the development of new submarine and offshore technologies ... · brazil, are generating major...

The Development of New Submarine and Offshore

Technologies in Times of Uncertainty

Guilherme Duarte de Abreu Farinha

Thesis to obtain the Master of Science Degree in

Mechanical Engineering

Supervisor: Prof. Manuel Frederico Tojal de Valsassina Heitor

Examination Committee

Chairperson: Prof. Viriato Sérgio de Almeida Semião

Supervisor: Prof. Manuel Frederico Tojal de Valsassina Heitor

Members of the Committee: Eng. Carlos Soligo Camerini

May 2015

i

Acknowledgements

To Professor Manuel Valsassina Heitor, who led me throughout this thesis, helped me to open my

mind to such different areas of interest and for giving me the fantastic opportunity to work with him.

To all the interviewers, I want to leave a word of gratitude for their help in this thesis, with a special

thanks to Carlos Camerini for his hospitality and guidance throughout my internship in ONIP/PUC-Rio.

I wish to thank all my Friends to whom I will be eternally grateful for supporting me throughout the past

years and whom I am expecting to count on for the rest of my life.

Last and most importantly, I would like to thank my Family for their never-ending support, patience and

dedication. Without them I could have never made it here.

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Abstract

The recent discoveries of new energy sources over the past decade, particularly the pre-salt fields in

Brazil, are generating major technological innovations. Promoted by the technological trajectory

pursued in the last 40 years, mainly in the North Sea and the Gulf of Mexico, subsea technologies are

considered to be the next technological revolution in the oil and gas sector.

This thesis includes two main tasks: the study of three pioneering and innovative projects developed in

Brazil in the area of subsea technologies and the analysis of new technologies based on additive

manufacturing. The selection of the project was based on the ANP’s innovation awards, which

highlighted these three projects. Two of these projects are in the area of subsea boosting, Albacora’s

Subsea Helico-axial Multiphase Pump and Albacora’s Subsea Raw Water Injection System, and the

other one in the area of subsea separation, Marlim’s 3-phase Subsea Separation System. The second

task was accomplished with an internship in the cluster of digital manufacturing laboratories present in

PUC-Rio and INT, both located in Rio de Janeiro, Brazil. Three key projects were studied, the Subsea

Cleaning Hub, the Modular Inspection System for Weld Analysis and the Smart Battery Monitor, and

experts in the area were interviewed.

Additive manufacturing is starting to bring some competences to the Brazilian industry, particularly

fomenting the development of small projects in start-ups or university spin-offs. However, the current

uncertainty scenario, created by the falling oil prices and the institutional corruption in Brazil, will slow

down Brazil’s industrialization strategy.

Keywords: Oil and Gas; Brazilian industry; Subsea technologies; Additive manufacturing

v

Resumo

As recentes descobertas de novas fontes de energia ao longo da última década, particularmente nos

campos do pré-sal no Brasil, estão a gerar grandes inovações tecnológicas. Devido à trajetória

tecnológica dos últimos 40 anos, principalmente no Mar do Norte e no Golfo do México, as

tecnologias submarinas são consideradas a próxima revolução tecnológica no setor do petróleo e

gás.

Esta tese está dividida em duas partes: o estudo de três projetos pioneiros e inovadores

desenvolvidos no Brasil na área das tecnologias submarinas e a análise de novas tecnologias

baseadas em fabricação aditiva. A seleção dos projetos foi baseada nos prémios de inovação da

ANP, para quem estes três projetos mereceram grande destaque. Dois destes projetos pertencem à

área da bombagem submarina, a saber, Albacora’s Subsea Helico-axial Multiphase Pump e

Albacora’s Subsea Raw Water Injection System. O terceiro, designado por Marlim’s 3-Phase Subsea

Separation System, pertence à área da separação submarina. Para a segunda parte, foi realizado um

estágio no cluster de laboratórios de fabricação digitail existente na PUC-Rio e INT, ambos

localizados no Rio de Janeiro, Brasil. Foram estudados três projetos-chave, designados por Subsea

Cleaning Hub, Modular Inspection System for Weld Analysis e Battery Pack Controler. Foram ainda

efetuadas entrevistas a especialistas da área.

A fabricação aditiva está a começar a desenvolver competências na indústria brasileira, fomentando,

em particular, o desenvolvimento de pequenos projetos em start-ups ou spin-offs universitários. No

entanto, o atual cenário de incerteza, criado pelos baixos preços do petróleo bem como pela

corrupção institucional no Brasil, irá certamente abrandar a estratégia de industrialização do Brasil.

Palavras-chave: Petróleo e Gás; Indústria Brasileira; Tecnologias Submarinas; Fabricação Aditiva

vii

Contents

Contents..............................................................................................................................vii

1. Introduction .................................................................................................................. 1

1.1. Context.................................................................................................................... 1

1.1.1. Towards an International Observatory of Global Policies for the Sustainable Exploration

of the Atlantic ................................................................................................................................... 2

1.2. The O&G Supply Chain ........................................................................................... 3

1.2.1. Segmentation ................................................................................................................... 3

1.2.2. Exploration and Production Sector .................................................................................. 4

1.3. The O&G Industry in Brazil ...................................................................................... 6

1.3.1. The Pre-salt Fields and Industrialization Policies ............................................................ 6

1.3.2. Uncertainty Scenario ....................................................................................................... 8

1.4. Thesis’s Framework ................................................................................................ 9

1.4.1. Motivation ........................................................................................................................ 9

1.4.2. Methodology .................................................................................................................... 9

1.4.3. Technology Development in Times of Uncertainty ........................................................ 10

2. Subsea Technologies..................................................................................................13

2.1. Subsea Processing Evolution .................................................................................13

2.2. Petrobras’s Subsea Technological Trajectory.........................................................15

2.3. Barracuda’s Subsea Helico-Axial Multiphase Pump ...............................................16

2.3.1. Project Overview............................................................................................................ 16

2.3.2. Design Challenges ........................................................................................................ 16

2.3.3. R&D Development Strategy .......................................................................................... 17

2.3.4. Adopted Solutions.......................................................................................................... 18

2.3.5. Developed Competencies ............................................................................................. 20

2.4. Albacora’s Subsea Raw Water Injection System ....................................................20


2.4.2. Design Challenges ........................................................................................................ 21




2.5. Marlim’s 3-phase Subsea Separation System ........................................................24


2.5.2. Technological Challenges ............................................................................................. 25


viii



2.6. Summary ................................................................................................................31

3. Additive Manufacturing in the O&G Industry ............................................................35

3.1. Process Description ...............................................................................................35

3.2. Industry Perspectives .............................................................................................35

3.3. The Digital Manufacturing Project...........................................................................36

3.3.1. Subsea Cleaning Hub .................................................................................................... 38

3.3.2. Modular Inspection System for Weld Analysis .............................................................. 43

3.3.3. Battery Pack Controler .................................................................................................. 47

3.4. Summary ................................................................................................................49

4. Conclusions .................................................................................................................50

Bibliography .......................................................................................................................53

Apendix A – Interviewed Specialists..................................................................................57

ix

List of Figures

Figure 1.1: Offshore production – current and future scenarios .............................................................. 1

Figure 1.2: The O&G industry value chain .............................................................................................. 3

Figure 1.3: E&P sector segmentation ...................................................................................................... 4

Figure 1.4: Petrobras’ R&D Expenses .................................................................................................... 7

Figure 1.5: Brazil’s industry productivity capability vs competitiveness .................................................. 7

Figure 1.6: Petrobras’ forecasts vs current oil price ................................................................................ 8

Figure 1.7: Breakeven oil prices for some oil producing countries.......................................................... 8

Figure 2.1: Subsea processing evolution .............................................................................................. 14

Figure 2.2: Offshore production system with subsea wells ................................................................... 15

Figure 2.3: Subsea layout for the subsea multiphase pump ................................................................. 16

Figure 2.4: Various modules of the Subsea Helico-Axial Multiphase Pump system............................. 19

Figure 2.5: Average monthly values for main pressures ....................................................................... 20

Figure 2.6: Pump flow rates since start-up ............................................................................................ 20

Figure 2.7: Albacora’s Subsea Raw Water Injection System ................................................................ 21

Figure 2.8: Subsea layout for the SWRI system ................................................................................... 22

Figure 2.9: Arrangement of the various modules in the SRWI system ................................................. 23

Figure 2.10: Artistic view of the separation system installed in the Marlim field ................................... 25

Figure 2.11: Adopted design for the SSAO ........................................................................................... 28

Figure 2.12: SSAO’s different modules ................................................................................................. 29

Figure 2.13: Compact SSAO layout ...................................................................................................... 32

Figure 3.1: Industry perspectives towards AM ...................................................................................... 35

Figure 3.2: Example of a FDM application ............................................................................................ 37

Figure 3.3: Example of a SLS application ............................................................................................. 37

Figure 3.4: Example of a subsea cleaning hub ..................................................................................... 38

Figure 3.5: Function diagram for the OMM 50 motor ............................................................................ 39

Figure 3.6: First subsea cleaning hub manufactured by TR Subsea .................................................... 39

Figure 3.7: Initial and final design for the cleaning hub ......................................................................... 40

Figure 3.8: Creation of the hub part and printed hub parts for the stress tests ..................................... 40

Figure 3.9: Stress test being conducted on one brush .......................................................................... 41

Figure 3.10: Test results for the 10 brushes.......................................................................................... 41

Figure 3.11: Worst case scenario during a cleaning operation ............................................................. 42

Figure 3.12: Final prototype................................................................................................................... 42

Figure 3.13: Examples of weld heights not in conformity and in conformity with Petrobras’ regulations

............................................................................................................................................................... 43

Figure 3.14: Camera and measurement system used in the first prototype ......................................... 44

Figure 3.15: First prototype in operation ............................................................................................... 44

Figure 3.16: Second prototype being prepared for riser inspection ...................................................... 45

Figure 3.17: Second prototype equipped with the first prototype’s camera .......................................... 45

Figure 3.18: Range of operability of the second prototype ................................................................... 46

Figure 3.19: Motor gears printed in Nylon and Steel ............................................................................. 46

Figure 3.20: An example of a LBL system ............................................................................................ 47

Figure 3.21: Battery pack controller and battery set sold by Sonardyne .............................................. 48

Figure 3.22: Battery pack controller developed by GIGA ...................................................................... 49

x

List of Tables

Tabela 2.1: Design data for the Subsea Helico-Axial Multiphase Pump system .................................. 18

Tabela 2.2: Material selection for the SRWI system (CS – Carbon steel; SDSS – Superduplex

stainless steel; HISC – Hydrogen induced stress cracking; CP – Cathodic protection) ....................... 24

Tabela 3.1: Design requirements for the first PIG prototype ................................................................. 43

1

1. Introduction

1.1. Context

The need for oil, natural gas, and other energy sources is growing dramatically, with worldwide energy

consumption projected to increase by more than 40 percent by 2035. The growing demand is fuelled

by a population that is predicted to increase 25 percent in the next 20 years, most of which is likely to

happen in countries with emerging economies, such as China and India.

In order to adapt to global energy demand, the deep sea exploration sector is under continuous

change and interest in technology that may help increase the levels of productivity and efficiency and

minimise the challenges and risks. The new locations of oil wells on the Brazilian offshore, the pre-salt

fields, are an example of a challenge to be handled by the oil and gas (O&G) industry. The

development of technologies in other sectors, for example in areas like composite materials,

electronics, control systems, numerical analysis methods (aerodynamics, structural, hydrodynamics),

communications and several others, and also the working frameworks to deal with the increasing

uncertainty, improve performance and lower costs. These developments are being adapted to the

deep-sea exploration sector, in which there is an exceptional need for radical and innovative solutions.

