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TABLE OF CONTENTS

1 INTRODUCTION .................................................................................................................3

2 OBJECTIVE ..........................................................................................................................3

3 MATERIALS TECHNOLOGY FOR THE OIL AND GAS INDUSTRY .......................4 3.1 Future development..........................................................................................................4 3.2 Concluding remarks .........................................................................................................5 3.3 Recent Materials Technology R&D initiatives ................................................................6

4 COMMON DENOMINATORS FOR INCREASED ROBUSTNESS..............................7 4.1 Management of oil and gas development projects ...........................................................7 4.2 Design ...........................................................................................................................8 4.3 Knowledge gaps ...............................................................................................................9

5 REFERENCES: ...................................................................................................................10

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1 INTRODUCTION Over the last three years the Norwegian Petroleum Directorate (NPD) has expressed some concern about the situation with respect to material selection and safety, triggered by recent experiences in the North Sea. During the period 1996 to 2002, 220 gas leakages (>0.1kg/s) have been reported on the Norwegian shelf /1/. Of the 220 gas leakages, 5 are connected to different types of failures on subsea pipelines, all involving through pipe wall fractures. The consequences of such failures are significant. The total cost (including the loss of income) of the pipeline failures is estimated to some 5-10·109 NOK. The impact on environment and human health and safety has not been significant in these cases. Most of the 220 incidents are smaller topside gas leakages. Luckily none have set on fire. The final product is intended to be a methodology for robust material selection in the oil & gas industry. A pre-project was initiated year 2002 and SINTEF Materials Technology was engaged by NPD for examining relevant internal SINTEF reports, NPD reports and other easily available information. Possible applications of the methodology are indicated in the report of the pre-project /2/: • Drilling equipment • Well completion • Structural materials • Subsea, topside and onshore production and pipeline systems • Flexible risers • Chains and mooring lines for floating units Subsequent to the finish of the pre-project report, a seminar with NPD, the Norwegian University of Technical and Natural science (NTNU) and SINTEF was held in Trondheim in January 2003 to achieve mutual understanding of the objectives of the main project. During this seminar, it was decided that SINTEF should submit a new, more detailed plan for the main project. For 2003 a focussed study on super martensitic stainless steels (S13Cr) pipeline material and flexible risers was requested. These cases were selected based on: • the relative large number of unexpected incidents • significant concequences regarding production down time • complexity of degradation mechanisms • large differences on construction of pipeline and flexible riser In this report a summary of the common denominators are presented. For more details, it is recommended to take a closer look on the part reports produced on flexible risers /3/ and S13Cr steels as pipeline material /4/.

2 OBJECTIVE The objective of the present project is to summarize trends in material selection procedures in larger oil & gas companies. The work is based on the use of existing knowledge in SINTEF, Marintek and NTNU and their industry network. The work has focussed on a combination of industry experience and research experience. The outcome of this project will be used as input to the RMS methodology.

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3 MATERIALS TECHNOLOGY FOR THE OIL AND GAS INDUSTRY Since the first findings of petroleum on the Norwegian Continental Shelf (NCS) back in the 1960s, the oil & gas nation Norway can look back on an impressing technological development which is well recognized internationally. During the last 30 years the oil and gas industry acting in the NCS, have positioned themselves as pioneers in several technological fields. The development of OLGA 1D multiphase flow simulator, a joint SINTEF/IFE product, is one excellent example of how Norwegian expertise made vital contributions to oil and gas transportation technology. Development and safe use of new and more traditional materials is another example. Safe and cost-effective use of materials gives the premises for realization of many other technology-leaps. As an example, deep water development with associated sub-sea intervention can be mentioned. The aggravating focus on increased safety and reliability stimulates research on associated subjects. The safety aspect in the offshore industry acts as a basis for increased profitability, safety and sustainability for future exploitation of our oil and gas resources. Also the judgment of possible environmental impacts is a crucial aspect, especially in the debate of expanding the offshore activities in the northern regions (Lofoten, Barents-sea). Because of our oil and gas industry developed in hostile environments, Norway has paved the way for use of steels (and other materials) under very demanding conditions. Development of materials and fabrication technologies has been followed by development of standards and guidelines for safe implementation. This situation is well recognized internationally, and will from our side in the future be followed up by increased engagement in international standardization communities. SINTEF Materials Technology/NTNU (and IFE in some specific areas) have been significant R&D partners during the above described development period. In the 1970s much attention was given to the development of low-alloyed steels with good welding properties, fracture and fatigue (corrosion-fatigue) resistance. This was followed by the development of hyperbaric (under-water) welding. Development and use of new types of stainless steels, titanium and composites were addressed during the 1980s. The 1990s has been characterized by the development of high-strength steels and corrosion resistant alloys (e.g. supermartensitic 13% Cr stainless steel quality), especially designed for offshore pipelines. The oil and gas installations and infrastructures will need continuously monitoring, upgrading and maintenance, still for many decades ahead. The future challenges with respect to “maintenance-free” sub-sea installations, general deep water solutions with high reliability, and down stream natural gas technology development, are examples which all require new and upgraded competence.

3.1 Future development Since the beginning of the Ekofisk development in the early 1970-ties Norwegian exploitation of oil and gas resources has moved into increasingly harsher environments. There is no indication that this trend will discontinue. The next steps could be fields in water depths of 2000 metes or more, or fields in ice. The past development has shown that new materials are taken into use at a steady rate. S13Cr steel pipelines and flexible risers are examples. For future field developments materials like high strength steels, titanium alloys, composites and advanced polymers may be required for critical components. For “bulk” applications (structures, pipelines, risers/riser towers, mooring systems, etc) the most likely development would be use of more corrosion resistant materials, improved corrosion control, and a gradually increased strength (especially for steels). Use of composites is likely to be somewhat increased where the combination of flexibility, weight reduction and non-corrosive properties are wanted. For metallic materials development of coatings and painting systems has to be improved. The general durability of coatings does have

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improvement potentials, and new products will soon be commercially available (e.g. smart paintings for crack detection). These developments will represent new challenges to the engineering community, with regard to basic material science, degradation mechanisms and safety assessment. In the light of this we think future recruitment, education and competence building will focus on; - improved understanding of fundamental ageing and degradation phenomena - how these mechanisms alter the structural integrity over the lifetime - how these effects can be quantified and be connected to modern risk assessment and lifetime

prediction/assessment methodologies - how this can be communicated via software/computational tools - how this information can be linked to the e-Field1 concepts for real-time monitoring,

operation and decision making support The classical disciplines Structural Engineering & Design, Materials Technology and Risk Assessment, should in the future work much closer and interactively. By stimulating this cross-disciplinary interaction, the challenges related to robust and cost-effective solutions in the oil and gas industries, competitive in an international industry, will be overcome and represent a significant added-value for the industry. There are three trends within Materials Technology and related areas we think will be further emphasized in future development for the oil and gas industry to ensure the most robust solutions; - the development of quantitative structural integrity methodologies/tools (coupling between

structural engineering, materials technology, risk/safety assessment methods) - the development of 3D flow assurance and multiphase flow tools, now going on in SINTEF,

will support further development of computational tools for degradation of materials - the development of nano- and functional materials. Furthermore, these trends and development scenarios could find many potential innovative solutions when coupled with the development in the ICT area, heading for fully integrated and real-time monitoring, control and operation tools within the frame-work of the e-Field concepts. The e-Field conceptual way of thinking should be adopted in the new boost in offshore engineering. Functional materials and smart/intelligent components will probably be introduced along with future development in the oil and gas industry, where censoring and monitoring functions are built-in for control and operation purposes. The e-Field concept also opens for including real-time direct calculations of the consequences of failures (based on physical degradation and crack propagation/resistance models).

3.2 Concluding remarks The situation on the Norwegian Continental Shelf is generally characterized as mature, and the solutions sought for will more and more be tailor-made for tail-production scenarios, and production in more difficult accessible areas (deep waters, long transport). However, there is still expected profitable oil and gas production for more than 30-50 and 70-100 years ahead, respectively. The National (Norwegian) Technology Strategy for Added Value and Competitive Advantage in the Oil and Gas Industry (OG21; see www.og21.org) has recently been established with 1 E-field combines all information in intelligent decision tools to support key work processes for a selected mode of operation

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commitment from all major oil companies operating in the North Sea basin. It is expected that future research and development within the oil and gas area will be consistent with this strategy. The strategy has been established recognizing the need to have a comprehensive and efficient system for research and technology development on a permanent basis in the oil and gas industry in Norway. The motivation is to develop new knowledge and technology to ensure economic and environmentally sound development of the resources on the Norwegian Continental Shelf. However, may even more important will be to ensure technology export on the international marked by developing world-class technology solutions.

