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Technological Trajectories in the Offshore Oil & Gas Industry
Dealing with Uncertainty in Ultra Deep Exploration in the South Atlantic
Leonardo de Jesus Durão dos Santos
Thesis to obtain the Master of Science Degree in
Mechanical Engineering
Supervisor: Prof. Manuel Frederico Tojal de Valsassina Heitor
Examination Committee
Chairperson: Prof. Mário Manuel Gonçalves da Costa
Supervisor: Prof. Manuel Frederico Tojal de Valsassina Heitor
Member of the Committee: Eng.º Cristiano Silva
May 2015
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Acknowledgments
I wish to express my sincere thanks to Professor Manuel Valsassina Heitor for his guidance
and availability throughout this thesis and for introducing me to such different areas of interest.
I would like to thank Engenheiro Rui Pimentel Santos for all the help and interview
opportunities he provided during my time at IN+.
To all interviewed specialists I want to leave here a word of gratitude for their valuable insights
to this thesis.
I wish to thank all my close friends to whom I will be eternally grateful for supporting and
encouraging me throughout the past years.
Last and most importantly, I would like to thank my parents for their never ending support,
patience and dedication.
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Abstract
The oil and gas industry is under major developments and changes with the discovery of new
ultra deepwater unconventional hydrocarbons reservoirs in the South Atlantic. New challenges raise
the question as to whether new disruptive technological paths should be explored as opposed to a
purely incremental innovation process. Therefore, the aim of this thesis is to study the processes of
technical evolution through technological trajectories, identifying the challenges and uncertainties
associated. The analysis of each technological trajectory and its key drivers was done through an
extensive literature review and interviews with specialists, complemented with a risk analysis based on
the IRGC risk governance framework.
This work identified three possible technological trajectories of development. The Continuity
trajectory is characterised by incremental innovations of technologies that were used before in a
similar context (e.g. FPSOs and wet completion), thus reducing technological uncertainty.
Nonetheless, developments based on this option might not forward a firm towards the technological
frontier.
The Intermediary trajectory aims to integrate common technological concepts within new
environments (e.g. Platforms with dry completion). Knowledge can be transferred to new fields with
limited technological risks but this trajectory limits the potential growth towards a leading market
position.
The Disruptive trajectory comprises radical innovations “subsea to shore” technologies,
eliminating the need for surface platforms. This trajectory represents large uncertainties but can lead
to an outstanding market position. However, there are a large number of technological and scientific
challenges that need to be overcome.
The work shows the complex interaction between technologies and environments and
acknowledges that no trajectory will be determinant by itself, but rather all of them will compete and
coexist with one other in different contexts. The analysis demonstrates the importance of flexibility in
engineering design to tackle the challenge of growing uncertainty in global markets.
Keywords:
Oil & Gas; Risk Governance; Ultra Deep Water; Platforms; Technology Development; Uncertainty
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Resumo
A indústria de petróleo e gás encontra-se em grande desenvolvimento e mudança com a
descoberta de novos reservatórios de hidrocarbonetos em águas ultra profundas no Atlântico Sul.
Novos desafios levantam a questão sobre os percursos que a exploração poderá seguir e se serão
percursos tecnológicos disruptivos, em oposição a processos de inovação puramente incrementais.
De tal forma, o objectivo desta tese é estudar o processo de evolução técnica por meio de trajectórias
tecnológicas, identificando os desafios e incertezas associadas. A análise foi feita por meio de uma
extensa revisão bibliográfica e entrevistas com especialistas, complementada com uma análise de
risco baseada no modelo de governança de risco desenvolvido pelo IRGC.
Neste trabalho foram identificadas três trajectórias tecnológicas de desenvolvimento. A
trajectória de Continuidade é caracterizada por inovações incrementais de tecnologias que foram
utilizadas anteriormente em contextos semelhantes (e.g. FPSOs e completação seca), reduzindo
assim a incerteza tecnológica. No entanto, desenvolvimentos baseados nesta opção podem não
lançar uma firma para a fronteira tecnológica.
A trajectória intermédia pretende integrar conceitos tecnológicos comuns em novos ambientes
(e.g. Plataformas com completação seca). O conhecimento pode ser transferido para novos campos,
limitando assim o risco tecnológico, mas esta trajectória limita o potencial de crescimento para uma
posição de liderança no mercado.
A trajectória Disruptiva engloba inovações radicais como as tecnologias “subsea para costa”,
eliminando a necessidade de plataformas à superfície. Esta trajectória representa grandes incertezas
mas pode levar a uma marcante posição de mercado. No entanto, existem elevados desafios
tecnológicos e científicos que precisam ser ultrapassados.
Este trabalho mostra a complexa interacção entre tecnologias e ambientes e reconhece que
nenhuma trajectória vai ser determinante por si só, mas todas irão competir e coexistir entre si em
diferentes contextos. A análise demonstra a necessidade de flexibilidade em projecto de engenharia
para enfrentar o desafio da crescente incerteza nos mercados globais.
Palavras-Chave:
Oil&Gas; Governança de Risco; Águas Ultra Profundas; Plataformas; Desenvolvimento Tecnológico;
Incerteza
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Contents 1. Introduction .....................................................................................................................................1
1.1. Motivation and Knowledge Gap ................................................................................................2
1.2. Oil & Gas Industry’s Value Chain ..............................................................................................3
1.2.1. The Upstream Sector Value Chain......................................................................................3
1.3. Offshore Production Facilities - Technological Overview ...........................................................5
1.4. The Pre-salt discoveries and the ultra-deep waters context .......................................................6
1.4.1. The technological challenges of the Pre-Salt ......................................................................7
1.5. Research Question and Thesis Outline .....................................................................................8
2. Scope and Methodology ..................................................................................................................9
2.1. Uncertainty in Engineering and Technological Trajectories ........................................................9
2.1.1. The Concept of Technological Trajectories and Technological Paradigm ............................9
2.1.2. Competition between Technological Trajectories .............................................................. 11
2.1.3. Potential technological trajectories for the Pre-Salt region ................................................. 12
2.2. Case Study Research ............................................................................................................. 13
2.3. Uncertainty Analysis and Risk Governance ............................................................................. 14
2.3.1. Concept definitions ........................................................................................................... 14
2.3.2. International Risk Governance Council Framework ........................................................... 16
2.4. Technological Trajectories: Processes of Technology Development ........................................ 17
3. Continuity Trajectory ..................................................................................................................... 19
3.1. Technological Systems ........................................................................................................... 19
3.2. FPSO engineering .................................................................................................................. 21
3.2.1. FPSO Design ................................................................................................................... 22
3.2.2. Rule Based Design ........................................................................................................... 22
3.2.3. Design Loads ................................................................................................................... 25
3.3. FPSO evolution ...................................................................................................................... 29
3.4. Case Study Analysis ............................................................................................................... 30
3.4.1. Case 1: Floating Liquefied Natural Gas (FLNG) Vessel ..................................................... 31
3.4.2. Case 2: Floating Production, Drilling, Storage and Off-Loading (FPDSO) vessel ............... 32
3.5. Current Challenges in Brazil & Future Developments .............................................................. 33
3.6. Risk Analysis .......................................................................................................................... 36
3.6.1. Benefits ............................................................................................................................ 36
3.6.2. Risks ................................................................................................................................ 37
4. Intermediary Trajectory ................................................................................................................. 38
4.1. Technological Systems ........................................................................................................... 38
4.2. Dry Tree vs Wet Tree.............................................................................................................. 42
4.3. Case Study Analysis ............................................................................................................... 43
4.3.1. Papa-Terra TLP................................................................................................................ 43
4.3.2. Deepwater Dry Tree Semisubmersible (DWDTS).............................................................. 44
4.4. Current challenges and Future Developments ......................................................................... 46
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4.5. Risk Analysis .......................................................................................................................... 47
4.5.1. Benefits ............................................................................................................................ 47
4.5.2. Risks ................................................................................................................................ 48
5. Disruptive Trajectory ..................................................................................................................... 49
5.1. Technological Systems ........................................................................................................... 49
5.2. Subsea Production System – The subsea factory ................................................................... 50
5.2.1. Subsea equipment evolution............................................................................................. 51
5.2.2. Subsea Market & Main challenges .................................................................................... 54
5.3. Case Study Analysis ............................................................................................................... 55
5.3.1. Case 1: SURF technologies.............................................................................................. 55
5.3.2. Case 2: Flow Assurance Technologies ............................................................................. 57
5.4. Choice of Development Concept – Platform or Subsea solution .............................................. 61
5.5. Risk Analysis .......................................................................................................................... 63
5.5.1. Benefits ............................................................................................................................ 64
5.5.2. Risks ................................................................................................................................ 64
6. Discussion and Summary .............................................................................................................. 65
6.1. Summary ................................................................................................................................ 65
6.2. Future scenarios for the Oil & Gas industry ............................................................................. 67
6.2.1. Growing Uncertainty: Risks and New Challenges.............................................................. 69
6.3. The Role of Industrial Policies ................................................................................................. 71
6.4. Opportunities for Portugal – Mechanisms of Development....................................................... 72
6.4.1. The OIPG - International Observatory of Global Policies for the Sustainable Exploration of Atlantic ....................................................................................................................................... 75
6.4.2. The +atlantic project ......................................................................................................... 76
6.5. Concluding Remarks .............................................................................................................. 78
6.6. Limitations and further work .................................................................................................... 78
Bibliography ...................................................................................................................................... 80
Annex A: Example FPSO Simplified Hull Design Procedure ............................................................ A
Annex B: Interviews Guideline Questions........................................................................................ B
Annex C: List of interviewed specialists .......................................................................................... C
Annex D: Interviews Transcript ....................................................................................................... D
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List of Figures
Figure 1.1: History of crude oil prices – Vertical grey areas indicate recessions ...................................2
Figure 1.2: 1, 2) conventional fixed platforms; 3) compliant tower; 4, 5) tension leg and mini-tension
leg platform(TLP); 6) spar; 7,8) semi-submersibles; 9) floating production, storage, and offloading
facility; 10) sub-sea production system and tie-back to host facility. .....................................................5
Figure 1.3: Santos Basin Pre-Salt Cluster ...........................................................................................7
Figure 2.1: Ideal trajectory of technology evolution ............................................................................ 10
Figure 2.2: Common process of technological evolution .................................................................... 11
Figure 2.3: IRGC Framework and respective phases ........................................................................ 16
Figure 2.4: Processes of Technology Development .......................................................................... 18
Figure 3.1: Technological evolution in FPSOs: Technology milestones and trajectories ..................... 20
Figure 3.2: FPSO vessel ................................................................................................................... 21
Figure 3.3: Main vessel hull dimensions ............................................................................................ 23
Figure 3.4: Number of operating FPSOs (based on data available at [33]) ......................................... 29
Figure 3.5: Processing plant capacity according to the number of FPSO projects as of 2014 ............ 29
Figure 3.6: Shell's FLNG plant........................................................................................................... 31
Figure 3.7: Azurite FPDSO with drilling derrick on the centre of the ship ............................................ 33
Figure 4.1: A-TLP; B-Spar Platform types; C-Semisubmersible ......................................................... 39
Figure 4.2: Technological Evolution of Platforms; Comparison of two deep water regions: GOM and
Brazil ................................................................................................................................................ 41
Figure 4.3: Papa-Terra P-61 TLP and P-63 FPSO in the back ........................................................... 44
Figure 4.4: Aker Solutions Dry Tree Semi .......................................................................................... 45
Figure 4.5: Long Stroke Tensioner (LST) and LSTs Array.................................................................. 45
Figure 5.1: Schematic view of possible subsea factory ...................................................................... 50
Figure 5.2: Principal advancements in Subsea equipment technology ............................................... 52
Figure 5.3: Technological evolution of subsea technologies: Milestones and trajectories ................... 53
Figure 5.4: Vortex Induced Motion (VIM) and Vibration (VIV) ............................................................. 56
Figure 5.5: Deepwater Gulf of Mexico oil phase diagram (APE: asphaltene precipitation envelope;
WAT: wax appearance temperature) (Source: [52] ) .......................................................................... 58
Figure 5.6: Hydrate Stability curve for a typical GOM gas condensate (Source: [53] ) ........................ 59
Figure 5.7: Hydrate formation in an oil dominant system ( Source: [54] ) ............................................ 59
Figure 5.8: Average recovery factors for fields with a platform and those developed with subsea wells.
Platforms are defined here as fixed structures with a drilling module (Source: [57] )........................... 62
Figure 6.1: Future plausible scenarios for the O&G industry (Source: [60] ) ....................................... 67
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List of Tables
Table 3.1: FPSO Phases - Main Characteristics (Source: Adaptation from) ...................................... 30
Table 3.2: Shipyard agreements made with international technological partners (Source: [41] ) ......... 34
Table 3.3: Benefits associated with the Continuity Trajectory ............................................................ 36
Table 3.4: Systemic risks associated with the Continuity Trajectory .................................................. 37
Table 4.1: Comparison of Wet and Dry Tree developments (Source: Author adaptation from [44] and
[2]) .................................................................................................................................................... 42
Table 4.2: Benefits associated with the Intermediary Trajectory ......................................................... 47
Table 4.3: Risks associated with the Intermediary Trajectory ............................................................. 48
Table 5.1: Different Flow Assurance Technology Areas (Source: Adapted from [55] ) ........................ 60
Table 5.2: Summary of advantages and disadvantages between the two concepts (Adapted from [56]
and [57]) ........................................................................................................................................... 62
Table 5.3: Benefits associated with the Disruptive Trajectory ............................................................. 64
Table 5.4: Risks associated with the Disruptive Trajectory ................................................................. 64
Table 6.1: Companies operating in Portugal with activities in the O&G sector .................................... 73
Table 6.2: Technological Platforms and respective challenges .......................................................... 77
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Abbreviations
ANP Agencia Nacional do Petróleo, Gás Natural
e Biocombustíveis (Brazil)
API American Petroleum Institute
APE Asphaltene Precipitation Envelope
AUV Autonomous underwater vehicle
BOP Blowout Preventer
BPD Barrels per Day
CAPEX Capital Expenditure
CENPES Centro de Pesquisas Leopoldo
Américo Miguez de Mello
COG Centre of Gravity
CFD Computational Fluid Dynamics
DTS Dry Tree System
DNV Det Norske Veritas
E&P Exploration and Production
EPC Engineering, Procurement and Construction
EPS Early Production Systems
EOR Enhanced Oil Recovery
LNG Liquid Natural Gas
FDI Foreign Direct Investment
FEED Front End Engineering Design
FLNG Floating Liquid Natural Gas
FSO Floating, Storage and Offloading
FSU Floating Storage Units
FPS Floating Production System
FPSO Floating, Production, Storage and
Offloading
FPDSO Floating Production, Drilling, Storage
and Offloading Vessel
GOM Gulf of Mexico
HTHP High Temperature and High Pressure
IRGC International Risk Governance Council
JV Joint Venture
LCP Local Content Policy
KBPD Thousands of Barrels per Day
MNE Multi National Enterprise
MODU Mobile Offshore Drilling Units
NCS Norwegian Continental Shelf
NPV Net-Present-Value
O&G Oil and Gas
OIPG International Observatory of Global
Policies for the Sustainable Exploration of
Atlantic
OPEX Operational Expenditure
PSV Platform Support Vessel
R&D Research and Development
ROV Remote operated vehicle
SURF Subsea Umbilicals Risers and Flowlines
TLP Tension Leg Platform
TTR Top Tensioned Risers
UAV Unmanned Air Vehicle
USA United States of America
VLCC Very Large Crude Carrier
WAT Wax Appearance Temperature
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1
1. Introduction
Increasing uncertainty in engineering in the oil and gas industry
Predictions appoint for a global population increase of 2 billion along with an economic growth
of 130 percent by 2040. As populations and economies continue to grow, so does the demand for
energy. It is estimated that 60 percent of this demand will be supplied by oil and natural gas (O&G),
showing the importance of this industry for many years to come.[1]
The increase in demand, followed by higher prices, along with the scarcity of easy-to explore
reservoirs, has been pushing the O&G industry to attempt exploration in unfamiliar areas with harsh
conditions as the deep sea. This trend of exploring further and deeper offshore was particularly
notable in the Brazilian offshore, where the state oil company Petrobras ordered a complete survey of
its continental shelf, leading to discovery of the pre-salt oil fields. The Brazilian pre-salt discoveries in
2007 leaded to a new technological frontier in the Oil and Gas sector. The large distances from the
coast (300 km) and high depths (up to 3000 meters of water column), together with the magnitude of
the reservoirs and oil characteristics, create a new paradigm for the exploration and production
offshore, especially from the technological point of view.
Despite the immense benefits that the pre-salt could give to Brazil, the technological risks are
high and depend on many key drivers that are subject to the increasing uncertainty in the global
markets. The price of hydrocarbons is still the main driver for project development and its volatility is
putting several projects on hold, not only in Brazil but in other regions as the North Sea for example. In
the past six months we witnessed a massive oil price drop from 110$, to a six-year low of nearly 50$
per barrel of crude. This will have repercussions throughout the industry, from the exploration to
refining and is putting some major oil exporting countries under a big pressure. However, the history of
oil has been always paved by instability since its early stages in the late 19th century. The most
important factor that affect oil prices are its availability on the world market, demand, and regulation of
prices and output through collaboration between oil-producing countries, which over the years has
been affected by events as wars or economic crisis. Some of the main events that shaped oil prices
since 1945 are the following:
1950: Korean War;
1956: Suez Crisis;
1967: Six-Day War;
1973: Yom Kippur War quadrupled the price of oil;
1979: Iranian Revolution;
1991: Gulf War;
1998: Economic crisis in Asia leads to a major fall in the price of oil;
2007-08: The financial crisis and unstable oil production first boosted prices and then
prompted a big drop;
2011: Arab Spring political unrest in Egypt, Lybia, Yemen, Bahrain and other
countries pushed up oil prices;
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Late 2014: The shale oil boom in the US and OPEC’s reaction not to reduce
production levels created an excess of oil in the market, dropping prices significantly.
Figure 1.1 shows a history of crude oil prices, where each the grey vertical bars represent the
recessions caused by some of the events aforementioned.
Figure 1.1: History of crude oil prices – Vertical grey areas indicate recessions
(Source: macrotrends.net/1369/crude-oil-price-history-chart - 5th of January 2015)
Given this scenario, the oil exploration industry is facing possible technological divides,
creating a need for a debate and reflexion on the future challenges facing the industry and on how
engineering can address the uncertainty context. This thesis aims to open the debate about
technological trajectories changes in the deep-water oil exploration.
1.1. Motivation and Knowledge Gap
The O&G industry is going through a phase of constant price volatility, significant technological
advancements, regulatory changes and opening to new areas of exploration and new markets. The
need to find new solutions to tackle the challenges of ultra-deep waters has become a key factor in the
industry. Companies are continuously searching for innovative concepts to understand and solve
situations that could not be considered before. Approaches that were used in the past few years are
also being adapted to the ultra-deep water context through incremental innovations.
Understanding how the evolution of O&G technologies influences the global production and
the international trends is of the utmost importance to understand the opportunities that may arise.
The motivation for this thesis is therefore to explore the technological trajectories in offshore oil and
gas exploration in ultra-deep waters, following these guidelines:
Give a brief overview of the O&G sector offshore, identifying the technological systems in use
today and the main challenges they face;
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Evaluate the three technological trajectories that can be developed in the pre-salt region, in ultra-
deep waters. The continuity trajectory, consisting of incremental innovations in systems already in
use. The intermediary trajectory, implementing platforms already used in different geographical
locations. The disruptive trajectory represents a radical innovation of subsea to shore
technologies. Each of these technologies represent different levels of technological risks and
benefits, therefore to better analyse each one and its limitations, two case studies will be
evaluated for each one;
Evaluate trajectories on a case study basis, using an extensive bibliographic research and
interview methodology;
Analyse the technological evolution and identify the future opportunities for the Portuguese
industry in the context of the +atlantic project.
1.2. Oil & Gas Industry’s Value Chain
The O&G industry is divided into three main segments: upstream, midstream and
downstream. The upstream sector consists of two phases, exploration and production (E&P).
Exploration refers to the search and prospection of new oil, gas or mineral reserves in different
geographies, while production consists of all the extraction operations of bringing the oil or gas from
the reservoir to the surface using artificial or natural methods.
The midstream segment includes the transport, storage and wholesale marketing of crude or
refined petroleum products. Pipelines and other transport systems present several challenges,
especially when considering the depths of some reservoirs.
The downstream sector refers to the refining of petroleum crude oil and the processing and
purifying of raw natural gas, as well as the marketing and distribution of products derived from those
raw materials. [2]
This thesis will focus on the upstream sector which is the most technology intensive.
1.2.1. The Upstream Sector Value Chain
A brief analysis of each segment of the upstream sector will be given. Seismic/ Reservoir Exploration
Consists on mapping the subsoil through the use of reservoir imaging systems technologies
and geological/geophysical equipment. The goal is to identify the types of rock, geological formations
and estimate the amount of oil available in the reservoir. This phase is conducted mostly by geologists
that analyse satellite images, small changes in Earth’s gravitational field and magnetic fields which
can be indicators of the presence of reservoirs. The most widely technique used offshore consist in
evaluating the seismic reactions of the subsea surface to a detonation or a compressed air-gun shot.
The reflection shock waves are then analysed by high sensitivity microphones and vibration detectors
giving the geologists a detailed map of the subsoil.[3]
4
Drilling and Completion of Wells
Once a reservoir is considered commercially viable, it is time to prepare the site for production.
Seismic analysis provides the best estimate for optimal drilling point, however it’s rare that the first
hole produces oil, therefore many holes are drilled in an iteration process to achieve the best one.
Offshore fields need support platforms for the drilling process. The most commonly used are
the MODU (Mobile Offshore Drilling Units). From these units a riser is launched, connecting the
surface to the seabed, carrying all the fluids necessary for the drilling and the drilling bits necessary to
penetrate the rock. During the drilling process several safety precautions must be taken into account.
One of the common problems is the imminent increase of pressure from the subsoil fluids, which is
controlled by the use of a Blowout Preventer (BOP).
When the desired depth is reached and oil is found, the well must be prepared for production,
this process is called completion of the well. The completion consists of cementing the well walls to
prevent it from collapsing, and to make sure that no oil mixes with the surrounding subsoil layers on its
way up. At the end of this phase the well is ready for extraction. [3]
Infrastructure, Production and Maintenance
Production of the hydrocarbons from the reservoir is done through a production riser, which
connects the well-head to the production platform. These risers are a very important part of the
process as they must endure harsh conditions on the sea, while carrying high pressure and high
temperature fluids inside. The extraction is made through a suction process which is powered by an
electrical system that feeds the extraction pumps. The oil flow is controlled by a structure called a
“Christmas tree”, which is essentially an assembly of valves, spools and fittings. The name comes
from the rude resemblance to a decorated tree. In cases where oil is heavy or the reservoir is reaching
its recoverable limits, it is necessary to create a second hole for the injection of water, gas or a mixture
of the two, so as to increase the pressure in the reservoir. The latter process is called Enhanced Oil
Recovery (EOR). [3]
Deactivation
After an analysis of the sustainability of the reservoir, and concluded its impracticality,
companies must conduct a process of plugging the reservoir. Additionally a clean sweep of the area is
also made, followed by the treatment of various natural surroundings and removal of infrastructures. It
is required by law to keep a check and monitoring of the field in post abandonment of the well. [3]
5
1.3. Offshore Production Facilities - Technological Overview
Over the years, the industry has developed a whole range of different structures to use on
offshore E&P, depending on size and water depth. Figure 1.2 gives an overview of the most common
offshore production facilities.
Figure 1.2: 1, 2) conventional fixed platforms; 3) compliant tower; 4, 5) tension leg and mini-tension leg platform(TLP); 6) spar; 7,8) semi-submersibles; 9) floating production, storage, and offloading facility; 10) sub-sea
production system and tie-back to host facility. (Source: [4])
Fixed platforms (Figure 1.2: 1,2) are built of concrete or steel legs and anchored directly onto
the seabed, supporting a deck with space for drilling rigs, production facilities and crew quarters.
These structures are indicated to shallow and calm waters.