The Atlantic plays, and will play in the near future, an important role in offshore O&G production.

Currently, the world has five mature offshore regions for O&G production, one of them being the

Brazilian coast. Since 2005, about 50% of the new O&G discoveries made in the world have been

located in Portuguese-speaking countries: Brazil, Mozambique and Angola. These new discoveries

have been changing the international O&G landscape, shifting its centre towards the South Atlantic.

Figure 1.1: Offshore production – current and future scenarios

2

1.1.1. Towards an International Observatory of Global Policies for

the Sustainable Exploration of the Atlantic

The identification of vast hydrocarbon resources in the Brazilian pre-salt formation and the

technological innovations that have led to the rapid increase of shale hydrocarbons resources in the

USA, are a sign of change in the world’s energy market (Tordo, Tracy, & Arfaa, 2011). The increase

supply of hydrocarbons in the North Atlantic (USA and Canada) and in the South Atlantic (Brazil),

West Africa (Angola), East Africa (Mozambique) and the Caribbean (potentially Venezuela) diminishes

the economic risks of the disruptions in the Middle East oil supply for Europe and the Atlantic nations.

Brazil alone is expected to double its daily oil production in 6 years, and by that time the pre-salt oil will

account for more than 60%.

The International Observatory of Global Policies for the Sustainable Exploration of Atlantic (OIPG) has

as its main goal to promote a cluster in the form of an observatory to stimulate the industry of sea

exploration, and all the adjacent businesses and services. New and innovative dynamics are pursuit

for the offshore industry with a view of sustainability to the sector in the South Atlantic and Sub

Saharan Africa (Gaffney, Cline & Associates, 2010). The need for radical innovations (although

regulation, essentially in Brazil, has lately diminished this evolutionary pattern (Oliveira, Ribeiro, &

Furtado, 2014) and the already in place clusters that are actively searching for technologies for

subsea processing (Oliveira, Ribeiro, & Furtado, 2014) are a contributing factor to the creation of this

observatory.

The hydrocarbon resources of the Portuguese-speaking countries will play a significant and growing

role in reshaping the geopolitics of energy (Oliveira, Ribeiro, & Furtado, 2014) (International Energy

Agency, 2013). There is a need for technologies and policies to govern the new offshore discoveries

and exploration in such a way to promote the clean, safe and cost-effective development of these

resources, while simultaneously promoting social and economic development across the region

(Oliveira, Ribeiro, & Furtado, 2014) (Furtado, 2013) (Tordo, Tracy, & Arfaa, 2011). Also of great

importance is the technological competition between the supergiant oil fields of the Brazilian pre-salt

and the shale resources of North America (Maugeri, 2012). The emergence of technological

breakthroughs, such as fracking, brought new challenges in terms of cost effective development (due

to the vulnerability of the crude price) making the regulatory frameworks in both countries to have a

determinant role in their innovation processes.

New industrialization strategies around the South Atlantic and Sub-Saharan Africa are of significant

interest to Latin America, Africa, as well as to Southern European and Mediterranean countries,

including Portugal, Spain, Algeria, Tunisia and Morocco. 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 (Oliveira, Ribeiro, & Furtado, 2014).

3

Pilot case studies will be conducted in terms of emerging opportunities for the deep-sea off-shore oil

and gas supply chain, including subsea technologies (submarine drilling and energy supply;

submarine robotics, submarine processing units, among others), the construction of new and

specialized platform support vessels (including the integration of renewable offshore energy sources),

the development of reliable onshore gas exploration processes as well as strategies designed to

minimize health, safety and environmental risks across all elements of these systems. Also a major

vector of the investigation will cover the areas of sustainable sea exploration in a moment of extension

of the Portuguese coastal influence in the Atlantic.

1.2. The O&G Supply Chain

1.2.1. Segmentation

Popularized by Porter (Porter, 1985), the value chain analysis investigates the sequence of

successive activities which are required to bring a product (or service), from procurement to the final

costumer. Such analysis can be done for individual firms, cluster of firms, whose value chain are

interlinked (usually involving suppliers, distributors/sellers and costumers) or for the whole industry

(Tordo, Tracy, & Arfaa, 2011). In this analysis the value chain for the whole O&G industry will be

considered, beginning with the hydrocarbon resources and ending in the final costumer, us.

The value chain starts with the exploration of potential hydrocarbon reserves. If hydrocarbons have

been found in sufficient quantities, the development process begins with the drilling of appraisal wells

to better access the size and commercial viability of the discovery. This stage is followed by the drilling

for full-scale production and the building of infrastructure to connect the wells to local processing

facilities. Together, these activities are generally called Exploration and Production (E&P), or can also

be referred as upstream activities. E&P requires a series of auxiliary services, such as seismic

surveys, well drilling, equipment supply or engineering services (Tordo, Tracy, & Arfaa, 2011). These

activities form an important part of the O&G value chain and their importance has been increasing

over the last decades, as operators are constantly looking for new ways to increase production of

existing reserves, and will be the main focus of this work.

Infrastructure such as transport (pipelines, ports, roads, etc.) and storage are also critical, as they are

the links between production and refining facilities. These parts of the value chain are also called

midstream activities.

Oil refining (or gas processing) is what transforms the extracted hydrocarbons into usable products.

The processed products are then distributed to the final user. These last activities can also be called

Refining and Marketing (R&M) or downstream activities.

Exploration Development Production Transport &

Storage Refining or Processing

Distribution & Marketing

Figure 1.2: The O&G industry value chain

4

1.2.2. Exploration and Production Sector

In order to better understand the E&P sector of the O&G industry, it’s useful to divide it into small

segments. A possible segmentation can be seen in figure 1.3.

Reservoir Information (1)

This phase consists in the exploration of the subsoil through technology, such as reservoir imaging

systems and geological/geophysical equipments. Both onshore and offshore, the mappings of the

wells are made as well as the seismic analysis (Jahn, Cook, & Graham, 2008) (Salgado Gomes &

Barata Alves, 2007).

This step is mostly conducted by geologists, using satellite images, who examine the terrain and rocky

areas. Small changes in Earth’s gravitational field and significant changes in magnetic fields can be

indicators of the presence of reservoirs. Still, the most widely used offshore technique consists in

evaluating the seismic reactions through:

Compressed-air gun – shoots pulses of air into the water (for exploration over water)

Explosives – detonated after thrown overboard for exploration over water (Jahn, Cook, &

Graham, 2008) (Salgado Gomes & Barata Alves, 2007)

These techniques can perceive the thickness of the various layers of the soil, through the reflection of

shock waves with the help of high sensitivity microphones and vibration detectors, and thus build

detailed maps of the subsoil (Jahn, Cook, & Graham, 2008) (Salgado Gomes & Barata Alves, 2007).

Figure 1.3: E&P sector segmentation (http://www.intelligenceoilandgas.com/overview_world.html)

5

Drilling and Casing of Wells (2, 3 and 4)

Once the field is chosen, and seismic feasibility study has been done, it is time to prepare the site,

both physically and legally.

Multiple holes are drilled into the ground so that the main hole can be prepared. Only in this main hole

is it possible to introduce the so-called conductor pipe (that will connect to the rest of the production

equipment), but remote locations require special attention and equipment.

For example, offshore fields need support from specific modules: Mobile Offshore Drilling Units

(MODU). These devices can also be further adapted to the production process since the conditions

require that the technology readily adapt and become more versatile. According to the need for high

levels of productivity and efficiency, there are submersible MODU, which usually consist of a barge

that rests on the sea floor at depths of around 30 to 35 feet; jackups, which are rigs that sit on top of a

floating barge and can operate in depths of up to 160 meters; drill ships, which have a drilling rig on

the top deck and can operate in deep water conditions and semi-submersibles which float on the

surface of the ocean and that can be converted from drilling rigs to production rigs, reducing the need

for a second rig to take its place once oil is found (Jahn, Cook, & Graham, 2008) (Salgado Gomes &

Barata Alves, 2007).

It is launched from the MODU the riser, which is the element that allows the connection between the

outside and the bottom of the sea. It is through this element that all fluids move and also the drilling

strings, used to drill to the desired reservoir (Jahn, Cook, & Graham, 2008) (Salgado Gomes & Barata

Alves, 2007).

On the surface, there is the Blowout Preventer (BOP), which allows the control of the entire system in

case of imminent increase of abnormal pressure that could lead to an uncontrolled explosion (Jahn,

Cook, & Graham, 2008) (Salgado Gomes & Barata Alves, 2007).

When the MODU hits the inside of the tank, engineers must seal the well to prepare it for the

production phase. Sorts of caps are used to seal the well and mud or seawater is used to provide the

pressure to ensure the stability of the structure. Upon reaching the predetermined depth, the well is

coated with cement, to prevent it from collapsing. The well is then ready for the extraction phase

(Jahn, Cook, & Graham, 2008) (Salgado Gomes & Barata Alves, 2007).

Infrastructure, Production and Maintenance (5, 6 and 7)

The extraction of products is made through a suction process, which is powered by an electrical

system that feeds the extraction pumps. In cases where oil is heavy, it is necessary to create a second

hole for the injection of water, so as to increase the pressure in the reservoir. The latter process is

called Enhanced Oil Recovery (Jahn, Cook, & Graham, 2008) (Salgado Gomes & Barata Alves,

2007). The next subsection will show the main equipments used in this phase.

6

Deactivation (7)

After an analysis of the sustainability of the reservoir, and with its impracticality determined, a process

of plugging the reservoir is conducted. In addition, a clean sweep of the area, treatment of various

natural surroundings and removal of infrastructures are made. It is required by law to keep a check

and to monitor the field in the post abandonment of the well (Jahn, Cook, & Graham, 2008) (Salgado

Gomes & Barata Alves, 2007).

1.3. The O&G Industry in Brazil

1.3.1. The Pre-salt Fields and Industrialization Policies

The approval, in 1997, of the Petroleum Law (Law 9,478) in Brazil put an end to Petrobras’s 40 year

hydrocarbon E&P monopoly. One of the main goals of this law, besides changing the hydrocarbon

E&P regime in Brazil, was to strengthen the competence installed in universities and research centres

installed in the country. When exploring a high productivity field, oil companies have to invest in R&D

1% of the gross revenue generated by that field. This clause, commonly known as the “1% R&D

Clause”, stipulates that least 50% of this value must be invested in R&D institutions accredited by

ANP.

In 2007, Petrobras discovered large amounts of pre-salt oil located in the Santos, Campos and

Espírito Santo basins. Petrobras’s estimates show that the proven Brazilian reserves could increase

from the current 15.3 billion boe, to more than 50 billion boe (Souza, Tigre, & Jacqueline, 2013), which

could put Brazil in the list of the 10 countries with the world’s largest oil reserves. The pre-salt fields

are located over 200km off the coast, 6400m below sea level, deep beneath a 4800m layer of salt

deposits. The location of the fields offers new challenges to the O&G industry, such as sequestration

of highly pressurized gases, the rapid heating and cooling of petroleum as it is extracted, corrosive

conditions, among others.

Petrobras forecasts a rapid and steady growth in its oil production in the next 3 years, expecting to

reach and annual output of 3.2 million bpd by 2018, where pre-salt oil will account for 52% of the total

annual output (Petrobras, Business and Management Plan, 2014).