3.3 Recent Materials Technology R&D initiatives Several initiatives have lately been undertaken (and are in progress), and some are planned in near future: a) Norwegian-Japanese cooperation on pipeline technology b) OG21 “Positioning Document” for Materials Technology. Included in this work is the

proposal of the establishment of a large R&D program on Structural Integrity. As a background for this document is the comprehensive technology gap studies within the defined Technology Target Areas as defined by OG21:

• Zero harmful discharge to sea • 30% reduction of emissions to the atmosphere • stimulated recovery • cost effective drilling • real-time reservoir management • deep-water floating technology • long range transport of well stream • seabed and downhole processing • competitive gas production and offtake

c) Internal strategic projects in SINTEF on pipeline integrity management (including sensor, monitoring and communication technology)

d) Cooperation with IFE and Statoil on residual stress field simulation (case: girth welding of pipes)

e) Stålmat initiative on Constraint effects in fracture mechanics assessment (Application of Constraint Corrections in Design and Failure Assessment)

f) International JIP initiative on hydrogen embrittlement g) Fatigue behavior in high/ultra-high strength steels (updating the design basis), including weld

repair methods and quantification on their effects h) DEEPLINE – Design, Installation and Operation of Deepwater Pipelines, a strategic

programme carried out by MARINTEK, funded by NFR and industry i) BFLEX – computer program for calculation of failure and degradation mechanisms in flexible

riser pipe-wall j) SIMLA – Numerical simulation tool to study stress distribution on a complete pipeline on the

seabed k) LINKpipe – Numerical simulation tool to study how cracks or defects affects the performance

of pipes

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4 COMMON DENOMINATORS FOR INCREASED ROBUSTNESS The common denominators presented here are based on the experience gained through the work on S13Cr steels as pipeline material and the work on flexible riser systems /3/4/. The design and construction of pipelines and flexible risers are very different. This also reflects the difference regarding degradation and failure mechanisms. Still there are many common experiences which could represent a more general basis to the term robust material selection.

4.1 Management of oil and gas development projects In this case management is linked to the technical leadership of the operator/owner/purchaser with focus on responsibility. The scope of the present project is mainly technical. However, the working group of this RMS project has been exposed to aspects of management of oil and gas development projects which undoubtedly must be taken into account regarding robustness. Cost-benefit approaches are in many cases the driving force for technology developments. For robust material selection this means increased utilization of materials, more narrow tolerances on properties and dimensions and reduced time schedules. It is clear that the organization and management of such field development project differs between the companies. But, the general aspects to consider are the following recommendations. Some of the input is based on experience from other projects, some is based on interviews with actual operators/suppliers and some is based on a questionnaire on S13Cr steel as pipeline material. The recommendations to the management are:

• taking responsibility for securing relevant competence and to secure interactions between fields of competence through all stages from design to operation.

• improving the use of "Best international practice". Technology transfer from one project to another should be outlined in written procedures.

• taking responsibility regarding the connection between design criteria and operational conditions (i.e. elevate the accuracy of lifetime assessments, evaluation of risk of failure etc.). Both flexible risers and S13Cr as line pipe material are considered as new technologies and the operational experience is too short to verify reliability and robustness in demanding applications. In this situation design must be based on test data. Accelerated environmental assisted tests may in many cases need to run for long periods to be realistic. This has to be accounted for if test data is not available.

• more detailed time schedules accounting for upcoming problems during construction projects. The oil companies are mostly satisfied with the time schedules regarding pipeline construction projects (cf. questionnaire on S13Cr steel). This is not the case looking closer on the requirements on fabrication schedules and how upcoming problems in this phase of construction have increased risk of poor design and lack of evaluations. Right now different types of cladded pipes are focused. Reeling or J-laying, introducing larger plastic strain to the pipe, is intended to be used for installation. Where is the time schedule and budgets for fundamental research on the integrity of such pipes during operation?

• the riser system should be included as a primary element of a production system, and reliability and robustness of the riser system should be considered at the stage of concept evaluation of a new field. Long term realistic tests and verifications should be expected in the evaluation of risk and lifetime assessments. So far the riser system has been considered as proven technology. This is not the actual case as the experience of long term durability is very limited and that the flexible riser systems are introduced to more and more demanding environments and loadings. When a flexible riser system is inherent in the field concept and the field conditions are more demanding, the designer is left with selection of new materials in the riser system. These new materials or material combinations are not verified for long term durability.

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• competition between suppliers of flexible riser systems has lead to unfortunate situations.

The design criteria differ and they keep the design basis as a secret. This makes comparison of the suppliers difficult. The commonality on fundamental research and development suffers also because of the secrets between the suppliers. It is recommended, on a contractual basis, that the operators require full and open access to details on the construction and the risk/lifetime assessments from the suppliers.

4.2 Design It is identified a large potential for increased robustness by improving the completeness of operational design of flexible risers and pipeline systems. The field experience on flexible risers and flowlines indicates that the design basis has been insufficient. The statement of insufficient design is based on experience from failure investigations, showing that the stress/loads in many cases have been underpredicted relative to the maximum allowable design stress/loading. This is often combined with wrong predictions of degradation- and failure mechanisms. New and unexpected failure modes have been experienced, in many cases related to material properties and degradation or failure mechanisms. Development of more accurate tools for design and life prediction by means of numerical simulations combined with new test methods, full scale testing, instrumentation and monitoring during operation and field experience in general should have had more focus. More effort on iterative design and verifications is emphasized. This can be partly realized through the following recommendations: -for flexible risers:

• enhanced requirements for third party evaluation of new pipe concepts or new applications of flexibles. Design of flexible risers involves advanced materials, interaction between very different materials in a complicated structure, and time dependent degradation mechanisms. This kind of independent third party expertise requires resources.

• fatigue design of armour wire based on operational conditions: Aqueous annulus with H2S and/or CO2 permeating from bore. Sea water ingress, oxygen level and cathodic protection are additional environmental factors.

• more work into the mechanisms of sealing and fixation in the end termination should be undertaken, in particular regarding response of polymer materials to cyclic temperature and stress, and to ageing mechanisms

• investigation of fatigue initiation and crack growth in PVDF materials. Recent design modifications of end terminations may lead to fatigue problems due to crack growth through the liner.

-for pipelines: • take into account the strain history from installation on the properties of the line pipe

material • take into account environmental impact on line pipe material properties regarding fatigue

crack growth and fracture. • take into account the effect of general corrosion on pipe wall thickness and local corrosion

(notch effects). • take into account typical weld defects (Engineering Critical Assessment) • requirements on increased documentation of seabed topography along the planned route of

the pipeline and how it affects the stress distribution on the pipe during normal operational conditions and shut downs (high cycle and low cycle fatigue respectively).

• after installation and before operation, document the exact position of the pipe to verify whether the design criteria are met or not. If deviations are registered, re-design and evaluation of remedial actions are highly recommended.

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• on pipe section(s), which are considered as most critical (highly loaded) during operation,

observe/register pipe movement during Ready For Operation procedure and initial operation for comparison with design criteria.

• improve the interaction between local and global design analyses. • avoid stress/strain concentrations in highly loaded sections. • in addition to the monitoring on the well head and pipeline end (platform/on shore),

improve monitoring of critical parameters on pipeline during operation as: -local loadings (stress) -cracking -wall thickness -pH -flow

4.3 Knowledge gaps This chapter looks closer on ways to reduce knowledge gaps and thereby reduce the risk of incidents offshore. The term "complete design" includes a complete understanding and quantification of all possible sources of environmental impact on the construction/structure during operation. However large holes are present today. This may be one of the major reasons why the predictions of lifetimes on S13Cr pipelines and flexible risers are questioned world wide. The design basis, the operational experience and operational monitoring/registrations are limited. The experience that has been accumulated through the last few years has shown that even if a flexible riser design or a S13Cr flowline has been fully qualified, failures have occurred in unexpected modes. These failures may likely be defined as a result of knowledge gaps. The following recommendations are likely reducing the risk of incidents and failure of such subsea systems: A. We have to close the gaps that are known and present today on pipeline- and flexible riser systems. This requires establishment of new relevant test methods and extensive testing and verifications programs. As soon as a test method is critically evaluated and regarded acceptable for qualification purposes, it is of main importance to standardize the method. It is also vital to implement the test results in relevant standards and specifications. B. Bring the design analyses closer to completeness (see section 4.2). C. It is clear that fundamentals regarding environmental assisted failure mechanisms are not fully understood. It is recommended that more basic and long term research is initiated to provide a better understanding of these issues (including Ph.D. programs). D. Strategic strengthening of the communities in the offshore industry, universities and research institutes on Environmental Assisted Mechanics (cf. EA Cracking, EA Fracture Mechanics, EA Fatigue etc.). Strategic investment on relevant equipment on a national basis is also necessary to bring forward, taking into account the large volumes of laboratory work connected to characterization and optimization of different materials exposed to different operational conditions. E. It is believed that closer collaboration between oil companies/operators, manufacturers/fabricators and research institutions/universities are likely an effective way of

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reducing technology gaps in the future. To be able to identify possible sources of failure, it is required open communication. This is especially a major challenge for suppliers of flexible risers.