Compliant towers (Figure 1.2: 3) consist of a narrow tower, attached to a foundation on the
seafloor and extending up to the platform. This tower is flexible, as opposed to the relatively rigid legs
of a fixed platform. Flexibility allows it to operate in much deeper water, as it can absorb much of the
pressure exerted by the wind and sea. These structures are used between 500 and 1,000 meters of
water depth.
Floating production platforms, where all topside systems are located on a floating structure
with dry or subsea wells. Some floaters are:
Tension Leg Platform, TLP (Figure 1.2: 4, 5) consists of a structure held in place by vertical
tendons connected to the sea floor by pile-secured templates. The structure is held in a fixed position
by tensioned tendons, which allow the use of the TLP in a broad water depth range up to about 1,800
meters. The tendons are constructed as hollow high tensile strength steel pipes that carry the spare
buoyancy of the structure and ensure limited vertical motion (heave).
SPAR (Figure 1.2: 6) consists of a single tall floating cylindrical hull, supporting a fixed deck.
The cylinder does not extend all the way to the seabed. Rather, it is tethered to the bottom by a series
of cables and lines. The large cylinder serves to stabilize the platform in the water, and allows for
movement to absorb the force of potential hurricanes. SPARs can be quite large and are used
for water depths from 300 up to 3,000 meters. SPAR is not an acronym, and is named for its
6
resemblance to a ship's spar. SPARs can support dry completion wells, but are more often used with
subsea wells.
Semi-submersible platforms (Figure 1.2: 7, 8) are platforms that are usually structured with
4 columns that are filled with sea water, allowing part of it to be submerged. This layout allows
more lateral and vertical motion and is generally used with flexible risers and subsea wells. These
platforms are widespread all around the world.
FPSO, Floating Production, Storage and Offloading vessels (Figure 1.2: 9) have the main
advantage of being a standalone structure that does not need external infrastructure such as pipelines
or storage. Crude oil is offloaded to a shuttle tanker at regular intervals, from days to weeks,
depending on production and storage capacity. FPSOs currently produce from around 10,000 to
200,000 barrels per day. An FPSO is typically a tanker type hull or barge, often converted from an
existing crude oil tanker. Due to the increasing sea depth for new fields, they dominate new offshore
field development at more than 2000 meters water depth. Most FPSOs use subsea wells. The main
process is placed on the deck, while the hull is used for storage and offloading to a shuttle tanker. The
offloading may be done to pipelines if there’s an existing infrastructure. FPSOs with additional
processing and systems, such as drilling and production of stranded gas LNG (Liquid Natural Gas) are
under consideration by several companies.
Subsea production systems (Figure 1.2: 10) are wells located on the sea floor, as
opposed to the surface. As in a floating production system, the petroleum is extracted at the seabed,
and is then “tied-back” to a pre-existing production platform or even an onshore facility, limited by
horizontal distance or "offset.” The well is drilled by a movable rig and the extracted oil and natural gas
is transported by subsea pipelines to a processing facility. This allows one strategically placed
production platform to service many wells over a reasonably large area. Subsea systems are typically
used at depths of 500 meters or more and do not have the ability to drill, only to extract and transport.
Drilling and completion is performed from a surface rig. Horizontal offsets of up to 250 kilometres are
currently possible. The aim of the industry is to allow fully autonomous subsea production facilities,
called subsea factories with multiple wellheads, processing, and direct tie-back to shore or a nearby
unit. [2]
Regarding water depth categories, the following are usually used: shallow water (0 –
299 meters), midwater (300 – 1199 meters), deepwater (1200 – 2199 meters), ultra-deep water(2200+
meters).
1.4. The Pre-salt discoveries and the ultra-deep waters context
In 2001, in order to start prospection of the new areas obtained in Santos Basin, Petrobras
ordered what proved to be the biggest effort of acquisition and interpretation of seismic data ever done
to date. The company’s engineers were convinced of the presence of hydrocarbons in the region
under the salt layer, due to the dimensions of their geological structures and to the sealing properties
of the salt, which increases the probability of containing oil.
7
The interpretation of the results in 2003 indicated real possibilities for the existence of
hydrocarbons; however the drilling wells would need to go through a layer of salt 2.000 meters thick, in
a water depth of more than 2.000 meters, operating in harsh conditions, 300 kilometres from shore.
Figure 1.3: Santos Basin Pre-Salt Cluster ( Source: [5] )
After several months of planning, the first region selected to explore was the area of Parati
(Figure 1.3) due to the knowledge and experience available about the geological structure above the
salt layer. In 2006, the well reached a depth of 7.600 meters and the presence of condensate gas, a
light component of petroleum, pushed forward the drilling of another well in the area of Tupi. Here, in
September 2006, Petrobras announced the findings of good quality oil of 28˚ API1, starting the pre-salt
era for the Brazilian offshore industry.
1.4.1. The technological challenges of the Pre-Salt
The discoveries of the pre-salt oil reservoirs pose many technical challenges to exploration
and production. One of the first challenges is associated with the type of reservoir. The knowledge
about the geological structures containing the hydrocarbons (carbonate rocks) is still limited and poses
a challenge when applying seismic technologies to the reservoirs.
The costs of drilling in very deep waters and under a salt layer are extremely high, the average
cost of drilling a well in the pre-salt is a US$1 Million/day with drilling operations lasting around 60
days. High pressures, lack of stability and salt corrosions are the main adverse factors.
Subsea pumping and separation is an important area with high investments. Some projects
started being developed by Petrobras and are now taking a new approach to tackle the pre-salt
challenges.
1 Oil quality is measured according to the API scale, developed by the American Petroleum Institute (API), in
which oil with density over 30º API is classified as light, while heavy oil has less than 19º API, and has a high viscosity and density.
8
Another determinant characteristic of the pre-salt reservoirs is the presence of contaminants,
with high concentration of CO2 and H2S present on the hydrocarbons, posing a high environmental
risk if released to the atmosphere. CO2 together with H2S render the fluids highly corrosive, which
requires expensive, more resistant materials as composites to be applied to production risers and
other facilities. Finding new cheaper materials to reduce costs is a possible solution. Separating and
reinjecting it back to an underground reservoir is one of the possibilities under development by
Petrobras and other companies.
There are also challenges in assuring the safe flow of the produced liquids and gases from the
wellbore to the offloading tanks. The high pressures and low temperatures under the sea can result in
hydrate or wax (paraffin) deposition, obstructing the flow and eventually halting production, causing
high economic losses. Flow assurance technologies are of the utmost importance for field
development and in the pre-salt they also face the challenge of acidity in the flow, causing pipe
corrosion, due to the high contents of contaminants. [6]
1.5. Research Question and Thesis Outline
This thesis aims to identify current technological challenges that are arising from newly
discovered pre-salt fields and related uncertainties associated with technological developments.
Technology innovation follows its own path according to the selection context and, as it will be shown,
a change in context changes the paths and creates new opportunities for development. These paths
are the technological trajectories.
Following this introductory chapter, comes a chapter with the concept definitions and
methodology. The methodology employed is based on a risk analysis evaluation and on case study
research, where, for each trajectory, one will present two case studies of innovative technologies
within the said technological path. Each trajectory was studied with and extensive literature review on
the topic, backed by several interviews to people in the industry and academia. Interview guidelines
and the list of specialists are available in annex B and C, respectively. A transcript of the most
important topics raised in the most relevant interviews is available in annex D.
In the last chapter, the knowledge gained from all the three trajectories is integrated in the
global scenario of the oil and gas industry, taking into account the big unknowns and the growing
uncertainty in the global economy. The perceived opportunities arising from technological change are
integrated within the +atlantic project, promoted by the OIPG, which consists on an international
agenda aimed to promote the scientific, technological and industrial capacity of Portugal towards the
sustainable exploration of Atlantic
9
2. Scope and Methodology
The oil and gas industry is in constant technological evolution. This evolution path, or
technological trajectory, changes and is shaped as new challenges emerge. This is a process paved
by uncertainty and associated risks that must be taken into account in order to help develop strategies
to maximize the benefits of a certain technological improvement or design approach.
In this chapter, the methodology used to evaluate the risks and benefits of each trajectory will
be presented. First, a brief overview of the concepts used throughout this thesis is given, followed by
the definition and validity of case study analysis. Last, the risk governance methodology will be
presented based on the International Risk Governance Council (IRGC) Framework.
2.1. Uncertainty in Engineering and Technological Trajectories
2.1.1. The Concept of Technological Trajectories and Technological Paradigm
Before proceeding, it’s important to define the concepts we’ll be using throughout the rest of
this thesis. The first one is the concept of technological paradigm, where the concept of technological
trajectory is inserted.
According to [7], a technological paradigm can be defined as a model and pattern of solutions
for selected technological problems, based on selected principles derived from natural sciences on
selected material technologies. Historically, the emergence and diffusion of new technological
paradigms have been closely associated with the rise of interrelated and pervasive radical innovations
which had the potential to be used in many sectors of the economy and to drive their long-run
performance for several decades.
Thus, the concept of technological paradigm does not simply describe a set of structural
techno-economic features in a static sense, but is inherently related to the dynamic behaviour of the
system, i.e. the growth potential that any given set of interrelated and pervasive radical technologies
entails.
The exploitation of such technological and economic potential proceeds along well-established
directions, the technological trajectories. So the technological trajectory is defined as the set of
evolutionary and cumulative characteristics that influences development and changes, experienced by
technology diffusion when used in production and services. [8], [9]
Technological change can also be conceptualized as a socio-cultural evolutionary process of
variation, selection, and retention. Variation is driven by technological discontinuities. As the core
technology of an industry evolves through long periods of incremental change, it will eventually be
punctuated by times when radical, new superior technologies displace old and inferior ones. [10]
“Radical” technological change will be associated with a movement up the design hierarchy,
i.e. when existing core concepts are challenged. Along the same lines, the notions of technological
paradigms are easily associated with the concept of technological discontinuities.[11]
10
So, old technologies can be substituted by new ones or improved with incremental changes,
suggesting that each technology has a life cycle. Thus, technological trajectories have their own
characteristics, such as the fact that they cross certain evolutionary stages. Meaning that progress is
slow in the early stages of development as the industry struggles with basic uncertainties, faster as the
early knowledge is acquired and slow again as the natural limits of the technology are reached.[12]
This ideal evolution process is illustrated in Figure 2.1.
Figure 2.1: Ideal trajectory of technology evolution (Source: cje.oxfordjournals.org/content/34/1/185/F1.large.jpg - 24th April 2015)
The acceleration of technology exchange during the past decades has rendered technological
evolution more complex, resulting on a constant combination of radical and incremental innovations.
Hence technological trajectories tend to follow a path similar to Figure 2.2, where a radical innovation,
in the form of a new product or process, opens up a new avenue of development. Depending on the
type of technology, the process can take a few months or several decades, until a new discontinuity
starts a new cycle. These innovations consist in the introduction of new production processes or the
considerable improvement of the existing ones by integrating different technologies.
In Figure 2.2, the radical innovation that results in the second curve originates a technological
discontinuity. This results in a technology initially not so widespread in the markets, hence the lower
level of the second curve in technology performance, which is followed by a period of intense
experimentation and optimization. The integration with the market determines the direction of the
following efforts of R&D which will originate in a series of incremental innovations.
Radical innovation
Tech
no
logy P
erf
orm
ance
Trajectory
defined (and
dominant design)
Trajectory
constricted
Time
Exploratory improvements
(design open)
Clear direction for
accelerated
improvements
Maturity
11
Figure 2.2: Common process of technological evolution
(Source: adapted from [13])
2.1.2. Competition between Technological Trajectories
According to [14], technologies are interdependent. Advances in a given technology rely on
advancements of other technologies, making the process complex with sometimes unexpected
outcomes. From this point of view, technological change is a phenomenon of clustering innovations.
Freeman and Perez, in [15], define the concept of the technological system as a set of radical and
incremental cross-linked innovations. Under certain conditions, the competition among technologies
can be regarded as the competition among technological systems. The choice of a dominant
technology becomes a competition between companies or even between national economies.
The search for efficient sets of technologies is a complex process governed by firms. Full of
failures and successes, technological learning is a key aspect of the process. Firms move their
innovation activities through technological trajectories, creating evolutionary patterns that lead to a set
of cumulative technological characteristics, eventually diffused in the production of goods and
services. A technological trajectory is standard way of solving problems within the framework of a
certain technological paradigm. [7], [9]
Technological trajectories are shaped by the selection context (a range of social, institutional,
economic and environmental situations) in which the firm operates. Often the decisions a firm faces for
any given circumstance is limited by the decisions one made in the past, even though past
circumstances are no longer relevant. This phenomenon is called path dependence, and provides a
useful platform to understand stability and change in the trajectories of firms and technologies
embedded in complex industrial networks. [16]
Although the selection contexts are influenced by the firm itself, its institutional setting is very
relevant: regulations and laws can facilitate or restrain the use of new technologies. There is always a
certain degree of uncertainty in the economic performance of new technologies. The ability of the
Radical innovation
Tech
no
logy P
erf
orm
ance
Time
Incremental innovations
Radical
innovation
Technological discontinuity
12
regulatory setting to mitigate the risks associated to these uncertainties is a crucial aspect of the
innovation process.
Firms move along technological trajectories through evolutionary stages as stated before. At
the early stage, a wide spectrum of possibilities and multiple concepts can be explored and there is
plenty of room for radical innovations. The expected economic performance of the innovations is
fundamental to choose winning concepts. At this stage, product innovations are more important and,
most often, several technological concepts are competing, each one having the potential to become
dominant. As the company moves along the technological trajectory, the number of technological
concepts in competition is gradually reduced.
After a dominant concept prevails, a more predictable avenue of innovation opens. The search
for economies of scale becomes a central aspect of the process and the incremental innovations
become increasingly relevant aspect of it. Notably, once a technology is adopted by a large group of
firms, it becomes dominant despite the fact that larger economic benefits can be expected from other
technological trajectories. This situation typifies what the literature calls a technological lock-in,
meaning that firms are reluctant to take risks associated with the adoption of different, although more
efficient, innovations. [12], [14]
Technological lock-ins are usual when a new trajectory is too risky in offering a predictable
economic return and breaking out is most often related to a radical change in the selection context of
the firm. According to [17], there are six reasons for breaking out of a lock-in situation: a
technology crisis; new regulations; technological breakthroughs; changes in demand patterns;
emergence of niche markets and scientific advances. These factors are largely associated with
changes in the learning process and the technology selection context. [16], [18]
Petrobras’ technological trajectory offers a good example on the roles played by the selection
context in the innovation process. So far, geology was determinant to finding offshore oil reserves but
its selection context was largely determined by geopolitics and the domestic regulations. The
emergence of a technological break-through such as fracking or a subsea factory is likely to disrupt
the selection context in which Petrobras has been moving so far. Indeed, the technological
competition between the supergiant oil fields of the Brazilian pre-salt and the shale resources of North
America is just starting. However, the competition is not limited to offshore versus onshore, within the
offshore segment presenting several evolutionary possibilities in the future. Regulatory frameworks in
oil exporting countries, especially as the environmental regulations are concerned, will have a
determinant role in the innovation process. [19]
2.1.3. Potential technological trajectories for the Pre-Salt region
The discovery of the Pre-salt fields changed the oil exploration scenario because, despite the
enormous economic potential of these reserves, they represent large technological obstacles.
Therefore, Petrobras and other companies are evaluating the possibility of using new offshore
production systems to tackle these challenges.
13
The real question that exploration companies ask nowadays is if the pre-salt and ultra-deep
waters represent a true technological divide from what was done in the past to what can be done
nowadays. This answer is not a trivial one, and although companies are investing more and more in
research and development for ultra-deep waters exploration, the road is still uncertain, with some
companies still focusing more on less risky and less technological intensive operations onshore or on
shallow waters.
On the Brazilian offshore, Petrobras, which on December 2014 reported a record production of
2.3 million barrels/day, plans to increase production to 3.3 million barrels/day by 2016 according to its
investment plan. To keep up with these numbers, the company is evaluating the feasibility of dry tree
systems concepts never employed before in Brazil. Other possibilities include subsea technologies
that would eliminate the need for platforms.
In a large scale, three technological trajectories that could be followed in the following years
were identified:
Continuity: incremental improvement of the technologies that were adopted in the post-salt
reserves (Campo’s Basin) where FPSOs, wet completion and flexible risers have a
determinant role;
Intermediary: implementing dry completion systems as the Tension Leg Platform (TLP),
SPAR Platform or new semisubmersible systems using dry trees;
Disruptive: “subsea to shore” technologies that require radical innovations leading to the
concept of subsea factory, which would eliminate the need of platforms.
Different technological trajectories have different risks and potential benefits associated, and
the choice will not be solely determined by the pre-salt technology but also by Brazilian regulations
and industrial policies. The three options don’t necessarily represent an overcoming of one over the
other, as the three of them will coexist and compete between them.
These trajectories will be analysed individually in the following chapters based on a case study
research method. The method’s advantages and its applicability to this context are explained in the
following section.
2.2. Case Study Research
In the following chapters, the analysis of each of the technological trajectories will be
supported by two case studies that follow an extensive literature review and interviews with experts in
academia, scientific institutions and industry. Case studies may involve multiple cases and numerous
levels of analysis, for example literature review, interviews and field work. The scope of a case study
is to investigate a contemporary phenomenon within its real-life context, especially when the
boundaries between the phenomenon and context are not clearly evident.
According to [20], case study research is a powerful method when “how” or “why” questions
are being posed, when the investigator has little or no control over the events, and when the focus is
14
on a contemporary phenomenon within some real-life context. All the three conditions are applicable
to the research questions of this thesis.
The process, like other research strategies, is a way of investigating an empirical topic by
following a set of specified procedures, such as: defining the research questions, specify the
population in case, select more than one data collection methods, have multiple investigators to
combine different data, overlap data and opportunistic data collection, analysing data, comparison with
conflicting literature and reaching closure. [21]
This method of generating theory presents the advantage of constant juxtaposition of
conflicting realities, forcing the research to widen his thinking, resulting in a process that it’s less
affected by previous preconceptions. The resulting theory is also closely linked with evidence, where
the investigator answers to the data from the beginning of the research. This tight interaction often
results in theory with a close link to reality.
However, some characteristics that lead to strengths, may also lead to weaknesses. The
intensive use of empirical evidence may lead to theory that is overly complex due to the staggering
volume of data, resulting on a theory that’s rich in detail, but lacks the simplicity of an overview
perspective.
The key to a good cross-case comparison is to look at the data in several different divergent
ways. The first tactic used was to select categories and then look for within-group similarities and
differences. This was done by approaching each of the three different technological trajectories
individually. In each trajectory, a pair of cases was analysed and then compared. This tactic forces the
researcher to look for similarities and differences between cases. Multiple cases extend external
validity and help against the observer biases. [21], [22]
2.3. Uncertainty Analysis and Risk Governance
A risk governance framework is a comprehensive approach that aims to help understand,
analyse and manage important risk issues for which there are deficits in risk governance structures.
By designing policies, regulatory frameworks and industrial strategies it is possible to deal with the
uncertainty that characterises the oil and gas industry.
2.3.1. Concept definitions
In order to better understand the risk framework used throughout this thesis, it’s important to
clarify some key-words and concepts first.
Risk is an uncertain (generally adverse) consequence of an event or activity with respect to something
of value. Risks are often accompanied by opportunities. [23]
Systemic risks are embedded in the larger context of societal, financial and economic consequences
and are the intersection between natural events, economic, social and technological developments e
policy-driven actions. The governance of systemic risks requires cohesion between countries and the
inclusion within the process of governments, industry, academia and civil society.[23]
15
Governance refers to the actions, processes, traditions and institutions by which authority is
exercised and decisions are taken and implemented. [23]
Risk Governance is defined as the identification, assessment, management and communication of
risks in a wide context. It includes the totality of actors, rules, conventions, processes and
mechanisms and is concerned with how relevant risk information is collected, analysed and
communicated, and how management decisions are taken. Risk accompanies change. Many risks,
and in particular those arising from emerging technologies, are accompanied by potential benefits and
opportunities.[23]
Complexity refers to difficulties in identifying and quantifying casual links between a multitude of
potential causal agents and specific observed effects. Complex Systems are by definition composed
of many parts that interact with and adapt to each other.
Uncertainty refers to a lack of clarity or quality of the scientific or technical data. Ambiguity results
from divergent or contested perspectives on the justification, severity or wider meanings associated
with a given threat.[23]
Technology-related emerging risks are of the utmost importance for the analysis pursued in
this thesis. They can be inserted in three broad categories:
A. Risks with uncertain impacts, with uncertainty resulting from advancing science and
technological innovation. The dominant feature of this category is a lack of knowledge and experience
about consequences that could result from deploying new technology, in the form of new processes
and products. The governance issues for category A risks deal with the decision to allow such
technology in commerce, and the implementation of appropriate risk management measures to avoid
or mitigate potential adverse consequences. Current examples include products and processes in
nanotechnology or synthetic biology. [24]
B. Risks with systemic impacts, stemming from technological systems with multiple interactions
and systemic dependencies. The defining feature of category B risks is a loss of safety margins due to
high levels of connectivity and interdependence. The main issue here is not the risk of the
technologies (this may be known or well-estimated), but the interactions of these risks with other types
of risks or activities that could lead to non-linear impacts or surprises. Examples of complex
interconnected systems are numerous in energy, transportation, communication, and information
technology.[24]
C. Risks with unexpected impacts, where new risks emerge from the use of established
technologies in evolving environments or contexts. The main problem here is that the potential
impacts of familiar technologies (both in terms of probability and magnitude) may be altered if they are
operated in a different context or organisational setting. Governance of these risks would seem well
established, but may in fact be inadequate. The change in context that can lead to a risk emerging
may involve ageing of infrastructure, complacency, and/or overconfidence in the ability to deal with
unexpected events. The commercial aviation industry provides a useful example of the importance of
effectively managing category C risks. [24]
From the categories listed before, one can think of many examples in the oil and gas industry
fitting into one, or several of them. Technical uncertainties are not determined by the changes in
16
nature alone, but are dependent on available knowledge about markets, since technology will
determine available product specifications, which in turn are constrained by acceptable market
opportunities. Thus technical and market/commercial risks are not clearly separable. For a given level
of technical knowledge, the more one knows about markets, the lower the technical risk. [25]
2.3.2. International Risk Governance Council Framework
The IRGC’s framework purpose is to give guidance in handling risk, even in situations of high
complexity, uncertainty or ambiguity. It can help detect current or potential deficits within the risk
governance process and encourages people to raise the relevant questions. By taking into full account
the societal context, the variety of risk cultures around the world and the role played by stakeholders, it
emphasises the crucial role of communication. The framework therefore offers an interdisciplinary and
multi-level governance comprehensive approach comprising the following steps:
1. Pre-assessment
2. Appraisal
3. Characterisation and evaluation
4. Management
5. Communication
These general categories, when interconnected and correctly applied to the different
problems, provide a thorough understanding of a risk and options to deal with them. However, the
framework should not be regarded as a rigid set of methods for risk analysis, but rather as an
overview of the potential for risk analysis to assist in improving risk governance. Figure 2.3 gives an
overview of all the 5 phases of the framework and how they interconnect between each other.
Figure 2.3: IRGC Framework and respective phases (Source: [23] )
17
IRGC’s approach begins with risk pre-assessment. It aims to clarify and frame into context the
various perspectives on a risk, defining the issue to be looked at and forming the baseline for how a
risk is assessed and managed. Mainly it addresses two key points:
The variety of issues that stakeholders and society may associate with a certain risk, and the
related opportunities;
Existing indicators, routines and conventions that may help narrow down what is to be
addressed as the risk, as well as the manner in which it should be addressed. [23]
Risk appraisal develops and synthetises the knowledge base for the decision on whether or
not a risk should be taken and, if so, how the risk can possibly be reduced or contained. Risk appraisal
comprises both a scientific risk assessment – a conventional assessment of the risk’s factual,
physical and measurable characteristics including the probability of it happening – and a concern
assessment – a systematic analysis of the associations and perceived consequences (benefits and
risks) that stakeholders, individuals, groups or different cultures may associate with a hazard or cause
of hazard.[23]
The characterisation and evaluation phase is intended to ensure that the evidence based on
scientific facts is combined with a thorough understanding of societal values when making the
sometimes controversial judgement of whether or not a risk is “acceptable” (risk reduction is
considered unnecessary), “tolerable” (to be pursued because of its benefits and if subject to
appropriate risk reduction measures) or, in extreme cases, “intolerable” and, if so, to be avoided. [23]
The forth step is the management of the risk itself. After the definition of a risk as tolerable and
acceptable, appropriate and adequate risk management must be made. Risk management includes
the generation, assessment, evaluation and selection of appropriate risk reduction options as well as
implementing the selected measures, monitoring their effectiveness and reviewing the decision if
necessary.
