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______________________________1 D.Sc, Senior Engineer Det Norske Veritas, DNV Rio de Janeiro, Brazil2 M.Sc, Principal Engineer Det Norske Veritas, DNV Rio de Janeiro, Brazil3 D.Sc, Principal Engineer Det Norske Veritas, DNV Rio de Janeiro, Brazil4

D.Sc, Customer Service Manager Det Norske Veritas, DNV Rio de Janeiro, Brazil

IBP1163_11

CHALLENGES ON DESIGNING PIPELINES FOR THE BRAZILIAN

PRE-SALT SCENARIOS

Danilo Machado L. da Silva1, Helio Alves de Souza Jr.

2

Lus Alberto DAngelo Aguiar3,Ana Paula F. de Souza

4

Copyright 2011, Brazilian Petroleum, Gas and Biofuels Institute - IBPThis Technical Paper was prepared for presentation at the Rio Pipeline Conference & Exposition 2011, held between September,

20-22, 2011, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event. The

material as it is presented, does not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute opinion or that of its

Members or Representatives. Authors consent to the publication of this Technical Paper in the Rio Pipeline Conference &

Exposition 2011.

Abstract

Over the years, new discovers and associated technical challenges have spawned significant research and

development efforts in a broad range of areas, in order to improve efficiency and reliability, and also to keep the risksassociated with the new scenarios in an accepted range. Some aspect that can be mentioned include, for instance,

improvements in line grade steels and innovations in the manufacture of tubular products; development of several

pipeline installation methods and lay-vessels; establishment of the mechanical behavior and the expected failure modes

of concern of long pipelines under various loads; investigation of new issues in fluid-structure and soil-structure

interactions, corrosion, welding, fatigue, integrity management philosophy, and many others.

Many of the issues mentioned have been brought about by the demands of the new frontiers, where the operating

conditions and the environmental parameters may lead to the introduction of new risks and situations not fully covered

in established standards and design codes.

Therefore, the objective of this work is to present and discuss the unique design needs and challenges related to the

offshore pipelines to be designed and installed on the Brazilian Pre-Salt fields. The paper presents and discusses, for

instance, aspects related to materials, design criteria, installation issues, and an approach for the evaluation and

qualification of new technologies.

1 IntroductionThe objective of an offshore pipeline is to transport a medium from one location to another. Several parameters,

including economic, technical, environmental issues, determine whether or not a pipeline system should be installed.

The solution may not rely only on the assessments of cost estimates and transportation requirements. Decisions may also

be influenced by technically less tangible aspects such as societal expectations of security of supply, requiring sufficient

redundancy in pipeline networks, or the political objectives of opening up new oil or gas provinces for economic or

strategic reasons.

The bases for design consist of the basic requirements to functionality, as well as a description of the environment

into which the pipeline will be placed, leading to the selection of pipeline dimension and routing. A large number of

requirements may be included in the bases for design. These comprise the physical pipe properties, such as diameter,

steel grade options and linepipe specification details, including supplementary requirements to codes and guidelines.

Significant also is the definition of parameters regarding flow assurance and pressure containment, i.e. design

temperature and pressure, maximum and minimum operating temperature, maximum operating pressure, and details of

incidental operation. Other factors include corrosion allowance, sweet or sour service, pipeline protection principles,

and possibly a number of design philosophy statements, where the use of proven technology or new technologies

qualification are necessary. It should be noted that even with a fair degree of certainty concerning these requirements,

the determination of basic design parameters can imply considerable engineering, especially in deep and ultra deep

waters.

Nowadays, the global trend is an increasing need for oil and gas. As the easily recoverable fields have been already

developed, the trend in the offshore oil and gas industry is going deeper into the more challenging outlook. The

Brazilian pre-salt reservoirs are a typical example with ultra deep waters and highly corrosive fluid requiring highly

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tailor-made and optimized design solutions. This unprecedented need for energy demand, driving the oil & gas industry

constantly into deeper waters and more hostile environments in search for recoverable resources, generates a need for

new pipelines, and the challenge for the pipeline engineers have always been to come up with methods and equipment to

meet such needs.