Due to the rapid production increase expected and the inherently technological challenges of the pre-

salt fields, Brazil can become one of the world’s most advanced technological innovation hubs.

Petrobras has been investing heavily in R&D, particularly in E&P, where it accounts for almost 50% of

its total R&D expenses.

7

The Brazilian government also saw the discoveries of these new pre-salt fields as an opportunity to

develop Brazil’s industry, and designed public policies to develop national production capacity. 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.

Both the Brazilian government and ANP’s policies (LCR and “1% R&D clause”) have generated limited

results in expanding Brazil’s producing capacity. In Petrobras’s big innovative projects, such as

FPSOs or subsea separators, national companies’ impact on the project 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 valves

or multiphase pumps, is imported, since local suppliers cannot satisfy Petrobras’s demand for such

equipment nor do they have the expertise and facilities to manufacture such products (Furtado, 2012).

0

500

1.000

1.500

2.000

2.500

3.000

2007 2008 2009 2010 2011 2012 2013

R$

mill

ion

Petrobras R&D Expenses

Total

E&P

Figure 1.4: Petrobras’ R&D Expenses (Petrobras, Financial Results)

Figure 1.5: Brazil’s industry productivity capability vs competitiveness (PROMINP, 2011)

8

1.3.2. Uncertainty Scenario

Petrobras defined its long-term investment strategy based on the variation of oil price in the next

years. However, by late 2014, world oil supply was higher than actual demand, which forced oil prices

to fall sharply, reaching prices as low as those back in 2009.

This difference between Petrobras’s expectations and the current oil price creates a big uncertainty

scenario about future Petrobras’s production expectations, especially since the pre-salt oil is much

more expensive to extract when compared to conventional oil sources.

However, ANP estimates that the pre-salt oil can be profitable if the oil prices go as low $60

(MercoPress, 2014). Brazilian policy isn’t helping either, especially when oil companies are looking for

cost-efficient goods and services along their supply chain: the LCR forces operators to use national

suppliers, which might not be the most competitive suppliers internationally, raising equipment costs.

The Brazilian economy doesn’t help the growth scenario expected for the Brazilian O&G industry

either. In 2013, the country fell into economic stagnation, and there are signs it might be entering in an

economic recession, as high inflation squeezes wages and consumers’ debt payments rise.

Investment, already down by 8% from a year ago, could fall much further and the real (Brazil’s

Figure 1.6: Petrobras’s forecasts vs current oil price (Petrobras, Business and Management Plan, 2014) (Nasdaq, 2015)

Figure 1.7: Breakeven oil prices for some oil producing countries (http://makewealthhistory.org/2014/12/16/break-even-points-for-oil-producers/)

9

currency) has fallen by 30% against the dollar since May 2013, which adds to the burden of the $40

billion in foreign debt owed by Brazilian companies that falls due this year (The Economist, 2015).

The corruption scandal at Petrobras has ensnared several of the country’s biggest construction firms

and paralysed capital spending in swathes of the economy. On April 22nd

2015, Petrobras issued its

results, after its books were scrutinized in the wake of the corruption scandal. The reported net loss

was R$21.6 billion, R$6.2 billion of which were directly related to the corruption probe. The rest was

impairment resulting from poor planning, declining oil prices, unrealized refinery project goals and

excess costs, such as over-priced goods purchased under tough national content rules – many of

which could also be ascribed to corruption (Fortune, 2015). This will force Petrobras to cut their

investment strategy aimed at developing offshore fields, since in the short term the company is

focused on its financial survival. Petrobras also announced it would cut its 2015 capital spending to

$29 billion, 34% below the planned average for each of the next five years and also cut spending by

another 13% to $25 billion in 2016. Besides harming Petrobras, Brazil’s biggest company, the scandal

has hamstrung two dozen of Brazil’s largest construction and engineering firms, bankrupting at least

five, and throwing thousands out of work (Fortune, 2015).

The difference between Petrobras’s expectations and the current oil price, as well as the current

turmoil in both the Brazilian and Petrobras’s finances creates a big uncertainty scenario towards the

future Petrobras’s investment strategy, and, consequently, its future demand for equipment. This

poses a serious risk to the Brazilian industrialization strategy to become one of the world’s leaders of

technological innovation.

1.4. Thesis’s Framework

1.4.1. Motivation

As explained earlier, today’s oil sector is involved in major changes mainly due to the appearance and

development of new types of technology. These events triggered the exploration of more complex

and, even more important, richer areas of our world.

The discovery of the pre-salt oil reservoirs in Brazil, despite its enormous economic potential, poses

new technological obstacles that must be overcome. Due to the remote and harsh environments of

these new fields, with long tie-back distances and difficult accesses for topside technology, subsea oil

processing presents a possible alternative. Also, existing offshore mature fields, which have already

passed their peak production, can benefit greatly with the development of this technology, as their

production can be enhanced and their life extended. Fully automated oil production fields consisting of

only subsea systems, which process the oil sending it directly to shore afterwards, is becoming a

potential scenario, disrupting the current technological paradigm.

1.4.2. Methodology

Motivated by the existing oil reserves in the deep-waters of Campos’ basin and the newly discovered

pre-salt reserves, Petrobras felt the need to adopt and qualify new technologies. Consequently, one of

Petrobras’s main focus areas was subsea technologies, more precisely subsea boosting and subsea

10

separation. This thesis studies 3 projects developed in Brazil: 2 in the area of subsea boosting,

Barracuda’s Subsea Helico-Axial Multiphase pump (SHMPP) and Albacora’s Subsea Raw Water

Injection System (SRWI) and 1 in the area of subsea separation, Marlim’s 3-phase Subsea Separation

System (SSAO). These projects were selected based on the ANP’s innovation awards, where they

were highlighted due to their pioneering and innovative character. Moreover, these 3 projects are also

the core of Petrobras’s innovation strategy for the next years, which aims to prove and develop the

technology basis for further developments and applications in subsea processing. These projects are

presented in Chapter 2, which after a brief introduction, focuses on the study of the main technological

challenges, the R&D strategy employed and the adopted solutions during the development of the

aforementioned projects. After this stage, conclusions about the current state of these technologies as

well as the existing technological bottlenecks are made. Data from other relevant projects in the areas

of subsea boosting and separation will also be used to complement the main conclusions drawn from

the study of these 3 projects.

A manufacturing technique that is gaining relevance in the oil and gas industry is additive

manufacturing (AM). AM, also known as 3D-Printing (3DP), is a manufacturing technique which

consists of various processes that can make a 3D object directly from a computer-aided-design

(CAD). AM could provide new innovative solutions for equipments to be used in O&G fields located in

extreme conditions (such as the ultra-deep waters in Brazil or the Arctic pole), as it allows engineers to

produce complicated designs to address the challenges presented by extreme conditions, without

having the constraints of traditional manufacturing technologies. Furthermore, it can also reduce the

development cycle of a product, speeding up the innovation process. An internship was taken in

Brazil, in its cluster of digital manufacturing laboratories, located in PUC-Rio and INT (the Brazilian

National Institute of Technology), to understand the benefits and the limitations of this technique. To

perform this analysis, key projects were studied and experts in the area were interviewed. The project

selection was made following ONIP’s (the Brazilian National Organisation for the Petroleum Industry)

recommendations on which projects had the highest impact and where additive manufacturing proved

to be more valuable. These projects were developed in cooperation with O&G companies: 2 of these

projects, the Subsea Cleaning Hub and the Smart Battery Monitor, were developed in a partnership

with a Brazilian subsea company, TR Subsea, while the other one, the Modular Inspection System for

Weld Analysis, was ordered by SAIPEM and was developed by INSFOR, a spin-off from PUC-Rio.

The study of these projects focuses on their various design stages, from the initial concept to the final

prototype, identifying the main benefits of the introduction of additive manufacturing brought during

their development.

1.4.3. Technology Development in Times of Uncertainty

Changes in the Brazilian social and economic context, brought about by the falling oil prices, the

economic recession and the institutional corruption, brings new and unexpected risks that must be

assessed. The investment strategy previously defined by Petrobras is now inadequate, as the

company is adapting, mainly by reducing future investments, to the present reality. This re-adjustment

has a significant impact throughout the rest of the Brazilian industry, which is, to a certain level,

11

dependent on Petrobras. This high uncertainty scenario, with various possible sets of interactions and

cascading effects, makes Brazil’s future unpredictable.

13

2. Subsea Technologies

2.1. Subsea Processing 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 was 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 subsea solutions 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 this 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, ideas previously considered impossible became possible. The new fields

presented major challenges, like higher pressures and temperatures associated to longer distances

from shore. 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).

From 2007 up until today, 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 2.1 shows

some of the principal technologic advancements in the time frame from 2002 to 2012.

Nowadays subsea processing systems are becoming more acceptable and available for operators.

Multiphase pumps are considered a robust and field proven technology widely used. A number of oil

services companies presently offer subsea processing equipment. Leaders in this innovative solution

include Expro (UK), Cameron, FMC Technologies and GE Oil & Gas (US).

Currently, subsea processing not only enables the development of deep-water reservoirs, but also

increases hydrocarbon production rates and ultimate recoveries from existing Brownfield projects (an

O&G field that has matured to a production plateau or even progressed to a stage of declining

production). Furthermore, the placement of the processing equipment on the seafloor reduces the

need for topside equipment and deck space, which reduces the CAPEX (Capital Expenditure) required

to develop deep-water discoveries, including satellite fields that would be otherwise uneconomic.

14

Currently, a typical subsea production system is generally composed by 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 (Jahn, Cook, & Graham, 2008) (Salgado Gomes

& Barata Alves, 2007).

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);

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.

Several wells can 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 flow lines (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.

Figure 2.1: Subsea processing evolution (http://pt.slideshare.net/Conference_Presentations/global-perspective-on-the-future-of-subsea-technology)

15

.

2.2. Petrobras’s Subsea Technological Trajectory

The discovery of the pre-salt fields changed the oil exploration scenario because, despite the

enormous economic potential of these reserves, the technological obstacles they represent are

substantial. Therefore, Petrobras and other companies are evaluating the possibility of using new

offshore production systems to tackle these new 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.

On the Brazilian offshore, Petrobras, which on December 2014 reported a record production of 2.286

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 general, three technological trajectories can be taken in

the following years (Oliveira, Ribeiro, & Furtado, 2014):

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;

Path breaking: “subsea to beach” technologies that require radical innovations leading to the

concept of subsea factory, which would eliminate the need of platforms.

Figure 2.2: Offshore production system with subsea wells (http://prosquip.com/surf.html)

16

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. It’s important to refer that the three options are not exclusive between them, as the

three of them can coexist and compete.

2.3. Barracuda’s Subsea Helico-Axial Multiphase Pump

2.3.1. Project Overview

The Barracuda Subsea Helico-Axial Multiphase Pump Project was a joint venture of Petrobras and

Framo Engineering. The total investment was US$ 31million (these resources were provided by ANP’s

R&D investment stipulation).

Multiphase pumping can bring several benefits to oil production, such as extending subsea tieback

distances, initiating and stabilizing flow in wells that cannot naturally produce to remote facilities and

reducing subsea-development costs (Hua & al., 2012) (Kuchpil & al., 2013).

This multiphase pump can achieve the highest pressure differential (60bar) available in the market.

With this pressure differential the productivity of the Barracuda field is enhanced by 6000barrels/day.

There are various multiphase pumps available in the market, but before the development of this one,

the maximum pressure differential achieved was 45bar. For Petrobras, this scenario wasn't attractive,

since similar results could be achieved using gas-lift technology. However, with pressure differentials

equal or higher than 60bar these pumping systems are attractive and productivity is greatly enhanced.