The final phase, communication, enables stakeholders and civil society to understand the risk
itself by allowing them to recognise their role in the risk governance process and giving them a voice
in it. This phase is of the utmost importance because its effectiveness is the key to create trust the risk
management decisions.
In the context of this thesis, focus will be given mainly to the appraisal phase, more precisely
to the concern assessment where an analysis of benefits and risks is made to each technological
trajectory.
2.4. Technological Trajectories: Processes of Technology Development
The selection context has a great influence on the path technological evolution takes. In the
case of oil and gas exploration technologies, the context is highly dependent on the characteristics of
newly discovered fields. In Figure 2.4, some of these characteristics are presented, originating in the
trajectories of technological innovation.
18
Figure 2.4: Processes of Technology Development
Environmental Conditions:
Climate, geology, sea
environment
Long distances: Platform - Well
Platform - Shore
Subsea operations not visible or
accessible to humans
High levels of CO2 Oil viscosity
Technological Challenges
Cooperative actions of R&D: oil companies, universities, research centers, service and equipment companies
CONTINUITY
Incremental innovations
Low Technical uncertainty
Reduced R&D investment
Short/medium term
effectiveness
New technologies based on
a matured concept, e.g.
FPSOs and wet completion
INTERMEDIARY
Technology adaptation to new
environments
Moderate Technical
uncertainty
Moderate R&D investment
Short/medium term
effectiveness
Application or integration of
technologies matured in other
environments, e.g. Floating
platforms in the Gulf of Mexico/
/ North Sea
DISRUPTIVE
Disruptive innovations
High Technical uncertainty
Heavy R&D investment
Long term effectiveness
Can lead to market leading
technologies
New concepts of oil
exploration, e.g. subsea
factory
Trajectories of Technological Innovation
19
3. Continuity Trajectory
When Petrobras faced the challenge of oil exploration on deeper waters in the 80’s, instead of
investing in radical innovations, developing and adopting completely new systems of production, it
opted for a technological strategy of incremental nature, consisting on the development and perfection
of the system the company dominated at the time, the FPSO (floating, production, storage and
offloading vessel). [26]
In this chapter one will dwell further into this trajectory and the main challenges it faces
nowadays. The analysis will start with a general overview of the basics in the engineering design
process of an FPSO hull and topsides, followed by two case studies of innovative topside technologies
and it finalizes with a risk analysis that presents the risks and opportunities associated.
3.1. Technological Systems
The oil and gas industry has been using vessels in offshore field development since the
1950s. The first ship shaped rig was used in the Gulf of Mexico in 1956 as a drilling rig, being capable
of drilling in water depths of up to 180 meters. Soon the versatility of vessels (in contrast to fixed
platforms) became evident and several new concepts were developed. Nowadays vessels are used
extensively, floating systems include:
Drillship (Vessel with drilling rig);
FSO (Floating, Storage and Offloading systems);
FPS (Floating, Production Systems);
FSU (Floating Storage Units);
FPSO (Floating, Production, Storage and Offloading systems);
Circular FPSO (Circular shape designed to withstand harsh sea conditions);
FLNG (Floating Liquid Natural Gas Vessel);
FPDSO (Floating Production, Drilling, Storage and Offloading Vessel);
PSV (Platform Support Vessels – Transportation of Supplies, Cargo and other equipment);
Pipe-laying Ships (Vessel used in the construction of Subsea infrastructure);
Diving/ROV Support Vessel (Floating base for ROV/diving operations);
Survey Vessel (Seismic survey vessels that locate offshore oil and gas reserves);
VLCC (Very Large Crude Carrier)
The range of technological systems is vast and the evolution of each one of them could be
further studied. In the context of this thesis one will analyse in detail the ship shaped FPSO due to its
relevance to the South Atlantic oil exploration. It’s important to note that some of these systems share
many similarities, consisting of evolutions of previous technologies thus their evolution being closely
related. This process of constant evolution is illustrated in Figure 3.1, which follows the history of
FPSO development within cycles of developments along some of the most important milestones.
20
1977 1995 2000 2010 2015
Spain, Mediterranean Sea The first FPSO was built for 120m of water depth. Shell Castellon
Brazil, Campos Basin Brazil’s first FPSO P.P. Moraes (later P-34) gets first oil as an EPS in 1979 with a 60kbpd processing capacity.
North Sea In 1993 the Gryphon
FPSO was the first to be placed on the N.S.
(110m water depth) by Kerr McGee
North Sea 1998: 16 operating FPSOs
1977-1995 The number of FPSOs was rising quickly, but they were mainly used as Early Production Systems (EPS). They lacked water injection and gas compression process plants. Processing capacity around 60kbpd.
Time
Technolo
gy P
erf
orm
ance
Brazil FPSOs showed higher op. efficiency When compared to fixed platforms or semis
Brazil, Campos Basin FPSO get full water
injection facilities and processing capacity of
100kbpd. P-31/p-33/P-35/P-37
1995-2000 Processing capacity increased to an average of 100 kbpd. Efficient operations and construction became a key factor, requiring a system of modularization construction.
Brazil, Campos Basin P-50 FPSO with a prod. capacity of 180kbpd, spread mooring and modularization construction
North Sea 1997: Norne FPSO is deployed at 380m water depth
Brazil, Santos Basin 2007: Pre-salt discoveries reinforce the role of the FPSO and raise the challenge of high CO2 content and higher depths
2000-2010 Processing capacity increased to an average of 180kbpd. The pre-salt raised the CO2 challenge. Higher productivity and storage tankers optimisation/size may only be achieved with newbuild hulls.
Brazil Standard FPSOs produce 180kbpd and modularization and standardization is enhanced with 8 equal FPSO being developed (replicantes)
Gulf of Mexico 2012: First FPSO deployed in the GOM, BW Pioneer, at 2500m water depth. Operated by Petrobras Americas.
North Sea Most advanced cylindrical FPSO developed, SEVAN 1000. This shape is better suited for harsh conditions. Prod. Capacity: 100kbpd 400 meter water depth
Incremental Price drop puts projects on hold; Lower investment on R&D; Focus on cost savings.
New Generation New systems with capacities up to 300kbpd and enhanced CO2 treatment facilities. New build hulls might become more
common.
2010-2015 Pre-salt challenges require new materials/process resistant to corrosion. Production capacity increases slight globally, with units producing 200kbpd. Standardization becomes key.
Figure 3.1: Technological evolution in FPSOs: Technology milestones and trajectories
21
3.2. FPSO engineering
A floating production, storage and offloading (FPSO) (Figure 3.2) unit is a vessel used by
the offshore oil and gas industry for the production, processing and for storage of hydrocarbons. An
FPSO vessel is designed to receive hydrocarbons produced by itself or from nearby platforms or
subsea templates, process them, and store them until offloading onto a tanker or, less frequently,
transported through a pipeline.
Figure 3.2: FPSO vessel (Source: rigzone.com/training/images/5700.jpg - 1st December 2014 )
FPSOs have been preferred in frontier offshore regions due to their versatility, and not
requiring an infrastructure to export oil. The key components of an FPSO are:
The vessel which may be a new build or, more usually, a tanker conversion;
The mooring system, which may be built upon a geostationary turret mounted inside the hull, which
leaves the vessel free to rotate to head into the prevailing weather. Or spread mooring, where the
vessel is stationary with surrounding mooring points in a circular shape.
The process plant, or topsides, whose configuration will depend largely on reservoir characteristics
and environmental factors; water and/or gas injection and gas-lift facilities are commonly included.
The world has approximately 200 FPSOs and about 60% are converted tankers. Although
there has been a shift toward new builds, very large crude carrier (VLCC) tanker conversions remain
the basis for projects in areas where benign environmental conditions (mild sea waves and swells) are
predominant, such as off West Africa, Southeast Asia, Australia, and Brazil.[27]
FPSOs are being increasingly used for deeper waters and a variety of functions related to
offshore drilling, production and storage, because of the following distinct advantages:
Capacity for internal storage and offloading
Commercial pressure for reducing capital cost
Commercial pressure for shorter lead times
Ease of reusability and decommissioning
22
New building yards, especially in the Far East (South Korea, Malaysia and Singapore for
instance), produce annually a significant number of ships. The FPSO hull is assembled from a large
number of “blocks” which are pre-outfitted and painted up to an advanced stage. The assembly period
in the building dock is normally only 8 to 12 weeks. In order to achieve such a tight schedule,
extensive and detailed planning is inevitable and critical to the overall yard performance. Since the
capacity of the yard's workshops and block storage area is matched to keep up with the dock capacity,
design changes are very difficult to incorporate once steel cutting has started. Late design changes
may impact the delivery time of many vessels and can therefore be unacceptable to the yard, even
when the owner is willing to pay for the change.
The issue referred before is characteristic to new building yards and, to a lesser extent,
conversion/repair yards. In general conversion/repair yards are more familiar with the offshore
approach. Here also the ability to implement late design changes is better, although they will result in
change orders and corresponding claims.
3.2.1. FPSO Design The design process of the FPSO starts by choosing the production capacity, followed by the
choice of modules and then the hull structural study. Challenges arise from the different design
practices and codes, quality standards, and maintenance philosophies used by the oil and gas and
marine industries, therefore FPSO engineering carries aspects from two cultures, shipbuilding and
offshore. The knowledge of ship design and offshore structures must be combined successfully to
achieve an efficient design. In this section, the main technical aspects of designing an FPSO vessel
are discussed in detail with a special focus on converted vessels and topsides integration.
Hull Design Philosophies
Some FPSOs are being converted from tankers that have been designed using a traditional
Class Rule type approach while other FPSOs are being designed according to more advanced
hydrodynamic / finite element calculation methods. It is often argued that the traditional design
procedures of FPSOs are based on simplifying component-based approaches that may underestimate
the loading (in comparison to advanced hydrodynamic models) but provide a large factor of safety on
the capacity. Results from some recent studies seem to indicate that the two approaches will result in
consistent safety factors against hull longitudinal failure.[28]
Since the FPSOs ordered by Petrobras are conversions, we’ll review the design philosophy
behind the Class Rule type approach.
3.2.2. Rule Based Design
The rule-based approach relies on using component-based expressions for strength
calculation and empirical expressions for wave bending calculation. Expressions for permissible wave
height as a function of length of ship were derived to satisfy an upper limit on wave induced stresses
and still water stresses, assuming the ship to be in a state of static equilibrium with the wave. Over the
23
years the acceptable induced stress have increased from 0.4 * yield stress to about 0.6 * yield
stress.[28]
In this section, some typical hull design aspects were selected to be studied. Links are made
to traditional shipbuilding practice and their incorporation in FPSO design. The following aspects are
discussed:
– Main dimensions
– General arrangement and tank layout
– Topsides Interface
– Hull Design Process
– Design Loads
– Deformation Effects
Main Dimensions
The main dimensions of an FPSO (Figure 3.3) are traditionally related to trading tankers, for
which ample design experience has been gained. Trading tankers, and especially those early built,
have relative high L/B and L/D ratios.
Figure 3.3: Main vessel hull dimensions
(Source: en.academic.ru/pictures/enwiki/83/Ship%27s_hull_shape_en.png
– 21st January 2105)
-Beam or breadth(B) is the width of the
hull;
-Draft/Draught (d) or (T) is the vertical
distance from the bottom of the keel to
the waterline;
-Freeboard (FB) is depth plus the height
of the keel structure minus draft;
-Moulded depth (D) is the vertical
distance measured from the top of the
keel to the underside of the upper deck;
-Hull Length (L).
Consideration shall be given to the extreme hull dimensions to ensure that they still match the
shipyard capacity available. Large shipyard docks are dedicated to mass production of a standard
type of vessels. Smaller dock capacities are sometimes available for one-off designs, which might be
beneficial since the FPSO is then built separated from the mainstream production line, which leaves
higher construction flexibility.
It should be realized that deviating too much in hull proportions from empirical experience
gained in traditional shipbuilding might lead to unforeseen effects in the design process and excessive
environmental loading on the hull. FPSOs nowadays still present the same dimensions ratios as in the
late 1970s.[29]
24
General Arrangement and Tank Layout
For any floating device, trim and stability (how the ship behaves in water) are the starting
points of the design. This is directly related to the general layout of the FPSO and hull arrangement.
Typical items to be considered are topsides weight distribution, riser hang-off points and storage /
ballast tank arrangement.
Trim and stability set boundaries for the topsides designer on the maximum allowable weight
and C.O.G. location. It may be difficult for the topsides designer to cope with these restrictions, since
the weight distribution of topsides modules is directly related to the process layout.
Depending on turret or spread moored option; the layout of topsides modules will affect the
design. Therefore the approach where the most hazardous systems, i.e. gas compression and the
safer systems, i.e. power generation and utilities, are fitted must be considered.
Topsides Interface
A ship structure is relatively flexible. Topsides modules must therefore be supported such that
they are compliant with the hull girder2. Also the topsides designer has to set his dimensions and
support arrangement in line with the ship structure.
The key issue in interface design is how design requirements for hull and topsides are
merged. The hull strong points are to be set early in the design process to facilitate topsides designer.
Often these dimensions have to be defined when hull design has not yet been completed.
Design Requirements
The most important design requirement to consider is hull deformation due to external or
internal loading. The support arrangement shall provide sufficient flexibility to isolate hull deflections; in
addition modules are limited in length to mitigate hull deformations effects. This support flexibility is a
necessity to avoid excessive stresses in the support structure itself, and eventually in the process
equipment. Process pressure vessels and piping are not designed for excessive deformations.
The topsides modules for the converted tanker are supported at the main decks in line with the
transverse webs, by means of a multiple column support. This principle proved to be a cost effective
option and is frequently applied for conversions. The web frames usually have a thickness of 12 –
15mm and are not designed for large concentrated loads. The module load is therefore spread over a
large number of supports, resulting in a favourable load introduction in the existing web frames. Hull
flexibility is only isolated in longitudinal direction. Vertical hull bending curvature is fully transmitted to
the module, which restricts the module length to a maximum of approx. 25 m. This affects the
modularization of topsides modules and prohibits the use of large preassembled units for converted
units.
2 Hull girder: the theoretical box girder formed by the continuous longitudinal members of the hull of a ship,
providing resistance to hogging and sagging.
25
FPSO Hull Design Process
Reviewing the differences and similarities between offshore and shipbuilding one should adopt
a design process which is based on maritime tradition supplemented with specific offshore needs. This
implies that the designer shall have thorough understanding of specific needs of both disciplines.[30]
Normally the design of the hull is an iterative process, known in the marine industry as the
“design-spiral”. Each separate design phase is passed through several times until the design
converges. A simplified representation of this process is present in Annex A.
The hull designer starts optimization of hull dimensions and tank arrangement using
comparable tanker designs. Based on storage capacity and estimated topsides weight, initial deck
space is provided to the topsides designer. The topsides designer in turn verifies the required deck
space for the module layout and provides a first estimate of module weight and C.O.G. This is
followed by an update of stability and motion behaviour. Hull dimensions are reconsidered if
necessary. Efficient communication between both design disciplines is of the utmost importance.
3.2.3. Design Loads
Load categories relevant to FPSO design are categorized according to hull loads and topsides
loads. Typical hull loads include water bending moments, shear forces, equivalent ship speed, motion
behaviour and explosion loads.
Equivalent ship speed in a stationary moored FPSO takes into account only the transit from
yard to site. Even if the movement of the FPSO is very limited during operations, it’s important to
define an equivalent ship speed because the traditional Rule formulae are based on ships sailing at a
specific speed and this term governs the aspect of internal and external design pressures, as well as
bottom impact pressures. Nowadays, equivalent ship speed for an FPSO lies between 8 and 15 knots
(the average cruise ship travels around 21 to 24 knots). [30]
Environmental loads resulting from sea conditions are one of the principal causes of hull
fatigue. In the North Atlantic, extreme waves can reach heights in the range of 16.5m to 18.3m. For
benign environments, as offshore Brazil, extreme wave heights are far smaller, ranging from 8 to 9m
[31].
When studying vessel stresses resulting from wave motion, two important wave induced loads
are the hogging, referring to the hull bending upwards in the middle and sagging, bending
downwards. Depending on the level of bend, this stress may cause the hull to snap or crack. During
loading and offloading of cargo, ships bend due to the distribution of the weights in the various tanks
on board.
One effective wave formulation is available in [32], and embodies implicitly the factor C:
𝐶(𝑒𝑓𝑓𝑒𝑐𝑡𝑖𝑣𝑒 𝑤𝑎𝑣𝑒 ℎ𝑒𝑖𝑔ℎ𝑡) = 10.75 − [300 − 𝐿
100]
1.5
𝑓𝑜𝑟 90 ≤ 𝐿 ≤ 300 (3.1)
= 10.75 𝑓𝑜𝑟 300 ≤ 𝐿 ≤ 350 (3.2)
= 10.75 − [𝐿 − 350
150]
1.5
𝑓𝑜𝑟 350 ≤ 𝐿 ≤ 500 (3.3)
26
The wave induced hogging and sagging bending moments and shear forces are defined as:
For positive moment 𝑀ℎ = +190 𝑀 𝐶 𝐿2 𝐵 𝐶𝑏 10−6 [𝑀𝑁𝑚] (3.4)
For negative moment 𝑀𝑠 = −110 𝑀 𝐶 𝐿2 𝐵 (𝐶𝑏 + 0.7)10−6 [𝑀𝑁𝑚] (3.5)
For positive shear force 𝐹ℎ = +0.3 𝐹1 𝐶 𝐿2 𝐵 (𝐶𝑏 + 0.7) [𝑘𝑁] (3.6)
For negative shear force 𝐹𝑠 = −0.3 𝐹2 𝐶 𝐿2 𝐵 (𝐶𝑏 + 0.7) [𝑘𝑁] (3.7)
Where all dimensions are in meters, M is a distribution factor which equals 1 over the middle
portion of the ship; F1 and F2 are distribution factors which are function of the hogging and sagging
bending moment ratio. Cb is the block coefficient that represents the ratio of volume occupied by the
ship in an imaginary block drawn around the submerged part of the hull. Full forms such as oil tankers
will have a high Cb where fine shapes such as sailboats will have a low Cb. One important factor to
recognise from the above relationships is that the effective wave height (which determines the wave
loading) is dependent on the length of the ship, L.
It is important to note that these are empirical expressions derived from tankers in the North
Atlantic, which might be used as a first design approach but ultimately the structural analysis will be
done recurring to computerized methods, as the Finite Element Method. In the context of this thesis
this formulations are important to have a notion of the variables to consider in the structural
calculations.
Still Water Loads
The design of a FPSO with a box-shaped hull results in significant still water loads, exceeding
the loads in a traditional tanker. The total still water bending moment is calculated by integrating the
difference between buoyancy and total weigh along the length of the ship.
An FPSO designed with a blunt and prismatic hull shape results in a constant distribution of
buoyancy along the length of the ship, including its ends. An excess of buoyancy near the ends of the
vessel combined with high topsides loads, results in pronounced sagging. Therefore, the hogging and
sagging moments (positive and negative respectively) won’t show an even contribution. This presents
problems to the structure of the hull and needs to be taken into account when choosing the topsides
and therefore the production capacity of the FPSO (higher production capacity means heavier
topsides).
A converted tanker, with less topsides weight and a more gradual buoyancy distribution shows
an even contribution of hogging and sagging moments, but has a considerable smaller production
capacity. [30]
Explosion Loads
Explosion loads are considered as an accidental event, which allows the full yield strength of
the material to be used. The ultimate strength capacity of the FPSO main deck structure underneath
27
the topsides modules should be checked for these events. Explosions may occur due to ignition of a
gas contamination between the ship’s main deck and topsides module lower deck. The most
vulnerable hull members to explosion loads are main deck stiffeners3. To cope with this event during
the initial design phase, the deck stiffeners are considered as individual single spring-mass systems.
Topsides Interface Loads
Topsides loads are relevant for designing the support structure and integration in the hull. The
following design conditions shall be considered:
o Installation / lift (dry weight)
o Transit (dry weight)
o Operation (wet weight)
The difference between dry and wet weight is the presence of liquids in pressure vessels and
piping equipment that can make up to 20% of the module weight. Usually wet weight is only
considered during operation on site.
Overall integrity
For the overall integrity of the FPSO on site, the following loads shall be considered:
o Topsides weight and Centre of Gravity (both dry and wet).
o Hull lightweight and C.O.G.
o Cargo crude oil
o Other liquids (Methanol, Marine Diesel Oil)
o Subsea Umbilical Risers and Flow lines (SURF)
o Future Topsides weight variation
o Future riser or SURF tie-in variations, as well as tie-in of possible future anchor legs
In order to account for future weight increase in the design stage, it is common practice to
spread future topsides weights proportionally over the individual modules while maintaining a constant
C.O.G., if no detailed information is available.
Deformation effects
Deformation effects are generally subdivided into categories to their order of magnitude, which
corresponds to their impact on the design:
1st order effects:
Vertical hull deflection
Longitudinal deck elongation
3 Stiffeners: secondary plates or sections which are attached to beam webs or flanges to stiffen them
against out of plane deformations;
28
2nd
Order effects:
Deformation of local support structure
Thermal effects
Tank loading deflection
For topsides modules supported on transverse web frames, as the ones in conversion FPSOs,
local support deformations shall be considered. The bending stiffness of the supporting structure can
be idealized using equivalent spring constants at the position of the module supports.
For FPSOs operating in mild environments with relatively high over day temperatures in
combination with aggressive sun shining, thermal effects are important. Global bending moments
result from a temperature difference between deck and bottom of the hull. Topsides modules, covering
the FPSO main deck normally function as isolation. When the number of modules is limited or for an
FSO, heating effects may become relevant. For tropical conditions thermal expansion is a semi-
permanent condition. Thermal effects in harsh environment are less relevant and are frequently
ignored.[30]
Transverse vertical tank loading deformations can become relevant depending on the FPSO
tank arrangement. Alternate or irregular tank filling of two or more adjacent crude compartments
results in deflection of the transverse web frames.
Engineering Approach
Global effects are best fitted in a simple engineering approach. Idealizing the longitudinal hull
structure as a beam, classical beam deflection theory may be applied. Considering a uniformly loaded
cantilever beam, vertical deflections are calculated using the following formula:
𝛿𝑍 =𝜎. 𝑙2
8. 𝐸. 𝑐 (3.8)
Longitudinal deck elongation is calculated using the following formula:
𝛿𝑋 =𝜎
𝐸. 𝑙 (3.9)
Where “𝑙” is the length of the module, 𝜎 the strength being applied, E the Young Modulus and
“c” the height of the main deck above the neutral axis of the hull girder. [30]
Deformation effects shall be considered for the ultimate response of the hull structure, and can
be based on the allowable bending stress. Hogging and sagging effects are assumed to contribute
equally to hull deflection. Deck elongation typically equals about 1 mm per meter.
29
3.3. FPSO evolution
The first FPSO in Brazil, one of the first in the world, reached first oil in July 1979 and was built
through the installation of a process plant over the deck of the P.P.Moraes oil tanker which would be
later renamed to P-34. That vessel represented the learning phase the company went through before
committing to building large FPSO in the mid-90s.
Nowadays, Petrobras is one of the most experienced companies in the operation of these
vessels, and, as can be seen in Figure 3.4, by 2014 around 25 percent of all the operating FPSOs
were in the Brazilian offshore.