The offshore pipeline technology is constantly evolving to keep up with the advances to locate and retrieve oil and

gas resources in deeper waters. Hence, the main drive in the offshore pipeline industry today concerns installing pipes at

deep and ultra deep water depths. Of course, the perception of deep water changed significantly during the last two

decades. In the beginning of the nineties, 300m water depth was considered deep. Nowadays, laying pipe in water

depths of 1500m is common practice.

The increasing water depth and pipelines diameter brought many challenges and sometimes no existing vessels

could lay the pipelines without major upgrading or modification. In this context, the knowledge of necessary installation

capacity for laying a particular pipeline is a critical factor when planning offshore pipeline projects. The trend in early

involvement of operators in installation analysis is more important in deepwater projects to remove any potential risks

(Choi, 1999).

The discovery of the Brazilian pre-salt fields has brought many challenges. The oil found in this area is at depths

that exceed 5000m, under an extensive layer of salt. Reaching this oil and bring it to the platforms are tasks that require

knowledge and technology. Brazil is one of the pioneers country in deep drilling, with decades of experience in the

operation of the offshore fields.

The deepwater experience acquired during the last 15 years and the current technological developments shallprovide the conditions to make possible, cost-effective & environment-safe the production in 3000 meters WD. Pre-Salt

Province brings new technological challenges that will require joint effort from operators, equipment suppliers, service

companies and research institutes, in order to develop robust and cost effective solutions.

The objective of this work is to present and discuss some design needs and challenges related to the offshore

pipelines to be designed and installed on the Brazilian Pre-Salt fields. The further sections of this work will present and

discuss aspects related to materials, design criteria, installation issues, and an approach for the evaluation and

qualification of new technologies.

2 Brazilian Pre-Salt Scenario Pipeline ChallengesThe Brazilian pre-salt refers to a cluster of rocks located off the Brazilian coast, between the states of Santa

Catarina and Esprito Santo, with the potential to generate and accumulate oil under a layer of salt found in ultra-deep

waters. This layer is not distributed uniformly and, in the Santos Basin, for example, can be as much as 2000 m thick.These reserves are located nearly 300 km off the coast. As a result, future platforms will be three times further

away from the coast than those that are currently installed at the offshore fields of the Campus Basin (state of Rio de

Janeiro).

General Pipeline Challenges includes development of new materials with better combination of high strength

weld ability - ductility, efficient thermal insulation material, efficient internal coating to reduce corrosion degradation

and friction factor for long distance pipelines, improvement of welding issues, new and modified installation methods

and the increase of vessel capability, an efficient integrity management, logistics for construction, ultra water deephs up

to 3000m; extreme meteocean conditions, presence of contaminants (CO2, H2S) and large diameters pipes.

All these challenges need to be overcome keeping in mind that the overall safety concern for an offshore pipeline is

to ensure, especially in the design phase, that during both construction and operation of the system there is a low

probability of damage to the pipeline, or to detrimental impact on third parties, including the environment.

3 MaterialThe pre-salt reservoirs recently explored in Brazillian offshore areas present some characteristics that can result in

the need for special solutions for material selection, not only in terms of intrinsic material conditions to respond to the

high static and dynamic loads, but also concerning interactions between material and environment. The combination of

high water depth, high well depth below sea bottom, special reservoir mechanical behaviour and the expected presence

of corrosive contaminants make the pre-salt reservoirs a challenge in terms of material selection in all phases of the

production development. In the following sections some of these challenges regarding pipelines design are discussed.

3.1 High Strength Pipeline SteelsPipelines for deep and ultra deep waters have been specified with high strength steels due to the high loads

impaired during installation and operation and the need for less weight for installation. Additionally, the use of moderate

grade steels in some cases may result in D/t ratio values for which some design direct calculations do not apply.

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The main issues regarding high strength materials for pipelines are related to material toughness and resistance to

cracking due to the presence of hydrogen and sulphides. It is known that toughness is reduced with increase in hardness,

but that effect can be (and must be) reduced with the use of microstructure control combined with thermal and thermal-

mechanic treatments. The most critical situation for high strength pipeline steels is the specification of this material for

sour service in high pressures (see next topic). This situation has been mentioned in one project development in the Gulf

of Mexico (Burk, 2010), and extensive qualification was indicated at that time as required, mainly considering the new

regulations to be implemented in that region. It must be noted that standards for sour service materials, like ISO 15156,

do not include the higher grades of pipeline high strength steels (HSS), and hence qualification is required in those

cases.