5 REFERENCES: 1. Oljedirektoratet: Sammendragsrapport, "Utvikling av risikonivå – norsk sokkel" Fase 3 –

2002, April 2003 2. J.M.Drugli, C.Thaulow, J.Ødegård, T.Rogne, R.Stokke, S.Berge, J.Berget: Pre-project,

"Robust material selection in the offshore industry", SINTEF Report STF24 F03202, January 2003

3. H.Lange, T.Rogne, "Material selection of weldable super martensitic stainless steels for pipeline material in the offshore industry SINTEF Report, STF24 F04222, February 2004

4. S.Berge, T.Glomsaker, "Robust Material Selection (RMS) in the Offshore Industry – Flexible risers", Marintek Report, February 2004

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TABLE OF CONTENTS

1. INTRODUCTION..................................................................................................................4

2. FLEXIBLE RISER WALL STRUCTURE .........................................................................52.1 Introduction ......................................................................................................................52.2 Carcass ...........................................................................................................................52.3 Liner ...........................................................................................................................72.4 Annulus ...........................................................................................................................82.5 Pressure armour................................................................................................................92.6 Tensile armour................................................................................................................102.7 Outer sheath....................................................................................................................102.8 Anti-wear tape ................................................................................................................11

3. FAILURE MODES..............................................................................................................123.1 Carcass failure modes.....................................................................................................123.2 Liner failure modes ........................................................................................................12

3.2.1 Pull out and rupture of pressure barrier in end termination ............................123.2.2 Collapse of carcass due to gas permeation......................................................133.2.3 Degradation of Rilsan ..................................................................................13

3.3 Failure modes for pressure armour.................................................................................143.4 Failure modes for tensile armour....................................................................................15

3.4.1 General ............................................................................................................153.4.2 Wear ................................................................................................................163.4.3 Fatigue and corrosion fatigue..........................................................................163.4.4 Hydrogen induced cracking ............................................................................173.4.5 Anti-wear tape.................................................................................................17

3.5 Failure modes for outer sheath .......................................................................................17

4. OPERATIONAL EXPERIENCE.......................................................................................194.1 Experience by Norsk Hydro...........................................................................................194.2 Experience by Statoil .....................................................................................................194.3 Information from suppliers of flexible risers .................................................................19

5. DISCUSSION .......................................................................................................................215.1 General .........................................................................................................................215.2 Metallic components ......................................................................................................21

5.2.1 Stainless steel ..................................................................................................215.2.2 Carbon steel.....................................................................................................21

5.3 Polymer components ......................................................................................................22

6. ORGANISATIONAL FACTORS ......................................................................................246.1 Choice of riser system ....................................................................................................246.2 Competition vs. openness in the market.........................................................................24

7. RECOMMENDATIONS.....................................................................................................267.1 General recommendations..............................................................................................267.2 Specific recommendations .............................................................................................26RELEVANT TESTS..............................................................................................................30

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INTRODUCTION

During recent years a significant number of flexible risers on the Norwegian Continental Shelfhave suffered from failure, for a variety of reasons. In several cases the failure mode was relatedto material properties, and was not foreseen in design. Long term durability and reliability of risersystems may be questioned.

In this report an overview of failure modes and critical factors for material selection is provided.The report is based on interviews of industry representatives with competence on flexibles, andgeneral knowledge within MARINTEK/SINTEF. Recommendations are given for improvedrobustness and reliability of materials for flexible risers.

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1. FLEXIBLE RISER WALL STRUCTURE

1.1 IntroductionFlexible risers are used for a range of functions: Production risers for gas and oil, water injection,gas lift, gas injection, oil or gas export, test productions etc. Flexible risers are also used fordrilling and well maintenance. In this report the discussion is limited to the transport function.

Flexible risers used for production, injection or export are likely to be subjected to a number ofconditions that may be affect the integrity of the riser. Due to the rather complicated wallstructure where materials with very different properties are interacting, Figures 1 and 2, a largenumber of failure modes are possible. Many of these failure modes are related to materialproperties. In this section the different layers of a flexible riser are described with respect tofunction, structure, material and possible failure modes.

Figure 1. Typical cross section of flexible pipe wall structure.(1) Stainless steel carcass(2) Thermoplastic liner

(3) Carbon steel pressure armour(4) Carbon steel tensile armour, two contra-wound layers

(5) Thermoplastic outer sheathPolymer tape, which is used to minimise friction and wear between layers of armour, is not

shown. Additional layers of material with low thermal conductivity may be applied in order toobtain specific thermal insulation properties of the pipe.

1.2 Carcass

The carcass is the innermost layer of a pipe, and the only metallic component that is in directcontact with the fluid in the bore. The carcass is made from stainless steel strip in a continuousprocess onto a mandrel. The material is stainless steel, typically AISI 316L or similar, that needsto be compatible with the chemical constituents of the transported liquids and/or gases.

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Figure 2. Pipe wall structure, in more detail.

The function of the carcass is to provide strength against external hydrostatic pressure, andmechanical protection of the liner against pigging tools and abrasive particles. The carcass alsoprovides strength to resist crushing loads during e.g. installation operations. At large water depthsthe hydrostatic as well as the crushing loads will increase.

The carcass is an open structure and does not provide any containment of internal pressure, i.e. oiland gas can flow freely across the carcass. Flexibility is obtained by the ability of each profile toslide with respect to the neighbouring profiles.

Figure 3. Typical carcass profile.

In the case of a damaged outer sheath, the external pressure will be acting directly onto the liner,and must be carried by the carcass alone. A basic design criterion is thus the external pressure atmaximum water depth, assuming empty pipe.

Carcass collapse may also be caused by release of absorbed gas in the liner. During high pressureoperations the liner will become saturated with gas, which will be released in periods of lowpressure shut-down. For multilayer liners, if proper venting is not provided for the slits betweenthe layers of liner, pressure may build to cause collapse of the carcass. The carcass is normallynot designed for this condition, which must be avoided by design or by operational restrictions.

The collapse capacity is strongly dependent on whether the carcass is fully supported by thesurrounding structure (liner/pressure armour) or whether there is a gap. A gap may be caused byseveral mechanisms:

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− Stretching and possibly deformation of the carcass due to force of gravity.− Shrinking of liner due to deplastification, possibly counteracted by swelling due to absorption

of hydrocarbons and/or gas.− Pressure induced creep of liner into gaps in pressure armour and carcass profiles.

The forming of a carcass profile from metal strip is a cold-forming process. For a given materialthere are technological limitations with regard to the thickness of a strip that can be formed to acarcass profile like the one shown in Figure 3. The collapse strength of the carcass, which isessentially determined by the stiffness (moment of inertia) of the profile, has basic limitations forthis reason. Collapse strength to resist hydrostatic pressure as well as crushing loads frominstallation equipment may be a limiting factor for deep water applications of large diameter pipe.

More compact and stiffer profiles are under development, Rytter and Rishøj (2002), that mayextend the deepwater range of flexible risers.

1.3 LinerThe liner is the sealing layer, made from a thermoplastic by extrusion over the carcass. In someapplications a multi-layer liner is used, with sacrificial layers on the inside and/or the outside ofthe sealing layer. The purpose of the sacrificial layers is to provide protection against the metalliccomponents. The liner is exposed to the fluid in the bore, and limits the upper service temperatureof the riser and the chemical composition to the various fluids that may be transported through theline.

Different materials may be used, depending on the design conditions. Three generic classes ofmaterials used as liner are:

− High density polyethylene (HDPE) and cross-linked polyethylene (XLPE)− Polyamide (nylon) (PA11 or PA12)− Poly vinylidene fluoride (PVDF)

Within each class of materials a large variability in properties are available. Some of the materialsused are brand names, protected by patents or licenses as shown in Table 1.