Figure 3.4: Number of operating FPSOs (based on data available at [33])
FPSO capacities have also evolved considerably over the years. The P-34 referenced above
had a production capacity of 45,000 barrels/day, 31 years later in 2010, the P-57 had a maximum
processing capacity of 180,000 barrels a day. Higher processing capacities exceeding
200,000 barrels/day have already been reached and the biggest FPSO on order at present is destined
for Nigeria, with capacities to offload up to 240,000 barrels/day. The processing capacity according to
the number of projects under development in 2013 is shown in Figure 3.5, where 58 percent of
required topside plants are within 100,000 to 200,000 barrels/day.
Figure 3.5: Processing plant capacity according to the number of FPSO projects as of 2014 (source: based on date available at www.offshore-mag.com/articles/print/volume-74/issue-5/fpso-outlook/projected-requirements-for-fpsos-over-the-next-five-years.html – 11st of February 2015 )
0
20
40
60
80
100
120
140
160
180
200
220
1980 1985 1990 1995 2000 2003 2005 2007 2010 2013 2014
Number
Globally
Brazil
<50 b/d; 14
50-100 b/d; 29
100-150 b/d; 44
150-200 b/d; 36
200+ b/d; 4 Gas; 10
30
Essentially we can divide the history of FPSOs into 4 phases, since 1980:
Phase I: From 1980 to the beginning of the 90s, FPSOs were used mainly as Early
Production Systems4;
Phase II: The period up to the end of the 90s comprises the boom of FPSO construction and
installation globally and particularly in Campos Basin;
Phase III: In this phase, that lasts until 2010, the use of FPSOs was consolidated and a
second generation of units was built, taking into account all the experience gathered in the
first wave of FPSOs from the second phase;
Phase IV: Nowadays, we’re on a phase where the demand for higher capacity requires a
new approach to FPSO building. Tanker conversations might become outdated.
The main characteristics of each phase are displayed in the following table.
Table 3.1: FPSO Phases - Main Characteristics (Source: Adaptation from)
3.4. Case Study Analysis
A strong growth in global energy demand will be the main driver of the industry for the years
ahead. One trend is the liquefied natural (LNG) gas projects, driven by a growing appetite for natural
gas. LNG emerges as a key factor to help some Europeans nations diversify their sources away from
Russian gas supply, which in the last decade has become increasingly used as fuel for power
generation, and to a lesser extent, as a substitute for oil as transportation fuel. A growing
environmental awareness is another important factor due to the lower greenhouse gases emission
levels of natural gas. Carbon emissions from natural gas are 70 percent lower than from the
corresponding energy output based on coal. That has helped Europe to achieve big reductions in its
greenhouse emissions. Natural gas is now being used to generate electricity instead of coal. In
Germany for example, this has cut carbon emissions by 20 percent since 1991.
Volatile oil prices, high operation expenditure (OPEX) on offshore fields and changing
trends in the global markets is forcing the industry to look for different solutions, adapting mature
technologies to the new challenges. In this section, two cases will be presented of new technologies
applied to the FPSO production system.
4 Early Production Systems have the goal to begin production early while full field development is being planned
and permanent facilities are being built. They help operators create an early cash flow .
Characteristics Phase
I – 1980-1995 II-1995-2000 III-2000-2010 IV- 2010- Present
Processing Capacity <60,000 ~100,000 up to 180,000 200,000+
Ship Size [length] Panamax,
Aframax [~245m] VLCC [~330m] VLCC [-330m] >400m
Design Life 5~10 years 20 years 25+ years 25+ years
Materials (piping and vessels)
Mainly Carbon Steel
FRP, Cu-Ni and CSS
+Duplex Stainless Steels
+Duplex Stainless steels,
composites
31
3.4.1. Case 1: Floating Liquefied Natural Gas (FLNG) Vessel Floating liquefied natural gas (FLNG) refers to vessels with technologies designed to enable
the development of offshore natural gas resources. This facility will produce, liquefy and store the
LNG, eliminating the need for long pipelines all the way to shore. With gas nowadays becoming
increasingly important among fossil fuels due to its cleaner burning, this option might represent the
future of offshore production vessels evolving from the FPSOs.
The first FLNG development in the world is Shell’s Prelude (Figure 3.6), destined to produce
and export LNG off the coast of Australia. The facility will be 488meters long and 74m wide, being the
largest floating offshore facility in the world. Its revolutionary technology will allow Shell to access
offshore gas fields that would otherwise be too costly or difficult to develop. Global Maritime, one of
the biggest marine engineering consultants, has also done a complete pre-FEED (Front End
Engineering Design) study for an FLNG to offshore Australia in 2010, and two concept development
projects to assess feasibility and field development aspects of two FLNGs for Aker Solutions. [34]
Figure 3.6: Shell's FLNG plant
(Source: http://www.seabreezes.co.im/images/content/news/201107/PreludeFLNG.jpg - 14th March 2015 )
A technical and economic viability study was also developed in 2012 by Cenpes (Research
and Development centre Leopoldo Américo Miguez de Mello) in Rio de Janeiro. However, the use of
this system is not directly related to the result of the study but to the competing method of exporting
natural gas, the gas pipeline. Supporters of the FLNG concept to offshore Brazil defend the fact that
the new technology can bring more profit and market share to Petrobras and gas pipelines carry risks
as well. However, it’s not likely we’ll see this technology in Brazil in the near future due to the
shipyards still being in the learning curve of this type of technology, which represents high costs and
lack of specialized manpower. [35][36]
The design and execution issues are new for a first of a kind project like this one; as a result,
there is more technical and execution risk for FLNG than for well-established concepts. What one can
see from this kind of vessels is that it is customized and site-specific and due to the big initial
investment, we might not see many units in the near future. [37]
32
3.4.2. Case 2: Floating Production, Drilling, Storage and Off-Loading (FPDSO) vessel
A Floating, Drilling, Production, Storage and Offloading (FPDSO) vessel, as the name
suggests, has the same functions as an FPSO plus the drilling function through a compact drilling rig
on-board the vessel. This concept was developed as an approach to cost-effective field development,
eliminating the need to use a mobile drilling offshore unit (MODU), an extremely expensive and time-
consuming operation. This vessel allied to a subsea completion system allows full field development
and operation from one single unit. [38]
The industry’s first FPDSO was installed in the Azurite field, in the Republic of Congo in 2009
(Figure 3.7). The project was developed by the North American “Murphy Oil” in partnership with “Doris
Engineering” and “William Jacob Management”, French and American respectively. The vessel was
deployed in a water depth of 2000 meters, 130 kilometres from shore, with a processing capacity of
40,000 barrels/day. The concept had been discussed in the market since the 1990’s but, until Azurite,
never became a reality. The choice of using this type of vessel was influenced by several key
variables that assured the technical and commercial viability of the field development. The need for
storage and offloading remains a key variable in the selection of a FPDSO, as in the case of the
FPSOs. Water depth also plays an important role due to the high cost of production and drilling units
in depths of 2000 meters, where the FPDSO manages to merge the two. Remote areas like the
Azurite field represent a challenge due to lack of infrastructure and high cost for the mobilization of
drilling rigs. The short lifetime of marginal fields5 is also a key factor in the choice of an FPDSO,
because of the need for well intervention capabilities, having a drilling rig on deck reduces the
operation cost. However, in fields with little well intervention or where the leasing of MODUs is
available at a lower cost, this concept might not have applicability because the drilling and well
completion phase is relatively short when compared to the total time the FPSO must be deployed over
the field, which can go up to 20-25 years. [39]
5 Marginal Field: an oil field that may not produce enough net income to make it worth developing at a given time.
However; should technical or economic conditions change, such a field may become commercial field.
33
Figure 3.7: Azurite FPDSO with drilling derrick on the centre of the ship (Source: http://api.ning.com/files/DSC09360.JPG - 21st March 2015 )
The industry interest on the concept has also reached Brazil. In 2008, the Finnish company
Deltamarin and the Brazilian offshore service company Petroserv S.A. have signed an engineering
contract for the basic and detail engineering of the Dynamic Producer (PIPA II) FPDSO for Brazilian oil
fields under a contract from Petrobras. This conversion is based on an existing tanker. The interest of
the industry leads to the conclusion that the FPDSO concept could compete efficiently on fields
currently being developed with traditional FPSO systems, but we’re yet to see the deployment of such
system in Brazil. [40]
The commercial benefits of FPDSO can be resumed in three points: lower combined cost of
drilling and production; accelerated production compared to a standard FPSO; and lower cost of
logistics and consumables. Azurite has shown that the incorporation of a drilling rig onboard a
conventional FPSO brings new hope to fields of similar geometry and in similar environments, like the
coast of Brazil for example, that before were considered marginally economic or uneconomic. In the
context of today’s lean economic times and volatile oil prices, this option might be a solution used
more often in the future.
3.5. Current Challenges in Brazil & Future Developments
Although it’s rare that a company can set itself in the technological frontier with a technological
trajectory based in incremental innovations, in the case of Petrobras it proved to be a success. The
company was a technological leader on offshore E&P for a long period of over 10 years, a singular
case in the petroleum history. The reason behind this was the combination of important opportunities
associated to technological choices that proved to be adequate, allied to technological capacitation
programs as the Procap, which matured the company’s presence in Campos Basin.
In 2007, the discovery of pre-salt supergiant oil reservoirs generated strong optimism
concerning the future Brazilian oil supply, both domestically and internationally. The Brazilian
34
continental shelf, geologically similar to the continental shelf of West Africa, should be the laboratory
for the innovations needed to move the oil industry to the new frontier opened by Petrobras with the
pre-salt. However, in order to minimize financial risks, the company has continued within the FPSO
trajectory.
The Brazilian government and ANP saw the discoveries and the continuity trajectory as an
opportunity to develop Brazil’s industry, and designed public policies to develop national production
capacity to address Petrobras naval demand. The Local Content Requirement (LCR) policy, forces
operators to acquire goods and services in the domestic market, and the non-compliance with this
policy results in heavy fines. Moreover the construction of eight identical platforms (“FPSOs
replicantes”) is a clear indication for the government that Petrobras and its network of suppliers are
committed to comply with the government’s local content policy.
Motivated by Petrobras long term demand for offshore and maritime equipment (early 2014
business plan anticipated orders of US$ 100 billion with Brazilian shipyards by 2020), several
technological partnerships with international shipyards and oilfield technological companies were
established (Table 3.2), in order to bring their technological expertise to Brazil.
Table 3.2: Shipyard agreements made with international technological partners (Source: [41] )
However, it is widely recognised that Brazilian shipyards are uncompetitive relatively to Asian
competitors, due to a combination of factors, including high labour costs and a shortage of skilled
workers, low productivity and a lack of cutting edge technology and management techniques. For
example, in Korea, a supervisor in average is capable of coordinating a team of 20 technicians, while
in Brazil one supervisor is responsible for a team of up to 5. The lower level of education results in
less autonomous technicians and workers, depending more often on their coordinator for decision
making. The productivity of the Brazilian shipyards is 3 to 5 times lower than the most moderns
shipyards in the world, located in Asia, where countries like South Korea, Japan and China have 80%
of the global market. [33]
In fact, a high number of shipyards and sector related companies report problems in a daily
basis. Between 2012 and 2013, more than a dozen national shipyards and EPC contractors passed
through financial difficulties and at least four engineering firms involved in important projects either
sought bankruptcy protection or were declared bankrupt. These difficulties have continued in 2014 and
Brazilian Shipyard Technological Partner
Atlântico Sul (PE) Japan Marine United Corporation/IHI
VARD Promar (PE) VARD – Grupo Fincatieri
Enseada do Paraguaçu (BA) Kawasaki Heavy Industry (30% stake)
Jurong Aracruz Sembcorp (100% stake)
Brasfels (RJ) Keppel Fels (100% stake)
OSX (RJ) Hyundai Heavy Industry (10% stake)
Inhaúma (RJ) Cosco
Rio Grande (RS) Mitsubishi Heavy Industries
35
the question now being asked is whether this is an inevitable part of the industry’s steep learning
curve or whether there are more fundamental issues affecting the sustainability of the sector in the
long term. [42]
Both Brazilian government and ANP’s policies have generated limited results in expanding
Brazil’s producing capacity. In Petrobras’ big innovative projects the impact of national companies is
small, contributing only with the “basic engineering” activities, where there’s little innovation, while the
innovative activities are performed by foreign companies. Also complex equipment, such as high
power turbines, large diameter valves or multiphase pumps, are imported, since local suppliers cannot
satisfy Petrobras’ demand for such equipment nor have the expertise and facilities to build such
products. [33]
Despite the issues facing the naval industry, ANP and Petrobras representatives show a clear
intention of developing “basic engineering” for a new generation of FPSOs with higher processing
capacity of up to 300 thousand barrels/day, when the Brazilian market is focused on vessels with a
processing capacity limited between 100 and 180 thousand barrels/day. The large number of wells
with high productivity rates may justify this intention; however, higher productivity represents a higher
technological risk due to issues like the weight of topsides, offloading procedures and hull dimensions.
The trend of using subsea separation may enable FPSOs with higher processing capacity. The
separation module occupies around one tenth of the space on deck, by placing it on the seabed, the
extra space could be used to enhance separation processes. Alternatively, it might be necessary a
new build vessel, large enough to withstand the larger production, which is something Brazilian
shipyards may not have capacity for.
The recent “Lava Jacto” operation, the corruption case involving Petrobras’ and its contracted
companies, is also starting to show its negative consequences. After having to remove 23 of its large
contractors, the state company had to reopen the bidding for the modules of its future FPSOs, inviting
only foreign companies. The list includes companies from China and Singapore, like Keppel Fels,
owner of BrasFels shipyard, among other countries. There’s the possibility that the modules might
even be constructed outside Brazil, going against the local content policy imposed by the government.
Petrobras’ justifies the decision with the need to speed up construction and delivery of the projects;
however it’s a clear sign of the lack of commitment to strengthen Brazilian Industry.
Construction delays and increased costs are bottlenecking the development of the wider oil
and gas industry in Brazil. Solving these issues will require investment, time and ideally input from
experienced players.
The future of Brazilian naval industry, idealized to support the FPSO trajectory, is uncertain
and some shipbuilders may fail. A process of consolidation seems likely, but that process, if
successful, should result in a stronger shipbuilding sector, better placed to meet the needs of its oil
and gas industry and to compete internationally.
36
3.6. Risk Analysis
FPSOs have been used for years, getting more popular lately with ultra-deep waters.
Solutions to present technical challenges are already being developed. However, there are still
difficulties, not only technical but also commercial as the case of Brazilian shipyards where building
efficiency is struggling to compete with Asian countries, which might jeopardize the plans of Petrobras
to increase its production goals.
In this section one will develop an analysis of the perceived benefits and risks that
stakeholders from different sectors associate with this technology, considering a technical and
economical point of view (there are several other categories of risks associated as health,
environmental or safety risks; however in the context of this thesis one will only approach the two
aforementioned). Economic risks can be issues that are either truly economic in nature or those that
are entwined with technical or execution elements. Both categories are essentially systemic risks with
systemic impacts due to the multiple interaction and dependencies that arise (refer to Chapter 2).
3.6.1. Benefits
The benefits for Brazil from continuing within this trajectory are vast. In the following list one
will enumerate some of the principal ones, grouping them into two categories, technical and
commercial.
Table 3.3: Benefits associated with the Continuity Trajectory
Benefits
Technical Economic
Past technical knowledge from over thirty years
of the use of FPSOs
Reduced upfront investment
Established design philosophies Abandonment costs are less than for fixed
platforms
Sea conditions in the South Atlantic are not as
harsh when compared to the North Sea for
example, requiring less hull strength
Retained value because they can be relocated to
other fields
Well known design loads Earlier cash flow because they are faster to
develop than fixed platforms
Several advantages related to the ease of
production operations (refer to initial section)
Allows for economic development of fields not
economic with other platforms
Topside flexibility allows for alternative designs
(see case studies)
Leasing FPSO units is a common practise –
transfers some of the risks from the field operator
to the contractor
Purpose build vessels present big advantages
and less design restrictions
Assumed residual value used as a competitive
tool in leasing bids
37
3.6.2. Risks The existence of risks and limitations, already mentioned, must be evaluated. The analysis of
risks must take into account the existent new solutions for the deep-sea offshore oil and gas industry.
The perceived systemic risks will be grouped in two distinct categories in the following table.
Table 3.4: Systemic risks associated with the Continuity Trajectory
Risks
Technical Economic
Conversion from tankers can pose structural problems and size limitations
Increased costs from increased complexity of
systems
Challenges in design when combining shipbuilding and offshore cultures
Lower peak production rates than expected
reduce revenues
Offloading is appointed as the most risky
operation during production (risk of collisions)
Excessive CAPEX and OPEX associated with the inherent unpredictability of the offshore environment
Limited production capacities result in lower
revenues
Risks associated to new technological
uncertainty
Environmental conditions (extreme weathers and waves)
Risk of losing the place in the technological frontier when competing with other technologies
Deck motions are not “riser friendly” and can
complicate process plant operation, causing
downtime
Low productivity shipyards in Brazil can’t compete with Asian shipyards; Delays and lower production capacity greatly affect revenues
Redeploying process is not as easy as it should;
FPSOs are usually designed with a specific field
in mind
Higher investment concentrated in: Hull Conversion; Energy generation (electric) module and Compression Module
38
4. Intermediary Trajectory
The intermediary trajectory aims for an integration of common technological concepts within
new environments. By applying technologies that have already been used elsewhere, generated
technological knowledge can be transferred to new fields with limited technological risks, but still
limiting potential for significant economic growth towards a leading market position. These mature
technological concepts are the platforms models already in use around the globe that mainly consist of
TLPs, SPARs and Semisubmersibles. The first two concepts typically employ dry trees, which, in deep
water development, imply that the Christmas tree is placed on the deck structure for direct access.
The semisubmersible concept uses a wet tree solution, with the Christmas tree on the seabed.
As the oil and gas industry moves further into deep water, the need for high performance
production platforms becomes acute. Therefore floater contractors are studying new alternatives to
enhance the current technologies; dry tree solutions are one of the options being evaluated. For
example, the dry tree semisubmersible (DTS) has been an appealing concept over the past few years
and several DTS concepts have been developed, due to their several advantages compared to wet
trees.
This means there’s a real conceptual choice to be made for new platforms in ultra-deep
waters, between dry and wet trees; a choice that used to exist only for shallow to medium water
depths. The actual selection of a floating system solution will involve a mixture of multiple technical
evaluations and constraints. In this chapter, one will analyse this trajectory in greater detail, starting by
presenting a summarized analysis of floating platforms design practises followed by the essential
differences between dry and wet trees. Two case studies will be presented, dealing with the use of dry
trees, and the chapter will finalize with a description of the current challenges to this type of
technologies and an assessment of the risks and benefits.
4.1. Technological Systems
As stated before, the most employed types of offshore floating platforms are the Tension-Leg-
Platform (TLP), the Spar Platform and the Semisubmersible platform, or Semi. The first two have
become more widespread in the Gulf of Mexico and in the North Sea. The third type is widespread all
over the world.
39
Figure 4.1: A-TLP; B-Spar Platform types; C-Semisubmersible
(Source: [19] )
The TLP (Figure 4.1 - A) has low vertical motion due to the special boundary conditions with
tendon restricting the heave, roll and pith motion. The tendons are the most critical element of the
platform, requiring high safety factors in terms of strength and fatigue because there is little
redundancy in these elements and they are very difficult to inspect and repair. The cost of the tendon
system tends to make the concept less competitive in deeper waters; hence the practical depth limit of
this type of platform is about 1800 meters. The record depth with this system was achieved by Conoco
Phillips, in 2004, in the Gulf of Mexico (Magnolia), anchored at 1433 meters. Stretching the water
depth limit in this context could pass by the use of composite tendons. There has been significant
technology development and evaluation of composite tendons by the industry, but so far they have not
been used on any installation. In face of the depths posed by the pre-salt and the costs that it would
present, this system won’t be adequate for exploration on those areas. [3]
Spar’s are formed by a vertical and deep cylindrical hull (up to 200 meters) with a mooring
system based on spreading anchors and mooring lines. This geometry allows for a considerable range
of motion but only slight vertical movements. There are three types of SBP: the classical, the truss and
the cell (Figure 4.1 - B). The truss spar has the advantage of requiring less steel than the original one,
weighting and costing less. The most recent variation of Spar’s, the cell, is essentially a variation of
the original one, with 6 smaller cylindrical hulls that are more easily and cost-effectively generated
through mass production. [3]
A B
C
40
The Spar can offer economic advantages when compared to the FPSOs for the exploration of
the Pre-Salt. They use less costly rigid risers and the dry completion systems are easier to control and
to intervene in the well. Moreover, dry Christmas trees, i.e. placed on the platform, are safer and do
not need expensive and remotely operated vehicles (ROVs) for routine operations. Another advantage
of the Spar’s is that they can have a permanent drilling rig on top, enabling the drilling of new wells
and increasing the oil recovery rate of pre-salt reservoirs. Researchers at CENPES call these
technological systems “factories of wells in the middle of the reservoir”. This is particularly relevant for
the development of reservoirs with small porosity and low permeability like Iara (a pre-salt reservoir).
However, the cost of this platform (US$ 3 billion) is much higher than the FPSO platforms, even for
those using new hulls. (US$ 1.3 billion contract in early 2010 for the construction of FPSO P-63). Due
to the deep draft, Spar units usually require offshore upending/installation. The risk of offshore
installation in unprotected environments and resulting cost is one of the major limitations of the Spar
concept. [19]
A semisubmersible (Figure 4.1 - C) platform has a hull (columns and pontoons) that, when
flooded with seawater, cause the pontoons to submerge to a predetermined depth. Semi
Submersibles are generally used for offshore Deepwater drilling operations with water depth ranging
from 600 meters - 3,600 meters and are deployed in areas such as the Gulf of Mexico and South
America. They are considered one of the most stable production platforms, due to the restricted rolling
and pitching resulting from the partially submerged columns.
Petrobras has several units in the Campos basin, like the P-55 that went into production in late
2013 in the Roncador field (1800 meters water depth), with a production capacity of 180 thousand
barrels/day. This type of platform is connected with wet trees, however, in the last decade, quite a few
Dry Tree Semi (DTS) concepts have been proposed by various designers. The industry has shown
significant interest in developing solutions especially for marginal fields in ultra-deep waters. Petrobras
has considered the possibility of using DTS concepts for Offshore Brazil as part of their Pre-Salt
developments. DNV (Det Norsk Veritas) has been involved in concept evaluations and performed
Approval-in-Principal for most of these concepts. [43]
The use of dry tree systems will be analysed in greater detail throughout this chapter, with
examples given as case studies. The evolution of these systems is depicted in Figure 4.2, where two
different geographical areas were studied. The Gulf of Mexico and offshore Brazil saw most of the
developments related to deep or ultra-deep waters, hence, by seeing how technology evolved
differently in different areas one can get a sense of the importance of the context in technological
development.
41
Figure 4.2: Technological Evolution of Platforms; Comparison of two deep water regions: GOM and Brazil
Time
Technolo
gy P
erf
orm
ance
1947 1960 1970 1980 1990 2000 2010 2015
GOM Brazil
First fixed platform “out of sight of land”. WD: 6 m Shore: 29
Fixed platforms boomed in the GOM. In this period several WD records were achieved: 1976 – 260 m 1978 – 310 m 1988 – 400 m
Fixed platforms reached the economical depth limit of 460 m.
Production starts offshore Brazil.
Imported Jack-up fixed platforms
used initially.
New type of fixed platform used: compliant tower. Better suited for higher water depths. WD: 500~530 m
Increasing WD required floating rigs. Most popular concept in the GOM was the TLP. Some records are: 1989 – 536 m 1994 – 872m 1996 – 896m 1999 - 1225m
TLP reached a practical limit of 1432m achieved in the Magnolia Field. Expensive mooring cables are the main reason.
To achieve higher WD the Spar platform was developed. Dry trees and more stability made this concept very popular. WD Record – 2450 m (Perdido
field 2010)
Semisubmersibles gain popularity with Petrobras for developments in Campos basin. WD: 120m
1988: Pioneering application of a semisubmersible. The concept didn’t compete with the TLP.
Discoveries in Campos basin pushed tech. development.
Increasing WD of up to 1500m required new approaches.
Semis used together with FPSOs in field development.