For pre-salt conditions, the presence of CO2 can be a critical point for the use of high strength steels, because of a

higher risk of failure due to internal corrosion, as the use of HSS allow the specification of thinner walls (e.g. less than

12mm). In those conditions it is recommended to perform a detailed corrosion assessment during early design in order to

assure that an appropriate corrosion allowance and corrosion mitigation actions are previously defined.

For pre-salt, the depths and pressures involved require the use of HSS in pipelines and risers, so challenges are

foreseen regarding fabrication, quality control (as more strict requirements apply), qualification (mainly for sour service)

and the assessment of corrosion related issues based on detailed reservoir fluids data, not always available.

3.2 Sour ServiceAs already mentioned, pre-salt reservoirs may contain H2S, and this contaminant can be produced together with the

oil and gas. It is known that sour environments can cause catastrophic failures due to mechanisms like Stress Corrosion

Cracking and Hydrogen Induced Cracking (stress oriented or not). Although H2S scavenging through chemical injection

in wells is foreseen (Beltro et al, 2009), it may be recommended to specify sour resistance materials for gathering lines,

both rigid and flexible. For rigid lines, the challenges for the use of HSS have been mentioned. For flexible pipes, the

great mobility of hydrogen can permit the embrittlement of amour steels, so specification of flexible pipes for H 2S

service is also important if this contaminant can be present. Another important issue is fatigue resistance of the flexible

riser in the presence of H2S. Considering the possibility of a reduced efficiency of the H2S scavenger, some amount of

hydrogen can reach the armors in a critical region for fatigue, and that will have to be accounted for in the qualification

of the flexible riser.

Regarding rigid lines, if materials accepted by ISO 15156 are specified, no major challenge will apply, if the

standard requirements are followed. The specification of high strength steels not covered by usual standards and codes,

as described in section 3.1, must be very well analyzed and documented, as different mechanisms can occur.

3.3 CO2 Corrosion Resistant AlloysUnlike sour corrosion, CO2 corrosion, also called sweet corrosion, cause metal loss that can be in many cases

visually observed and measured, if access is permitted. The corrosion cause thinning and loss of containment capacity in

pressurized components, like in a pipeline or riser. Pre-salt conditions in Brazilian offshore coast have indicated the

presence of CO2 in high amounts, like 8-12% for Tupi field (Beltro et al, 2009). With this amount of CO 2 and in high

pressures it can be expected a low pH, sufficient to cause general and/or localized corrosion in carbon steels. The use of

corrosion inhibitor is one of the solutions that can be implemented, but the efficiency will depend on many other factors

and will have to be evaluated case by case. In most severe applications corrosion resistant alloys (CRA) can be

necessary.

The use of CRA in subsea pipelines and risers is covered by design codes. First challenges for these materials

relate to availability and price. For long flowlines and deep risers the use of CRA may be economically unfeasible.Besides that, technical aspects can be critical as well, as for instance, welding problems. BP has faced significant

challenges with dissimilar weldings when using CRA together with low allow and carbon steels (Burk, 2010), including

cracking occurrences.

Another issue regarding the use of CRA in subsea applications regards to the hydrogen embritllement resulting

from the cathodic protection. Guidelines to prevent cracking caused by this mechanism have to be followed (DNV-RP-

F112, 2008), and extensive qualification is recommended.

The use of CRA as clad and liner for flowlines and risers have been mentioned as an option for the pre-salt

developments (Burk, 2010). In addition to commercial and economic issues associated with this option, some limitations

need to be considered. Many of those limitations are related to uncertainties from different application of clad pipes,

which have been studied in joint industry projects (DNV, 2007). One main issue to be considered is fatigue resistance.

For lined risers, the use of weld overlay in the pipe ends, where girth weld is performed, can create a region with

different fatigue behavior, which needs to be carefully evaluated. The same applies to the use of partial clad in critical

fatigue areas, an option that has been mentioned for the pre-salt development (Beltro et al, 2009; Simpson et al, 2007).The presence of a galvanic cell in the riser, even in a non critical fatigue region, can be detrimental to the point of

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reducing local pressure containment capacity and allowing rapid nucleation and propagation of fatigue cracks. The use

of partial cladding must be based on extensive testing covering a large range of conditions, considering possible changes

in fluid composition and treatment efficiencies. The use of corrosion inhibitors can be beneficial for reducing the

galvanic effect of the material transition, but this requires that the environment is very well known, and the inhibition

efficiency can be established based on these conditions, and monitored during operation. Integrity monitoring of those

transition points is a main challenge, due to access limitations. A permanent installed monitoring device could be

considered for these locations.

