs have been used to develop offshore elds around the world since the late 1970s. They have been used predominately in the North Sea, Brazil, Southeast Asian/South China Seas, the Mediterranean Sea, Australia, and off the West Coast of Africa. As of 2008 there were 190 FPSOs in operation or under construction worldwide.

5.2.1 FPV and FPSO De nitions

FPSO Floating Production, Storage and Of oading

By Floating The body is in equilibrium when oating.

This could include semi-subs, monohulls, deep draught semi-subs and spars, but does not include TLPs. Note that the motion characteristics of the deep-draught semi-sub and the spar permit the use of deck mounted dry trees whereas the rst two types have normally to deploy subsea completed wet trees.

By Production the unit supports processing equipment to fully treat live well uids, with separation gas compression, water injection, cooling and heating systems, water treatment, fuel gas, chemical injection etc...

By Storage the processed oil is held in tanks on the unit prior to export. Gas cannot be stored and must be exported by pipeline, used for power generation, reinjected, used for subsea gaslifting or ared.

By Of oading a means by which the oil product is transferred to a shuttle tanker or other export system like pipelines.

FPV Floating Production Vessel

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As above, but without a storage capability. Here the production must be connected to an export system such as pipelines or a Floating Storage Unit (FSU) or seabed storage system.

5.2.2 FPSO Total System Building Blocks

The FPSO total system is illustrated in Figure 1.26 with respect to a monohull with a subsea development.

The building blocks on the vessel are:

Vessel hull including storage

Turret and swivel

Deck-based process plant

Of oading system to shuttle tanker(s) or export line

Other units accommodation, aring, etc.

The building blocks from the vessel downwards are:

Mooring lines

Riser systems

Subsea systems of:

Wellheads and Xmas trees

Manifold/templates

Pipelines and owlines

Subsea control system

Offshore operations

IMR

Drilling and reservoir interfaces

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Figure 1.26

FPSO Components.

The main components comprise: Hull, Mooring System, Turret System, Risers and Subsea Facilities, Topsides Processing Units, Export System, Field Layout and Safety and Regulations

Source J E & P Associates.

FPSOs have a number of different mooring types. For single-point mooring which allows the vessel to weathervane (taking up the position of least resistance to the weather conditions) they require a turret. In calm areas they do not need to weathervane and so can be spread moored with the risers being draped over the vessels side.

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Figure 1.27

Turret Moored FPSOs.

Single-point Mooring. FPSOs with Internal and External Turrets.

Source J E & P Associates.

Figure 1.28

Spread-moored FPSOs.

Spread-moored FPSO with Risers Draped Over the Sides.

Source J E & P Associates.

These overall FPSO building blocks will be examined in more detail throughout the course.

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5.3 Worldwide Operating Floaters and Current Development

FPSOs and FPVs are widely used throughout the world.

There are currently 18 FPSOs operating in the UK North Sea and eight in Norwegian waters. In addition there are several FPVs and FSUs in operation.

The Brazilian offshore elds utilise a large number of FPSOs and FPVs, some operating in more that 1,000 m water depth. There are more than 31 FPSOs in Brazilian waters.

There are more than 14 FPSOs operating in Australian and New Zealand waters. And more to follow.

There are many FPSOs in the South China Sea and other SE Asian locations both in shallow and deep water. There are 17 in China; seven in Vietnam; six in Indonesia; plus seven in other locations.

There are a very large number of FPSOs operating off West Africa, particularly in deepwater, with many more planned Nigeria 14; Angola 14; Congo, Gabon and Guinea three each; plus four elsewhere.

To date the Gulf of Mexico has many semi-submersibles, SPARs and TLPs with more planned. The rst FPSO will soon be operational in the GoM.

The Canadian Terra Nova Field and White Rose Fields utilised FPSOs.

FPSOs also operate in the Mediterranean and Caspian Seas.

New Floating Production Systems (e.g. Sevan SPS 300) are continuing to emerge in Brazil and the North Sea.

The rst Deepwater FPSO is now operating in Indian waters.

Examples are given in Figures 1.29 and 1.30.

Figure 1.29

Examples of Single-point Morred FPSOs.

Source Statoil and Wickipedia Common.

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Figure 1.30

Disconnectable Turret Moored FPSO (External Turret).

Jabiru FPSO A FPSO with an external turret operating in Australia. The turret is of the disconnectable type. In these waters the FPSO must disconnect and move away during cyclones.