To qualify the desired pressure differential, Framo Engineering updated existing hydraulic and

mechanical technology already used in similar projects, creating a High Boost Helico-Axial multiphase

pump.

This pump sits bellow 1060m of water.

2.3.2. Design Challenges

Multiphase pumping faces several challenges for its development (Hua & al., 2012):

Pump design for installation in a specific environment takes into account parameters such as

bottom hole pressure, water cut, gas fraction, and other reservoir parameters. Over time,

Figure 2.3: Subsea layout for the subsea multiphase pump

17

these parameters may deviate from these initial expectations, so the multiphase pump should

be designed to have a wide range of operating parameters to cope with changing flow

conditions. In addition, a variable-speed drive (VSD) is commonly used to provide

additional operating flexibility;

Continuous liquid flow alternated with long gas pockets can be expected on a random basis

(highly transient flow conditions). In extreme cases, this can be 100% liquid followed by 100%

gas (i.e., gas volume fractions – GVF – from 0 to 100%), which cause sharp fluctuations in the

pumped-mixture density. As a result, the pump load, and, thus, the torque of the shaft, may

undergo abrupt variation that can result in serious mechanical problems in the pump. To avoid

mechanical problems, these fluctuations must be dampened to an acceptable level before the

mixture enters the pump inlet;

Gases are continuously compressed from the pump's inlet until the pump's outlet. This leads

to a significant reduction in the GVF and volumetric rate, as well as an increase in the mixture

density. Specifically, as the pressure increases, the gas volume decreases which causes a

rise in the temperature. Normally, the pump is cooled by the fluid passing through it, but when

running under high-GVF conditions, the gas-compression effect can result in a significant

temperature increase that may lead to thermal expansion in some elements of the pump. This

effect can cause premature failure in some temperature-sensitive components;

High axial loads imposed to the bearings due to the axial thrust created by the high differential

pressure imposed.

High performance and reliability, in order to reduce maintenance costs.

Due to the high differential pressures achieved by this pump, another big challenged faced during its

development is the high axial load imposed to bearings due to the axial thrust.

2.3.3. R&D Development Strategy

In order to overcome the aforementioned challenges, Petrobras launched a program to qualify,

through flow loop tests and field operation, a helico-axial multiphase pump which could achieve the

desired differential pressure.

Multiphase flow conditions were evaluated using reservoir and flow simulations. Actual flow conditions

are dependent of the reservoir pressure, well productivity index and other factors. These parameters

can be different from the parameters considered at the simulations and will change along the well life.

Since there's a huge uncertainty in simulating the real flow conditions, pessimist, base and optimistic

cases were evaluated.

Transient and slug frequency simulations were carried out with a typical flow rate in order to analyze

typical start-up conditions with gas-lift and help the design of the flow mixer and flow splitter (the flow

mixer and splitter are used to dampen the changes in density of the incoming flow).

All the main components and subsystems were submitted to Factory Acceptance Tests (FAT) to

evaluate if they meet their technical requirements. In addition, the motor-pump was submitted to

extended hydraulic performance tests, where the predicted pump performance curves were compared

18

with the experimental data. These tests have been carried out with multiphase flows using water with

air, and mineral oil (30 cP) with air.

Finally, the pump was submitted to Site Integration Tests (SIT) to evaluate functionality and to

demonstrate system interactions and interfaces. During the SIT a special slug test was carried out to

evaluate if the flow mixer, pump, drive and control system were capable of handling operation with

slug flow. The test loop was modified to generate slugs and a densitometer was used to monitor the

flow pattern at pump intake. These tests were performed with air and water.

2.3.4. Adopted Solutions

The operating conditions the pump is subjected to are (Kuchpil & al., 2013):

Steady state well production;

Pump start with and without gas-lift;

Shutdown (normal pump shutdown, platform emergency shutdown, electrical power shutdown,

X-tree shutoff and platform separator);

Pigging through pump bypass;

Chemical injection with ethanol;

Flow line depressurization to hydrate dissociation;

Flushing to withdraw the pump module or flow lines.

To achieve the desired differential pressure, Framo Engineering introduced some modifications and

improvements in the hydraulic and mechanical design of existing helicon-axial technology. Many

critical components were based on the current design used in conventional pumps. For example, in

order to reduce the axial loads imposed on the bearings, it was decided to use a balance piston. The

balance piston to reduce axial thrust is very common in monophase pumps and/or gas compressors,

but its application in multiphase pumps have never been tested before.

Based on the multiphase flow parameters and operating conditions defined above, a 13 stage pump

was defined. The other design data can be consulted in the table 2.1.

Table 2.1: Design data for the Subsea Helico-Axial Multiphase Pump system

Operational point Operational limits

Differential pressure 60 bar 70 bar

Pump speed 3480 rpm 1500 to 4600 rpm

Power 820 KW 1530 KW

Torque 2250 Nm 3149 Nm

Suction pressure 88 bar 64 to 126 bar

Gas at pump intake 35% 70%

Fluid temperature 65°C 4°C to 85°C

19

This system was designed using a modular philosophy, comprising a total of 5:

Torpedo sub-base;

Flow base;

Pump module;

Umbical terminal module (UTM) and vertical connection module (VCM);

Subsea control module.

Besides these subsea modules, a variety of topside equipments were installed in the FPSO to protect

and operate the SHMPP. The main topside equipments used to accomplish these tasks are:

Variable speed drive (VSD);

Pump control cabinet (PCC);

Motor control cabinet (MCC);

Operator workstation (OWS);

Control fluid hydraulic power unit (CFHPU);

Electric power unit (EPU);

Engineering workstation (EWS);

Barrier fluid hydraulic power unit (BFHPU);

Topside data hub (TDH).

A detailed explanation of each of the subsea modules as well as the topside equipments used in the

SHMPP can be found in (Kuchpil & al., 2013).

Figure 2.4: Various modules of the Subsea Helico-Axial Multiphase Pump system

20

2.3.5. Developed Competencies

With this new technology of Subsea Helico-Axial Multiphase Pump, differential pressures higher than

60bar were achieved for the first time. This project also enhanced oil production from the Barracuda

field as can be seen in the figures below (Kuchpil & al., 2013).

The expansion of the operational envelope of subsea helico-axial multiphase pumps will enable its use

in important scenarios, accelerating the number of applications and increasing the benefits of this

important subsea boosting method. Moreover, from figures 2.5 and 2.6, it can be concluded that this

project was successfully developed, achieving the proposed performance.

2.4. Albacora’s Subsea Raw Water Injection System


The Albacora Subsea Raw Water Injection System (SRWI) was a joint venture of Petrobras and

Framo Engineering with 20% of local content. Framo Engineering subcontracted FMC Technologies to

design the flow base, VCMs (vertical connection modules), valves and the subsea control system.

Figure 2.5: Average monthly values for main pressures

Figure 2.6: Pump flow rates since start-up

21

In mature fields, the installation of conventional seawater injection systems on existing topside

facilities can be a problem. These conventional systems require the installation of too many pieces of

equipment on the production units, demanding large areas that sometimes are not available. Other

restrictions can occur, such as load limitations. One alternative to overcome these problems is the

Subsea Raw Water Injection (SRWI) technology, by which most of the system is installed at seabed

and seawater is injected with minimum treatment, leading to a much lower impact in the topside

facilities.

This system collects seawater 100 m above the seabed. Then, the collected seawater goes through a

filter installed at the system's inlet and receives a nitrate injection. After this minimum treatment, the

water goes directly to the wet X-tree and then to the producer reservoir.

Water injection has a high economic impact in offshore projects, because it affects directly the

recovery factor and the production flow rates. With the installation of this system in the Albacora field,

the production was increased by 45000 barrels/day.

This system is sitting bellow 400 m of water.

2.4.2. Design Challenges

The SRWI presents many technical challenges in order to achieve a successful installation of this

system (Buk Jr. & al., 2013):

Seawater compatibility with the reservoir rock and fluids, which can cause a loss of injectivity;

Microbiologically Influenced Corrosion (MIC) if there are stagnant areas or long shut in periods

during operation;

Saline fluid is highly corrosive to most metallic alloys due to the presence of dissolved oxygen;

Sour corrosion in producer wells if reservoir souring is not prevented;

Hydrogen Induced Stress Cracking (HISC) if duplex stainless steels and cathodic protection

are used simultaneously;

Galvanic Corrosion if dissimilar materials are in contact;

Figure 2.7: Albacora’s Subsea Raw Water Injection System

22

Reliability of the subsea equipment and power systems.


The main components have been already used in similar applications, presenting suitable reliability in

subsea scenarios. The back flushing system of the filter had already been qualified by other

companies, but Albacora system is the only one electrically driven. The development of SRWI was

considered as a low risky activity, but required extended factory acceptance tests for the filters, since

their malfunction would be responsible for the loss of injectivity of the reservoir.

A feasibility analysis was also performed to study the how solid particle counting and sizing, bacteria

and dissolved oxygen concentration varied across the seawater depth, and what impacts they could

have on the SRWI performance. The oxygen concentration variation with the water depth is an

important parameter to be assessed as it influences the material selection. An assessment of the

suitability of a range of alloys was carried out supported by literature data and crevice corrosion tests.

For an initial ranking of the candidate alloys for service in oxygenated seawater, the Pitting Resistance

Equivalent Number (PREN) was used.

Laboratory tests (immersion and electrochemical) using some alloys were also performed in

Petrobras’ Research Centre (CENPES) to check their behavior in natural seawater in different

temperatures.


Based on the studies performed, it was decided to install 3 SRWI systems in the Albacora field. These

3 systems inject a total of 16500 m3/day of seawater in seven wells. One system will inject water in

three wells in piggy-back layout and the other two systems will inject in two wells each, also in piggy-

back layout. The subsea layout for this system can be seen in figure 2.7.

Figure 2.8: Subsea layout for the SWRI system

23

Based on the seawater characterization tests performed (solid particle counting and sizing, bacteria

and dissolved oxygen concentration), it was decided to take the seawater approximately from 100 m

above the seabed.

The various modules comprising this system are:

Water intake system;

Pump module;

Subsea control and monitoring system;

Barrier fluid hydraulic power unit (BFHPU);

Topside pump and control system.

A more detailed explanation of each module can be found in (Buk Jr. & al., 2013).

Although each location has its own specific flow rate and pressure requirement, all the Albacora

pumps are identical, in order to keep spare parts and total system cost as low as possible. The only

difference are the speed and the power level, since each one is driven by its own variable speed drive

(VSD) and the operating points are close to the best efficiency line for all the pumps. As a

consequence, all the pumps are interchangeable between the locations, with power limited by the

respective VSD.

Figure 2.9: Arrangement of the various modules in the SRWI system

24

The material selection made for the SRWI can be consulted in table 2.2 (Buk Jr. & al., 2013).