3.4 Cathodic Protection of Deepwater RisersCathodic protection of risers didnt present main challenges related to the efficiency of galvanic systems, until the

need to design and operate deep and ultra deepwater risers. In order to avoid detrimental effects on riser fatigue,

installation of anodes is not recommended in the riser sections. Hence, it has been usual to install anodes in subsea

structures located in riser terminations. These include subsea templates, riser bases and dedicated structures (sledges)

with cable connection to the riser or pipeline. The long distance to be protected in case of deep and ultradeep risers is

something to be considered carefully in the design phase, as interferences can occur. During the design, attenuation

checks are mandatory when spacing between anodes exceed the recommendation of the design codes. Additionally,

anodes installed too close form each other in clusters can cause shielding effects, reducing the useful current output. The

use of anode sledges connected by cable and clamping systems can result in high voltage drop in the electrical

connection, with impact on the current output and also on the protection length of the anodes along the pipeline.

Another issue related to cathodic protection and that needs also to be addressed is hydrogen embrittlement of high

strength components. The use of sophisticated components in subsea installations with different materials can increase

susceptibility to this mechanism, so usual prevention measures shall be followed (DNV-RP-B401, 2010).

4 Deep Water Pipeline Installation IssuesThe main objective of the pipelaying operation is to position the pipeline along a predefined path on the seabed

only by means of controlling the pipelay vessel position, while at all times ensuring the structural integrity of the pipe. In

other words, the pipelay operation consists of controlling the pipe deformation from the vessel to the seabed, the pipelay

vessel motion, and position and motion control of the pipe touchdown point at the seabed.

The primary objective of a pipelay operation is thus to position the touchdown point as close as possible to the

reference path on the seabed. A secondary objective can then be to move the touchdown point at a desired speed alongthis path. These two objectives must be satisfied such that the structural integrity of the pipe is ensured.

Of course, the field layout selected for a particular offshore development has a significant influence on the

pipelines and in particular the installation techniques. In deep water fields, which are dominated by subsea wells, the

field layout tends to be very different from those selected for more conventional water depths. In the past, pipelines

tended to be relatively simple inter-platform links or links between the field and the shore. Now in deep water designs,

the flowlines tend to be much more complex, with the need for end termination structures and several midline structures

including valves and tees to facilitate tie-in of additional wells into the main flowline systems. These structures can be

relatively large and need to be installed together with the pipelines, greatly influencing the complexity of the offshore

pipelay operations (Perinet, 2007).

The inclusion of all these subsea structures (PLEM, PLET, midline tee, etc) into pipelines has been a major feature

in new pipeline systems in recent years. As a result pipeline installation operations are no longer a pure pipelay activity

but also involve the handling and lowering of these structures which is becoming a major part of the operation.

Consequently, the overall efficiency and feasibility of pipelay operations is not simply related to the rate at which thevessel can lay pipe, but a combination of the lay rate together with the efficiency of the vessel to install structures as part

of the pipeline. And then all currently available pipelay techniques have a place in the deep water market, with no one

dominating the complete picture (Perinet, 2007).

A number of challenges arose in relation to availability of equipment within the region and logistics to support the

deepwater construction operations. It is critical that at project commencement a thorough evaluation of selected vessels

and major installation equipment items, such as flowline and riser lay systems, is conducted to determine if they are

adequate when all contributing factors such as dynamic loading, contingency requirements and spare equipment are

taken into account. Large construction vessels primarily used to install pipelines, risers and mooring systems are

generally extensively booked up a number of years in advance and have limited windows of availability. The

requirement for such a vessel, or major item of equipment such as a large capacity heave compensated winch, if not

identified and confirmed at the tender stage, needs to be confirmed and ordered very early in the project life cycle as

restricted availability may impact the project schedule.

As more offshore pipelines are installed in increasingly deepwater, many specialized design and installation

problems have to be solved to meet the new challenges. The solutions adopted during the design stage of a pipeline

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system can greatly influence the techniques available for installation. Major impacts come from insulation, midline and

end structures, internal corrosion protection and fatigue.