First TLP offshore Brazil working together with FPSO. Campos Basin WD: 1180m
Field developments with semisubmersibles continued in Campos Basin. WD: up to 2000m
Technolo
gy P
erf
orm
ance
Time
Advances in seismic technologies resulted in discoveries in extremely harsh conditions, also under salt layers.
Alternative to standard platforms start being used, e.g. first FPSO employed in the GOM
2007:Pre-salt discoveries raise questions as how to develop those fields. WD>2000M
Water depths of up to 2440 m rendered semisubmersibles suitable for field developments.
FPSOs took the lead due to Petrobras expertise.
New phase of development started in Santos basin. New approaches needed for CO2 and H2S levels.
42
4.2. Dry Tree vs Wet Tree
The technical constraints and evaluations required when choosing an offshore technological
solution are typically the water depth, environmental and soil conditions, existing infrastructure, flow
assurance, product type/conditions, riser system, subsea system layout and export options. These
technical aspects will be associated with cost evaluations related to CAPEX and OPEX. Depending on
geographical area, there could be additional constraints related to local content requirements as in
Brazil.
Early in this selection process, one of the key decisions to be made is whether the field’s wells
will be equipped with wet or dry trees. This choice is highly complex and it will heavily depend on the
development scenario and the relevant boundary conditions. In Table 4.1 a comparison between both
solutions is made, focusing on some high level cost (CAPEX and OPEX), technical and safety issues
which distinguishes the two options.
Table 4.1: Comparison of Wet and Dry Tree developments (Source: Author adaptation from [44] and [2])
Feature Wet Tree Dry Tree
Drilling Expenses High, requires MODU Lower, drilling directly from floater
CAPEX (facilities) Lower, smaller/simpler hull High, larger and more complex floater/hull
OPEX High, requires MODU Less costly, can be done from floater
Flexibility in development Minimal floater impact Restricted to floater layout
Riser/ Vessel Interfaces Simpler Interaction Complex Interaction
Structural; hull and topside Traditional More complex, floater dependant
Offshore work/ flexibility Less effort Some heavy lifting may be required
Flow Assurance Potentially long flow path/lines Shorter flow path
Safety (shut-in location) At seabed, hence low risk to personnel
In floater well bay, close to personnel
Access to reservoir Requires MODU, i.e. costly
Direct access from floater reduces well intervention cost and higher potential to improve reservoir management
The riser/vessel interfaces to operate dry trees are more complex due to the stability
requirements of the platform, which must respond to the motion of the sea in a limited and predictable
way. Because the floating system moves in relation to the risers and trees, a riser hang-off system is
required that supports the risers and accommodates this relative motion and these systems are often
quite big and complex. The risers that connect to the dry trees on TLPs and spars have their
movements ‘decoupled’ from the platform, so that, as the platform responds to the sea, the risers do
not. This is achieved by keeping the tops of the risers under nearly constant tension, using hydraulic
top tensioners that compensate for platform movements, or by attaching buoyancy cans to the risers
to support them vertically. [44]
43
Despite the drawbacks associated with dry tree system in ultra-deep water, the benefits of
efficient drilling and OPEX cost are paramount. Wet tree field developments tend to offer economic
improvement in areas such as platform requirements, reduced offshore construction and development
flexibility, but lack the efficient drilling and completion capability. [43]
4.3. Case Study Analysis Dry Tree systems have been widely used throughout the world and present several
advantages. The demand for technology innovation in the industry is creating a shift of this type of
technology to areas never employed before. In this section, two case studies will be presented,
focused on the use and evolution of dry tree systems and their applicability.
4.3.1. Papa-Terra TLP
The Papa Terra oil field is operated by Petrobras in partnership with Chevron and started
production in November, 2013. Located 110 kilometres from the coast in deep water at Campos
Basin, it has an extra heavy oil formation with an API gravity ranging between 14 and 17. With a water
depth of 1180 meters, it’s considerably shallower than the pre-salt fields in Santos Basin, however, the
combination of heavy oil, water depth and distance from shore makes developing the Papa-Terra field
a very complex task, requiring several innovative solutions to be incorporated, with flow assurance
strategies becoming a key driver.
To develop this field, Petrobras employed the use of a tension leg platform installed 350
meters away from an FPSO, with multiphase flow between units. This platform is the first TLP platform
to be built and operated in Brazil. The P-61 will operate together with the P-63 FPSO unit. Together,
the units have the capacity to produce 140,000 barrels of oil per day from the 18 wells they are
connected to. All the P-61 production will be transferred to the P-63 to process, store and offload
extracted oil to shuttle tankers. The strategy of developing the heavy oil field production in deep
waters, using the TLP in combination with the technologies on board the FPSO P-63 (Figure 4.3), can
be considered an innovative and very attractive concept in Brazilian oil industry. [45]
Due to the oil viscosity, this project demanded a new approach on fluid behaviour modelling
and the adoption of some technologies never before seen in the Campos. For example, the wells will
be equipped with Submerged Centrifugal Pumps and the platform will be equipped for workover
procedures (maintenance works). The production will be transferred, through high power multiphase
pumps to the FPSO P-63, where the processing takes place. This layout of combining two different
pumping systems (liquid in the well and multiphasic in the topside) was an option employed by the first
time by Petrobras. Another example is a new fluid model to be used in flow simulation that considers
viscosity data measured in laboratory. Bottom line, the dry tree will allow for well intervention to be
quicker, mitigating production losses. [36]
44
Figure 4.3: Papa-Terra P-61 TLP and P-63 FPSO in the back
(Source: floatec.com/wp-content/uploads/2014/04/pt-p61_08.jpg - 28th March 2015)
Despite the platform being anchored at 1180 meters, about half the depth of some pre-salt
fields, it is still a clear case of the company following an intermediate trajectory, using a common
technological concept and applying it in a new context, the Brazilian offshore.
4.3.2. Deepwater Dry Tree Semisubmersible (DWDTS) Dry Tree Semis (DTS) offer many advantages when compared to its competitors, the TLP and
the SPAR. So far, no Dry Tree Semi has been selected as the host platform for a deep-water field
development project. However companies are considering its application and there are concrete
projects under study by big oil field services companies like the Norwegian Aker Solutions.
The main advantage of DTS compared to TLP is that it has no water depth limitation and does
not require a tendon system which is expensive in terms of fabrication and installation. Unlike the
Spar, which has a limited deck space due to its single-column form, DTS offers a large open-deck
area. This leads to greater flexibility in the well bay layout. The large deck area of DTS can easily
accommodate topside facility arrangements on a single level or two levels. DTS also offers a number
of construction and installation improvements over the Spar. For the Spar, the topside integration has
to be conducted offshore through expensive heavy lifting vessel or complicated float-over operation
and thus the commissioning work has also to be done offshore. For DTS, both the topside integration
and commissioning can be performed at quayside, which is much cheaper. Therefore, it is expected
that DTS will be cost competitive with the TLP and overcome the size limitations on the Spar in the
near future. [46]
Aker Solutions is developing a deep water DTS design based on a conventional semi-
submersible shape consisting of a ring pontoon with four corner columns and a ring pontoon hull. The
real innovation and key to get this concept working is the array of long stroke tensioners that support
the Top Tensioned Risers (TTR) during drilling and production. The TTRs are supported by motion
compensating tensioners, mounted on the lower level of the deck box structure (seeFigure 4.5).The
tensioners regulate the tension applied on the top of the risers, ensuring they do not exceed design
strength when the hull moves up, and do not buckle when the hull moves down. This is a passive
compensation system based on air pressure and air volume control which operates hydraulic ram-
45
style cylinders with a typical vertical stroke length of up to 10-13 metres – the stroke length is selected
to accommodate the sea conditions in each geographical location. [43]
Long-stroke TTRs are not new and are employed on drilling semis and drillships, but in these
cases only a single drilling riser is involved, which is not the case of this concept. Here 12 or more
long-stroke TTRs are aligned together in an array in the well bay, with the dry trees spaced out both
vertically and horizontally to allow for easy access.
Figure 4.4: Aker Solutions Dry Tree Semi
(Source:[46])
Figure 4.5: Long Stroke Tensioner (LST) and LSTs Array
(Source:[47])
The DTS is based on a conventional semisubmersible hull form, essentially four columns and
a deck box, but it has a deeper draft when compared to the typical 25-40 metre draft for a wet tree
production semi. The hull of the DTS extends further downwards so that wave forces on the pontoon
are reduced, limiting heave motion of the vessel and assisting the use of dry trees. The deep draft
design provides improved motion characteristics over traditional semi designs to accommodate the
functionality of the TTRs.
The challenges currently faced by the DTS concept are:
How to arrange these riser tensioning systems in a practical and safe manner inside a limited
space on the semisubmersible deck;
Extended structure means more steel and cost;
Larger deck spacing to allow longer stroke raises the centre of gravity and thus affects the global
performance:
In case there’s a high number of wells connected to the platform, due to the tensioners the whole
unit becomes stiffer, which influences the dynamic motion behaviour of the platform. [48]
The concept and most technologies associated to it are still under evaluation by DNV (Det
Norsk Veritas) for Approval-in-Principle, but it’s clear that there’s significant interest by the offshore
industry in developing competitive DTS solutions. Although there are still uncertainties about the
overall system maturity such as constructability and draft limitations, the technology of utilizing long
46
stroke tensioners or alternative hull forms can overcome the technical challenges associated with
these concepts.
4.4. Current challenges and Future Developments
Dry tree solutions employed in deep waters is a relatively new trend and the technology is
under constant development. Proper evaluation on the feasibility of new concepts and components is
essential to ensure their successful materialization. Conventional dry tree solutions, like the Spar and
TLP, although still widely used, will prove to be inefficient in increasing water depths.
For ultra-deep water dry-tree semis the design practices are still not well-established and lack
operational experiences. There are however typical checkpoints and focus areas for any floater
design. A few of these are included in the following list: [43]
Strategies for optimal motion characteristics (floater/design dependent)
Integrated analysis (coupled analysis is recommended for highly non-linear systems)
Extendable draft vs fixed draft (geographical constraints on water depths in coastal areas)
Tensioner stiffness Heave damping (floater and system dependent)
Direct Wave loading on TTRs/tensioners (need to be taken into account with multiple TTRs)
Mooring system (floater dependent, taut system may be required for DTS)
Steel Catenary Risers and umbilicals (hang-off motions are crucial)
Vortex Induced Motions (checkpoint for most floaters/areas these days)
Simultaneous drilling and production operation
Long-Stroke riser tensioning system and hull interface (with/with-out riser keel support frame)
Constructability and topside integration
Inspection, Maintenance and Repair
Dry-trees are also expanding to the vessel context. A new and unique concept of FPSO using
dry-trees is under development by the Japanese National Oil Corporation, heading a Joint Industry
Project. The concept main attribute is the use of Compliant Vertical access Risers (CVAR). These
compliant but rigid risers, fitted with syntactic buoyancy, connect wells from the seafloor to the surface
Christmas trees mounted on the vessel, and can compensate for vessel motion. According to the
company, the CVAR-FPSO would achieve its maximum potential in calm and deep waters as Brazil,
West Africa, Indonesia, etc. This example serves to show that the adaptation of dry trees to new
contexts will happen in the future and the innovative process comes from different areas around the
globe.
In the Brazilian context, despite the advantages of the dry trees, these systems would delay oil
production in the pre-salt, jeopardizing Petrobras need for fast cash flow to develop its pre-salt
reserves in the short-medium term. In parallel, this decision would compromise the government’s aim
of quickly increasing domestic oil production to minimize Brazil’s deficit in the balance of payments as
well. Although the movement to the SBP intermediary trajectory seems to offer no major technological
difficulties, it can hardly provide the short term economic results that Petrobras and the government
47
are looking for. Therefore, the dry completion system is likely to remain only a niche technological
strategy in the Brazilian pre-salt. [19]
4.5. Risk Analysis
The use of proven technologies considerably reduces the technical risks of their feasibility,
however different risks arise as the need for integration and adaption might present a big technological
leap depending on the context. This trajectory enables companies to limit technological risks, but still
limits potentials for significant economic growth towards a leading market position.
Following the same procedure as in the previous chapter, one will summarize the perceived
benefits and systemic risks that stakeholders can associate with this trajectory.
4.5.1. Benefits
There are several benefits arising from adopting an intermediary trajectory, most of them
resulting from the lack of uncertainty companies might face when employing these technologies. In the
following table one will enumerate the principal perceived benefits.
Table 4.2: Benefits associated with the Intermediary Trajectory
Benefits
Technical Economic
Technologies already used or still in use – no major technical difficulties
Reduce CAPEX due to less costly maintenance
Dry trees allow for simpler maintenance operations
General economical improvements in field developments
Low assurance is generally simplified with dry-trees
Economic risks can be better evaluated due to past experiences with these platforms
Improved reservoir management with the use of dry-trees
Investments will have more predictable outcomes
48
4.5.2. Risks Although systemic are lower than the ones one might find in a disruptive trajectory, they still
exist and must be taken into account. For example, having for base a mature technology might hinder
the innovation process. This and other perceived risks are present in the following table.
Table 4.3: Risks associated with the Intermediary Trajectory
Risks
Technical Economic
Integration and adaptation of solutions takes time – delays to oil production
Delays jeopardize Petrobras short term economic goals
Restricted flexibility when compared to FPSOs Limits the potential to reach the technological trajectory
More complex structural interaction between risers and floater
Research and development costs might render some options uneconomical in the short term
Innovation is limited as most of these platforms have converged to the most efficient design
Relocation of platforms is very rare – often decommissioned
49
5. Disruptive Trajectory
The discovery of pre-salt reserves in Brazil has boosted the development of a segment in the
area of oil exploration and production, in which technological innovation is of extreme importance.
Known as “subsea to shore”, this disruptive technological trajectory involves highly specialized
technologies and large-scale offshore equipment working on the seabed, exporting oil & gas through
pipelines to shore or to nearby floating platforms. Making it possible to remote-control the transport of
hydrocarbons, consisting of a standalone subsea factory, carrying out tasks currently conducted on
the surface.
The figures related to the segment indicate a promising future. According to the IEA
(International Energy Agency), investments in Brazil will reach US$65 billion per year in oil exploration
and production to 2035. In the not-too-distant future, in 2020, the country will have installed 47% of all
the E&P underwater equipment in use around the world. Based on Petrobras’ Business &
Management Plan, subsea is the area responsible for an expected total investment of US$153.9
billion in oil E&P between 2014 and 2018.
The next section will consist of a brief overview of these technologies, its applications and
limitations of operability, followed by two case studies on specific technologies associated to subsea,
which aim to give a better understanding of the challenges. The chapter finalizes with a risk
assessment, identifying the main risks and benefits of these technologies.
5.1. Technological Systems
Subsea technologies have been around for more than 40 years, evolving into different
systems, being the subsea wellhead the pioneer. A subsea wellhead consists essentially of a wellhead
assembly and Christmas Tree (usually referred to as a wet tree), which is basically identical in
operation to its surface counterpart. Subsea wells have been used in support of fixed installations for
recovering reserves located beyond the reach of the drillstring or used in conjunction with floating
systems such as FPSOs and FPSs.
Since the first wellhead in the GOM, hundreds of subsea completion systems have been
installed and are in operation. Complex multi-well subsea systems have been installed, and ROV
intervention has become an integral part of the subsea completion system. Even though subsea wells
is a matured technology, only recently the paradigm of moving production processes to the seabed
emerged. Subsea processing and boosting is now a reality and will continue to develop along with the
so called SURF technologies (Subsea Umbilicals, Risers and Flowlines). The most disruptive of
concepts is the subsea factory where the need for platforms is eliminated and where this chapter will
focus the most.
To summarize, the subsea technological systems are:
Wellhead Systems (Wet Christmas Trees)
SURF – Subsea umbilicals, risers and flowlines
ROVs for remote operations/maintenance
50
Subsea processing and boosting
Subsea factory
It is important to note that the subsea architecture differs from one region to another. For
instance, the Norwegian approach is to have the processing plant 100% on the seabed (founders of
the subsea factory concept). In the other hand, the Brazilian approach to subsea is based on 90% on
the seabed, keeping some essential systems on the topside as the electrical module, which is a great
challenge to deploy on the seabed.
5.2. Subsea Production System – The subsea factory
The term subsea factory (Figure 5.1) was coined by the Norwegian state oil company Statoil in
2012 as part of their technological strategic plan which aimed to achieve a production target of 2.5
million barrels of oil per day by 2020 (in 2012 the company production was 1.12 million bpday). The
goal is to launch a subsea factory in deep and cold environments by 2020. The company believes that
the future resources are further from the land, at greater depths and in colder and harsher
environments, rendering the subsea factory vital to take advantage of business opportunities in these
areas. Since then, the concept has raised a lot interest in the industry and its application has been
considered in other locations as the Brazilian deep offshore.
Figure 5.1: Schematic view of possible subsea factory (Source:
upstreamonline.com.cdn.bitbit.net/incoming/article1325041.ece/alternates/article_main/Subsea_factory.jpg - 1st February 2015 )
A typical subsea production system is generally composed of the submerged well, including
the wellhead, the ”Christmas tree” underwater, interfaces connecting the drain system, the drain
pipelines and risers (flowlines) and also the control systems and operation of the well, including
umbilicals that are part of the sub-distribution system, which is commonly refered in the industry as
SURF, Subsea Umbilicals, Risers and Flowlines.
To the components outlined above one should still add the power supply function, essential for
the functioning of the system. The components of the subsea production system are:
subsea drilling systems (drilling);
51
subsea christmas trees and wellhead;
umbilicals and risers (communication interfaces and subsea flow - topside);
subsea manifolds and subsea connection systems;
tie-in and disposal systems;
Control Systems;
Subsea electrical grid.
Several wells may coexist in the same field. These may be integrated into a structure
designated by aggregating physical template or alternatively, forming a cluster and lying individually
connected through flow lines to a common structure (the manifold). In both cases, transport of raw
materials to the surface is performed by larger flowlines (risers) discharging into the floating platforms
Floating, Storage and Offloading (FSO) or Floating, Production, Storage and Offloading (FPSO).
These floating structures may have additional capacity for processing hydrocarbons. Disposal of
products can also be made directly to onshore facilities (seabed to shore logic).
This new paradigm of subsea development brings a new technological trajectory commonly
referred as subsea to shore, supported by radical innovations, such as multiphase pumping and laser
drilling that would enable the elimination of platforms.[49]
5.2.1. Subsea equipment evolution
Ever since the world’s first subsea well was brought into production in 1961 in the Gulf of
Mexico, the development has moved forward in big leaps, with Norway at the forefront since the 90s.
Norway’s first subsea project was in 1982 and when Statoil started the Gulfaks field development, the
decision was made to invest in subsea production, on the seabed.
In the early 90s, it had been established that production on the seabed was a realistic option.
Engineers started looking for less complicated and more cost-effective solutions. The aim was for the
subsea systems to be fully integrated with the existing infrastructure, with the subsea solutions were
linked up to the platform.
Towards the end of the 90s, the Norwegian Continental Shelf was leading the way in the field
of subsea technology and Statoil started introducing their technology in other areas of the world. As a
result, subsea technology was tested off the cost of Western Africa. Several of the large international
companies started taking an interest in these solutions, and the technology gradually became more
and more common. This brought the costs down, and systems providing improved functionality and
higher well recovery rate were introduced.
From 2002 to 2007, was a period when ideas previously considered impossible became
possible. The new fields presented major challenges, as higher pressures and temperatures
associated to longer distances from shore (e.g. Kristen, Ormen Lange and Snøhvit were a few of the
fields discovered in this period). It was decided to use subsea technology, and long pipelines were
built to bring the oil and gas ashore. During this period, major advancements were achieved in the
modules of water removal and water injection. In 2007, the world first seabed separation facility was
installed in the Tordis field (Norway).
52
From 2007 up until today, the technological evolution has advanced exponentially. Shell’s BC-
10 project offshore Brazil, in 2009 was the world’s first subsea system with gas/liquid separation and
boosting. In 2011, Total’s pazflor project offshore West Africa used the region’s first subsea gas/liquid
separation. In 2012, Subsea7 started the Gullfaks (Norway) subsea compression project, where gas is
to be compressed and exported to shore, with offshore operations due to start in 2015. Figure 5.2
shows some of the principal technologic advancements in the time frame from 2002 to 2012.
Figure 5.2: Principal advancements in Subsea equipment technology
Nowadays subsea processing systems are becoming more acceptable and available for
operators. Multiphase pumps are considered a robust and field proven technology widely used. There
are a number of oil services companies that presently offer subsea processing equipment. Leaders in
this innovative solution include Expro (UK), Cameron, FMC Technologies and GE Oil & Gas (US).
Some of the aforementioned technological milestones are depicted in Figure 5.3, where one
can see the evolution process of subsea technologies and its various cycles of development.
TIME
Ca
pa
bilit
y / C
om
ple
xit
y
Multiphase
& Injection Pumping
Water Removal &
Debottlenecking
Full Subsea
separation
Subsea Gas
Compression
3 Phase Separation
Subsea Water Removal
Boosting & Injection
53
1961 1990 1995 2005 2015
80s: Focus on how it would be possible to move the production down to the seabed. Subsea technology was mainly focused on subsea wellheads.
Time
Technolo
gy P
erf
orm
ance
Early 90s: Subsea processes (e.g. pumping, injection) become a realistic option. Search for less complicated and more cost-effective solutions. Subsea solutions integrated with existing infrastructure.
Late 90s to 2005: Subsea tech. became more common, costs went down. New systems with higher functionality and higher well recovery rate.
2005 to 2008: Prolific period of innovation. Ideas previously considered impossible became possible. Decided to develop subsea systems with long pipelines due to increasing distances.
1980 2008
Gulf of Mexico First subsea wellhead in the world.
North Sea, 1982 The first subsea project is developed in the Frigg field, Norway. WD: 100m Shore: 230 Km
North Sea, 1988 The first subsea multi-well template was deployed in the Tommeliten field, NO. WD: 75m Shore: 300 Km
North Sea Small reservoirs became financially viable with subsea solution tied-back to platforms (e.g. Sleipner, Heidrun
and Norne)
Oseberg field, offshore Norway, gets remotely controlled subsea gas injection. WD: 100m Shore: 140 Km
Norwegian tech. tested offshore Western Africa.
New discoveries present major challenges: further from shore and HPHT reservoirs.
North Sea, Norway
Fields brought into production in this period: Yme,
Lufeng (Kina), Åsgard, Sygna
and Sigyn.
Kristin field developed with robust subsea
solution. Reservoir
pressure and temp: 900 bar and
170 ºC. Highest on NCS.
WD: 370m
Ormen Lange & Snøhvit fields (NO) were developed with long pipelines to shore (120 and 140 Km respectively). No surface installations. WD:850–1000m
2008 to present: Subsea main issue still limited recovery when compared to traditional platforms. Technologies to tackle this problem were developed.
Smart-wells aim to increase recovery by gathering more data. Tyrihans field (NO, 2009) is an example of application.
Subsea factory concept emerges. (Statoil goal for 2020). Ultra-deep waters open new challenges and opportunities for subsea evolution.
World’s first subsea gas compression scheduled for 2015 in Åsgard field.
WD: 240-310 m
Tordis field (NO) saw the first full scale subsea separation. Recovery was increased from 49 to 55 percent.
First heavy oil subsea separator is developed in Brazil, Marlim field, Campos Basin. WD: 870m Shore:110 Km
Subsea artificial lift (electrical pumps) developed for Parque das Conchas, Brazil. WD: 2000 m
Figure 5.3: Technological evolution of subsea technologies: Milestones and trajectories
54
5.2.2. Subsea Market & Main challenges
The subsea factory concept has a capital intensive nature due to the many challenges it still
faces and high research and development investment needed, therefore project development is
closely tied to the market demand and to high oil prices.
The global subsea market is witnessing an increased CAPEX spent globally; however the high
initial and operation costs will delay some larger projects. The market has recovered in the Gulf of
Mexico, and this region is probably the healthiest market globally. African deep waters, no longer just
West Africa, but now much of Africa, continues to see a lot of deep water subsea activity. Asia-Pacific
continues to grow, although Australia has become constrained by cost increases. Areas in Asia, for
example, ENI’s Jangkrik project in Indonesia, have seen some of the largest subsea contracts to date.