Material Producer Used by supplierRilsan® PA11 + plasticizer Atofina AllSolef® 60512 PVDF/CTFE* Solvay NKT, WellstreamSolef® 1015/078 PVDF + plasticizer Solvay WellstreamGammaflex® PVDF/HFP** Atofina + Technip TechnipCoflon® PVDF + plasticizer Atofina + Technip TechnipHDPE/XLPE

*Copolymer with Chlorotrifluoro-ethylene**Copolymer with Hexafluoro-propylene

The trade names Coflon® and Gammaflex® are hold by Technip but are probably based onKynar® and Kynar Flex® respectively from Atofina, possibly modified by use of their ownadditive package, particularly plasticizer.

Table 1. Polymers used in the liner for flexible risers

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A major criterion for selection of liner material is the design temperature. In general, HDPE hasvery good chemical resistance and maintain good mechanical properties up to ~60°C. However,hydrocarbons like crude oil, methane, methanol etc., are absorbed and may work as plasticizer.Therefore, if the bore fluid contains hydrocarbons, HDPE may be used at low and moderatetemperatures only, generally below 20 – 30°C. Crosslinking may in general improve high-temperature properties and in addition reduce the absorption of hydrocarbons, and thus XLPEmay be used at somewhat higher temperatures than HDPE.

Polyamide materials may be used at higher temperatures but is very sensitive to humidity. In thecase of a high water cut, polyamide suffers from hydrolysis at elevated temperatures. The mainmechanism of hydrolysis of PA11 and PA12 is chain scissoring (reduced molecular weight),causing brittleness. Prediction of service life in various environments has probably been a majorcomplication with this material, Ottøy (2001). The Rilsan User Group (RUG), which is acollaboration between a range of operators and suppliers, have however developed a newprocedure to predict the life time and degradation rate for Rilsan® and published by API as aTechnical Report (API TR 17 RUG). According to API TR 17 RUG, the extrapolated service timefor Rilsan® at 60°C in a typical well flow (humid, pH4) is 20 years. Nevertheless, Rilsan isconsidered as the most used liner material within the North Sea, MCS (2001).

PVDF may be used at higher temperatures, possibly 130°C with present brands. However,typically 20% plasticizer is added to PVDF homoploymer, in order to improve processing(extrusion) properties and reducing the possibility for defects like blisters. In contact withhydrocarbons, the plasticizer tends to be extracted from the PVDF, leading to permanentshrinkage of the material which again has contributed to several failure modes as described indetail in the next chapter: Pull-out or rupture of the liner at the end termination and decompressionof the carcass due to pressurized gaps between the layers. The former problem has been mitigatedby use of accelerated deplastification of the end section of the liner before mounting of endtermination.

A recent method to improve the processability of PVDF without use of additives is to apply acopolymer. Solef ® 60512 and Kynar Flex® are PVDF copolymers. For the Solvay material thecomonomer applied is, according to available information, CTFE (chlorotrifluoro-ethylene), andfor the Kynar Flex® the comonomer is HFP (hexafluoro-propylene). New development is alsoongoing for liner materials in order to resist even higher temperatures, MCS (2001). Thisdevelopment is mainly run by the suppliers and the material industry.

1.4 AnnulusThe section between the liner and the external sheath is the pipe annulus. This is an openstructure with no pressure barrières. In a pipe that is transporting a fluid under high pressure, gasand liquid will permeate through the liner and cause pressure build-up in the annulus. To preventrupture of the external sheath, the annulus is vented at the end terminations, typically at 1 baroverpressure.

In the as-fabricated state, void space in the pipe annulus is filled with atmospheric air. Fatiguedesign of steel armour wire in the annulus has been based on an assumption that the environmentis benign. However, during operation the chemical composition may change, for several possiblereasons:

Leakage by damage of the outer polymer sheath, caused during installation or operation. Thiswould lead to sea water flooding of the annulus. Depending on the nature of the leak, sea water in

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the annulus could be depleted of oxygen, or possibly saturated with air. Efficiency of cathodicprotection is uncertain. Sea water may be combined with H2S and/or CO2 due to permeationfrom the well flow.

Permeation of species from the product flow, notably water (H2O) which may condense andaccumulate in the annulus, in combination with gaseous components like hydrogen sulphide(H2S), carbon dioxide (CO2) and methane (CH4).

Risers which have been subjected to sea water ingress may be repaired, flushed with inhibitor, andre-installed. Inhibitor fluid, possibly with some residual sea water and with CO2 or H2S due topermeation from the well flow, could have an effect on residual fatigue life.

These environments may have a significant effect on fatigue life of steel components, and need tobe considered in design and operation.

1.5 Pressure armourThe primary function of the pressure armour is to resist the hoop stress due to internal pressure.The pressure armour is also a strength component with respect to external forces, e.g. crushingforces due to handling or accidental loading.

The pressure armour is an interlocking profile made from rolled carbon steel with tensile strengthin the range 700 – 900 MPa. Three different profiles are currently in use, Zeta/Flexlok, C-clip andTheta, Figures 4-6. Some of these profiles are protected by patents or licenses.

The interlocking of the pressure armour is a limiting factor for the minimum bending radius of theriser. If this limit is exceeded, irreversible damage to the flexible line will occur, leading toperforation of the liner when subjected to internal pressure.

Figure 4. Zeta/Flexlok interlocking profile used as pressure armour.

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Figure 5. C-clip interlocking profile used as pressure armour.

Figure 6. Theta-shaped interlocking profile (two variants) used as pressure armour.

For high pressure applications the interlocking layer may be strengthened by an additional layer offlat steel profiles that are not interlocked, cf. Figure 3.

Zeta/Flexlok is used by Technip and Wellstream. However, the two suppliers have developedproprietary variants of the profiles.

C-clip® is used by NKT, and Theta® is used by Technip.

1.6 Tensile armourThe tensile armour is two or four counterwound layers of armour wire and provides strengthagainst axial stress caused by internal pressure and by external loads. The tensile armour alsoprovides torsional strength to the pipe. However, for torsional loads in a direction leading tounwinding of the outer layer of armour the strength and stiffness is poor.

1.7 Outer sheathThe function of the outer sheath is to provide a seal against the sea water in order to preventcorrosion and to give mechanical protection to the steel armour. The loads typically applied on theouter sheath is impact, erosion and tearing as well as, in certain cases, external or internalpressure. The material is extruded thermoplastic – HDPE or Rilsan®. According to available

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information, MCS (2002), nearly 40% of the riser failures are due to external sheath damage andmost of these took place during installation.

1.8 Anti-wear tapeIn a flexible riser subjected to cyclic bending the steel armour will slide cyclically. If two layersof steel armour are in direct contact, wear may take place. For this reason anti-wear tape isapplied between layers of steel armour. The tape is not leak-proof, and fluids in the annulus mayflow through the tape.

The materials used are thermoplastic tape like Rilsan with a thickness in around one millimetre.The tape is subjected to significant contact stress and large slip amplitudes. Cumulative slip for a20 year design may be of the order of 50⋅103 m. The tape must thus retain a minimum strength atthe temperature of the armour, and to be wear resistant.

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2. FAILURE MODESDue to the complicated and composite structure of a pipe wall, a large number of failure modesare possible. In this section failure modes as known from service experience and full-scale testsare described. Failure modes due to mechanical overload are not discussed in any detail. Focus ison failure modes that are related to material properties and material selection.

2.1 Carcass failure modesThe carcass may be subjected to a large number of failure modes; overstretching, fatigue, radialcollapse, wear, erosion, corrosion and damage from pigging and similar operations.

Radial collapse has been reported in several cases, caused by pressure build-up in multi-layerliners. Calculations have showed that in these cases the pressure was in excess of the designcollapse pressure for the carcass. The cause of the collapse was thus not related to materialproperties or designed capacity, but due to an unexpected mode of loading.

Fatigue or wear damage of the carcass has not been reported in the open literature. Due to thestructure and loading on the carcass, fatigue is not a likely failure mode, except as secondarydamage due to initial damage in the production phase or due to pigging or the like.

The carcass may be subjected to erosion and erosion-corrosion in production risers for gas-condensate fields with sand production. Full scale tests have demonstrated significant materialloss under conditions representing realistic operational conditions, Kvernvold (1992). Predictiontools have limited accuracy, and the design envelope for safe operation is uncertain.

The full scale tests have shown that corrosive environments with CO2 will give enhanced erosionrates. Plain corrosion has not been reported for the carcass.