Equipment Type Environmental

Conditions Involved Risks Selected Material

Connector T<15⁰ C Erosion, Corrosion CS with clad in alloy

625

Strainer T<15⁰ C Fouling, Deposition,

Plugging

SDSS with anti-fouling

coating

All (with or without CP) T<20⁰ C HISC (CP), Crevice

Corrosion Alloys with PREN>40

Sand Screen T<90⁰ C Corrosion CS with internal GRE

lining

Sand Screen T<90⁰ C Crevice Corrosion PREN>60

Casing T<90⁰ C Pitting and Crevice

Corrosion Alloys with PREN>40

Tabela 2.2: Material selection for the SRWI system (CS – Carbon steel; SDSS – Superduplex stainless steel; HISC – Hydrogen

induced stress cracking; CP – Cathodic protection)

Studies were performed to assess the reservoir souring potential as a result of raw seawater injection

in Albacora field. Based on these studies, it was decided to prevent biogenically generated H2S

production. This was an important issue to be dealt with because populations of H2S -generating

microbes (sulfate-reducing bacteria) can grow in reservoirs subjected to the injection of sulfate-rich

water. These bacterias increase the amount of H2S in the produced fluids. The adopted solution was

to continuously dosing a nitrate salt in the injected water. With nitrate salt present in the seawater,

microbial H2S formation in the reservoir is inhibited.


The development of the SRWI project, created a new database for corrosion-resistant materials. This

database can be extremely helpful for future Subsea Raw Water Injection projects, as it can save both

time and money when selecting materials for subsea applications.

The SRWI technology can play an important role in enabling or increasing seawater injection in some

fields, mainly mature ones. These SRWI systems will increase oil recovery, accelerate oil production

and generate significant economic benefits. However, some reservoirs will require additional

treatment, like fine filtering or sulfate removal, which could be necessary in future developments.

2.5. Marlim’s 3-phase Subsea Separation System


The Marlim 3-Phase Subsea Separation System (SSAO) was a joint venture of Petrobras and FMC

Technologies. Framo Engineering, Prysmian, Statoil’s research center in Porsgunn and ESSS also

collaborated. The total investment was US$ 90 million (these resources were provided by ANP’s R&D

investment stipulation) with 67% of local content.

25

This project won ANP’s zero edition prize for technological innovation. It is the world’s first system for

deepwater separation of heavy oil and water which reinjects the separated water into the same

producer reservoir. The reinjected water helps to keep up the pressure in the reservoir, increasing oil

production and the recovery factor, and, consequently, debottlenecking topside facilities (FPSO) and

reducing operational costs.

The SSAO is also an environmental friendly technology as it reduces waste disposal to sea.

Considering that environmental legislation is continuously becoming stricter for disposal of water with

oil content, this technology will contribute to the sustainability of the oil industry in the future.

Marlim field was chosen for the installation of this system because it is a mature field which is

exploited by 8 floating platforms that are now reaching their maximum water processing capacities.

Marlim was the field where the return on the investment from applying this technology would be the

highest.

This unit is sitting bellow 870 m of water, and is connected to one production well, one injection well

and to the FPSO P-37. Figure 2.9 illustrates the oil-water subsea separation system of Marlim.

2.5.2. Technological Challenges

The Marlim field in the Campos Basin posed several challenges to the introduction of the SSAO

(Euphemio & al., 2012) (Oliveira & al., 2007) (Orlowski & al., 2012):

Heavy (API 22°) and highly viscous oil with a great tendency to form stable emulsions due to

its chemical features (high acidity and asphaltene content) makes separation a delicate art;

Heavy oil solution involve high amount of fluid handling due to high water injection flow rates;

Several operators, during the last decade, focused on subsea separation processes using

light oil (for example the systems installed in the Troll and Tordis fields in Norway), hence

there was a lack of know-how regarding heavy oil subsea separation;

Figure 2.10: Artistic view of the separation system installed in the Marlim field

26

Installation of production heating systems, which are used in topside facilities to provide

separation at higher temperatures (90°C), was not feasible in the present case, forcing

separation to take place at around 50°C, which is deleterious to the oil and water separation

process;

Due to the water depth of the installation site and the fact that the SSAO is a pilot for future

even deeper applications, conventional gravity separators used in previous subsea separation

projects were considered unfeasible. Such vessels would be too heavy because of external

hydrostatic pressures and difficult to manufacture due to materials required for the produced

fluids;

Flow assurance issues such as hydrate formation, which can cause blockage of a valve, had

to be considered. Hydrate formation could occur mainly during system shut down and start-up

operations, since subsea bottom temperature is about 4°C, below hydrate formation curve for

the normal operating conditions. For this project, this became even more challenging, since

the equipment piping would be in many situations, filled in with different fluids. Some of the

piping would be filled with oil and gas, while some other segments would be filled with water;

Overall water removal efficiency and reinjection was set to 70%;

The required water quality for reinjection, relating to oil and sediment content after separation,

is very strict in order to avoid loss of injectivity and reservoir damage (100 ppm of oil with a

maximum of 11 ppm in volume of solids);

High robustness and low maintenance of the equipment;

Leveling of the subsea station after its subsea installation to ensure the separator was was

performing at its maximum efficiency.

The control and operation of the SSAO imposed also several challenges (Pereira & al., 2012):

Strong interactions between different process components;

System dynamics are stiff due to small liquid hold-ups and low gas oil ratio in the system;

Pressure drops of inline cyclonic equipment need to be balanced to ensure optimal

performance;

Only choke valves are qualified for subsea application;

Constraints in valve opening/closing speed and the importance of limiting the number of valve

movements put restrictions on controller performance;

Instrumentation is limited compared to topside facilities.


In order to overcome the aforementioned challenges, a series of R&D projects targeting different

technology gaps foreseen in subsea processing equipment were conducted. Experimental tests for

emulsion generation prediction, development of additives with chemical compatibility, determining

reservoir limitations of oil and solids content in injected water, studies on slug flow impact and

mitigation strategies, solids handling and water cut measurement method were some of the projects.

27

In terms of subsea equipment several new technologies were evaluated to be employed underwater

for the first time, by means of a very extensive and broad Technological Qualification Program (TQP)

(Capela & al., 2012). Some of the equipment tested in the TQP is listed below:

Separation systems;

Sand removal system for the outlet separator vessel;

Ejectors;

Flow orifices (orifice plates);

Flow restrictors for the control of the multiphase sand remover reject;

Vortex breakers to minimize hydrate formation risk at the connection points between the

multiphase flow circuit and separated water flow circuit of the system.

The main controlling parameters of this system are the oil and solid concentration in the separated

water. These parameters have to be constantly and accurately measured on-line in order to prevent

reinjection of out-of-specification water. Therefore, great effort was put in the development of sand

detectors and oil-in-water meters. Also, because compact separation systems are too sensitive to

fluctuations (slugs, for instance), Petrobras made a significant effort to develop and improve intelligent

process control systems, in order minimize these equipments’ deterioration. Several dynamics

simulations of the various processes were used as a design tool (Pereira & al., 2012).


For the oil and water separation process, Petrobras tested 3 different separation technologies: In-line

Cyclonic Device, In-line Electrostatic Device and Tubular Separator. After various simulations and

tests, the separation core of the system was conceived. Firstly there would be a gas and free water

separator, followed by an in-line electrostatic coalescer and lastly another oil and water separator.

This system could deal with any ratio of emulsion-to-free-water present in the upcoming flow. With the

knowledge gained with the various tests performed, Petrobras decided to simplify the system and

assume that most part of produced water will be in the form of free water. This hypothesis led to a

simpler conception for the SSAO, which now comprises only the free-water separation part, besides a

de-oiler and a sand management system. Neither electric coalescer nor downstream separator are

included. The Pipe Separator, a tubular separator, technology (patent licensed from Statoil) for the

bulk oil-water separation was chosen. The Pipe Separator concept uses the gravity separation

principle and its tubular nature allows application in greater water depths without need for heavy wall

thickness as compared with conventionally shaped separation vessels (Oliveira & al., 2007). To

perform the water polishing to the levels necessary for water injection, hydrocyclones were selected.

28

After the TQP was completed, a final design was proposed and can be seen in figure 2.10.

The flow from the production well gets routed to the separation unit. The first equipment it encounters

is an inline sand remover, which removes most of the sand from the incoming flow. The removed sand

is sent to the outlet vessel of the system. It is followed by the gas harp (gas-liquid gravity separator).

This arrangement of interconnected vertical pipes aims to remove the free gas present in the flow.

Doing this enables the following section of the pipe separator to handle a predominant liquid phase.

The gas removed in the gas harp is routed directly to the outlet separator where it is later recombined

with the previously separated oil. The oil and water present after the gas harp flows through the pipe

separator and over its length gets separated by normal gravity force. By the time the flow reaches the

end of the pipe separator the two fluids are fully separated (water at the bottom and oil at the top).

That arrangement then enters the outlet vessel. Gas and oil are mixed and exit through one of the

vessel’s outlet to the topside platform. Water exits from the other outlet and passes through an inline

sand remover followed by two continuously set of hydrocyclones to remove the amount of oil present

in the water. The removed oil from the hydrocyclones in sent to the platform. After leaving the

hydrocyclones, the pressure of the treated water is increased to meet the reservoir demands. The

amount of water to be reinjected is controlled by an oil/water interface system installed in the reservoir.

This system is connected to a frequency variator which controls the injection pump’s angular velocity.

Before being injected, the quality of the water (concentration of oil and grease) is monitored to ensure

it meets the reservoir standards.

In order to reduce the overall weight, dimensions and increase the compactness of this system, it was

decided to divide this system in various modules. This solution also makes subsea recovery and

reinstallation operations easier to be performed. A modularization study was made and it was

concluded that the best arrangement for the system would be with 10 retrievable modules, which are

(Orlowski & al., 2012):

Figure 2.11: Adopted design for the SSAO

29

Bypass module;

Multiphase sand remover module;

Pipe separator module;

Water sand remover module;

Hydrocyclones module;

Pump module;

Water injection choke module;

Recirculation and flushing module;

Two electro-hydraulic module for multiplex control (EHCM).

Besides these modules, the system has 3 vertical connection modules (VCMs) and 3 umbilical

terminal modules (UTMs). These components connect the SSAO to the production and water injection

wells and to the topside production platform. Figure 2.11 illustrates the various modules comprising

the SSAO system.

Figure 2.12: SSAO’s different modules

30

The hydrate strategy adopted was also crucial during the development of this project. Hydrates start to

appear when free gas and free water are present and their temperature is below the hydrate formation

temperature, for a given pressure.

The ambient sea water temperature 870 m below the sea level in the Marlim field is 4°C. After a

detailed investigation on the hydrate formation curve of Marlim oil, it was concluded that hydrates

would start to appear if oil temperature falls below 15°C. Based on this characteristic, operation during

normal production is above hydrate formation temperature. In case of a planned shutdown of the

system, critical components are injected with Mono Ethylene Glycol (MEG), which inhibits hydrate

formation. A detailed study was conducted to evaluate which parts of the system pose little or no risk

on hydrate formation when the system is off. The main goal of this study was to reduce the number of

MEG injection points, making the operation less complex and reducing costs. In the study, the system

was divided in 4 parts: low pressure water lines, high pressure water lines, multiphase lines and

chemical injection lines. The study showed that hydrates had higher tendency to be formed in the

multiphase and the chemical injection lines. MEG injection points were installed on the multiphase

lines and both the multiphase and the chemical injection lines were coated with thermal insulation.

In case of an unplanned shutdown, the system was designed to have a total of cool down time of 6

hours. This cool down time is achieved by thermal insulation of critical areas.

The ultimate system safeguard is a full depressurization to about 5bar, which is enough to dissolve

any hydrates, in case of hydrate plugging. This depressurization can be performed within 4 hours and

requires depressurization of both the production flow line and the gas lift line.

A more detailed description of the hydrate prevention strategy employed can be found in (Duarte & al.,

2012).