The pipe-in-pipe system, for instance, can provide a higher level of thermal insulation than wet insulation coatings,however the resulting pipeline is very much heavier which has a large impact on the pipelay and on the in place

behavior of the pipeline. For example in the case of S-Lay, the required laying tension and the loads on the stinger

will be very much higher in the case of pipe-in-pipe. The influence on the in place behavior of the pipeline is somewhat more complex as it is influenced by many other

factors. For example in the case of a short line, the thermal effects can be mitigated with a low axial friction which

does not mobilize high axial compression, giving an advantage to a lighter pipe with wet insulation coating.

However in the case of pressure driven effects, the heavy pipe provided by the pipe-in-pipe system can provide

mitigating effects. As stated previously, the inclusion of subsea structures will have a significant influence on both

the pipeline installation techniques and the in place behavior of the pipeline. The structures should be designed

with both the in place functionality and the installation in mind. Large, heavy, bulky structures can be very difficult

to install inducing high static and dynamic loads in the pipelay system. Consideration of installation during the

design phase can help in reducing these loads. The subsea structures will also affect the in place behavior of the

pipeline by providing restraints for the axial displacement.

As a result of the number and size of structures included within the pipeline system it is essential that theinstallation of the pipelines is considered at an early stage in the field development. As far as possible the

structures should be designed to provide as little impact as possible on the pipelay activities. However the reality is

that the structures will significantly increase the amount of time required to lay the pipeline and this must be taken

into account when selecting the pipelay technique to be used.

The methods for corrosion protection can also influence the installation techniques. In the case of highly corrosivefluids it may be necessary to select a corrosion resistant alloy (CRA) material for the line pipe. This can be in the

form of a solid CRA pipe or a clad pipe. Both of these materials can prove difficult to weld and as a result the

installation could be more efficient using a reeled solution where all of the welding is performed onshore.

The fatigue resistance of deep water pipeline is now a major issue for pipeline installation, which influences therequirements for weld quality and inspection.

Another very important engineering activity, which can have a significant influence on the overall cost for the

installation and operation of a pipeline system, is the definition of the pipeline route:

The pipeline route selection should be performed to give the economically optimal solution for the pipeline owner.This comprises the costs of fabrication, installation, operation and decommissioning. Normally the most cost

effective solution will be the shortest possible route. However, different features along the pipeline route, such as

severe seabed conditions, environmentally sensitive areas, and existing facilities for oil/gas production, may force

the pipeline away from the most direct route.

Detailed route selection should be performed to reduce the number of free spans, and consequently the number ofpipeline supports, in particular in areas with extremely uneven seabed.

4.1 Pipeline Installation MethodsIt should be highlighted that, over the years, cost reduction has been a major driving force in the pipelaying market.

The key factor to competitive pipelaying was the welding performance. The three methods that dominates installation of

long pipelines today are S-lay, J-lay, and reeling.

Keeping the pipe under tension to maintain the bending and axial stresses within an acceptable range is a keyconcept to all these installation methods. Through continually controlling the tension on the pipeline being laid,

excessive bending and kinking of the pipeline is avoided without the necessity of extensive support structures or buoyant

support means, which would not be feasible for deep waters.

Each installation method has specific advantages and the choice of equipment is determined primarily by pricing

policy. On small diameter lines of limited length, reeling is very competitive. J-lay has clear advantages when combining

heavy-lift work with SCR installation and can be attractive for heavy, short lines. S-lay is fast and economical, and

dominates the market for deepwater pipeline installation. It can deal with SCRs and in-line structures, and can avoid

their rotation equally well as the other pipelay methods. By carrying out the required equipment upgrades, the current

trends in deeper water pipeline systems can be accommodated by the S-lay installation method.

S-Lay

The main advantage with the S-lay method is that the long firing line, running from bow to stern, enables parallel

workstations for assembly of pipe joints, such that up to four pipe joints can be added at the time. This makes the

method fast and economical, particularly for long pipelines. However, for large water depths, the pipe must be supported

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to a near vertical departure angle, which requires a very large stinger to avoid damaging the pipe. The major

disadvantage of the S-Lay is the difficulty of installing midline and end structures with the pipeline.