2.2 Liner failure modes

2.2.1 Pull out and rupture of pressure barrier in end termination The end termination of the liner must provide two functions:

- Sealing of pressure in the bore- Fixation of liner to prevent pull-out

Various mechanical solutions are employed by the suppliers. In one early design the polymerlayers were restrained in the axial direction by a clamping force by use of a locking ring. Theclamping force was in the original design applied on the polymer sheet onto the carcass and wastherefore limited by the stiffness of the carcass. Upon thermal cycling the compressive forcesgenerated in the polymer layers at high temperature due to higher thermal expansion than thesteel, will relax and after some time or cycles, tension will appear in the polymer at lowtemperature. This mechanism in combination with migration of plasticizer in the PVDF resultedin 1994-95 at Snorre in pull-out from the end termination.

The mechanism of pull-out was verified in a mid-scale test by MARINTEK, Berge and Eide(1999).

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After redesign of the end termination the problem was solved and has not appeared later inservice. However, the improved fixation has lead to a different problem, fatigue cracking initiatedby the imprint of the locking ring. Failures have been reported in mid scale testing and in service.This is a problem which may require more research, Melve (2001).

2.2.2 Collapse of carcass due to gas permeationGas in the bore will under high pressure diffuse into the polymer liners and be solved in thepolymer. This is a very slow process and takes several weeks, up to a few months, in order toreach steady state conditions. A large amount of gas may be solved in the polymer material. Forrisers with multiple liners, pressure will build up between the liners and create a pressurized gapwhen the bore pressure is reduced. For high operational bore pressure (typical of gas injection,~30 – 40 MPa) there may be solved more than enough gas in the polymer to diffuse into the gapand build up a gas pressure at the interface, large enough to collapse the carcass if the bore isdepressurized.

The mechanism has been predicted by use of simulation, Glomsaker (2002). Typical result fromsimulation of the gas pressure inside the liner after pressurization of a riser from 1 bar to 390 bar,and subsequently depressurization again to 1 bar, are shown in Figure 7.

a) Pressurization b) Depressurization

A second failure mode related to diffusion and solution of gas in the polymer is blistering ofinternal voids. Very little information is available for this failure mode.

2.2.3 Degradation of RilsanRilsan® (PA11) is until now the most used liner-material in flexible risers, MCS (2001). Thereare several degradation mechanisms for polyamide like thermal degradation, oxidation,photodegradation, absorption of water etc. However, for PA11 in the actual humid environmentfree of oxygen, the dominating process will be hydrolysis. Hydrolysis results in scissoring of thepolymer chains and cause brittleness of the material. There has been large uncertainty about howto predict hydrolysis rate in order to ensure 20 years life time of the product. The hydrolysis rate

Figure 7. Gas pressure in a three layer liner of PVDF.The outer gap is located at radius = 0.093 m

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increases rapidly with temperature and somewhat less with increasing sourness. Most of thefailures related to degradation of Rilsan (as on Njord) however, seem to have been caused byunderestimated water content in the fluid. In addition, Atofina claims on their web page that therehas never been documented a flexible pipe failure caused by failure of polyamide-11 operatedwithin the recommended service window. The operators however claim that there were largedivergences between different aging models until the API TR 17 RUG was prepared by the RilsanUser Group – founded in 1998 consisting of a large number of operators and suppliers. Asindicated in Figure 8, this work resulted in a significant reduction of predicted life time. Thedegree of degradation is according to this procedure quantified by the inherent viscosity – whichis a magnitude calculated from the viscosity of the polymer in a suitable solvent, corrected forcontent of plasticizer. This magnitude is named corrected inherent viscosity (CIV). CIV reflectsthe degree of degradation because the viscosity is related to the average molecular weight of thepolymer, at a certain temperature and solvent, through the Mark-Houwink equation. The RUG hasestablished CIV = 1.2 as end-of-life criterion for Rilsan because at this level of degradation onefind an abrupt drop in mechanical properties. We also note that in the RUG-method there are nooption considering unsaturated or dry environment – life time predictions are suggested to alwaysinclude a saturated water phase.

0

5

10

15

20

25

30

50 55 60 65 70 75 80 85 90 95 100Temperature [°C]

Life

tim

e [y

ears

]

pH=4 (API TR 17 RUG )pH=5 (API TR 17 RUG )pH=7 (API TR 17 RUG )Saturated (API RP 17B)Unsaturated (API RP 17B )

2.3 Failure modes for pressure armourThe pressure armour is subjected to several degradation mechanisms:

In a pipe that is subjected to cyclic bending, the contact points of the profile will slide cyclically,with considerable contact stress. Due to the varying bending, the contact pressure will vary

Figure 8. Predicted life time for Rilsan® for various service temperatures according to API RP17B (2002) and API TR 17 RUG (2002)

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cyclically. This is a problem particularly for the Zeta profile, Figure xx, where the contact stresscauses cross-wire bending. The sliding may thus result in significant cyclic stresses in the cross-wire direction and possibly fatigue failure. The fatigue life may be affected by fretting at thecontact points. The associated failure mode is cracking parallel to the wire axis.

Ovalisation of the pipe due to curvature variations and possibly side loads from a bend stiffener ora bellmouth will give cyclic stresses longitudinal to the armour profile, and possible fatiguecracking normal to the axis of the armour.

Both these failure modes have been reported from full scale fatigue testing of risers with Zetaprofiles. Theta and C-clip profiles appear to have better fatigue properties.

The presence of aqueous environments with H2S and/or CO2 may have a significant effect onfatigue strength. Such environments are probable. Gas will permeate through the liner from thehigh pressure well flow. Fresh water may also permeate from the bore, or there may be sea wateringress through damage in outer sheath.

At the contact points the armour may be subjected to wear.

Computational methods based on finite boundary elements are available for calculation of crosswire stress of pressure armour, Sævik et al. (2001). Test methods have been developed for cross-wire and longitudinal fatigue loading of pressure armour, Berge (2001). The effect ofenvironment may also be tested in small scale, Berge et al. (2003). The methodology for doingfatigue design analysis is thus established and proven, Sævik (1998), Berge et al. (2001).

2.4 Failure modes for tensile armour

2.4.1 GeneralPotential failure modes for tensile armour may be listed as:

− overload in tension, possibly in combination with internal pressure, causing tensile failure− overload in bending or compression causing wire disarray or birdcaging− overload in torsion causing unwinding of armour or birdcaging− fatigue− corrosion fatigue− fretting fatigue− wear− hydrogen induced cracking− corrosion.

The overload modes of failure are not related to material properties, but to design and operationalconditions.

The remaining modes may be linked, and a large number of synergistic mechanisms are possible –at least in theory.

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2.4.2 WearIn early design of flexible risers the layers of tensile armour was laid directly against each other,with direct metallic contact. For this design wear of tensile armour was considered to be thelimiting factor for service life of flexible risers. Wear life was assessed by rotating bendingtesting, which was a very conservative test. Since approximately 1990 fabricators have appliedlayers of polymer tape – anti-wear tape – between layers of metallic armour. Provided the tapecan withstand the contact pressure, this has proved to be effective, and wear is no longerconsidered a problem for tensile armour. However, the long term durability of anti-wear tape indemanding conditions (large contact pressure and/or high temperature) has not been proved, asdisussed in Section 3.4.5.

2.4.3 Fatigue and corrosion fatigueDesign analysis has shown that fatigue of tensile armour may be critical with respect to designlife. In the as-fabricated state, void space in a pipe annulus is filled with atmospheric air. For thisreason fatigue strength criteria have been derived on the basis of fatigue tests in air, assuming theenvironment in a pipe annulus to be benign. Service experience has shown that during operationthe chemical composition of the annulus is likely to become corrosive, for the following possiblereasons:

- Leakage by damage of the outer polymer sheath, caused during installation or operation, orby malfunctioning venting valves. This would lead to sea water flooding of the annulus.Depending on the nature of the leak and the distance from the leak, sea water in the annuluscould be depleted of oxygen, or possibly saturated with air. Efficiency of cathodicprotection is uncertain. Sea water may be combined with hydrogen sulphide (H2S) and/orcarbon dioxide (CO2) permeating from the bore. There is also a possibility for MicrobialInduced Corrosion (MIC) as sulphide reducing bacteria (SRB) may develop in stagnantseawater.

- Permeation of species from the product flow, notably gaseous components like H2S and/orCO2, possibly in combination with fresh water (H2O) which may condense and accumulatein the annulus.

- Risers which have been subjected to sea water ingress may be repaired, flushed withinhibitor, and re-installed, Taylor et al. (2002). Inhibitor fluid, possibly with some residualsea water and with H2S and/or CO2 due to permeation from the well flow, could have aneffect on residual fatigue life.