Brazil continues to be a large subsea market along with the North Sea in Norway. The Norwegian
government offers subsidies that the UK North Sea does not offer, to encourage exploration. As a
result, it is expect that the Norwegian North Sea will remain healthier than the UK North Sea. [50]
As stated before, the goal of Statoil is to launch the subsea factory by 2020. The recent
technological steps in realizing this goal include completion of the first subsea solution for the
separation and injection of water and sand from the Tordis wellstream, and the development of the
first subsea facility for injection of raw seawater on Tyrihans. Several projects, the company noted,
such as the oil-dominated multi-phase transport on Tyrihans and Snohvit's gas condensate transport
are a few examples of the major components of the subsea factory development.
A subsea production factory may extend itself through a big area in order to tieback new fields
to existing facilities. However, long subsea tiebacks come with inherent challenges.
Subsea main challenges
Some of the most demanding challenges are the flow assurance issues arising from the
different operating regimes which may be combined with more viscous fluids and/or fluids at low
pressures or low temperatures. Issues like the deposit of paraffins (wax) or asphaltenes are a major
concern because they can block the flow, halting production completely.
Allied to flow assurance concerns, there is also a growing interest in the subsea industry to integrate
novel numerical analysis as early as possible into the design cycle. This is mainly due to the
technology paradigm shift that has been occurring in this industry in the last couple of years. Until very
recently, in order to reduce the risk of a failure, there was a reliance on expensive over-designed
solutions as there were limited concern about the weight and bulkiness of the equipment. Nowadays
there is an aggressive structural behaviour optimisation approach to all subsea equipment, especially
to the group of SURF (Subsea Umbilicals Risers and Flowlines) technologies. These technologies are
under constant stress due to the harsh conditions of the sea and it’s therefore imperative to cope with
the increasingly demanding operation conditions and difficult economic viability.
Subsea equipment needs to be connected to topside power distribution equipment via
individual subsea cables rendering the operation complex and costly due to the amount of cables,
55
topside space and riser capacity needed. The solution might be the implementation of a subsea power
grid which is the project being developed by Siemens in Norway, where the four main components
(transformer, medium-voltage (MV) Switchgear, variable speed drive, and power control and
communication system) will all be located on the seabed. By implementing a subsea power hub and
grid, operators of subsea fields will be able to distribute power more widely.
This trajectory can offer a solution to the problem of the high share of CO2 that will come out
from the pre-salt reservoirs as well. The separation of CO2 in the seabed (followed by its re-injection
in the reservoir) increases their oil recovery rate and it avoids environmentally damaging emissions.
But these technologies are still in the experimental stage, and the low oil prices will probably delay
further developments in the short term.
In the following section one will analyse two case studies in order to deepen the understanding
of some of the challenges subsea technologies faces. The first case study will explore SURF
technologies and their challenges, while the second will be focused on Flow Assurance Technologies.
5.3. Case Study Analysis
As stated in the last section, there are still major challenges to overcome in order to enable a
fully working subsea factory. In the following sections we will explore two of these challenges through
the use of case studies.
5.3.1. Case 1: SURF technologies
The safe and efficient interconnection from the topside platforms and vessels to the well heads
and pumps on the seafloor is necessary to transfer power and data, as well as hydraulic and other
fluids to guarantee reliable oil extraction operations. The local generation of electric power and the
subsequent distribution to various appliances achieves lower generation costs. In addition, broadband
communication systems are now an essential feature of the most modern communication and process
control systems. Subsea Umbilicals, Raisers and Flowlines form this vital link among the various
centres of operation. They must be able to withstand high mechanical and chemical stresses, high
operating temperatures and pressures in order to ensure the continuous and reliable supply of
services in the harsh environments below the sea.
The longevity of piping systems has a direct impact on overall field performance, since cost
and downtime associated with replacement and repair are very high. The reliability and fatigue life of
the riser system is largely dependent on subsea currents and the pipes response to them; this
response is primarily driven by vortex induced vibrations (VIV), and vortex induced motions (VIM).
These motions are represented in Figure 5.4, where VIV are portrayed as a mass-spring-damper
system in the cross-flow direction, while the VIM is the same systems in the in-line direction. This
representation is a simplification as the real motions have several degrees of freedom and exist on all
directions.
56
Figure 5.4: Vortex Induced Motion (VIM) and Vibration (VIV)
(Source: http://web.mit.edu/towtank/www/images/viv3.jpg - 25th March 2015 )
In the past, the industry has relied on simple structural analysis methods to predict the effects
of VIV. These approaches tend to be overly conservative, making the decision process concerning
structural integrity of subsea piping systems difficult. Computational fluid dynamics (CFD) is being
used to complement other analysis methods by providing higher fidelity information that is otherwise
unattainable.
Though CFD simulations have been successfully employed by top tier global Oil & Gas
companies to conduct small-scale analyses of risers and their VIV countermeasures, large scale
numerical simulations of VIV and VIM are still a challenge nowadays for most general purpose CFD
codes. In particular, due to the riser system’s very large ratio of length to diameter (L/D), the number
of nodes required for a full-scale simulation has historically challenged the capacity of many
computational facilities and most are not feasible for real product development cycles.
Besides the current induced motions, most flowlines are subjected to High Pressure and High
Temperatures (HP/HT) due to the content they transport. Laying these flowlines on an uneven seabed
may result in unacceptable levels of high stress or strain; therefore seabed modification can be
simulated in a finite-element model and re-run to confirm the desired decrease in those levels. The
finite-element model may be a tool for analysing the “on-site” behaviour of a flowline and the several
load cases subjected during its lifetime, for example[51]:
Installation;
Pressure testing (water filling and hydro test pressure);
Pipeline operation (content filling, design pressure and temperature);
Shut down/cool down cycles of pipeline;
Upheaval and lateral buckling;
Dynamic wave and/or current loading;
Impact loads.
When dealing with SURF technologies, corrosion is also a big issue, especially in the pre-salt
fields that have a higher CO2 content than normal, requiring special materials highly resistant to
corrosion; for this reason Petrobras has been using special steel alloys which are very expensive.
According to the Head of Flow Assurance at Galp, some of the corrosion resistant risers used in
offshore Brazil have an operation life of around 5 years, while the production platform is deployed for
57
20 to 25 years. Replacing and repairing operations are costly and time consuming, resulting in high
operative expenditures (OPEX).
Another aspect regarding CFD applied to SURF technologies is erosion. Erosion occurs when
solid particles in the flow (sand), or droplets in the gas flow, scrape against the walls of pipes and
equipment. It is a difficult process to monitor due to its variable nature, but CFD erosion numerical
analyses are becoming a key part on understanding and predicting this process.
Some of the requirements identified when developing SURF engineering projects are:
Pre-project and feasibility studies
Design and FEED studies
SURF detailed engineering packages
Independent design verification analysis
Auxiliary equipment design: bend stiffener or restrictor, and installation aids
Expertise in hydrodynamics, vortex induced vibrations; structure in any type of risers systems
Expertise and analysis for installation of pipelines, risers and subsea equipment
5.3.2. Case 2: Flow Assurance Technologies
The concept of flow assurance is the ability to produce fluids economically from the reservoir
to the production facilities over the life of the field and in all conditions and environments. Flow
assurance is critical to deep water oil and gas projects, where extreme conditions such as high
pressures and low temperatures promote the formation of oil & gas hydrates, originating blockages
that either reduce or shut-off oil and gas production altogether and remediation costs can be high. The
major areas of concern with flow assurance are wax, asphaltenes, and hydrates.
Figure 5.5 is an oil phase diagram from a deep water Gulf of Mexico field, depicting crude oil
phase changes as pressure and temperature are decreased in a production system. The diagram
shows how asphaltenes, wax, and hydrates form as the crude flows from the reservoir into a flowline
(line A – D). Gas also comes out of solution if the pressure in the system drops below the bubble point
pressure.
58
Figure 5.5: Deepwater Gulf of Mexico oil phase diagram (APE: asphaltene precipitation envelope; WAT: wax appearance temperature) (Source: [52] )
Samples of reservoir fluids should be tested for potential formation of asphaltenes, wax, and
hydrates, and appropriate facility design and/or treatment programs should be considered during
project planning. Proper fluid characterization is important in understanding the conditions under which
these flow restrictors form. Knowing the pour point of a hydrocarbon fluid (temperature at which it
ceases to flow) is important in the design of production systems.
Wax and Asphaltenes Wax and asphaltene formation in pipelines and risers is a significant flow assurance problem,
particularly offshore where remediation costs are significantly higher than onshore. While asphaltene
formation restricts flow in production systems, it does not usually stop flow completely, as does wax.
The wax appearance temperature (cloud point temperature) and asphaltene flocculation points
(precipitation point) can be measured in the laboratory, and should be considered when designing
production systems. Formation prevention techniques include pipeline heating and insulation, and
chemical and hot oil treatments. Remedial techniques include chemical and hot oil treatments, and
pipeline pigging.
Hydrates
Hydrate formation in deep water is more likely to occur due to low ambient water temperature
at high pressure (resulting from greater subsea depths), during both shut-in6 periods and during
normal operations. Figure 5.6 is a hydrate stability curve for a typical Gulf of Mexico gas condensate
showing how at lower temperatures small changes in pressures can result in hydrate formation.
6 Shut-in: Period of time the well is closed, either for maintenance purposes or for pressure build-up analysis
59
Figure 5.6: Hydrate Stability curve for a typical GOM gas condensate (Source: [53] )
While the majority of hydrates plugging problems have occurred in gas and gas-condensate
systems, hydrate plugging can occur in oil systems as well, particularly as water-cut7 increases. In
most deep water Gulf of Mexico oil developments, high water-cuts have not been achieved; however,
with the application of subsea separation and boosting technologies, fields will be produced to higher
water-cuts. As such, the design of subsea processing systems for oil fields should consider hydrate
formation. In oil systems with <50% water cut, hydrates form as follows[54]:
Water is entrained as droplets in an oil-continuous-phase emulsion;
As the flowline enters the hydrate-formation region (low temp-high press), hydrates grow rapidly
(hydrate shell around droplet);
Hydrate shell grows inward;
Hydrate droplets agglomerate, forming large masses, which can plug the pipeline.
The previous steps are illustrated in Figure 5.7.
Figure 5.7: Hydrate formation in an oil dominant system ( Source: [54] )
7 Water- cut: ratio of water produced compared to the volume of total liquids produced;
60
Removal of hydrate plugs in production systems is difficult and slow, and requires a large
amount of energy. Additionally, one cubic foot of hydrate can contain as much as 182 scf of gas, so
the process of depressurizing a hydrate plug can result in a rapid release of gas, creating safety
concerns. A better approach to managing hydrates in a production system is by prevention rather than
removal. Prevention is achieved through pressure and temperature control, and through chemistry.
Temperature in production systems is managed through tubing and pipeline heating and
insulation, while the addition of chemical hydrate inhibitors to the flow stream creates larger hydrate
free regions. Pressure in production systems is controlled through isolating and bleeding-off pressure
in pipelines. Subsea equipment also plays an important role in assuring the phase separation, thus
reducing hydrate formation on water, oil and gas mixtures.
In the following chart (Table 5.1) we’ll present a summary of some of the principal
technologies of flow assurance used nowadays assessed into two maturity levels: emerging and
matured. Emerging technologies are those that are growing and yet going through some
developments, while matured technologies are well established technologies and have been around
for a decade or more.
Table 5.1: Different Flow Assurance Technology Areas (Source: Adapted from [55] )
Flow Assurance Technology Areas
Applicability Maturity level Solution type
Thermal Insulation Hydrates/Wax
prevention Matured Thermal
Direct Electric Heating
Hydrates/Wax
prevention; Plug
removal
Matured Thermal
Electrically heated
pipe-in-pipe
Hydrates/Wax
prevention Emerging Thermal
Cold Flow Hydrates/Wax
prevention Emerging Thermal
Chemicals: Methanol,
Ethanol
Hydrates/Wax
prevention; Plug
Removal
Matured Chemical
Asphaltene inhibitors Asphaltenes Matured Chemical
Paraffin inhibitors Paraffins/wax Matured Chemical
Drag reducing agents Pressure drop
prevention Emerging Chemical
Subsea separation –
Water removal
Hydrate prevention
Increased Oil Recovery Emerging Hardware
Erosion probe Erosion rate
measurement Matured Hardware
A new patented process currently being studied is Cold Flow in which hydrate particles are
allowed to form, but their agglomeration is prevented through emulsification. This process keeps the
hydrate particles entrained in the oil phase, allowing the hydrate particles to flow. Drag reduction
chemicals, usually polymers solutions, are also an important emerging technology that is especially
effective in reducing the flow problems of high viscosity oils. [55]
61
5.4. Choice of Development Concept – Platform or Subsea solution
Technological progress with subsea production has been rapid. Such installations can now be
used in most conditions, and costs have been reduced sharply. A real choice exists today on a
number of discoveries between platform-based or subsea development solutions. The choice of
concept is a complex business, with input from many interested parties and technical disciplines.
Examples of key subsea developments on the Norwegian Continental Shelf that faced a
demanding choice of concept are Ormen Lange and Snøhvit in the Norwegian Sea and Barents Sea,
respectively. The Ormen Lange field started production in 2007 and has been developed using
24 subsea wellheads in four seabed templates on the ocean floor are connected directly by two 30
inches (762 mm) pipelines to an onshore process terminal. In Snøhvit, the development comprises 21
wells. The subsea production system is planned to feed a land-based plant via a 160 kilometres long
submarine gas pipeline with diameter of 680 millimetres (27 in). The gas from Snøhvit will be used for
liquefied natural gas (LNG) production. [56]
If, as in these cases, the development involves a tieback of subsea facilities to a newly built
land-based terminal, this will be included as investment in the net-present-value (NPV) calculations.
On the other hand, when the choice is to tie back to an existing processing facility, which could now or
over time be used by other projects, an opportunity cost must always be calculated for its use.
Fixed platforms offer a number of advantages, which need to have a value put on them. Such
installations permit a flexible well work strategy, particularly if the platform has its own drilling facilities.
They offer lower costs for EOR (enhanced oil recovery) campaigns after a few years of learning
lessons on the field, and they normally have higher regularity over their producing life. New recovery
technology, which emerges after development has ended, is often easier to adopt when a platform
system has been chosen. [57]
The biggest advantage of subsea installations is the lower initial investment. On the other
hand, costs are higher for operation and maintenance, flexibility is lost, and it is far more expensive to
drill new wells or implement necessary changes to existing ones. An improvement measure on a
subsea well often requires five times the earnings potential than would be needed for an intervention
in a platform well. Delays to well intervention are one consequence of this. However, a subsea facility
is often a relevant option in very deep water, where the amount of material needed for the platform
renders the initial investment too high. It is also a good choice for small fields and reservoirs with a low
level of complexity. Continuous advances in subsea technology have also gone some way in reducing
the disadvantages of subsea developments.
The aforementioned points along with some additional ones are summarized in Table 5.2. As
stated in the beginning of this section, the choice of concept is a very complex process where different
stakeholders take part, so the following chart serves as a mere introduction to what needs to be put
into account when posed with this choice.
62
Table 5.2: Summary of advantages and disadvantages between the two concepts (Adapted from [56] and [57])
Platform Subsea
Pros Cons Pros Cons
Technical flexibility High initial investment Lower initial investment Less technical flexibility
Lower EOR costs
Restricted number of
wells (limited by the
template slots)
No restriction on the
number of wells (extra
wells may connect to
floating units)
Higher EOR costs
Higher production
regularity
In case of erroneous
reservoir evaluation,
the resulting
development can fail to
justify the high cost
(best suited for low
uncertainty reservoirs)
Due to lower initial
investment, it can be
the only alternative
with positive NPV (in
the case of low oil
prices or fields with
small volumes)
Higher operative costs
Lower operational risk
Might not be ideal
solution in the short-
term
Good option in low
complexity fields
Higher operational
risks due to emergent
technologies
Easier to adapt to new
topside solutions
Continuous
development is
achieving better
recovery rates
Limited adaptability
Opportunity cost must
be considered if it’s
tied-back to existing
facilities
Essentially, the choice of development concept has a great impact of the cost of future EOR
work. A solution based on a dedicated drilling rig, for instance, will normally have greater potential
than platforms without such facilities or than subsea solutions in which a mobile rig must be chartered
each time. This affects not only the flexibility, but also the cost of new wells. However, initial
investments on platforms with dedicated drilling facilities are considerably higher than subsea
solutions and higher than traditional platforms. Platform wells also have better production regularity,
while mechanical damage can, as a rule, be repaired and wells brought back on stream in reasonable
time. Taken together, these considerations mean that developments based on platforms with their own
drilling facilities have a substantially higher recovery factor. This is illustrated in Figure 5.8.
Figure 5.8: Average recovery factors for fields with a platform and those developed with subsea wells. Platforms
are defined here as fixed structures with a drilling module (Source: [57] )
63
The recovery factor is defined as the proportion of the oil in a reservoir that is recovered. The
recovery factor for offshore oil fields normally lies between 10% and 60%, but can reach close to 80%
in certain favourable cases. A global overview of recovery factors is provided in [58]. They report an
overall factor of 46% for the North Sea, and describe that Norway has achieved higher recovery
factors when compared with other countries. Today the average oil recovery rate worldwide is only
between 20% and 40%, which leaves great room for improvement, where a small increase could yield
substantial financial gains. In the Norwegian case, according to [59], in 2009 an increase of 1% of the
oil recovery rate would yield net revenues on the order of USD 20-30 billion with the oil prices at the
time (around 80$ a barrel).
There are nowadays real options favouring the platform solution, and real options favouring
the subsea solution, which is in constant development. In many cases, the combination of these two
solutions (a few subsea wells in the beginning followed by an optimized platform based on the
information from subsea wells) looks to be a more-convenient approach to develop the petroleum
fields using modern real-option concepts.
When choosing a concept, it is often impossible to establish which solution is unambiguously
and objectively the best because so many sources of uncertainty exist. In such circumstances,
decisions are influenced not only by knowledge but also by power. The relative strengths of the
various technical disciplines (reservoir, drilling, facilities, and project execution) will mean a great deal
in practice. This is difficult to handle in all organizations. Therefore, efficient communication between
all stakeholders is of the utmost importance to ensure the best choice possible considering available
data. [57]
5.5. Risk Analysis
The constant change in the industry and technological evolution comes with inherent
associated risks and benefits. As seen in chapter 2, technology-related risks play a great role in the
decision process when the choice lies between employing a matured technology or an emerging set of
technologies as the subsea factory addressed in this chapter.
The subsea factory concept conveys risks with uncertain impacts due to the lack of knowledge
and experience about consequences of deploying this new technology, but also systemic risks due to
the multiple interactions and dependencies these technologies present. The decision to allow the
employment of such technologies worldwide must take into account appropriate risk management
measures to avoid or mitigate potential adverse consequences as oil spills for example.
In this section, as in the previous two chapters, one will develop an analysis of the perceived
main benefits and risks that stakeholders from different sectors associate with this new technology
and its possible future implications.
64
5.5.1. Benefits
The benefits associated with subsea technologies and with the subsea factory concept are
vast. While some of them are technical, related directly to the technology itself, others are economical,
either truly economic in nature or entwined with technical or execution elements.
Table 5.3: Benefits associated with the Disruptive Trajectory
Benefits
Technical Economic
Allows access to difficult/marginal reserves
where a platform would not be economical/safe
Potential cost saving (lower initial investment and
opportunity cost if infrastructure is present -
pipelines )
Combination with platforms can provide best of
both worlds
Disruptive technologies put companies in the
technological frontier (improved market share)
Reliability standards being set – structured
approach
Greater R&D investments can attract more
investors
Potential less environmental impacts
Human intervention only remotely – increased
security
5.5.2. Risks
Subsea technologies have inherent risks as mentioned before. The following list includes a
selection of the main risks found during the analysis to this field development concept.
Table 5.4: Risks associated with the Disruptive Trajectory
Risks
Technical Economic
Requires ROV(remotely operated vehicle) for
maintenance operations
Business risk of investing in low maturity
technologies
Digital oil field control systems are prone to
cyber-attacks – data breaches, “hacktivism” and
threats to operational technology can cause
production stoppages and decrease production
Cyber-attacks are also a commercial risk, with
disruption reducing revenues
Oil spills – how to prevent and solve this situation
in the new subsea context still unclear
Strict regulations in the admission of new
technology and safety guidelines may slow the
adoption of certain technologies
Recovery rate still lower than platforms Project development highly dependent on oil
prices due to high costs
Control of deep water systems highly depended
on sensors and remote systems
Deeper waters mean less accuracy in
communications (e.g. acoustical systems)
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6. Discussion and Summary
6.1. Summary
The new challenges for the deep-sea offshore oil and gas exploration but also for the
sustainable exploitation of the oceans are leading the technology development to rapidly adapt to new
contexts. There is much debate over whether technical evolution should be a continuous process,
characterised by less risky incremental innovations, or disruptive, where radical and innovative
solutions are employed.
Therefore the main purpose of this thesis was to identify and understand the technological
evolution, identifying the main technological trajectories perceivable for the exploration of deep-waters,
specifically in the pre-salt regions where in 2007 giant oil fields were found (refer to Chapter 1:
Introduction). The discoveries brought many challenges and raised several questions for stakeholders,
who want to know if the pre-salt can represent a real technological divide or just an adaptation to a
new context.
In this scope, three main technological trajectories were identified:
Continuity: incremental improvement of the technologies that were adopted in the post-salt
reserves (Campo’s Basin), the FPSOs, wet completion, flexible risers or semisubmersible
platforms;
Intermediary: implementing dry completion systems as the Tension Leg Platform (TLP), SPAR
Platform or new semisubmersible systems using rigid risers;
Disruptive: “subsea to shore” technologies that require radical innovations leading to the
concept of subsea factory, which would eliminate the need of platforms.
Different technological trajectories represent different challenges, risks and associated
benefits. There was a need for a robust risk governance framework to complement the present
analysis, thus the International Risk Governance Framework (IRGC) was used and it is explained in
greater detail in Chapter 2: Scope and Methodology. Besides the risk analysis, a case study
methodology was also used, where for each of the trajectories two appropriate case studies where
chosen to broaden the view on the technologies development happening in each trajectory, hence
deepening the overall understanding of what is being studied. This methodology is also clarified in
Chapter 2.
In Chapter 3: Continuity Trajectory, the FPSO vessel was studied in detail, mainly the
engineering design of a vessel and all the challenges associated with it. Some research was
developed regarding the evolution in the use of such systems and two case studies of vessel
adaptations were presented. The first one is focused on the Floating Liquefied Natural Gas (FLNG)
vessel, which is a vessel capable of extracting and processing natural gas offshore, without requiring
gas pipelines to shore. And the second case study is about Floating Production, Drilling, Storage and
Off-Loading (FPDSO), which is essentially a FPSO with a drilling rig built-in, capable of well
intervention without the use of an external drilling platform. This FPDSO is capable of a complete field
development on its own. The chapter continues with the current challenges in Brazil and future
66
developments of this technology and finalizes with a risk analysis of following the continuity trajectory,
focused on technical and economic aspects.
The following chapter, Chapter 4: Intermediary Trajectory discusses a trajectory aimed for an
integration of common technological concepts within new environments. Such concepts include the
widespread platforms as the TLPs, SPARs and Semisubmersibles, used in great number in the Gulf of
Mexico and North Sea. The choice of concepts is discussed as well as the differences between using
dry or wet Christmas trees. The case studies for this trajectory aimed to understand how innovation is
being done on already mature technologies. The first one focuses on the Papa-Terra TLP, which was
the first platform of this kind to be used offshore Brazil. The second case study discusses the new
concept of semisubmersible with a dry tree that has the potentially be used on ultra-deep waters. The
chapter continues with the current challenges for this type of technologies and future developments
and finalizes with a risk analysis.