J-Lay

The J-Lay method involves welding the pipeline together from a series of joints in the vertical position where the

welding necessary work is concentrated into one workstation. The most common way of dealing with this is by

increasing the length of the stalk, which is welded into the pipeline in the vertical position. This can be anything from

double joints of pipe, which are preassembled before loading into the vertical welding location to up to six joints of

preassembled pipes.

J-lay has many advantages. The pipe leaves the barge steeply such that the total length of the free pipe is shortened

and less applied tension is required for sagbend control. The touchdown point is not as far behind the vessel as for S-lay,

due to the lower applied tension, so that positioning of the touchdown is easier, and the pipe can be installed more

accurately. Also the complexity involved with a stinger is eliminated. The main drawback with the method is that the

tower only facilitates one workstation, making the J-lay method inherently slower than the S-lay method.

Steep S

The overall lay rate for the J-Lay vessels obviously increase with the stalk length, however this laying rate remains

reduced. The alternative is to extend the S-Lay method which has been developed over many years into a very efficient

system for laying pipelines involving multiple work stations, consequently increasing the lay rate compare to J-Lay.

With S-Lay all of the welding is performed with the pipes in the horizontal position, consequently it is necessary to

support the pipe using a stinger structure beneath the lay barge as it is transformed from the horizontal into the verticalplane. The main issue with S-Lay is its ability to lay pipe in deep water. This can be achieved by adopting a form of

Steep S-Lay by setting the lift off point of the pipe from the stinger as near vertical as possible. However to keep the size

of the stinger to a reasonable size, the curvature has to be increased. However, this will result in higher strains in the

pipe wall in the overbend region.

Different studies have been performed in order to apply the main part of the tension after the over-bend section

with a submerged tensioner. This will lead to lot of advantages by not combining the tension force and bending effect

with impact on strain level and curvature gradient. This could be a potential solution to increase the depth limitations of

S-Lay and Steep S-Lay. However there are some significant challenges to be overcome relating to the reliability of the

mechanical equipment in an underwater environment (Perinet, 2007).

4.2 Pipeline Installation Analysis and DesignThe design and installation of pipelines must comply with established standards, DNV-OS-F101 for instance. The

objective of this standard is to ensure safety, and to specify the minimum requirements to be satisfied by any designer.

To ensure the validity and usability of the standard, the cutting edge research developments and experiences from the

most challenging pipeline projects are reflected in each new revision of this standard. DNV-OS-F101 considers a design

practice based on so-called limit states for the pipeline design. In the limit state design, all relevant failure modes for a

pipe are formulated as limit states, which are classified into one of the four categories:

1. Serviceability Limit State (SLS),

2. Ultimate Limit State (ULS),

3. Fatigue Limit State (FLS),

4. Accidental Limit State (ALS).

The limit state is the limit between an acceptable and unacceptable condition expressed in mathematical terms

derived through design formulas for a given failure mode. The limit state design identifies the different failure modes

and provides specific design checks to ensure structural integrity. The pipeline capacity is then characterized by the

actual capacity of each individual failure mode. For more on limit state design in the DNV-OS-F101, see Mork et al.(1998).

The structural analysis of an offshore pipeline under construction and installation deals with the computation of

deformations, internal forces, and stresses as a result of external loads and the structural properties of the pipe. A short

pipe section, like a single pipe joint appears to behave much like a rigid body, whereas a long pipe of several hundred

meters is very elastic and behaves almost like a string. Hence, the pipe string behavior is highly dependent on the water

depth.

Structural deformation of the pipe during construction depends on the method and equipment used for installation,

the structural properties of the pipe and the environmental loads. Installation of offshore pipelines is to a great extent

weather dependent, and part of the installation engineering analysis comprises the determination of the acceptable limits

(wind speed, wave height, current) for the installation to take place.

Success in reconciling economic design on one hand with demonstrable safety of the pipeline on the other is

dependent on the availability of accurate meteo-marine data. This consideration should be made fundamental to theplanning and execution of all environmental data gathering and analysis.

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The site specific wave conditions may have a significant impact on pipeline projects, technically as well as cost-

wise. The wave conditions influence the pipeline installation method, the choice of pipelay vessel, and the feasible

installation period.