Source J E & P Associates.

The current range of FPSO deployed worldwide are listed in Table 1 which can be found in Appendix 1 at the end of this module.

Directed Learning: Review the table of FPSOs provided in APPENDIX 1 and other information on them and comment on the following:

Which areas of the world use FPSOs a lot?i.

Why are there large numbers of FPSOs in some areas and not others?ii.

Hunt for good illustrations of FPSO vessels on the web.iii.

Share your views and ndings with other participants.

5.3.1 Regional Differences

From the above it may appear that the FPSO monohull is the way ahead. This may be a current trend but it is important to consider and understand all forms of FPSOs to seek the most appropriate system for individual eld developments. There is a major difference in the requirements (and so of the solution) for FPSOs in terms of the prevailing weather. This ranges from:

Benign off West Africa and Brazil

Moderate off the North Sea

Severe off the West of Shetlands

Ice oes off Western Canada

Cyclones off South China Sea and Australia

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There are differences in operating systems of FPSOs because of the local environmental conditions. e.g. between the benign seas off West Africa and the very stormy seas of the North Sea.

Also the case of new build vs conversions is somewhat regional. To date in Norwegian water all the FPSOs have been new builds. In the UK waters it is about 50:50 new builds and conversion. In other areas of the world less than 10% may be new builds.

5.3.2 Advantages of Floater Systems

LOCATION/FIELD SIZE

Nowadays FPSOs are often rst choice for new areas where there is little or no existing infrastructure with the possibility of a tie-back to existing hosts or accessing existing export lines. The self contained nature of the FPSO including its shuttle export system, make it ideal for such locations.

In the early days the FPSO seemed to be the solution to small marginal elds (say up to 20,000 bopd), but nowadays they are being used on elds with 250,000 bopd production.

WATER DEPTH

Floating production systems were rst used in shallow water depths, where they competed with jacket platforms. As exploration and production have moved to ever increasing water depths, production from bottom founded structures is no longer viable and the range of oating systems must be deployed.

MOBILITY

In a number of areas of the world it is not possible to design a production system host that can survive the local weather conditions. Here FPSOs are an ideal solution with a disconnection capability to shut down the wells, disconnect and move off station. At the end of the weather situation the FPSO may come back and reconnect to the well systems.

DECOMMISSIONING/RE-USE

Finally a major advantage that oating systems have over xed platforms is that at the end of the eld life they may be easily decommissioned and disconnected and taken to dockside. Very often the oating facility can be refurbished or upgraded and re-deployed to another eld.

An example of re-deployment of an FPSO is the Australian Skua FPSO. This was a converted VLCC. Production at the eld nished a few years ago. The FPSO was refurbished and re-deployed in the Elang/Kakatua Fields. In 2008, having completed its work there it was withdrawn from the eld and was re-deployed again to a new eld in 2009.

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6. FPSO MARKET OVERVIEW

The FPSO Market Overview is provided here by a selection of Figures from Douglas-Westwood Ltd (www.dw-1.com).

Figure 1.31

FPSO Market.

Source Douglas-Westwood Ltd.

Figure 1.32

FPSO Market Drivers.

Source Douglas-Westwood Ltd.

57

Figure 1.33

FPSO Supply Options.

Source Douglas-Westwood Ltd.

Figure 1.34

FPSO Leading Field Operators.

Source Douglas-Westwood Ltd.

58

Figure 1.35

FPSO Leasing Day Rates.

Source Douglas-Westwood Ltd.

Figure 1.36

Floaters CAPEX to 2012.

Source Douglas-Westwood Ltd.

59

APPENDIX 1

TABLE 1 WORLDWIDE DISTRIBUTION OF FPSO VESSELS

NORTH & SOUTH AMERICA

BRAZIL

BRASIL Dec 2002

BW PEACE Mar 2009

CAPIXABA May 2006

CIDADE DE NITEROI MV 18 Q4, 2008

CIDADE DE RIO JANEIRO MV14

Jan 2007

CIDADE DE SANTOS MV20

CIDADE DE SAO MATEUS 2008

CIDADE DE VITORIA (GOLFINHO II)

2008

ESPADARTE Aug 2000

ESPIRITO SANTO (Parque de Conchas)