Since this is the most advanced subsea process system to date, with several “first ever” applications

of separation equipment subsea (harp, Pipe Separator, desanders and hydrocyclones), a highly

complex control system was developed. 7 control loops (level controller, two pump flow rate

controllers, multiphase choke valve-DP controller, two hydrocyclone controllers and a flushing

controller) and a number of complex automatic sequences comprise the SSAO in order to assure the

proper functioning and performance.

All control logic is located and executed topside. All electric and hydraulic power is supplied from

topside to subsea. The main topside equipments used for the SSAO control are: Master Control

Station (MCS), Power and Control Module (PCM), Control Hydraulic Power Unit (HPU) and Barrier

Fluid Hydraulic Power Unit (BFHPU).

Two types of subsea sensors were developed and qualified for this project: differential pressure

transmitter, which transmits both absolute and differential pressures with required accuracy and oil in

water monitor. This last sensor is installed downstream the water injection pump and is used to

evaluate the water quality for re-injection.

Another area of great focus during the conception of the control system was the reduction of the

control loop response time. The control loop response time was high due to the fact that all subsea

control is done topside, which makes communication slower. The use of hydraulic actuated choke

valves, instead of the conventional topside continuous modulating control valves, also contributed for

31

the increase in the response time. The adopted solution was to implement a control logic that would

allow some process fluctuations in order to avoid excessive step choke movements. This solution not

only makes the control loop response time lower (choke valves are subjected to less step movements)

but also reduces the wear of the choke valves. This is achieved by the use of dead bands for the PID

controllers and by the logic parameters adjustments for the hydrocyclones module chokes.

A more detailed description of the control system can be found in (Pereira & al., 2012).


Several new competencies were developed with the conception, construction and installation of this

pilot project:

Subsea heavy oil separation;

Qualification of new, more efficient and compact separators;

New sensors;

Control logic for subsea applications;

In-depth hydrate formation knowledge.

The execution of a complex and extensive R&D project such as this one exposed the level of

efficiency of the company’s processes for design, bureaucracy handling and communication. This

project also improved the way international projects and business ventures are handled in Brazil.

The Marlim 3-Phase Subsea Separation System proved to be an excellent technological basis for the

installation and development of more subsea separators in existing mature and pre-salt fields.

2.6. Summary

Based on the projects studied, Petrobras is taking a risk-conservative approach when introducing new

technologies to its O&G fields. Petrobras decided to develop these three projects for installation in

existing fields which faced restrictions that demanded new technological solutions (for example, the

Albacora field demanded a higher water injection rate than planned, and it wasn’t economically viable

to install any traditional topside equipment in the existing platforms – leading to look for new solutions

in the field of subsea technologies). This approach proves how Petrobras is leading with the

development of new technologies for subsea boosting: develop them for installation in brownfields that

could beneficiate the most with its installation, reducing the risk.

The strategy adopted in the development of the projects in the area of subsea boosting was an

incremental one. Petrobras opted to choose the Helico-axial technology for both these projects, a

technology has a long track record with more than 15 installations and a cumulative operation time of

over 750000 hours (Luce & al., 2013). The biggest technological challenge, while developing the

Barracuda Multiphase Helico-Axial pump, was reducing the axial loads on the bearings. The adopted

solution was to re-qualify, for multiphase pumps, a very common solution used in monophase pumps

and gas compressors, the balance piston. Moreover most of the critical components used in this

32

project, were adopted from previous successful applications. The Albacora’s SRWI system also didn’t

develop new technology. The main challenges faced during the development of this project were the

proper material selection required to deal with the conditions caused by seawater and a proper filter

selection in order to avoid loss of injectivity of the reservoir. The pioneer character is clear on both

these projects, requiring huge investments and long technology qualifying programs, and closing

existing technological gaps. However they didn’t bring any disruptive solutions in the field of subsea

boosting. Furthermore, they are very dependent on topside equipment, such as the power and control

modules, to guarantee their proper operation. There are still some developments and improvements to

be achieved. Subsea VSDs, umbilical optimization, MPP without mechanical seal barrier fluids and

standardization of subsea interfaces are some of the technological gaps still to be closed

(Albuquerque & al., 2013). The closing of these technological gaps can bring further benefits, helping

to overcome technical and economical constrains.

In the case of subsea separation, Petrobras took a more challenging approach, developing new

technology for subsea scenarios. This supports the importance Petrobras has been giving to qualify

new separator technology for deep waters. Currently, a new R&D project is being developed by

Petrobras and PROCAP Technology Program – Future Vision in order to evaluate new technology for

a Compact SSAO. The first step of this project is the evaluation of potential arrangements for subsea

stations using core technologies for oil-water separation (tubular separator, hydrocyclones and

electrocoalescer). This study aims to map the technological gaps that must be overcome, for a real

field application, and also to serve as a preliminary qualification program. The scenario used for this

study is a mature field with a water depth of 900m. The compact SSAO will receive production from a

mainfold, which is connected to 4 wells. The separated gas and oil will be sent to the topside platform

which is located 6000 m away from the compact SSAO. The separated water is going to be injected

into 3 wells, in a piggy-back configuration. This arrangement can be seen in figure 2.13.

Figure 2.13: Compact SSAO layout

33

The main difference between the Compact SSAO and the SSAO is the number of production wells

each system is connected to (4 production wells for the Compact SSAO and 1 production well for the

SSAO). This means that the Compact SSAO has to be able to process higher flow rates than the

SSAO, which poses some restrictions on the choice of the oil-water separator and also presents new

challenges regarding valve selection.

Tubular separation technologies such as the Pipe Separator, constituted by only one pipe, aren’t

feasible. A potential solution is to adopt multiple pipe geometry. However flow channelling for the

various pipes, phase collection as well as sand handling from the various pipes pose a big challenge

and make this type of technology unsuitable for this system. Hydrocyclones, due to their compactness,

would be the best option. However there is very little information about their performance when

dealing with high oil content at the inlet. The only information available is limited to model fluids, which,

in some cases, fail to simulate accurately heavy oil behaviour. Another issue regarding hydrocyclones

is their ability to deal with sluggish inlet conditions. More dynamic analysis with different water cuts

and flow rates at the inlet as well as simulation of the dynamic behaviour of these systems, to improve

the control systems used, have to be done in the TQP. Electrostatic devices, such as the Electrostatic

Coalescer and the Electrostatic Separator, might prove to be essential for producing oils with even

lower water content, after the primary oil-water separation is completed. The application of electrical

fields to break stable emulsions of oil and water has proven to be a very successful method. Although

this technology has been used only on topside facilities, recent experiments proved this technology

can be applied also on subsea environments (Albuquerque & al., 2013).

As previously said, continuous modulating control valves aren’t qualified, yet, for subsea applications.

Because subsea technology is becoming more complex, choke valves cannot withstand the

technological requirements from these systems, and continuous modulating valves will have to be

qualified for subsea applications. A proper qualification of these valves also allows a faster response

time to be implemented in the control loop of the system and, consequently, optimize the oil-water

separation process (the optimization of the oil-water separation process in the SSAO was not

employed on behalf of less choke valve movements). Another problem in the Compact SSAO

development is the multiphase separation phenomenon due to shearing from the well choke valve.

The multiphase fluid separation can make the oil-water separation process unsuccessful, which

affects greatly the Compact SSAO’s performance. This problem didn’t exist in the SSAO because it

was connected to only one well and, consequently, the well choke valve was installed downstream of

the SSAO. But because the Compact SSAO is connected to 4 production wells, the well choke valves

have to be installed upstream of this system in order to have a proper control of each well. A possible

solution for this problem is to use low shear valves, a conceptual design patented by Petrobras seven

years ago, instead of the conventional choke valves. Several tests are being conducted in order to

qualify this new technology for subsea applications. Another great challenge Petrobras is facing

nowadays is the monitoring of dispersed oil in the water flow. To overcome this technological gap

Petrobras is developing new instruments and equipments, which use technologies such as light and

laser scattering and fluorescence measurement. After the proper qualification of this technology, the

next challenge is its incorporation with the other systems. The successful incorporation of this

34

technology can enhance the performance of the overall system as it can increase separation

efficiency.

35

3. Additive Manufacturing in the O&G Industry

3.1. Process Description

Additive Manufacturing (AM), also known as 3D-Printing (3DP), is a manufacturing technique which

consists of various processes that can make a 3D object directly from a computer-aided-design

(CAD). In the past AM was used exclusively for rapid prototyping, however due to recent technological

developments the field of applications of this technique is rapidly increasing. Innovation in materials

(metal and thermoplastic powders, among others) as well as binding sources (laser melting, electron

beam melting, among others), made this manufacturing revolution possible.

While traditional manufacturing processes such as lathing or milling, are considered subtractive

manufacturing, they create an object by removing unnecessary material, additive manufacturing

creates an object one layer at a time, building it from the ground up. Thus, AM offers clear advantages

when compared to the other manufacturing techniques, such as material and energy savings and

provides design flexibility, which in turn allows for lighter and stronger parts.

3.2. Industry Perspectives

The global market for AM is growing rapidly, and is currently valued at over $2.2 billion and is

estimated to value $10.8 billion by 2021 (Lloyd's Register Energy, 2014). Technical applications range

from numerous industries as Energy, Aerospace and Biomedical. General Electric (GE) is considered

to be one of the early adopters of this manufacturing technique. In November 2012 GE acquired

Morris Technologies and its sister company, Rapid Quality Manufacturing, companies which specialize

in additive manufacturing in the aerospace, energy, oil and gas, and medical industries (3ders, 2014).

Although there are many conservative companies towards AM, especially in the O&G industry, a study

showed that in the future AM is going to have a significant impact in this industry (Lloyd's Register

Energy, 2014).

Figure 3.1: Industry perspectives towards AM

36

For example, as drilling conditions become more extreme (ultra-deep waters and some areas in the

Artic pole), AM can be a possible solution as it allows engineers to design sophisticated parts to

address these challenges.

3.3. The Digital Manufacturing Project

In 2012, ONIP (the Brazilian National Organization for the Petroleum Industry) coordinated the

implementation of the Digital Manufacturing Project, making use of funding made available through

ANP regulatory framework. This project was created to meet the demand of product development and

prototypes for the O&G sector. The available services involve manufacturing processes controlled by

computers such as:

Engineering and product design

Development of boards and electronic circuits

3D scanning

Rapid prototyping in various materials

This project was implemented in INT (the Brazilian National Institute of Technology) and PUC-Rio

(Pontífica Universidade Católica do Rio de Janeiro – a Brazilian university), where it was implemented

in 3 research centres:

NEXT (Núcleo de Experimentação Tridimensional): product design, small size 3D printed

prototypes, CNC technology and a robot arm to build large models and 3D scanning;

GIGA (Grupo de Inovação e Gestão Ambiental): electronic prototyping, automation and

embedded technologies;

ITUC (Instituto Tecnológico da PUC-Rio): material analysis, metrology, research and

technological development.