Carbon steel in aqueous environment with H2S and/or CO2 is susceptible to corrosion, and thefatigue strength is likely to be affected. SN curves for fatigue design are empirical, and need to beassessed on the basis of relevant data. Until recently no standardised test methods were availablefor this type of testing. A test protocol has now been worked out and is being applied in fatiguetesting of armour wire, Berge (2002). Guidance is given on the following:

− specifications for the environment− specimen preparation− fatigue loading procedure− data processing

Recommendations are given on treatment of mean stress effects in fatigue design, and a unifiedmethod is proposed for assessment of SN design curves from test data.

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No cases of service failure due to fatigue of tensile armour have been reported in the openliterature. On the other hand, very few dynamic risers on the Norwegian Shelf have seen morethan five years of service loading, which is approximately 25% of a typical design life. Untilservice experience has been gained, corresponding to the design criteria, fatigue design must bebased on test data and design analysis.

2.4.4 Hydrogen induced crackingTensile armour is generally classified on the basis of “sweet” or “sour” service, following thecriteria given by NACE (National Association of Corrosion Engineers), NACE TM 02-84 (1996).

Sour service wire has a strength generally below 800 MPa. Sweet service wire has a tensilestrength in the range 1200-1400 MPa. One fabricator is using a “basic sweet” wire with strenghtin the range 800-900 MPa.

Norwegian operators have been conservative in their specification for tensile armour, using sourservice armour for all production risers even if the product flow is sweet according to the NACEcriteria. The reason for this conservatism is the possibility that wells that are initially sweet, maybecome sour through production life. The main reason for development of hydrogen sulphide isthe use of sea water for re-injection, and development of sulphate reducing bacteria inside theformation.

No cases of hydrogen induced cracking of armour wire have been reported in the open literature.

2.4.5 Anti-wear tapeThe anti-wear polymeric tape that is applied between layers of metallic components is a secondaryelement of a pipe wall, with no function in terms of sealing or strength. If the tape fails, however,wear and fretting fatigue is likely to affect the service life of the steel armour, and the service lifemay be significantly reduced, Berge and Sævik (1993).

Rilsan® and other types of thermoplastic material are used for the tape. In cases of high contactpressure and in combination with high temperature the tape may be subjected to wear, creepdeformation and other types of degradation mechanism.

The API Recommended Practice and Specifications do not specify any requirements with regardto the properties of anti-wear tape. Procedures used by the suppliers of pipe for qualification oftape materials are not known.

No failure of anti-wear tape has been reported. It should be borne in mind that anti-wear tape hasbeen used for approximately ten years, and relatively few flexible riser systems with tape havereached their design life. MARINTEK has developed a test facility for wear testing of polymertape, simulating the conditions of tape between layers of armour wire, Berge et al. (2001). It isknown from the testing that the properties of different tape materials can vary widely with respectto friction, creep behaviour and wear. The API documents provide little guidance on test methodsand acceptance criteria for the tape. This is obviously a topic for further investigations.

2.5 Failure modes for outer sheathFor a flexible riser subjected to cyclic bending, the outer sheath will experience the largest cyclicstrains. The outer sheath is also at a low temperature, and is thus conceptually vulnerable to

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damage. However, no fatigue failures of the outer sheath due to normal operational conditionshave been reported.

Above the waterline, the outer sheath may be subjected to direct sunlight, which may causeageing. However, this has not been reported as a problem.

On the other hand, a large number of failures have been reported, due to two main reasons:

− Damage due to rough handling, impact, etc. during installation or operation.− Failure of the venting system, causing pressure build-up in the annulus and failure of outer

sheath by bursting.

Water ingress has also been caused by malfunctioning or even lacking venting valves.

None of these failure modes are related to material properties, and will not be discussed herein.

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3. OPERATIONAL EXPERIENCE

3.1 Experience by Norsk Hydro

A survey of the flexible risers operated by Norsk Hydro is given in Table 3.

Platform Number offlexible risers

Liner material Replaced Failure Mechanism

Visund1) 28 PVDF 5 Collapse of carcassdue to gas permeation

Njord 20 PVDF

PA-11 (Rilsan®)

132) Collapse of carcassdue to gas permeation

Degradation of Rilsan

Snorre A1) 5 PVDF 4 Pull-outTroll B 33 PA-11 (Rilsan®) 1Troll C 35 PA-11 (Rilsan®) 0Others 30 3Total 151 26

1) Currently operated by Statoil.2) Some risers have been replaced more than once.

The history of failures has been reported in the open literature, Olsen et al. (2002).

3.2 Experience by StatoilStatoil has not (so far) been able to release written information to the project on failed pipes.However, some information has been released through oral discussions.

Statoil has in general experienced somewhat less problems with flexible risers compared to NorskHydro, cf. Table 3. This may have been fortuituous. From discussions with key persons in thetwo companies it appears that the approach to the use of flexible risers is based on the sameknowledge and technology, and the use of the same suppliers.

3.3 Information from suppliers of flexible risersThere are currently three suppliers of flexible risers world-wide:

- NKT Flexibles (Denmark)- Technip Coflexip (France)- Wellstream Co (UK and USA)

Table 3. Summary of Norsk Hydro’s experience on flexible risers

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The market for flexible risers is very competitive, and the three suppliers are very reluctant todisclose details about the materials and material selection procedures. In general the procedurescomply with API 17B and API 17J. In addition the suppliers carry out much work in-house andas commissioned work through research institutes. Very little of this is public domaininformation.

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4. DISCUSSION

4.1 GeneralThe operators Norsk Hydro and Statoil both base their purchase procedures on the generaldocuments API Specification 17J (API-17-J) and API Recommended Practice 17B (API-17-B) inaddition to API Technical Report 17 RUG (API-TR-17-RUG) for life time assessments forRilsan® liners.

API-17-J put the responsibility for design and material properties on the flexible pipemanufacturer. Both the design and the material properties shall be verified by a third party.Corrosion protection and operational conditions (internal conditions, external conditions andinsulation), necessary for the manufacturer to define load cases, are the responsibility of thepurchaser. There is no requirement in the standards for the purchaser to verify their analysis by athird party.

4.2 Metallic components

4.2.1 Stainless steelStainless steel is used for the carcass structure, which is in contact with the fluid in the bore.Standard grades are generally used, 304, 316 and similar. No problems related to materialproperties (corrosion, fatigue, wear, etc.) have been reported in the open literature.

The main design problem of the carcass is to provide structural strength against external loads.This problem is related to material grade through material strength properties, and formability forfabrication. However, this aspect is considered to be outside the scope of work for the presentproject.

4.2.2 Carbon steelCarbon steel is used for pressure armour and for tensile armour. The profiles are produced byrolling and/or drawing. The main criterion for selection of material grade is whether the productflow is “sour” (containing H2S) or “sweet”.

The NACE criterion is used as a definition of sour service. As discussed in Section 3.4.4 Statoiland Norsk Hydro have adopted a conservative approach towards selection of material grade forarmour wire, using sour service wire for all risers that are designed as production risers, regardlessof chemical composition of the initial well flow.

No problems related to HIC have been reported in the open literature.

Due to the finding that the annulus of a flexible riser is likely to be filled with water, much workis currently ongoing to verify the integrity of risers that are in operation, taking into account thereal environment. The design condition for flexible risers may in the future be based onwaterfilled annulus. In that case corrosion fatigue may become a major design criterion.

Currently each supplier of flexible risers has its own proprietary (and confidential) set of SNcurves for fatigue design of armour wire. There are reasons to believe that the SN curves from the

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individual suppliers may differ significantly, even for in-air conditions. The suppliers have verylittle data on fatigue strength in aqueous conditions containing H2S and/or CO2.

In a Joint Industry Project that is carried out by MARINTEK/SINTEF an extensive testprogramme has been undertaken, to provide a basis for design of flexible risers with water-filledannulus. In the programme, the following scenarios are studied:

- Leakage by damage of the outer polymer sheath, caused during installation or operation.This would lead to sea water flooding of the annulus. Depending on the nature of the leak,sea water in the annulus could be depleted of oxygen, or possibly saturated with air.Efficiency of cathodic protection is uncertain. Sea water may be combined with hydrogensulphide (H2S) and/or carbon dioxide (CO2). There is also a possibility for MicrobialInduced Corrosion (MIC) as sulphide reducing bacteria (SRB) may develop in stagnantseawater.

- Permeation of species from the product flow, notably water (H2O) which may condense andaccumulate in the annulus, in combination with gaseous components like H2S and/or CO2.