Q4,l 2008

FLUMINENSE FPSO Aug 2003

FRADE April 2008

MARLIM SUL Jun 2004

P-31 Oct 1998

P-33 2002

P-34 Dec 2005

P-35 Aug 1999

P-37 July 2000

P-43 Dec 2004

P-48 Feb 2005

P-50 April 2006

P-53 Dec 2008

P-54 Aug 2007

P-57 Q4, 2010

P-62

PERIGRINO Q1, 2010

PETROJARL CIDADE RIO DAS OSTRAS

Mar 2008

PIPA II FPDSO 2009

POLVO July 2007

SEILLEAN Feb 2006

SEVAN PIRANEMA Oct 2007

CANADA

SEA ROSE (WHITE ROSE) Nov 2005

TERRA NOVA Jan 2002

US GOM

PIONEER 2010

MEXICO

BOURBON OPALE

TOISA PISCES

YUUM KAK NAAB June 2007

SOUTH EAST ASIA

CHINA

BOHAI MING ZHU Dec 2002

BOHAI SHI JI (CENTURY) Oct 2001

BOHAI YOU YI HAO Nov 2004

CHANG QING HAO (CNOOC 102)

Dec 2007

FEN JIN HAO 2004

GLOBAL PRODUCER VIII (Hai Yang Shi You 112)

Jul 2004

HAI YANG SHI YOU 111 Oct 2003

HAI YANG SHI YOU 113 Aug 2004

HAI YANG SHI YOU 117 (PENG LAI)

Q4, 2008

MUNIN Dec 1997

NAN HAI FA XIAN Nov 1994

NAN HAI SHENG LI Mar 1996

NAN HAI XI WANG 1996

NANHAI ENDEAVOUR (FEN JIN HAO)

Jul 2002

NANHAI KAI TUO 2000

WENCHANG ii 2008

XIJIANG (Hai Yang Shi You 115)

2009

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VIETNAM

BA VI 1993

CHI LINH 1985

CUULONG MV9 Oct 2003

RANG DONG I 1998

RUBY II Mar 2009

RUBY PRINCESS Oct 1998

SONG DOC MV 19 2008

INDONESIA

ANOA NAYUNA April 1990

BELANAK Dec 2004

BROTOJOYO Jul 2006

KAKAP NATUNA April 1986

MV 8 LANGSA VENTURE Dec 2001

SAN JACINTO 1994

THAILAND

JASMINE VENTURE MV 7 June 2005

RUBICON VANTAGE Jul 2008

TANTAWAN EXPLORER Feb 1997

MALAYSIA

BUNGA KERTAS LUKUT April 2004

KIKEH Aug 2007

PERINTIS April 1999

PHILIPPINES

RUBICON INTREPID Jun 2008

AUSTRALIA & NEW ZEALAND

AUSTRALIA

CHALLIS Dec 1989

COSSACK PIONEER Nov 1995

CRYSTAL OCEAN Nov 2005

FOUR VANGUARD (WOOLLYBUTT)

2003

FRONT PUFFIN Oct 2007

GRIFFIN VENTURE 1994

JABIRU VENTURE Aug 1986

MAERSK NGUJIMA-YIN Q3, 2008

MODEC VENTURE 11 Mar 2005

MONTARA VENTURE Q3, 2008

NGANHURRA Jul 2006

NINGALOO VISION 2009

NORTHERN ENDEAVOUR 1994

STYBARROW MV 16 Nov 2007

NEW ZEALAND

RAROA Q3, 2008

UMUROA Jul 2007

WEST AFRICA FPSOs

NIGERIA

ABO April 2003

AGBAMI Q3, 2008

AKPO Q4, 2008

ARMADA PERKASA Q3, 2008

BERGE OKOLOBA TORU LPG 2005

BONGA Nov 2005

EAT GORTUNE 2008

ERHA April 2006

KNOCK ADOON Oct 2006

MYSTRAS Jan 2004

SEA EAGLE (EA FPSO) Jan 2003

SENDJE BERGE Mar 2005

TRINITY SPIRIT 1997

USAN/UKOT 2012

ANGOLA

DALIA Aug 2006

GIMBOA 2008

GIRASSOL Dec 2001

GREATER PLUTONIO Oct 2007

KIZOMBA A Aug 2004

KIZOMBA B Jul 2005

KUITO Dec 1999

LPG SANHA Jan 2005

MONDO Jan 2