There available technologies in these research centres are the following:

Fused Deposition Modelling (FDM): this process uses two kinds of materials, a modelling

material, which constitutes the finished object, and a support material, which acts as a

scaffolding to support the object as it's being printed. During printing, these materials take the

form of plastic threads, or filaments, which are unwound from a coil and fed through an

extrusion nozzle. This technology can only be used with plastics;

37

Selective Laser Sintering (SLS): this technology uses powder materials, such as nylon or metal, which

are dispersed in a thin layer on top of the build platform inside a SLS machine. A laser, which is

controlled by a computer pulses down on the platform, tracing a cross-section of the object onto the

powder. The laser heats the powder either to just below its boiling point (sintering) or above its boiling

point (melting), which fuses the particles in the powder together into a solid form. Once the initial layer

is formed, the platform of the SLS machine drops, exposing a new layer of powder for the laser to

trace and fuse together. This process continues again until the entire object has been printed;

Besides these two technologies, it was also installed in GIGA a cluster of 8 machines, which are able

to do print a pined circuit board prototype, with the following arrangement:

LPKF ProtoLaser U3: Ultraviolet laser system for processing printed circuit boards. can work

with virtually any PC board substrate;

Figure 3.2: Example of a FDM application (http://www.custompartnet.com/wu/fused-deposition-modeling)

Figure 3.3: Example of a SLS application (http://www.custompartnet.com/wu/selective-laser-sintering)

38

LPKF ProtoMat S43: PCB milling system

LPKF MultiPress S: Bonds complex PCBs with up to eight layers in one pass;

LPKF MiniContac RS: Electroplating system for throughhole platings;

LPKF ProtoPrint S: Manual stencil printer;

LPKF ProtoPlace S: SMT assembly;

LPKF ProtoPlace BGA: Assembles BGA components, CSPs or flip-chip components;

LPKF ProtoFlow S: SMD reflow soldering, curing conductive through-plating paste and other

thermal processes requiring accurate control.

In the next section, a brief description of the most relevant projects develop in this cluster of digital

laboratories is presented.

3.3.1. Subsea Cleaning Hub

This project was developed in a partnership between TR Subsea, a Brazilian company which

manufactures and outsources tools and equipments for subsea inspection, and ITUC. This cleaning

hub is equipped with a handle for ROV operation and it is used to clean the wellhead before the rest of

the subsea production equipment is installed. It consists of a brush head rotated by a hydraulic motor

and uses a cleaning solution, dispensed through the brush head, to make the cleaning process more

efficient.

The standard hydraulic motor used on this type of equipment is the OMM 50 Sauer Danfoss, so this

was the starting point for the design of the motor. Moreover, the cleaning hub had to be able to

withstand the forces generated by this motor during a normal cleaning operation.

Figure 3.4: Example of a subsea cleaning hub

39

Before this partnership was established, TR Subsea tried several times to manufacture this equipment

in-house, however they couldn’t attain the necessary quality requirements for its application in the

O&G industry. On first prototype designed by TR Subsea, the brushes couldn’t clean the wellhead

properly, due to their lack of quality.

On the second prototype, TR Subsea switched the brushes to ones made with nylon. Although this

change improved the cleaning efficiency, the nylon brushes couldn’t withstand the loads generated by

the motor during a long period of time.

Figure 3.5: Function diagram for the OMM 50 motor

Figure 3.6: First subsea cleaning hub manufactured by TR Subsea

40

The development of this product started with an initial CAD designed in IEPUC. The main goal of this

phase was to evaluate the number of necessary brushes as well as the final dimensions of the hub.

An initial diameter of 275.00mm was considered, but it was decided to decrease it to 255.00mm in

order to widen the range of applicability (the initial diameter could only be used in 70% of the

wellheads due to its larger diameter) and also to save material in the production stage.

In order to qualify this product for the O&G industry, several physical stress tests were performed to

simulate the operating conditions. In order to decrease the development cost of this product, it was

decided to test only a slice of the product, due to its spherical symmetry.

The hub part was printed using Fused Deposition Modelling (FDM) and the selected material was

ABS. Special attention was given to guarantee similar mechanical properties between the test part

and the final hub, which was made from an industrial plastic.

The physical tests consisted of applying a shear force on each brush, in a point distanced 12mm from

the hub, to determine their yield force. A total of 10 tests were performed.

Figure 3.7: Initial and finals design for the cleaning hub

Figure 3.8: Creation of the hub part and printed hub parts for the stress tests

41

The test results performed on all 10 brushes can be seen in figure 3.10 and Table 3.1. The number of

each test matches the numbering in figure 3.7.

Maximum Force (N) Average

(N)

Standard

Deviation

(N)

Test Part

CP1 CP2 CP3 CP4 CP5 CP6 CP7 CP8 CP9 CP10

2680 2537 2492 2653 3101 2926 2801 2631 2190 1974 2598 331

Table 3.1: Test values

Besides characterizing the mechanical properties of the brushes, the tests conducted also had the

objective of testing whether the hub was strong enough to withstand the loads generated. In case the

hub failed during the stress tests, modifications on its design had to me made to increase its

mechanical resistance.

After the mechanical characterization of the brushes was performed, the final step for the qualification

of this product was to evaluate if the brushes could withstand the forces generated by the motor during

Figure 3.9: Stress test being conducted on one brush

Figure 3.10: Test results for the 10 brushes

42

a cleaning operation. It was considered the worst case scenario: the motor is generating the maximum

torque (according to the function diagram, about 100N.m), and one of brushes closest to the centreline

of the hub (distanced 0.0498m) is blocked (for example, by some dirt present in the wellhead). This

scenario would generate the highest possible force one brush would be submitted with a value of

2007N.

The location of this maximum force corresponds to the test parts CP1 and CP2. According to figure

3.9, this force would not be sufficient for the brush to enter in its plastic regime (approximately 2600N),

which meant the final design is able to withstand all the loads generated during a normal cleaning

operation.

Initially was decided to manufacture the final product the same way the test parts were manufactured,

however, due to the high costs associated using this technology, it was decided to use a conventional

manufacturing technique (milling) instead of printing it. The cost associated for printing the final

prototype was R$14.400 while the cost for milling it was R$2.400.

Figure 3.11: Worst case scenario during a cleaning operation

Figure 3.12: Final prototype

43

In the beginning of March 2015, the final prototype was delivered to TR Subsea to test its performance

in real conditions. If problems concerning its mechanical resistance or cleaning efficiency are found,

the system will be returned to ITUC for modifications. Otherwise, TR Subsea will start to mass

manufacture it.

3.3.2. Modular Inspection System for Weld Analysis

This project was developed in a partnership between Petrobras, SAIPEM (Società Anonima Italiana

Perforazioni e Montaggi – an Italian O&G industry contractor) and INSFOR (a Brazilian robotics

company – a spin-off from IEPUC). Petrobras contracted SAIPEM to produce and install the risers for

the P-55 platform. All risers installed on Petrobras’ platforms need to have their weld heights checked

before installation in order to verify if they comply with Petrobras’ quality regulations. This inspection is

made while the risers are still in the factory.

Traditionally, the weld heights were inspected using a small robot which had a metal sheet, of the

same diameter as the internal diameter of the riser, attached on it. If, after the inspection, the metal

sheet was damaged, the weld heights were not in conformity with Petrobras’ quality standards and the

riser couldn’t be installed on the platform.

In contrast to the traditional method for weld inspection, SAIPEM wanted to use a different method for

its risers’ inspection, which consisted of inspecting visually the weld while measuring its height. Due

their expertise and work on this field, SAIPEM subcontracted INSFOR to develop a PIG capable of

achieving the proposed goals. When this project was proposed to INSFOR, SAIPEM already had

risers in stock, which meant the first robot had to be developed quickly. The design requirements for

this first prototype were:

Wheels could not be metallic

Maximum measurement uncertainty of 1mm

Able to inspect risers from 8” to 12” of internal diameter

Minimum autonomy of 15m

Own illumination system

Tabela 3.1: Design requirements for the first PIG prototype

The first prototype was finished 15 days after SAIPEM subcontracted INSFOR. Most of the parts were

bought except the motor support which was printed in PUC-Rio. It was decided to print the support

Figure 3.13: Examples of weld heights not in conformity and in conformity with Petrobras’ regulations

44

instead of manufacturing, since it would require a third company, and, due to time constraints, it was

not feasible.

The camera used for visual inspection was a standard high resolution camera able to perform a full

360º rotation to inspect the whole weld pool. Furthermore, INSFOR installed two lasers on the camera

to measure the weld height. This measurement was done using a proprietary software developed by

INSFOR, which, based on the position of both lasers, calculates the weld height. Using this method,

INSFOR was able to achieve a maximum measurement uncertainty of 0.1mm.

Due to the rapid development of the first prototype, there were a number of parts which had to be

improved, since they broke after some usage. For example, the arms connecting the wheels to the

body of the robot and the motor gears broke frequently during normal operation. Consequently, it was

decided to develop a second prototype from scratch.

The design philosophy for the second prototype was to create a modular robot which, just by changing

few parts, could be used in any riser. On the second prototype it was also decided to change the

visual inspection and measurement methods by adding two sets of cameras, one set being

responsible for the visual inspection and the other for the weld height measurement. The height

measurement method was also reformulated. Instead of using a two-point laser measurement, it was

decided to measure it using a continuous line. The main benefit of this new system was the ability to

Figure 3.14: Camera and measurement system used in the first prototype

Figure 3.15: First prototype in operation

45

measure the whole weld arc height. With this new system, the maximum measurement uncertainty

also decreased to 0.03mm.

Due to the resources available, it was decided to print all the parts, except for the cameras, motor and

wires, which were bought. By printing the entire prototype’s parts, the product development,

comparing to the traditional method, was, according to ONIP, reduced in up to 5 times. Not only the

construction and assembly phases were reduced, as all the parts could be printed and assembled

quickly, but also the CAD phase, enabling an innovative product development. Furthermore, it also

allowed a lighter prototype, since more sophisticated designs for the various parts could be

accomplished.

To increase the prototype’s traction and reduce the vibrations during operation, it was decided to

substitute the wheels (as used in the first prototype) for rubber belt tracks. Another main reason for

this change was to keep the prototype from being blocked in a weld, as was the case with wheels.

Figure 3.16: Second prototype being prepared for riser inspection

Figure 3.17: Second prototype equipped with the first prototype’s camera

46

As can be seen in figure 3.18, the second prototype uses a spring, a male thread and a nut to adjust

its arm’s length. This system allowed the second prototype to be used in a more broad range of risers,

ranging from 6” to 15” of internal diameter.

If one wants to use this robot on smaller or larger risers, only the arms connecting the central body of

the robot and the rubber tracks need to shortened or enlarged, making the robot suited for operation in

any type of riser diameter.

Since all the parts of the 2nd

prototype were all developed by INSFOR, several tests were performed in

order to ensure the proper durability of the prototype. Stress and fatigue tests were made on the

tracks and on the arms connecting the central body and tracks. Furthermore, one of the big problems

on the first prototype was the wear of the motor gears. 3 sets of gears, made from different materials

(Polylactic Acid, Nylon and Steel), were tested to in order to check their wear during normal operation.

The test concluded that the nylon gears still suffered some wear during operation, while the steel

gears were fully suited for this application. However due to the high cost associated with the steel

gears, it was not feasible to use them in the robots. Consequently it was decided to use nylon gears,

while printing substitute parts for future replacement.

Three robots were produced and are currently operating on the P-55 platform, Iracema and Pre-Salt

fields, all operated by Petrobras

Figure 3.18: Range of operability of the second prototype

Figure 3.19: Motor gears printed in Nylon and Steel

47

3.3.3. Battery Pack Controler

This project was developed in a partnership between TR Subsea and GIGA. One of the equipments

TR Subsea outsources to O&G companies are acoustic transponders which are used in Long-baseline

systems (LBL), a class of underwater acoustic positioning systems. LBL systems use a network of

acoustic transponders installed on the seabed, widely spaced over the area to be covered. Their

position must be accurately determined prior to using the system. The position of the moving object

that needs to be located is deduced from the travel times of the signals received from each

transponder. Measurement of the absolute durations requires a system of interrogation of

transponders by the moving object. After calibration, long-baseline systems can yield localisation

accuracies of around a meter.