The disruptive trajectory presented in Chapter 5: Disruptive Trajectory focuses on subsea
technologies and the concept of subsea factory. These technologies, although still not matured,
enable full field operations remotely on the sea bed, exporting through pipelines to shore or nearby
platforms. This trajectory presents high risks and still requires a big number of radical innovations to
be considered truly feasible, however it represents a change in paradigm and a major technological
breakthrough capable of revolutionizing the way exploration and production is made in the future. The
evolution of these equipments in the recent decades is discussed, as well as the main challenges they
face. The case study analysis focuses on two of these challenges, namely the Subsea Umbilicals
Risers & Flowlines (SURF) technologies, which make the link between all the subsea systems, and
Flow Assurance technologies. One section is dedicated to the choice of development between
platform and subsea solution and the chapter finalizes with a risk analysis.
In this final chapter, Chapter 6, the knowledge gained from the analysis done in the previous
chapters must be integrated in the global scenario of the oil and gas industry. Considering the recent
events, the big unknowns and the role of growing uncertainty in the global economy, one will position
the technological paths role in the “big picture” and how they can influence and be influenced by
possible future energetic scenarios and industrial policies.
A recurring theme in this thesis is change, in contexts, technologies and paradigms. With
change many opportunities arise and that is where this thesis is linked with the +atlantic project,
performed under the scope of the OIPG. +atlantic consists of an international agenda aimed to
promote the scientific, technological and industrial capacity of Portugal towards the sustainable
exploration of the Atlantic, taking advantage of the many opportunities arising internationally as the
new oil and gas discoveries in Portuguese speaking countries, the extension of the Portuguese
continental shelf and the shift in paradigm towards subsea exploration.
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6.2. Future scenarios for the Oil & Gas industry
In order to develop some plausible scenarios for the future, one must take into consideration a
big range of aspects. Some though must go into the big trends in the energy industry, such as
demographics, emerging energy technologies, new fuel sources, energy consumption and climate
change. Next, one must consider the big unknowns, like the performance of global economy, whether
policy will favour the adoption of green policies and the global scenario of growing uncertainty.
Taking these aspects into consideration, Deloitte has developed a vision for 2040 of the Oil & Gas
industry [60], where four possible scenarios emerged:
Sustainable globalization
The decline of oil
The hegemony of traditional oil producers
Dominance of fossil sources
The scenarios and their relative positions relative to an axis of Energy Source
Competitiveness vs Geopolitical Globalization are illustrated in Figure 6.1.
Figure 6.1: Future plausible scenarios for the O&G industry (Source: [60] )
Scenario 1: Sustainable Globalization
In this scenario, relative geopolitical stability favours economic growth and trade cooperation
between countries. With high demand, new alternative sources of energy, finally economically viable,
would add to the supply of conventional fuels. It is a scenario in which ordered growth in the
geopolitical axis and a green future in the axis of competitiveness between energy sources
predominate.
Scenario 2: The decline of oil
In this scenario we would see a decline in the importance of oil in the global energy matrix. It
would be a world in which alternative energy sources would gain impetus, with a lower demand for oil
due to lower economic growth, combined with technological innovations and advances in alternative
Ordered Growth
Conflictive Growth
Grey Green
Dominance of Fossil sources
Sustainable Globalization
Hegemony of traditional oil producers
Decline of Oil
Energy Source Competitiveness
Glo
balizati
on
G
eo
po
liti
cal
68
sources. The preponderance on the geopolitical axis would be at the conflictive stagnation end,
maintaining the green hypothesis on the competitiveness of energy sources axis.
Scenario 3: The hegemony of traditional producers
Politically, this scenario is similar to that of number 2: political tensions in several corners of
the world would not decline and China and other emerging countries would continue to stagnate,
which would contribute to a fall in global demand. The difference would be that the countries that
today dominate the oil and gas market would continue to exercise power in 2040, with oil firm and
strong in the global energy matrix. It would be a scenario in which the hypothesis of conflictive
stagnation would combine with the grey extreme of the competitiveness of energy sources axis.
Scenario 4: Dominance of fossil fuels
In the fourth scenario, the geopolitical axis would again tend toward ordered growth, with
competitiveness of energy sources leaning toward the grey end. Alternative energy vectors would not
be established as viable options and natural gas would not be commercialized through a global
market. With this, sources of fossil origin would multiply, which would combine with conventional oil
and gas exploration to supply growing demand from the emerging economies.
The four scenarios aforementioned are merely avenues of possible developments, because in
the present context of growing global uncertainty, no scenario will be determinant by itself. The future
of the energy sector might be a mix of two or more of these situations, where no scenario will
materialize itself completely and where uncertainty and systemic risks will play an ever growing role.
Nonetheless, taking into consideration the axis proposed in Figure 6.1, one can comment on
some aspects of the present energetic situation. Regarding energy source competitiveness, we are
leaning to the grey energy sources, where fossil fuels will continue to meet most of the world demand,
with gas (LNG) becoming the fastest growing fuel (increasing 1.9 percent per year), used more and
more to produce electricity. Due to improved vehicle efficiency, demand for oil will grow slowly.
Therefore, supply will have to be moderated and growth in US shale oil will eventually start to level off.
Although, electric cars are a reality, they are still not widespread and affordable to the average
consumer. The current oil crisis also puts pressure on other renewable energy sources, which become
less competitive. [61]
The actual low oil prices result from tensions between OPEC (Organization of Petroleum
Exporting Countries) and the US, where OPEC is keeping production levels high in order to reduce the
oil price and drive the US shale-oil boom to a halt. Therefore, in the geopolitical axis, we’re leaning
more towards a conflictive situation.
Considering those aspects, one can comment we’re advancing to scenario 3. In this scenario
the effects for Brazil and the pre-salt would not be the most favourable. If the prices controlled by
OPEC continue at a low level, this could impair exploitation of the pre-salt reserves. With the
economic viability of the pre-salt in doubt, the country could return to being a net importer of fuel. Oil
and gas exploration plans would have to be revised by operators in this context. In its search for
69
competitive oil and gas reserves for exploration and production, the Brazilian industry would turn to
other Latin American countries, such as Argentina, Bolivia, Peru and Mexico. In the absence of a
global supply of LNG, there could be an exit of companies that are significantly dependent on the
resource. These companies would migrate to countries – such as the United States – where supply of
the resource is more reliable and inexpensive. [60]
These changes would aim in a redefinition of directions for the Brazilian oil and gas segment.
Reduced demand and increased supply would drive prices down and create an adverse scenario.
Management adjustments, cost cutting and a greater emphasis on operational efficiency would
become imperative.
However, there’s still very high uncertainty in the oil price outlook. Predictions appoint to a
growth in demand for oil in the second half of the year, which could increase the prices to around $70
dollars per barrel as we enter 2016. But the band of lower and upper limits widens over time, and
according to [62], the limits are of $32/barrel and 108$/barrel for December 2015. In this scenario, the
technological evolution is highly conditioned, as companies opt for either less conservative solutions
or to halt ongoing projects. Hence, the “subsea to shore” trajectory will face some challenges in the
near future with several projects already in stand-by in the North Sea.
As mentioned before, uncertainty is one of the main conditioners of current investments and
technological developments, and even though it represents a risk, the challenges and possible
benefits associated are a great opportunity for companies, institutions and governments to adapt their
frameworks and policies to an ever changing world. In the next section, one will dwell deeper into the
current uncertain landscape and the new challenges it brings.
6.2.1. Growing Uncertainty: Risks and New Challenges
The global macro-economic environment remains challenging without any apparent signs of
easing, requiring the role of risk management to rapidly evolve. There is a much larger connectivity
between the different risks and nowadays companies are starting to see the risk management
discipline as an enabler of sustainable growth an innovation.
According to [63], the top five risks expected to rise over the following years by the energy
sector are: Legal risks, Emerging risks, Business risks, Regulatory requirements and Operational
risks. Legal risks refer to the cost and loss of income caused by legal uncertainty, which can take the
form of regulatory or legal action, disputes for or against the company or failure to meet obligations.
Emerging risks were defined in chapter 2, with particular importance given to technology-related
emerging risks. Business risk refers to the possibility of inadequate profits or even losses due to
uncertainties, e.g. changes in consumption patterns or increased competition. Regulatory
requirements refer to the restrictions, licenses, and laws applicable to a product or business, imposed
by the government. Finally, Operational risks are defined as the risk of loss resulting from inadequate
or failed internal processes, people and systems or from external events.
The large scope of the risks may lead executives and boards to become overwhelmed into
paralysis, or deeming the problem too large to ever be effectively managed. While it’s true that
70
stakeholders can’t anticipate or prepare for every conceivable risk, it is possible to take a methodical
approach to separate the credible and realistic risks from the less relevant for their assets. Hence the
importance of frameworks like the one proposed by the IRGC, to give guidance in handling risk, even
in situations of high complexity, uncertainty or ambiguity.
Regarding the current energy market, in the long term, the risks associated with lower oil and
gas prices could be very adverse. If prices linger at today’s low levels for an extended period,
operators could be faced with some difficult decisions about their existing and future assets. Today’s
oil and gas sites may eventually become uneconomic.
To address these challenges, operators have been using a mix of mid-term planning and
short-term cutbacks. Firms are generally finding savings by cutting staff, consolidating resources,
delaying exploration and drilling, and even holding off on the completion of existing wells without
making fundamental changes to their business models. These efforts are helping to keep them solvent
and their investments in place in hopes of a quick turnaround in oil prices. [64]
How can Engineering be part of the solution? Engineering can be part of the solution by helping energy operators cut costs and raise
revenues in innovative ways. Carefully planned facilities engineering can do the following for
operators:
Cost reductions through process optimization: focusing on efficiency improvements, addressing
product quality needs, and eliminating redundancies. The overall goal of process optimization is to
reduce the cost of production at existing sites and reduce long-term maintenance needs; [64]
Flexibility in Engineering Design: flexibility enables the system to avoid future downside risks and
take advantage of new opportunities. By cutting losses and increasing gains over the range of
possible futures, flexible design can improve overall average returns; [65]
Revenue generation through debottlenecking: identifying where revenue stream is being
constrained by improper or less than optimal site designs; [64]
Strategic site planning: Engineers can develop plans for retrofit applications and new builds, thus
minimizing the cost of construction and ongoing maintenance and upgrade costs; [64]
Pre-engineering to prepare for the eventual upturn: operators need to take careful steps to cut
capital expenditures and operating costs today with an eye toward returning to investment mode in
the future. This also extends to site planning and asset acquisition, preparing both for a changing
market and a changing regulatory environment. [64]
By considering these value-added options, engineering firms are well positioned to provide
these services with better efficiency, streamlining, and cost-saving innovations. Oil and gas firms
cannot give up on existing assets as a result of market pressures because it will cost more to get back
into production mode later if they do. Maintaining a readiness to return to the market at higher
production levels is important. Now is the time to work more effectively to extract maximum
productivity from existing facilities by building value, maintaining flexibility, and improving efficiency.
[64]
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6.3. The Role of Industrial Policies
The selection context of a certain technological trajectory is shaped by several external
factors, which range from social and institutional to economic and environmental situations. The
institutional setting is particularly relevant as regulations can facilitate or restrain the use of new
technologies. Thus the relation that Industrial Policy has, and how it should adapt to a climate of
uncertainty, must be taken into consideration.
There is a great debate regarding the role of industrial policies. The most recurrent argument
against it is that it is “picking winners” and thus distorting competition, while exposing governments to
its established interests.[66] However, the times have changed and international competition has
taken a different shape to adapt to an era of knowledge economy with extremely rapid innovation and
rapidly falling prices and fast-changing product characteristics, where knowledge and education is
considered as a productive asset, essential to adapt to market uncertainties.[67] In this case, the
government and its interventions in the market can play a positive role in industrialization by facilitating
the generation and spread of knowledge to all stakeholders. In the knowledge economy, public sector
is thought to be more of a facilitator of the creation and spread of knowledge by and among private
firms rather than an agency governing the market and guiding private firms in which activities they
should invest.
In this context, according to Rodrik in [68], the right industrial policy is one that creates and
maintains strategic collaboration and coordination between the private and public sectors, enhancing
the flow of information from the market to the government in order to design the most appropriate
forms of government interventions. The instruments of such policy, financial or nonfinancial, aim to
internalize the externalities related to knowledge and knowledge spillovers at different stages of
knowledge generation and dissemination. Strengthening of industry–university or industry–science
relations are an essential component of such instruments. The state generally plays a role as a
facilitator and coordinator, not the driver (as in traditional industrial policy) of knowledge generation. In
the selection of the firms to be funded for knowledge investments, the state does not adopt “picking
the winners” type of a policy where the firms are selected in advance, but rather leaves it to the market
forces to determine those firms. In short, the government can intervene in the market to facilitate risk
sharing and to establish collaborative relations among private entrepreneurs on different stages of the
value chain.[69]
One important theme of industrial policies is the so-called local content policy, which aims to
extend the benefits to the local economy beyond the direct contribution of the extractive industry of
their exhaustible resources, through links to other sectors. Increasing local content is becoming a
policy priority in many resource-rich developing countries, among both mature and recent entrants to
the industry.
In Brazil the strong local content policy (LCP) framework and regulations have driven an
increasing share of local employment, goods and services, and are contributing to re-establish Brazil
as a shipbuilding nation. Brazilian regulations mandate targets for goods and services of domestic
origin. In this sense, they encourage the emergence of a competitive local supply industry by
72
incentivizing inward investment by international suppliers and service contractors that strive to meet
these targets. If set too high compared to existing and short-term local supply capability, policy targets
might reward less than competitive suppliers. If not carefully designed, LCPs run the risk of
entrenching unproductive practices, higher costs, and lower quality for lack of competition. This risk is
probably greatest in emerging countries with mature or large-scale upstream petroleum sectors. In
Brazil the sheer scale and potential profitability of existing and future business opportunities in the
E&P sector, affords the government considerable power to set stringent local content regulations. [70]
6.4. Opportunities for Portugal – Mechanisms of Development
The extension of the Portuguese continental shelf, the predicted development of the South
Atlantic, related with exploration and production of hydrocarbon, and the enlargement of the Panama
Canal, strengthening maritime connections, all bring possible opportunities for Portugal which must be
characterized and put into a context of industrial developments and national technological
capacitation. Additionally, the industrial growth of the oil and gas sector in Brazil which is being
followed by other Portuguese speaking oil-producing countries, as Angola and Mozambique,
represents an opportunity for Portugal.
In order to characterize the opportunities, it’s important to evaluate the Portuguese industry
and what it can offer nowadays to the oil and gas sector. The following table includes some of the
main company with operations related to the oil and gas industry with activities in Portugal. The
selection was based on operations size and on the contacts developed in the context of the +atlantic
in order to give a sense of what is done and can be done in Portugal. An exhaustive analysis of the
companies is out of the context of this thesis.
73
Table 6.1: Companies operating in Portugal with activities in the O&G sector
Company Name HQ
Location Type of work
Supply chain
Main contractor
System integrator
Product supplier
Service Company
R&D
AMAL Setubal Metal works
ARSOPI Vale de Cambra
Metal works
Martifer Oliveira de
Frades Metal works
TechnoEdif Lisboa Engineering services
MPG Construções
Setubal Naval Construction
Lisnave Setubal Naval Services
Technip Portugal
Lisboa Project Management,
engineering and construction
NOV Houston,
USA
Project Management, engineering and
construction
Subsea7 London,
UK
Project Management, engineering and
construction
Tekever Lisboa Marine robotic
systems
UAVISION Torres Vedras
Unmanned Aerial Systems
CEIIA Maia Product Design and
Concept
WAVEC Lisboa Offshore Renewables
Hydrographic Institute
Lisboa Low-cost multiuse
buoys
IPMA Lisboa Sea and atmosphere
research
CINTAL Faro Research in submarine
technologies
MARETEC Lisboa Modelling, monitoring and management of
marine areas
MarSensing Faro Marine acoustic
technologies
Critical Materials
Guimarães Structural Health
Monitor
ActionModulers Mafra Security Consulting
Hidromod Oeiras Hydric and marine
modulation
CINAV Almada Naval Investigation
Solidal Esposende Subsea cables
Fibersensing Maia Sensor and
measurement units
ActiveSpace Coimbra Aerospace
engineering services and products
GALP Lisboa O&G company
PARTEX Lisboa O&G company
blueCape Casais da
Serra CFD numerical
Esri Portugal Lisboa Big Data Analytics
As seen in Table 6.1, the panorama of the Portuguese industry is very scarse when it comes
to the oil and gas industry. This results in part from the lack of tradition to invest in this sector, but also
due to the small dimension of the economy, which hinders the ability to invest in a capital intensive
74
industry as the oil and gas. It is therefore important to identify the principal mechanisms through
which countries can develop their technological capacity. What history tells us is that the main
channels through which weaker economies can access international knowledge and technology are
through foreign direct investment8 and domestic investment. [71], [72]
Foreign Direct Investment assisting the technology catch-up
Technology Catch-up results from lagging countries accessing technology developed in
leading nations, adapting it effectively to local circumstances, and subsequently relying more on
indigenous innovation.
Multinational Enterprises (MNEs) can diffuse technologies to lagging countries in three ways:
i. By directly transferring technology to affiliate or joint ventures (JV);
ii. Through spillover effects;
iii. And/or through doing R&D within the country. [72]
The importance of such diffusion is well recognised and once sufficient absorptive capacities have
developed in the country, MNEs can bring technology and know-how to a local economy. This can
take place either through foreign direct investment (FDI) and/or through non-equity modes (NEMs) of
international production9 and/or through their global R&D activities. [72]
Foreign technology-driven industrialization commences through innovations based on the
adoption of foreign technologies that require lower-skilled human and entrepreneurial resources. As
time passes a country can begin to add its own innovations, expanding the global technological
frontier. For industrially lagging countries the rise of global production sharing has increased the
importance of complementarities between foreign sources of technology and domestic absorption
capabilities. This is because successful industrial development now requires countries to be
competitive not in the complete production of some good, but in the production only of a component
(‘trade in tasks’) wherein they need exceptional capabilities. This development has opened up a range
of opportunities for poorer countries, which may be more likely to be able to find a niche in which to
specialize rather than be competitive along the entire production chain. In other words, finding a
comparative advantage in a ‘slice’ of the production chain may perhaps be easier than finding a
comparative advantage in the entire production. [72]
But, as always, matters are not so simple. As far as FDI as a vehicle for technology transfer is
concerned, it is difficult to establish empirically whether and how important FDI is. Several studies are
focused on this matter, and many agree that the influence of FDI, through the role of joint ventures,
does show higher productivity with JV due to their foreign shareholding. [73] This finding can be taken
as support for industrial policies encouraging joint ventures, which is the goal of project +Atlantic which
will be discussed in the further sub-chapters.
Regarding the integration into global value chains, the current global market might render it
easier, but it also may be less “meaningfull”, in the sense that it might not have a high expression on
8 Foreign Direct Investment: An investment made by a company or entity based in one country, into a company or
entity based in another country. 9 Non-equity modes of international production may include contract manufacturing, services outsourcing,
contract farming,franchising, licensing and management contracts
75
exports. Therefore, integration will require a greater emphasis on innovation, implying that domestic
investment in innovation capabilities becomes more important in the industrialization process.
Domestic investment for technology adoption
Whereas technological transfer through FDI may be important in theory, in practice it is often
constrained due to a lack of domestic absorptive capacity. Hence domestic investment is also crucial,
and the lack of it may delay development. It’s also important to notice that the stage of development is
also an important factor to consider, because FDI and domestic absortive capacities will interact in
different ways across different stages of development.
The message is that technology lagging countries can benefit substantially from FDI, but only
if they have made complementary investments in absorptive capabilities. For more developed
countries, which produce on the technological frontier, it is their absorptive capacities, rather than FDI
that seem to play the most significant role in explaining economic growth and improvements in
technological performance.
In conclusion, effective technology transfer from MNE is achieved by domestic investments in
human capital and infrastructures, through efforts of attracting returning migration of skilled workers
(e.g. the high level of emigration of Portuguese engineers), and the practise of requiring joint ventures
(JVs) with foreign companies. [66], [71], [74]
6.4.1. The OIPG - International Observatory of Global Policies for the
Sustainable Exploration of Atlantic
The International Observatory of Global Policies for the Sustainable Exploration of Atlantic
(OIPG) main goal is to promote a consortium, in the form of an observatory, to stimulate the industry
of sea exploration, and all the adjacent businesses and services where the Oil & Gas industry is
included. By improving the understanding of the innovation dynamic in the South Atlantic industries,
new opportunities can be identified and better exploited. [75]
New industrialization strategies around the South Atlantic are of significant interest to Latin
America, Africa, as well as to Southern European and Mediterranean countries, including Portugal.
Literature suggests that the process by which countries or regions can develop and foster their
industrial structure in a sustainable and responsible way, is to either explore different combinations of
the capabilities they already possess, or accumulate new capabilities. Although exogenous shocks
may create opportunities to explore different activities, endogenous growth is a complex and time
consuming process, very much dependent on the structure and level of infrastructures, incentives and
institutions, which are particularly affected by existing regulatory frameworks.
Considering all these aspects, it was clear the need for an initiative that would stimulate new
innovation dynamics and technology-based products and services, in order to better exploit the future
opportunities. The +atlantic initiative was then created. This initiative, promoted through the OIPG,
aims to stimulate an international agenda for scientific, technological and industrial development for
76
the sustainable exploration of the Atlantic, leading the way for the cooperation between countries and
companies, by creating and/or strengthening consortiums and joint ventures. The details of this
program and the main technological areas it approaches are explained in the next section.
6.4.2. The +atlantic project
The +atlantic initiative aims to stimulate the national offer of technological services and
products with the potential to integrate the international value chains for the sustainable exploration of
the Atlantic. It’s therefore intended to promote qualified employment and investment in R&D activities
and engineering activities oriented to the exploration of live and non-live resources, including the
hydrocarbon and seabed minerals, as well as ocean monitoring services and systemic risk
governance.
The fundamental strategic goal is to stimulate the Portuguese industry through the absorption of
skills and know-how from top-level engineering sectors which are relevant to the context of the
extension of the Portuguese continental shelf and to the challenges arising in the South Atlantic. This
goal of developing technological and industrial capacity will be achieved through a set of three
strategic tools:
Attract and secure qualified human resources in Atlantic regions, stimulating qualified
employment in engineering and research and development;
Attract and increase public and private investment in R&D in those regions, promoting
technological and industrial developments towards the sustainable exploitation of the Atlantic;
Promote international cooperation between an extensive network of engineers and technologists
working the observation, monitoring and surveillance activities, energy and living resources as
well as the sustainable exploitation of the oceans.
The +atlantic international agenda focus on four main technical areas, namely Observation
Systems, Subsea Technologies, Surface Technologies, and Port Technologies and Systems, together
with a comprehensive set of horizontal programs promoting international risk governance initiatives
and the capacity building of Atlantic regions. A platform approach has been considered through four
Technology platforms that derived from an in-depth study about current ocean technology related
markets and a cross matching between identified opportunities and challenges with current and
prospective national technological competences. The platforms and some of their challenges are
summarized in the following table.
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Table 6.2: Technological Platforms and respective challenges (Source: http://www.oipg.org/docs/Atlantico_Sumario_PT_v06abr15.pdf -15th April 2015)
TP1 - Observation Systems: Ocean Monitoring, Control and Surveillance (MCS)
TP2 - Ocean Subsea Technologies
Low cost multi-use buoys Integrated computational models Networks autonomous platforms Image processing algorithms to improve
fishing activities Mini satellites for low cost monitoring Unmanned Autonomous Vehicle(UAV) for
long endurance flights Maritime Common Information Environments
Landers for deep sea long term monitoring Cooperative robotic systems for sea mapping UAV for deep sea operations Advanced mooring ropes CFD analysis to the subsea industry SURF equipment and analysis SURF non-destructive inspection Big Data analytics
TP3 - Ocean Surface Technologies TP4 - Port Technologies and Systems
Deep water foundations for offshore wind turbines
Wave energy converter Offshore platform to serve as test bench Platform Support Vessels Innovative automation technologies Top-side modules for the O&G industry Basic engineering of new gen. FPSO Offshore aquaculture system
Logistic Single Window Introduction of Nat. Gas and Renewables in
ports LNG Floating Storage Regasification Unit Monitoring and Safety systems Flexibility in Port planning and design
This initiative, by promoting the debate between companies, research institutions and
governmental institution, also contributes for the debate of new industrial policies based on the
effective flow of knowledge, essential for the actual knowledge economy (refer to section 6.3). This
debate was promoted in an event that took place the 14th of April in Instituto Superior Técnico. In this
roundtable, representatives of 47 entities (companies and research and governmental institutions)
took part on a debate about the opportunities for the development of new products and systems to
integrate the international value chains. One important aspect that companies and entities are
confronted when attempting to penetrate such international markets, is the question: “What have you
done in this sector so far?” Since there’s little to no tradition in the oil and gas sector, the answer to
this question is typically no, not due to lack of will or human capital, but due to the lack of projects
made available to the Portuguese industry. Therefore there is a need for our industry show itself
outside as a competitive option for engineering services and that must be done by the synergy of
different companies working together domestically with international companies.