5 Qualification of New TechnologiesThe new challenges described in this work will certainly drive the industry to the development of more complex

systems in which new technologies will be considered. In this scenario, safety, confidently and long time operations

without intervention are some of the main principles to take into account.

The decision to use a brand new technology can be very difficult, particularly for high cost projects. The project

team needs to be confident that a technology can be implemented successfully and will perform as designed. The project

management team, in general, is reluctant to use the first version of a technology in its design, even when the new

technology is critical to the industry. That occurs because, in general, a new technology is not adequately covered by

established codes and procedures. It must therefore be qualified by following a systematic process where the required

functionality and reliability is obtained by identifying uncertainties that need to be reduced through adequate

qualification methods such as testing and analyses.

DNV defines Technology Qualification as the process of providing the evidence that the technology will function

within specific limits with an acceptable level of confidence. Confidence in this context is more than just the reliabilityof the technology. It is also about ensuring that the confidence is developed not just with the technology developer but

with the end user as well as the other stakeholders in a project. The commercial value of the new technology is only

realized when the confidence in the technology is developed for all involved parties. While this may seem obvious it is

quite often forgotten in the race to qualify a new technology. Likewise, many big expensive tests have been performed

that demonstrate that the technology can work but not that it will work reliably. Such tests add little value in terms of

developing the confidence in the technology. This is why a systematic approach to technology qualification helps to

reduce costs and improve the confidence in the technology.

For new technology, in particular, it can be noted the lack of relevant codes and standards. Qualification according

functional reliability targets is then the only rational approach.

It is clear that, in technology qualification processes, the technology shall be unambiguously and completely

described, through text, calculation data, drawings and other relevant documents. It is important that the limits of the

technology are stated and that all relevant interfaces are clearly defined. The specification shall identify all phases of the

new technologys life and all relevant main parameters.The specification with the available detail level at each phase of the development process is the input to the

qualification process. The specification and functional requirements shall be quantitative and complete. Note that these

requirements must have been agreed upon by all relevant stakeholders.

Based on the specification, a review/ screening of all possible requirements and limitations to the technology shall

be performed and the functional requirements specified. The critical parameters shall be identified and a critical

parameters list shall be created.

5.1 DNV-RP-A203 Qualification Procedures for New TechnologyDNV has developed a formal risk based technology qualification process with the stated objective of providing a

systematic approach to the qualification of a new technology ensuring that the technology functions reliably within

specified limits. A guideline for such a systematic qualification process is given by DNV-RP-A203, Qualification

Procedure for New Technology and DNV-OSS-410, Technology Qualification Management.It should be noted that the technology qualification process differs from other third party services (such as

classification, certification and verification), which confirm that the technology is documented in compliance with

specified codes and procedures.

The objective of the qualification process is to utilize a systematic approach to document that any technology

development is adhering to the criteria of DNV-RP-A203 as assessed by DNV as an independent body. The role is to

facilitate and give guidance to follow the steps in order to obtain the Certificate of Fitness for Service for the new

technology.

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Figure 1 Qualification Work Process.

At the concept stage the knowledge of the technology is limited, and the uncertainty in service life (or mean time

between failures (MTBF)) is large. The aim of the qualification process is to reduce the uncertainty to an acceptablelevel in order to determine the service life (or MTBF).

Figure 2 Qualification Work Process Main Objective.

For new technology, in particular, there will be little or no generic reliability data available at the concept stage.

The reliability therefore has to be documented by identifying all failure modes of concern and derive the technical

data/knowledge necessary to determine the service life (or MTBF).

Opportunities and possible benefits due to new technology development are many, but uncertainties and lack of

confidence due to limited experience can be better understood in the way to improve reliability. Possibilities can be

foreseen in the industry due to production improvement, cost reduction, equipment life extension, economical viability

etc.

6 Final RemarksThe design and installation of an ultra-deep water pipeline, in particular at the Brazilian Pre-Salt scenario, presents

a long sequence of engineering challenges that have to be successfully completed.

The combination of high water depth, high well depth below sea bottom, special reservoir characteristics and the

expected presence of corrosive contaminants make the pre-salt reservoirs a challenge in terms of material selection.

The main issues regarding high strength materials for pipelines are related to material toughness and resistance to

cracking due mainly to the presence of hydrogen and sulphides.