One of the most common applications of this technology in the O&G industry is the exact positioning

of the drill strings on the location referenced by the seismic surveys. It is also used to monitor the

exact ROV position while it is operating.

TR Subsea deals with all the logistics associated with these systems, such as the leasing of these

systems to O&G companies, all the maintenance (replacing the batteries of the transponders) and

repair, when needed.

Before this project, TR Subsea used to buy the acoustic transponders sets, which include the

transponders’ batteries, a battery pack controller and the transponder, from an UK-based-company

called Sonardyne. Since the whole set is imported, a large portion of the total cost comes from the

batteries. Initially, one of the alternatives TR Subsea sought to decrease the cost was to only buy the

battery pack controller and the transponder from Sonardyne, while buying the batteries in Brazil,

hence reducing the set’s cost. Sonardyne, however, only sells the battery pack controller with the

batteries, since it would as they are assembled together in the factory. It sells, however, the

transponder separately. Consequently, TR Subsea developed this partnership with GIGA in order to

develop a similar battery pack controller to the one sold by Sonardyne.

Figure 3.20: An example of a LBL system

48

Sonardyne’s battery controller has the following architecture:

A pined circuit board of 12” by 0.785”;

1 15V module for connecting the battery packs (a total of 10 packs, connected in parallel, can

be connected). Two different types of battery packs can be connected:

o 4 lithium 3.75V batteries connected in series, performing a total output of 15V;

o 10 alkaline 1.5V batteries connected in series, performing a total output of 15V;

2 shunts (1 ohm each) connect in parallel (making a total resistance of 0.5 ohms) to measure

the current passing in the circuit;

A polyswitch (resettable fuse), to protect the circuit against overcurrent faults;

A smart battery monitor integrated circuit, which communicates with the transponder via 1-wire

protocol.

This project was divided in two parts: the development of the hardware and, after that, the

development of a desktop software application to program the battery pack controllers.

Figure 3.21: Battery pack controller and battery set sold by Sonardyne

49

Since the system had to be fully compatible with Sonardyne’s transponder, this project started as a

reverse engineering of the one of Sonardyne’s battery pack controller. The first step was to design the

whole system’s architecture. This step was followed by the fabrication of hardware prototypes in order

to check if the system was could fulfil all the design requirements. Since this is a two-layer board, the

machine nº 3 (the multilayer press) was not used. After producing and testing a first prototype, GIGA’s

team found a design error that had to be corrected. After some modifications, a second fully functional

prototype was produced. Thanks to the digital fabrication capabilities installed in GIGA, the whole

process of development had the duration of 1 month.

After the hardware was fully functional, the software was developed. To use the software, the user

needs to connect the battery pack controller to the computer. The software allows the user to read

information about the batteries, such as how many energy has been used and its temperature.

Furthermore, when connecting new batteries in the system, the user can reprogram the chip, by

resetting its counters and informing what type of batteries are installed (alkaline or lithium).

On February 2015 the whole system (hardware+software) was delivered to TR Subsea in order to test

it in real conditions. If some problems are found, the system will be returned to GIGA for

hardware/software modifications. Otherwise, TR Subsea will start to mass manufacture it.

3.4. Summary

The main goal of the digital manufacturing project was to install manufacturing capabilities in R&D

centres so they could attend the demand of the Brazilian industry. So far this project has been

generating positive results. Besides the three projects studied here, more than 20 different projects

have already been developed since the digital manufacturing project started, most of which were only

proof of concept. FMC Technologies Brazil has also been using the facilities to develop mock-ups for

new equipment concepts, such as X-trees and manifolds. Based on the projects studied and the

interviews made, the main benefit manufacturing technique currently brings is the reduction of the

product development cycle, as new solutions can be tested and modified in a matter of hours.

Figure 3.22: Battery pack controller developed by GIGA

50

4. Conclusions

Changes in the Brazilian social and economic context, brought about by the falling oil prices, the

economic recession and the institutional corruption, brings new and unexpected risks that must be

assessed. The investment strategy previously defined by Petrobras is now inadequate, as the

company is adapting to the present reality, mainly by reducing future investments. This re-adjustment

has a significant impact on the Brazilian industry, which is, to a certain level, dependent on Petrobras.

This high uncertainty scenario, with various possible sets of interactions and cascading effects, makes

Brazil’s future unpredictable.

The critical issue that arises today in Brazil is, on the one hand, to reduce its annual oil output until oil

prices start to rise, focusing efforts on the development of endogenous capacity, or, on the other hand,

keep increasing its production while buying technology from foreign companies and not developing its

own industry.

The increase in Brazil’s annual oil production, verified in the past decade, was accomplished by

buying most of the necessary technology from foreign companies. This caused a great dependency

from foreign technology, as Brazil’s policies did not foster the development of its own industry to meet

its technological demand.

Figure 4.1: Brazil’s annual oil output in the last decade (Energy Information Administration)

The study of the three subsea projects showed that the subsea development strategy pursued by

Petrobras can be considered to be somewhere in between an incremental and a disruptive one. Some

of the solutions used in these projects were not new, where others led to the development and

qualification of new technologies for subsea environments.

In the case of subsea boosting technologies, the Helico-axial concept was chosen for both projects, a

technology that has a long track record of successful application in subsea environments.

Furthermore, the biggest technological challenge, while developing the Barracuda Multiphase Helico-

Axial pump, was reducing the axial loads on the bearings. The adopted solution was to re-qualify, for

multiphase pumps, a very common solution used in monophase pumps and gas compressors, the

2

2,1

2,2

2,3

2,4

2,5

2,6

2,7

2,8

2,9

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2006 2007 2008 2009 2010 2011 2012 2013 2014

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nd

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ay

Brazil Total Oil Production

51

balance piston. In the case of subsea boosting technologies, it can be concluded that Petrobras opted

for a more incremental technological trajectory.

For subsea separation, the adopted strategy had a more pioneering character than the one adopted

for subsea boosting. Previous projects developed in this area, such as the Troll and Tordis, used

conventional gravity separators. These types of separators were not feasible, due to the water depth

of the installation site (870m) of Marlim’s 3-Phase Subsea Oil and Water Separation. This forced all

the involved actors to adopt new technologies not yet used anywhere, leading to the qualification of a

new technology to be used in subsea environments, the inline Pipe-Separator. Furthermore, since the

separated water is injected in the producing reservoir, the water quality, relating to oil and sediment

content after separation, as to go through a very strict process of quality control, in order to avoid loss

of injectivity. This also fomented the development of new technologies, such as new sensors to

monitor the oil in water content of the separated water and new control logic for subsea applications,

which will be valuable and will serve as a new technological basis for future projects in this area.

The adopted strategy for subsea boosting, on the one hand, decreases both risks and costs, but, on

the other hand, only achieves incremental benefits. The one adopted for subsea separation is a more

challenging one, requiring massive investments in R&D and a great efficiency in communicating and

managing all the involved parties. This is a sign of the great importance this specific area has towards

Petrobras’s future. In 2012, Petrobras started a new project, the compact SSAO, which aims to qualify

new types of compact separators to be used in deeper waters. Equipments such as hydrocyclones,

low shear valves, gas-liquid compact separation oil in water monitoring sensors and electrostatic

coalescer separators are all being current qualified for new applications in deep-waters (Albuquerque

& al., 2013). Moreover, Petrobras is also implementing R&D projects to evaluate and qualify subsea

high differential pressure multiphase pumps as well as developing new technologies to optimize the

use of multiphase pumps in its environments. Although there are technological constraints that were

not assessed in this analysis, such as electrical energy generation and transmission, it is clear that the

concept of the subsea factory is being pursued by Petrobras, as their efforts have been to qualify

existing topside equipment for subsea environments and increasing tie-back distances.

The main goal of the digital manufacturing project was to install manufacturing capabilities in R&D

centres so they could attend the demand of the Brazilian industry. In contrast to the current

industrialization paradigm in Brazil, which makes Petrobras the big responsible for the industrialization

in Brazil, forcing the oil company to buy equipment from Brazilian companies, this project aims to give

the necessary tools, for the development of new projects, to R&D centres and universities. Moreover,

it is focused on a new manufacturing technique which will have a big impact on the O&G industry,

digital manufacturing. For this reason, the installation of this cluster of machines in PUC-Rio and INT

is also very beneficial for the proper qualification of human resources, which are learning how to use

this manufacturing technique effectively. This bottom-up approach is starting to bring some

competences to the Brazilian industry, particularly fomenting the development of small projects in

start-ups or university spin-offs. From the three projects studied one can see how beneficial this

technology was for small Brazilian companies. Not only is the product development cycle greatly

shortened, as PUC-Rio is able to develop final prototypes in a matter of weeks, as for example the

52

Modular System for Weld Analysis, but the final cost of the part is also reduced. Furthermore, this

project also brings indirect benefits to the rest of the industry. For example, the development of the

Battery Pack Controler created new opportunities for the battery manufacturing facilities in Brazil, as

starting from now, TR Subsea will start to buy batteries from Brazilian suppliers instead of buying them

from Sonardyne. Although this technology can only attend to a small niche of the Brazilian O&G

industry, mainly helping the development of small and traditional projects, and it is still not cost

competitive when comparing it to traditional manufacturing techniques, the benefits it brings, not only

for the industry, but also for the qualification of human resources, cannot be overlooked.

On April 22nd

2015, Petrobras reported a net loss of R$21.6 billion, R$6.2 billion of which were directly

related to the corruption probe. This will force Petrobras to cut their investment strategy aimed at

developing offshore fields, since in the short term the company is focused on its financial survival.

Petrobras also announced it would cut its 2015 capital spending to $29 billion, 34% below the planned

average for each of the next five years and also cut spending by another 13% to $25 billion in 2016.

Innovative projects, such as the ones studied here, are also expected to be postponed until more

friendly scenarios arrive. These projects require long technological qualification programs, qualified

human resources, which Brazil currently lacks, and massive investments, which Petrobras cannot

afford now. Moreover, industrial policies, such as the local content, are not the most beneficial in this

scenario either, since it forces operators to use national suppliers, raising equipment costs. Hence, a

reduction in Petrobras’s demand for new and innovative equipment is expected, and, consequently,

Brazil’s oil production. This reduction in Brazil’s oil production is not expected to be a dramatic one

though, since the country’s economy still depends significantly on its oil exports. Despite its negative

consequences, this scenario can also be beneficial for the Brazilian industry. Due to the internal

restructuration period in Petrobras, it is not expected that the company pursue any big innovative

project in the two years. This gives the opportunity to local companies and institutions to prepare

themselves and narrow their technological gap and lack of human resources until Petrobras decides to

increase their oil output and start exploring new oil fields.

53

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A. Interviewed Specialists

Interviewed Person Company/Institution

Carlos Camerini ONIP

Felipe Gouvea ONIP

Elias Ramos de Souza ANP

Tathiany Moreira ANP

Daniel Camerini Ativatec

António Neves TR Subsea

Francisco Martins INT

Guilherme Lorenzoni NEXT/PUC-Rio

Flávio Carvalho NEXT/PUC-Rio

Julio Guedes INSFOR

Caio Mehlem GIGA/PUC-Rio

Allan Albuquerque ITUC/PUC-Rio

Fernanda Povoleri Technip

Cristiano Silva Technip

Tor Berge S. Gjersvik FMC Technologies

Artur Costa CEiiA

Table A.1: List of interviewed specialists

the development of new submarine and offshore technologies ... · brazil, are generating major...

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