- Risers which have been subjected to sea water ingress may be repaired, flushed withinhibitor, and re-installed, Taylor et al. (2002). Inhibitor fluid, possibly with some residualsea water and with H2S and/or CO2 due to permeation from the well flow, could have aneffect on residual fatigue life.

SN curves for fatigue design are empirical, and need to be assessed on the basis of relevant data.No standardised test methods are available for this type of testing. For this reason a test protocolwas worked out for the JIP, Berge (2002). In the protocol guidance is given on the following:

- specifications for the environment- specimen preparation- fatigue loading procedure- data processing

Recommendations are given on treatment of mean stress effects in fatigue design, and a unifiedmethod is proposed for assessment of SN design curves from test data.

All three suppliers of pipe are participants of the MARINTEK/SINTEF JIP. An anticipatedoutcome of the JIP is a unified approach to fatigue design of armour wire. The JIP is planned torun until 2005.

4.3 Polymer componentsTypical characteristics for failures related to polymers can be classified as follows:

- Unexpected chemical exposure (humidity in bore fluid – Rilsan degradation- Unexpected failure mechanism (gas pressure between layers of multilayer PVDF liner- Unexpected mechanical loading (rough handling during installation, dropped objects,

fatigue of liner in end connection due to thermal cycling- Failure of ancillary equipment (Blocking of vent ports)- Unexpected material behaviour (pull-out in end termination)

Thus, the failures may be linked both to the design input, design and material knowledge as wellas handling of the pipe during installation and operation. Concerning robust material selection,

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actions and guidelines may be introduced in the design phase as well as in the design input phase– i.e. estimation of operation conditions. Particularly important is that many of the failureenvelopes have started with the polymer materials.

The industry has already taken a step forward concerning degradation rate of Rilsan® by theRilsan User Group (RUG). It seems like the API-TR-17-RUG document has succeeded inestablishing a more reproducible procedure for life-time estimation of Rilsan®. Thus this workhas probably increased the safety of the liners although there have not yet been any failures offlexible risers solely due to incorrect life time estimation. The procedure claims to be conservativein the aspect that the criterion is applied on the inner wall, and thus ignoring the reduced ageingrate of the outer wall due to temperature gradient and diffusion of water through the wall.However, the document is not consequent in this issue because, elsewhere in the same document,it is claimed that wall thickness has no effect on degradation rate. This should mean that thediffusion rate of water is high compared with the aging (hydrolysis) rate, which is also found byJacques et al. (2002). There are also still topics that need further investigation; this includeseffects of organic acids, ethanol and, indeed, how to model cumulative exposure. Because theprocedure is based on a minimum CIV, it also applies a time based safety factor on the criticalCIV value that decreases with more severe environment – from 2 at pH = 6 to 1.6 at pH = 4.

Nevertheless, the impression is that the oil companies have little influence on the materialselection concerning polymer liners in the flexible risers. Given the operational conditions and thechemistry of the produced fluid, it is left to the manufacturers (and a third party evaluator) todocument that a material is proper.

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5. ORGANISATIONAL FACTORSThe scope of the present project is mainly technical. However, material selection for flexible riserdesign is also contingent on organisational factors. Some of these will be discussed briefly.

5.1 Choice of riser systemFor the water depths and general design conditions on the Norwegian Continental Shelf, two risersystems are feasible:

− Top tensioned steel risers− Flexible risers

Top tensioned steel risers can be used with fixed platforms or tension-leg platforms. If a floatingplatform – ship or semisubmersible – is chosen, there is no option other than flexible risers, due tothe dynamic response of the system.

When selecting a field concept, fixed versus floating production systems are evaluated verythoroughly, being a major decision. In this evaluation, the riser system has generally been seen asproven technology. Thus, the robustness and reliability of the riser system tend to be non-issuesin this phase. This relates to the general design as well as the selection of materials.

The outcome of such a process may be that the designer of the riser system is left with a decisionto use flexible risers, even if this is the less optimum riser system for a certain application. As aresult, flexible risers have been used in gradually more and more demanding applications, at a ratethat has not allowed accumulation of any significant service experience. The large number ofriser failures that has been experienced on the Norwegian Continental Shelf in recent years is anindication that the application of flexible risers to more and more demanding applications mayhave been too rapid.

The failure statistics given by Norsk Hydro shows that all failures related to materials were linkedto un-expected behaviour of the thermoplastic liner, in most cases linked to long term durability.With more effort into long term and realistic testing, many of these failure modes could have beenpredicted.

The lesson learnt is that research and product development should have a wider time horizon, withmore time and effort for the long term tests which are required for verification of service life androbustness.

5.2 Competition vs. openness in the marketThe API documents (API 17B and API 17J) have lead to a major improvement with regard tocommonality in design practices. However, the API documents do not always specify the designcriteria, like fatigue design SN curves, or temperature limitations for use of specific linermaterials. To quote from the Scope of API 17B,

“In general, flexible pipe is a custom-built product that can be designed and manufactured in avariety of methods. It is not the intent of this document to discourage novel or newdevelopments in flexible pipe. On the contrary, it is recognized that a variety of designs andmethods of analysis are possible. For this reason, some topics are presented in general terms

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to provide guidance to the user while still leaving open the possibility of using alternativeapproaches.”

For this reason, on many aspects of pipe design it is left to the supplier of pipe to establish thespecific criteria, and to provide the justification for these criteria. In this process the APIdocuments provide general advice only, and much of the evaluation is left to the supplier and apossible third party.

The three suppliers of flexible risers are acting in a very competitive market. Technologicaladvancements in design and materials are kept as well protected secrets, and use of third party iskept to a minimum. Even failure statistics and failure analysis reports which could contributetowards improved reliability over-all, are shielded from insight. Due to the market forces,operators seem to accept this situation.

As a result, there may be little commonality between the approaches taken by the three suppliers,even for design problems that are very similar and not product specific. One example is fatiguedesign criteria for tensile armour, which is a rather standard product made from Carbon steel. Thethree suppliers have their own proprietary and confidential set of design criteria, which may varysignificantly for virtually the same type of component and material, in some cases even suppliedfrom the same group of vendors. It is difficult to find a rationale for this situation.

A similar description applies to the thermoplastic materials used for the liner. The three suppliersrun separate courses with regard to development and qualification of new materials, in some casesinvolving patent rights. Some of the failure modes and corresponding design criteria are related tocomplicated time-dependent material performance, like creep, thermal cycling and ageing, and tothe interaction between the thermoplastic liner and metallic components, that cannot be modelledproperly. Time is limited for accumulation of long term experience through service or full scaletesting. A more open research environment could obviously give a broader perspective, andimproved insight.

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6. RECOMMENDATIONS

6.1 General recommendations

− The riser system should be included as a primary element of a production system.Reliability and robustness of the riser system should be considered at the stage of conceptevaluation.

− Flexible risers is a new technology, and the operational experience is too short to verifyreliability and robustness of risers in demanding applications. In this situation design mustbe based on test data. However, accelerated tests may in many cases need to run for longperiods to be realistic. Research with a sufficient time horizon should be encouraged, toverify design criteria related to time degradation processes.

− The experience that has been accumulated through the last few years has shown that even ifa flexible pipe design has been fully qualified, risers have failed due to new and unexpectedfailure modes. This indicates that the behaviour of the materials and in particular theinteraction between the different materials in a pipe wall is not fully understood. It isrecommended that more basic and long term research is initiated to provide a betterunderstanding of these issues.

− The competition between the suppliers of flexible risers has lead to a situation whereconfidentiality about product properties and design criteria has become an obstacle foradvancement of reliability and robustness. The suppliers should be encouraged to worktowards a larger degree of commonality in design practices and design criteria.

− Design of flexible risers involves advanced materials, interaction between very differentmaterials in a complicated structure, and time dependent degradation mechanisms. Thirdparty evaluation requires very advanced knowledge of materials and structure of a flexibleriser. There is a need for independent expertise, with the resources that are required.

6.2 Specific recommendations

− Fatigue design of armour wire has until very recently been based on SN curves obtainedfrom testing in air. Service experience has shown that a likely environment in the annulusof a pipe will be aqueous, with H2S and/or CO2 permeating from the bore. Sea wateringress, oxygen level and cathodic protection are additional environmental factors. Fatiguedesign criteria for armour wire need to be reconsidered.

− Sealing and fixation of the liner in the end termination has proved to be a problem.Improved end coupling design has appeared to alleviate the problem of liner pull-out.However, with improved fixation, fatigue crack growth through the liner has become apotential failure mode. Due to the short history of the improved design, no pipe design hasyet been proved through service history to have a 20 year design life. More work into themechanisms of sealing and fixation in the end termination should be undertaken.