For pre-salt conditions, the presence of CO2 can be a critical point for the use of high strength carbon manganese

steels, because of a higher risk of failure due to internal corrosion. Pre-salt reservoirs may contain H2S, and this

contaminant can be produced together with the oil and gas. It is known that sour environments can cause catastrophicfailures due to mechanisms like Stress Corrosion Cracking and Hydrogen Induced Cracking. The effects of CO2 and H2S

in the fatigue behavior of risers in the conditions of the Pre-Salt developments shall be analyzed carefully. The use of

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HSS, CRA and clad pipelines will probably require the need for extensive qualification processes to assure the adequate

behavior in the severe operational conditions expected. Special attention shall be addressed to riser fatigue behavior in

internally corrosive environment, and the effectiveness of corrosion inhibition.

Regarding installation method, each one have specific advantages and the choice of equipment is determined

primarily by pricing policy. On small diameter lines of limited length, reeling is very competitive. J-lay has clear

advantages when combining heavy-lift work with SCR installation and can be attractive for heavy, short lines. S-lay is

fast and economical, and dominates the market for deepwater pipeline installation.

Moving into ultra-deep water, transportation of produced fluids is often challenged by a number of factors that

affect operational process economically and increase environment and safety risk, mainly when conventional

technological solutions are used. As discussed in this work for the Brazilian Pre-Salt scenarios, where risks related to

pipelines and subsea system leads to new technological solutions for which reliability is therefore significant and need to

be fully understood.

7 ReferencesBeltro, R.L.C. et al, 2009, Challenges and new technologies for the development of the pre-salt cluster, Santos Basin,

Brazil, OTC - Offshore Technology Conference, paper 19880, Houston , TX, USA.

Borelli, A.J., Perinet, D., J-Lay and Steep S-Lay : What Future for Conventional Pipelay Barges ?, Offshore

Technology Conference, OTC 8562, Houston, 1997.Brooks, J., Cook, E.L., Hoose, J., Installation of the Mardis Gras Pipeline Transportation System, Offshore

Technology Conference, OTC 16638, Houston, 2004.

Burk, D.J., Ribardo, C.L., 2010, Thunder Horse Materials, Welding and Corrosion Challenges and Solutions, OTC -

Offshore Technology Conference, paper 20401, Houston, TX, USA.

Choi, H.S., Jo, H.J., 1999, Characteristics of Ultra-Deepwater Pipelay Analysis, Offshore Technology Conference,

OTC 10710.

Det Norske Veritas, 2007, Guideline for Design and Construction of Clad and Lined Pipelines, Confidential Technical

Report.

DNV-RP-A203, 2001, Qualification Procedures for New Technology ,Det Norske Veritas.

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Veritas, Norway.DNV-OS-F101, 2010, Submarine Pipeline Systems,Det Norske Veritas.

DNV-OSS-410, 2010, Technology Qualification Management, ,Det Norske Veritas.

DNV-RP-B401, 2010, Cathodic protection design,Det Norske Veritas, Norway.

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Murray, G., Lowther, D., Ledingham, A., Stensgaard, T.J., 2008 Kikeh Development: Subsea Equipment Installation

Challenges for Malaysias First Deepwater Development, Offshore Technology Conference, OTC 19637, Houston.

Mrk, K. J., Collberg, L., Bjrnsen, T., 1998, Limit state design in DNV'96 rules for submarine pipeline systems:

Background and project experience, Offshore Technology Conference, OTC 8671.

Perinet, D., Frazer, I., 2007, J-Lay and Steep S-Lay : Complementary Tools for Ultra Deep Water, Offshore

Technology Conference, OTC 18669, Houston.

Perinet, D., Frazer, I., 2008. Strain criteria for deep water pipe laying operations, Offshore Technology Conference,OTC 19329.

Pulici, M., Deep Water Sealines Installation by Using the J-Lay Method the Blue Stream Experience, ISOPE

International Offshore and Polar Engineering Conference, Hawaii, 2003.

Simpson, P.J. et al, 2007, Petrobras P-55 SCR design challenges and technical solutions, ISOPE.

Steenhuis, A., van Norden, T., Regelink, J., Krutzen, M., Modifications to the Pipelay Vessel Solitaire for the

Independence Trail Project, Offshore Technology Conference, OTC 19059, Houston, 2007.

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