It is evident there’s still a long road ahead and technology development takes time, money and
it might fail. It is paramount there a specific objective as a guideline for companies and entities to
cooperate, thus it is important to reinforce and raise the debate on these subjects.
78
6.5. Concluding Remarks
This thesis analysed three possible trajectories of technical development in the offshore oil &
gas industry, focusing mainly on the challenges and opportunities in the South Atlantic. Case studies
provided evidence of the complex interaction between technologies and the environments, which
depend on several factors that vary widely between different contexts. For example, in the case of the
FPDSO (section 3.4.2), the development key driver was the high cost of leasing MODUs offshore the
Republic of Congo, while, in the case of the development of Shell’s FLNG (section 3.4.1), the long
distances from shore played a more important role.
So technical (distances, water depths, etc.) and commercial (leases, oil price, etc.) risks are
entangled and can change over time. Considering for example the oil price, it can greatly influence the
desirable design and value of an exploration system. Identifying the drivers that influence system
design and performance is a very important task. They may be economic, technical, regulatory and
others. What this work shows is that, for each technology, they are usually much broader than initially
considered. For example, in the case of the subsea factory (section 5.2), besides the tremendous
technical challenge, which is usually the designer main concern, the regulatory and safety regulations
must also be considered, allied to the commercial risk of a company using such technologies for the
first time.
This leads to the problematic on how to deal with uncertainty in engineering. The challenge of
forecasting future possibilities must take into account unpredictable events, hence the importance of
establishing different scenarios or trajectories of development. However, these trajectories are
interconnected and affect each other, thus the best practise is to include enough flexibility in the
system to allow the operator to adapt it to changing circumstances. The example of the dry tree
semisubmersible concept (section 4.3.2) is a great demonstration of flexibility applied to a matured
system.
Regarding the future of oil exploration in deep waters in the South Atlantic, it is likely that the
FPSOs will remain the technological choice in the near future, especially considering the current
unstable oil price context. However, the main challenge of the pre-salt and a key-driver of technology
development, the high content of CO2 and H2S will require innovative solutions, which may appear as
a disruptive subsea option or an incremental innovation integrated in the new generation of FPSOs.
6.6. Limitations and further work
The methodology used was based on an extensive literature review, and an interview method
to cover the information on all topics. The work presents two ways for gathering scientific knowledge
and one may observe important results and conclusions from the investigation performed. After an
extensive literature review on all topics, not only the three technological trajectories but also the deep-
sea offshore oil and gas industry, all the information was corroborated by a large spectrum of
interviews. The application of this knowledge to the +atlantic project as a way of identifying future
79
opportunities of investment and technology development is the most important part of this work. This
last part makes the research extremely relevant and reinforces the importance of an observatory as
the OIPG.
The most important barriers to this thesis were the little readiness of individuals and groups
(interviews) to engage in systematic and interdisciplinary thinking and sharing valuable insights, which
made it more challenging to extract concise valuable information. The staggering valuable of
information (analysis of almost all aspects of the upstream oil and gas sector) allied to the time
constraints inherent to the development of a master thesis also posed a challenge in the development
of this work. Regarding the risk analysis, the ideal procedure would be to talk to an even wider range
of stakeholders, however the aforementioned time constrains makes this a very challenging task.
In terms of further work, all the chapters regarding the technological trajectories may be further
studied, not only in terms of interviews, but also in terms of literature review on the technical aspects
or specific experiments to further prove some aspects of the technologies being discussed. Each
trajectory embodies several “smaller” trajectories within itself, which can be the subject of study for
other academic works. A less technical approach can be also followed, where it’s given more attention
to the role of industrial policies in the selection environment.
This thesis is a first approach on a comparative study between the three trajectories foreseen
(in a macroscopic level) to be followed in ultra-deep sea oil and gas explorations, and what
opportunities arise from technological change. As part of the OIPG, this work is a first step on
gathering knowledge on the aforementioned topics and should be continuously updated, especially
considering the uncertainty and fast paced technological evolution that characterises the industry.
80
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A
Annex A: Example FPSO Simplified Hull Design Procedure Source: [30]
B
Annex B: Interviews Guideline Questions
The interviews aim to gather more information from specialists in industry and academia,
along with their personal views on the subject. The following questions were used as guidelines. The
method employed was a semi-structured interview, where there is no set of rigorous questions, but
rather a framework of themes to be explored, allowing new ideas to be brought up during the interview
as a result of what the interviewee says.
Oil & Gas Sector
What are the main changes, nowadays, on the O&G sector worldwide technologically and business
related?
Is it possible to refer the major risk in the O&G sector?
Are these risks being carefully governed? Strategies to solve them?
Which are the main technical challenges for the next 2, 5 and 10 years’ time?
FPSOs, Subsea and other Offshore Technologies
Which kind of projects are under development specifically related to FPSOs? And to other kind of
offshore technologies?
What are the main advantages of using FPSOs for exploration and production in the O&G sector?
What are the main risks associated to the use of this kind of technology?
What is the view on other technological trajectories, like dry completion platforms (TLP and SPAR)
and Subsea factories? Can they overcome the use of FPSOs in the future?
Can you talk about the expectable evolution of these technologies in 2, 5 and 10 years’ time?
Portuguese Industry
Which projects are being developed in this area, in this company/institution?
Is there enough knowledge (technological capability and human resources) in the Portuguese
industry to develop new equipment for offshore/naval oil and gas industry?
Where could a company/institution find support to enter the oil and gas sector?
Which are the main end-users the company have?
What are the main challenges and risks associated to the technological capacitation of the
Portuguese industry in the sector of oil and gas?
C
Annex C: List of interviewed specialists
Interviewed Person Company/Institution
Eng. Rui Baptista Galp
Eng. Samuel Pacheco AMAL
Dr. Filipa Ribeiro IST
Eng. Fernanda Povoleri Technip Brasil
Eng. Jorge Trujillo Galp
Dr. Eduardo Filipe IST
Eng. Rui Pimentel Santos IN+
Dr. João Fernandes IST
Eng. Nuno Vaz FMC Konsberg Subsea
Dr. Helena Geirinhas IST
Eng. Ricardo Maia Critical Software
Eng. Ruben Eiras Galp
Dr. Jorge Miranda IPMA
D
Annex D: Interviews Transcript In this annex follows a transcript of some of the most relevant interviews for the context of this thesis. Interviewee: Samuel Mendes Pacheco, Engineer
Occupation: CEO at AMAL
Interview date: 06/01/2015
AMAL, Construções Metálicas SA is a Portuguese company, part of the AMAL group.
Specialized in working with special steels, as the duplex stainless steels, and other materials as
Titanium, the company has a big portfolio of projects in the oil and gas industry with clients all over the
world, as BP or Esso for example. One big part of their work is in the construction of topside modules
for FPSOs and other offshore platforms. According to Engineer Samuel Mendes Pacheco, chief
executive officer, the construction of modules amounts for roughly 100 M€ annually, being around 40
percent of the company business volume. The company’s main builds are the Power distribution
modules (2 MTon and between 10 to 12 month under construction) and the Pipe-Rack connections,
however the company has capacity to build any type of module. Some of the companies working in
collaboration with AMAL in Portugal are: TechnoEdif, Martifer, TCPI, Caetano Coatings and Nova
Citacor.
The goal of AMAL for the next 5 years is to develop research and development capacity and
engineering services in addition to its production capacity. The company aims to achieve this by
gathering a cluster of companies working in partnership with Peniche’s naval shipyard, which will have
a requalification investment of 14 million euros from the shareholders group AMAL and Oxicaptal.
Other important international projects undergoing at AMAL are joint ventures with SINOPEC, piping
construction for MARATHON, platform structures for GPF SUEZ and contract with GE to work in a
Brazilian shipyard.
Regarding the company’s activities in Brazil, the company has dealt with some issues
regarding the country’s workforce and labour policies. The workers show a low level of training, which
results in lower competiveness, while the labour policies in the country require a lot of bureaucracy,
making it difficult to deal with the employers, resulting in a high number of strikes. The Local Content
Requirement (LCR) law, enforced by the Brazilian Government, requires a minimum of 60% of the
project to be built in Brazil, putting additional pressure on external companies which are forced to work
with companies with lower competitiveness when compared to other external companies.
When asked if Brazil would have capacity to invest in some of the FPSO emerging trends, like
the Gas-to-Liquid module or a FLNG, Samuel Pacheco comments that it will be highly unlikely on the
short term. In order to build the replicantes (8 identical FPSOs), Brazil is having a lot of troubles, from
shipyards closing to the corruption cases where 23 service companies were accused of corruption. A
restructuring process will be necessary in the Brazilian naval industry.
E
Interviewee: Rui Baptista, Engineer
Occupation: GALP; Ex-Director of Exploration & Production in Brazil
Interview date: 12/12/2014
In the context of this thesis, I had the opportunity to interview Engineer Rui Baptista, currently
member of the Innovation and Technology department at Galp and previous director of Exploration &
Production in Brazil. According to Rui Baptista, the main challenges nowadays in the O&G industry
are to surpass the existent technological barriers and reduce costs. Challenges will be closely
connected to oil prices, which, if too low, result in certain fields not even being considered for
development. Hence, the challenges will exist as long as the oil price justifies its production.
Regarding Brazil, it’s a well-known fact that Petrobras is aiming for a new generation of FPSO,
with higher production capacity up to 300 thousand barrels per day, however this option must be
carefully analysed, because, despite the inherent technological challenges, there’s the security issue.
Vessels like the FPSO are key parts in oil operations; therefore they are prone to external attacks, as
pirate attacks faced previously off the cost of East Africa. A high production FPSO would be a
preferred target in an event like this. Furthermore, if a high capacity FPSO stops, either by an attack or
malfunction, production comes almost to a halt, so it might be preferable to have a larger number of
vessels but lower productivity than a single high productivity vessel.
Still regarding FPSOs, Rui Baptista sees the main operational risk as the offloading procedure.
This process is very sensitive due to the several mooring cables and structures surrounding the
vessel, which can lead to dangerous collisions that can have adverse consequences. In the FPSOs
operated by Petrobras, the mooring system is fixed (instead of turrets where the FPSO is allowed to
steer according to the currents) possibly due to the higher safety associated, especially when
offloading. The riser systems were also discussed, particularly the usability of rigid risers in deep
waters. The opinion of engineer R. Baptista is that they might not add advantages to subsea
installations, due to the more complicated construction and installation when compared to flexible
risers. These risers will be employed only if the oil is particularly heavy (high density and viscosity).
For these oils, flexible risers present many flow assurance challenges, thus being less appropriate.
On the subject of the subsea factory, R. Baptista comments that it’s likely not going to be
employed for up to 10 years. What will likely happen is the use of subsea equipment (separation)
together with FPSOs or FSOs. The subsea factory concept is more attractive in the North Sea due to
the weather conditions with lower temperatures and stronger currents than the Atlantic.
Galp is participating actively in the deep-water oil fields in Santos Basin in Brazil.
According to Eng.R.Baptista, the goal of the company is to reach a production level of 300 thousand
barrels per day. Achieving this number may pass by a better asset management.
When asked about the Portuguese industry, the interviewee comments there are some good
examples of companies/institutions who managed to develop some projects for this sector, as CEIIA,
but in the bigger picture the industry wouldn’t be competitive enough nor have enough expertise to
develop a cluster of oil and gas related industries in the short term. However, there’s still a lot of
unexplored potential regarding seabed minerals off the cost of Angola and Mozambique.
F
Interviewee: Maria Filipa Gomes Ribeiro, Dr.
Occupation: Professor at I.S.T. – Petroleum Refining and Petrochemical, Chemical Engineering
Department
Interview date: 13/01/2015
Doctor Maria Filipa Gomes Ribeiro is a professor at I.S.T. in the department of Chemical
Engineering. Her area of research is directly connected with hydrocarbons and the teaching activity is
centred on Petroleum Refining and Petrochemical and Project and Design of Chemical Industries.
The purpose of this interview was to further discuss the chemical processes involved in the
exploration and production of hydrocarbons and of the utmost importance when considering flow
assurance technologies (refer to Chapter 5 – Case Study 2). Some of the companies in Portugal with
activities regarding these technologies are Galp, Partex, Technip and TechnoEdif.
The main areas of research of Dr. Filipa Ribeiro are related to the downstream sector
(refineries), which has been considerably more affected with the oil price crisis than the upstream
sector. The mind-set of the downstream sector is to reduce costs to the maximum, which has been a
huge challenge when the available oil is priced so high. Therefore, the trend on the downstream sector
is to go towards larger refineries that have high production capacity in order to lower the final product
price and maintain competiveness. This is pushing smaller refineries to close doors. The technical
issues faced by refineries are very different from the ones faced on subsea installations, however the
main cause of flow problems are still very similar, specially the asphaltenes and resins (wax) that can
form in the pipelines.
Asphaltenes are amongst the heaviest compounds present in oil, and are solid at room
temperature. Resins molecules are bonded with asphaltenes in solution, they ensure that the
asphaltenes don’t deposit, hence there’s a chemical balance between both molecules. However, the
resin molecules can precipitate due to a number of factors such as sudden drops of temperature and
pressure, therefore disrupting the balance between molecules and originating problems in the flow.
This is what happens in many offshore operations where the oil is under high temperature and
pressure in the reservoir and suffers a sudden change when extracted.
When asked about the rise of unconventional oil and gas sources and the implications to the
downstream sector, Dr. Filipa Ribeiro commented that the oil from shale is considered “young” oil,
where the contaminants are different than he ones found in traditional oil sources. Therefore refineries
will have to adapt and change their refining processes in order to transform the raw material into
market products.
G
Interviewee: Fernanda Povoleri, Engineer
Occupation: TECHNIP Brasil – Project Manager
Interview date: 25/01/2015
Technip is a multinational company, established in Paris and currently present in 48 countries,
focused in project management, engineering and construction for the energy industry. Their projects
range from the deep subsea oil and gas developments to complex onshore structures. Technip
Portugal established its activities in 2011, focusing in subsea and flexible pipeline engineering (e.g.,
risers).
This author had the opportunity to talk to Engineer Fernanda Povoleri, which has a vast
experience working with Technip, being currently in Brazil and having worked before at Technip
Portugal. Fernanda is a Mechanical Engineer and has taken the roles of Project Manager in several
projects, including FPSOs, more specifically the P-48 and P-43 operated by Petrobras in the Campos
Basin since 2004.
The FPSO was Petrobras’ main choice due to the clear advantages it presents, being more
economically viable. Therefore Brazil has made investments in the shipyards to support these
structures and the P-43 had its hull reinforced in a shipyard in the state of Rio de Janeiro. The
production capacity of P-48 and P-43 is 150 thousand barrels/day. In terms of project design, the
production capacity is the first thing to be decided, the next step is to design the modules and their
layout and finally the hull is studied to assure structural integrity.
Petrobras has the goal to achieve higher production rates in their FPSO of up to 300 kbpd.
Regarding this topic, Eng. Fernanda Povoleri commented that to achieve this level of production it is
likely necessary to have new build hulls, however, these are more expensive than conversion hulls.
Alternatively, it may be possible to increase production in traditional FPSOs by transferring some
processes to the sea bed, allowing extra space for larger processing modules. For example, the fluid
separation module occupies in average one tenth of the vessel topside, hence, positioning it on the
sea bed would allow for the expansion of the remaining topside modules.
Each FPSO project involves several job placements directly and indirectly. Considering only
engineering, each vessel project employs around 500 engineers. The areas that generate higher
investment is the hull conversion, the compression module and the electric power module. However,
Fernanda commented that some of the projects in Brazil are currently in stand-by mainly due to the
recent corruption scandals which resulted in the the bankruptcy of companies providing services to
Petrobras. The industry is waiting for the release of Petrobras’ budget plan in order to make decisions
on how to deal with the following years. The current substantial project in Technip Brazil is a contract
for the topside construction and integration, the commissioning and start up assistance of the P-76.
The project is scheduled to be complete by mid-2017.
H
Interviewee: Jorge Trujillo Mercado, Engineer
Occupation: GALP – Head of Flow Assurance and Process at Galp Energia
Interview date: 30/01/2015
Engineer Jorge Trujillo is Head of Flow Assurance and Processes in GALP Energia. This
interview was done in the context of the +Atlantic project along with Engineer Rui Santos, Executive
Director of the project. The purpose of this meeting was to further understand the complexity
associated to flow assurance technologies and the main challenges oil companies face.
Jupiter is one of the fields Galp operates in a consortium with Petrobras in the Santos Basin.
On this field and in the pre-salt in general, Jorge Trujillo referred the problems arising from the high
CO2 content. CO2 requires the use of corrosion resistant materials, a study of the fluid properties to
better predict the effects of said corrosion and ultimately it needs to be removed, as releasing it to the
atmosphere would represent a big environmental hazard. Carbon dioxide removal technology is
important not only from the environmental aspect but also because this same gas can be later
reinjected in the reservoir for enhanced oil recovery, raising the reservoir inner pressure. In Jupiter,
Jorge Trujillo commented that this is currently a challenge because the actual technology in use to
remove CO2 has a bad performance and the company is limited to only one provider of this
technology. Regarding the flexible pipelines, the ones currently in use last about 5 years in operation
with the present CO2 levels, while the platform is designed to be deployed for 25 years. Changing
ageing pipelines is a costly and time-consuming operation, therefore there’s still big room for
improvement in terms of materials. Some of the flow assurance issues could be reduced by
transferring some topside operations to the seabed as water treatment/separation and boosting, thus
minimizing topside loads.
According to Jorge, the main requirement to develop efficient flow assurance solutions is to
deeply understand the fluid and its behaviour. Such deep understanding often comes from universities
and research centres, where the fluids are studied in great detail. Therefore Galp looks for
partnerships within universities like I.S.T. in the areas of corrosion, materials and production chemistry
which includes the development of surfactants (compounds that lower the surface tension between a
liquid and a solid) and polymers (used to control fluid properties, e.g. control drilling fluid viscosity).
This is an area deeply related to chemistry so the application of solutions used in pharmacology to
flow assurance is not uncommon.
As a final note in the interview, Jorge Trujillo affirmed that this is a relatively easy area to enter
the market provided the solution is innovative and the knowledge behind it is solid. The initial
investment is relatively low because the optimum places for dissecting and understanding fluid
behaviour are laboratories and flow loops, often present in universities and research institutions, and
the final outcome can have a big value for the industry.
I
Interviewee: João Carlos Salvador Fernandes, Dr.
Occupation: Professor at I.S.T. – Surface engineering, corrosion and material protection, Chemical
Engineering Department
Interview date: 09/02/2015
Doctor João Fernandes is a professor at IST in the Chemical Engineering Department and an
active member of GECEA (Grupo de Estudos de Corrosão e Efeitos Ambientais). He has a vast
experience regarding surface engineering and materials resistant to corrosion, topics extremely
relevant to the flow assurance subject. The purpose of this meeting was to further understand the
professor’s experience with the oil and gas industry and explore the possibilities of further projects.
This interview was done in the context of the +Atlantic project along with Engineer Rui Santos,
Executive Director of the project.
Dr. João Fernandes mentioned that some projects in partnership with Galp (Petrogal in Brazil)
have been discussed but didn’t move forward. Mainly due to the imposition that Brazil set in which the
R&D budget must be distributed only to laboratories accredited by ANP. According to Dr. Fernandes,
the GECEA group has plenty of human capability to develop corrosion resistant subsea technologies,
but in order to move forward it would need an investment in an autoclave that could simulate the high
pressure conditions found in deep waters and the response of the material to carbon dioxide, sulphur
and salt waters under these conditions. This investment has an estimated cost of 100,000€ and it
would allow the group to extrapolate several of its projects to oil and gas related problems.
Some of the projects being developed by GECEA are: the selection and analysis of new
materials to specific situations where corrosion is an issue; development of corrosion resistant
coatings; characterization of the tribological proprieties of materials (e.g. Aluminium alloys) in a macro
and microscopic level; and microbiological corrosion, which results from the action of bacteria in the
materials.
J
Interviewee: Helena Maria dos Santos Geirinhas Ramos, Dr.
Occupation: Professor at I.S.T. – Non-Destructive testing and materials, Department of Electrical and
Computer Engineering
Interview date: 10/02/2015
Doctor Helena Geirinhas is a professor at I.S.T. and senior researcher in the Institute of
Telecommunications (I.T.). Main areas of research include NDT (non-destructive testing) through the
use of eddy currents, ultrasounds and innovative technologies as the GMR (gigantic magnetic
resistors). This type of technologies has obvious implications in the oil and gas industry due to high
number of equipment under adverse conditions as the pipelines. For deep-water subsea lines, where
normal onshore non-destructive examination validation practices are cost prohibitive, inspection
accuracy are keys to managing costs. This interview was done in the context of the +Atlantic project
and the purpose was to further understand the implications of these technologies and explore future
possibilities.
Regarding the Oil and Gas industry, Dr. Helena Geirinhas mentioned that there’s a growing
market demand for innovative NDT techniques, more reliable and less expensive. One of the
technologies with promising results is the use of a guided wave transducer array. The method
employs mechanical stress waves that propagate along an elongated structure, allowing for hundreds
of meters to be inspected in some cases. The implications for pipelines are massive, especially for
buried pipelines with difficult access. Another technology mentioned is the use of a network of sensors
in a structure that could overtime triangulate the defect, giving exact coordinates on where to act.
According to Dr. H.Geirinhas, the Institute of Telecommunications has enough know-how on
how to develop and apply these technologies to the oil and gas sector, provided there’s investment
and interest from the companies. The main areas identified where the IT could develop technology
are: PIGs (used for the inspection pipelines from the interior – measure of corrosion, thickness and
coatings), where the sensors can be improved to get better results with higher velocities; guided
waves as mentioned before; and Structural Health Monitoring, which is the use of sensors actively
monitoring the “health” of a specific structure.
K
Interviewee: Jorge Miranda, Dr.
Occupation: Instituto Português do Mar e da Atmosfera (IPMA) – President of IPMA
Interview date: 10/03/2015
Doctor Jorge Miranda is the president of the Portuguese Institute of Sea and Atmosphere
(IPMA) and an associate professor at Universidade de Lisboa. This interview was done in the context
of the +Atlantic project and the purpose was to further understand the needs of Portugal in terms of
sea-related technologies and explore future possibilities, especially in the context of the extension of
the Portuguese continental shelf.
One theme discussed was the role of observatories placed at the sea, which are extremely
important for monitoring and prospection. Jorge Miranda referenced that there’s enough human
capacity to integrate teams for observatories in Portugal provided there is a structure. IPMA has a new
vessel for geophysics prospection that will be used as an observatory for operation on the sea bed,
having its base in “Margem Sul”. However, the easier way to start in this field is to employ small and
low-cost array of environmental observatories in the sea bed which could work autonomously,
broadcasting information about the sea. Considering the length of the Portuguese continental shelf,
there should be higher investment in the observatories, especially in Azores and Faro. By analysing
the sea bed several opportunities could arise, particularly in the exploration of submarine minerals.
The sea presents several opportunities for technology development, one example of them are
the development of buoys. This represents a more realistic challenge for the Portuguese industry and
there’s a big demand for buoys, especially in areas of aquaculture and fisheries, where Portugal has a
high activity. The buoy market is mature and stabilized, which can reduce the risk of investment.
The development of new materials fit to withstand the harsh sea conditions was also
appointed as an important challenge. Some of the materials used in aquaculture have a very short life
due to salt corrosion, becoming often uneconomical due to maintenance requirements. Developing
materials that could tackle this problem can open a lot of opportunities, due to the applicability to other
industries as the oil and gas.
