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Technological Trajectories in the Offshore Oil & Gas Industry Dealing with Uncertainty in Ultra-deep Exploration in South Atlantic

Leonardo Santos

Centre for Innovation, Technology and Policy Research (IN+), Department of Mechanical Engineering,

Instituto Superior Técnico P1049001 Lisboa, Portugal

The oil and gas industry is under major developments and changes with the discovery of new ultra

deep water 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 paper is to study the processes of technical evolution through

technological trajectories. The analysis of each technological trajectory and its key drivers was done in a

case study basis, through an extensive literature review and interviews with specialists. 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 to 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.

Introduction

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 was particularly notable in the

Brazilian offshore, 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 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.

This paper 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.

Concept Definition and Competition between Technological Trajectories

Before proceeding, it’s important to define the concepts we’ll be using throughout the rest of this

paper. The first one is the concept of technological paradigm, where the concept of technological trajectory is

inserted.

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According to [2], 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. [3], [4]

According to [5], 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 [6], 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.

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.

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. [7]

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.

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). [8]

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 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.[9]

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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 by 2014 around 25 percent of all the operating FPSOs were in the

Brazilian offshore. [10]

Most FPSO projects (60%) are based on tanker conversions as opposed to new builds, and usually

most projects are unique in a sense that they are adapted to the specific oil field. This creates flexibility in

designs and in this section I will analyse two of these situation where the context significantly changed the

design process.

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, 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. [11]

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. [12][9]

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. [13]

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. [14]

The industry’s first FPDSO was installed in the Azurite field, in the Republic of Congo in 2009. 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

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mobilization of drilling rigs. The short lifetime of marginal fields1 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. [15],

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. [16]

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.

Current Challenges and Future Developments

The Brazilian government and ANP saw the pre-salt discoveries and the continuity trajectory as an

opportunity to develop Brazil’s industry, designing public policies to develop national production capacity to

address Petrobras naval demand. The Local Content Requirement 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 suppliers are committed to comply with the government’s local content

policy. [10] 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. 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. [10] 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 industry and to compete internationally. [7]

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. This trajectory enables companies to limit technological risks,

but still limits 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 deepwater

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. [17]

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

1 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.

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will involve a mixture of multiple technical evaluations and constraints. In this section, one will analyse two

clear cases of matured technology adaptation to different environments.

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. [18]

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, can be considered an innovative and very attractive concept in

Brazilian oil industry. [18]

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. [9]

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.

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. [19]

Aker Solutions developed 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 (Figure 1) 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. 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-style cylinders with a typical vertical stroke length of up to 10-

13 metres – the stroke length is selected according to sea conditions in each geographical location. [20]

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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.

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. [22]

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 stroke tensioners or alternative

hull forms can overcome the technical challenges associated with these concepts.

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.

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. [7]

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 are looking for.

Therefore, the dry completion system is likely to remain only a niche technological strategy in the Brazilian

pre-salt.

Figure 1 - Aker Solutions DTS & TTR Array

(Source: [21])

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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. [23]

The challenges faced by this trajectory are considerable. 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. Furthermore, the high amount of subsea

umbilicals, risers and flowlines (SURF) 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. The equipment used to transmit power to the seabed also represents a bottleneck in the subsea

factory development. Current technology can transmit only limited amounts of power, which does not allow

connections to multiple equipment items in an effective manner. Some of these challenges will be analysed

in greater detail.

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 2, 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.

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.

Figure 2: Vortex Induced Motion (VIM) and Vibration (VIV)

(Source: http://web.mit.edu/towtank/www/images/viv3.jpg - 25th March 2015 )

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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[24]:

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 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.

Subsea and SURF technology is a highly specialized field of application with particular demands on

Engineering & Technical Services; covering service elements from flow assurance simulations and studies,

pipeline and subsea design to detailed installation and tie-in studies.

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 3 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 solution if the pressure in the system drops below the bubble point pressure.

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.

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Wax and Asphaltenes

Wax and asphaltene formation is a

significant 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-in2 periods and during normal

operations. At lower temperatures small changes in pressures can result in hydrate formation.

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-cut3 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[26]:

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 4.

Figure 4: Hydrate formation in an oil dominant system ( Source: [26] )

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.

2 Shut-in: Period of time the well is closed, either for maintenance purposes or for pressure build-up analysis

3 Water- cut: ratio of water produced compared to the volume of total liquids produced;

Figure 3: Deepwater Gulf of Mexico oil phase diagram (APE:

asphaltene precipitation envelope; WAT: wax appearance temperature) (Source: [25] )

10

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.

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. [27]

Current Challenges and Future Developments

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. Brazil continues to

be a large subsea market along with the North Sea in Norway.[28]

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.

Conclusions

This paper 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 , 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, 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, 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 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, will require innovative solutions, which may appear as a disruptive subsea option or an

incremental innovation integrated in the new generation of FPSOs.

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