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− Liner materials are subjected to long term deterioration mechanisms, like hydrolysis,deplastification creep and ageing. In order to meet ever more challenging operationalconditions, new material grades of thermoplastics are being introduced at a rate which doesnot allow accumulation of service experience. Thus, qualification is to a large extent basedon accelerated tests under simulated conditions. The methods used for qualification testingand the design criteria should be evaluated critically.

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REFERENCES

API TR 17 RUG (2002). The ageing of PA11 in Flexible pipes (final draft for publication 21-10-2002 SJG).

Berge S and Sævik, S (1993). Correlation between theoretical predictions and testing of two 4-inch flexible pipes. Proc. Energy-Sources Technology Conference (ETCE), American Societyof Mechanical Engineers (ASME), Houston, USA.

Berge S and Eide OI (1999), Facility for thermal cycling of end terminations of flexible pipe.Third European Conf. on Flexible Pipes, Umbilicals and Marien Cables – Materials Utilisationfor Cyclic and Thermal Loading. J. A. Witz (ed.), London, UK.

Berge S, Sævik S, Langhelle N, Holmås T and Eide OI (2001). Recent developments inqualification and design of flexible risers. Int. Conf. Offshore Mechanics and ArcticEngineering (OMAE), Rio de Janeiro, Brazil.

Berge, S (2002). Test protocol: Corrosion fatigue testing of armour wire for flexible risers.MARINTEK Report MT70 F02-127 (confidential).

Berge S, Bendiksen E, Gudme J and Clements R (2003). Corrosion fatigue testing of flexibleriser armour – procedures for testing and assessment of design criteria. Int. Conf. OffshoreMechanics and Arctic Engineering (OMAE), Cancun, Mexico.

Glomsaker T (2002). Calculation of permeation of gas into PVDF liner for Njord GI riser.SINTEF MATEK Memo, 2002-05-03 (confidential).

Jacques B, Werth M, Merdas I, Thominette F and Verdu J (2002), Hydrolytic ageing of polyamide11. 1. Hydrolysis kinetics in water. Polymer, 43, pp 6439 – 6447.

Kvernvold O (1992). Erosion-corrosion in inner steel carcass of flexible pipes. Int. SeminarFlexible Pipe Technology, O. Olufsen (ed.), Trondheim, Norway, 1992.

MCS International (2001). State of the Art – Flexible Riser Integrity Issues, Study Reportprepared for UKOOA.

Melve B (2001). Principles for life time estimation of PVDF pressure barriers in hightemperature flexible pipes based on fracture mechanics. Int. Conf. Offshore Mechanics andArctic Engineering (OMAE), Rio de Janeiro, Brazil.

Olsen PG and Rongved K (2002). Operators experience with flexible risers. Int. Conf. OffshoreMechanics and Arctic Engineering (OMAE), Oslo, Norway.

Ottøy MH, Finstad H, Mathiesen MW, Moursund B and Nakken T (2001). Field experiences onRilsan-ageing compared to data from ageing model. Int. Conf. Offshore Mechanics and ArcticEgnineering (OMAE), Rio de Janeiro, Brazil

Rytter J and Rishøj N-J (2002). A novel compression armour concept for unbonded flexible pipes.Offshore Technology Conference (OTC), OTC 14059, Houston, USA.

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Sævik S (1998). A new method for calculating stresses in flexible pipe tensile armours. Int. Conf.Offshore Mechanics and Arctic Engineering (OMAE), Lisbon, Portugal.

Sævik S, Gray LJ and Phan A-V (2001). A method for calculating residual and transverse stresseffects in flexible pipe pressure spirals. Int. Conf. Offshore Mechanics and Arctic Engineering(OMAE), Rio de Janeiro, Brazil.

Taylor TS, Joosten MW and Smith F (2002). Technical solutions applied for the treatment ofdamaged dynamic risers. Int. Conf. Offshore Mechanics and Arctic Engineering (OMAE),Oslo, Norway.

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RELEVANT TESTS

API 17B and API 17J list a large number of tests that are relevant for qualification of flexiblerisers. Some of these tests are non-standard, and described in the API documents. Relevantstandards are given below.

RELEVANT DOCUMENTS:

API RP 17B, Recommended Practice for flexible pipe, American Petroleum Insitute (1998)

API Spec 17J, Specification for unbonded flexible pipe, American Petroleum Institute (1998).

API Std 1104, Welding of pipelines and related facilities.

ASTM A29, Specification for steel bars, carbon and alloy, hot-wrought and cold-finished –general requirements.

ASTM A370, Test methods and definitions for mechanical testing of steel products.

ASTM D256, Test methods for impact resistance of plastics and electrical insulating materials.

ASTM D413, Test method for rubber property – Adhesion to flexible substrate.

ASTM D570, Test method for water absorption of plastics

ASTM D638, Test method for tensile properties of plastics.

ASTM D671, Test method for flexural fatigue of plastics by constant-amplitude-of-force.

ASTM D695, Test method for compressive properties of rigid plastics.

ASTM D746, Test method for brittleness temperature of plastics and elastomers by impact

ASTM D789, Test method for determination of relative viscosity, melting point, and moisturecontent of polyamide (PA).

ASTM D1044, Test method for resistance of transparent plastics to surface abrasion.

ASTM D1238, Test method for flow rates of thermoplastics by extrusion plastometer.

ASTM D1242, Test method for resistance of plastic materials to abrasion.

ASTM D1525, Test method for Vicat softening temperature of plastics.

ASTM D1693, Test method for environmental stress-cracking of ethylene plastics.

ASTM D2143 Test method for cyclic pressure strength of reinforced, thermosetting plastic pipe.

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ASTM D2583, Test method for indentation hardness of rigid plastics by means of a Barcolimpressor.

ASTM D2924 Test method for external pressure resistance of reinforced, thermosetting plasticpipe.

ASTM D2990, Test method for tensile, compressive, and flexural creep and creep rupture ofplastics.

ASTM D1141, Standard practice for the preparation of substitute ocean water, American Societyfor Testing and Materials (1998).

ASTM E466, Standard practice for conducting force controlled constant amplitude axial fatiguetests of metallic materials, American Society for Testing and Materials (1996).

ASTM E739, Standard practice for statistical analysis of linear or linearized stress-life (S-N) andstrain-life (ε-N) fatigue data, American Society for Testing and Materials (1991).

ASTM E831, Test method for linear thermal expansion of solid materials by thermomechanicalanalysis.

Handbook on Design and Operation of Flexible Pipes, Berge. S. and Olufsen, A. (eds.), SINTEFReport STF70 A92006, 1992.

ISO 8457-2, Steel wire rod, Part 2 – Quality requirements for unalloyed steel wire rods forconversion to wire.

ISO/DIS 13628-2, Flexible pipe systems for subsea and marine applications.

NACE MR 01-75, Sulfide stress cracking resistance metallic materials for oilfield equipment,National Association of Corrosion Engineers (1996).

NACE TM 01-77, Standard test method: Laboratory testing of metals for resistance to sulfidestress cracking and stress corrosion cracking in H2S environments, National Association ofCorrosion Engineers (1996).

NACE TM 02-84, Standard test method: Evaluation of pipeline and pressure vessel steels forresistance to Hydrogen-induced cracking, National Association of Corrosion Engineers (1996).

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APPENDIX A

Sources for this investigation:

The written sources, mainly found in the public domain literature, are listed in the report.

It has been very difficult to obtain any written information on pipe failures and failure modes fromoperators and suppliers of flexible risers. Permission was given to use the table showing theservice experience of Norsk Hydro, Table 3.

A similar table from Statoil has not (yet) been released, due to unresolved discussions withinsome of the licenses. Suppliers of pipe are involved in those discussions.

Representatives of Statoil and Norsk Hydro were interviewed. Both companies are commendedfor giving very open and detailed information about practices and experiences with flexible risers.The views that were presented in the interviews are reflected in the report. However, since theinformation was given orally, the authors of the present report are not in a position to quote thesources or to give specific references.

Representatives of all three suppliers of flexible risers were interviewed. The suppliers indicatedthat they are prepared to answer general questions only, preferably on a questionnaire format. Onexplicit questions it was made clear that very little information could be released on on-goingtechnical developments in materials technology. It was furthermore indicated that due to thesensitivity of the issues, approval to release information would take much time. For this reason,with the time allocation that was given for the project, it was not found feasible to pursue thisidea.

MARINTEK/SINTEF has been engaged in a variety of projects on flexible risers, also involvingmaterials technology. All of the work has been commissioned work with rather strictconfidentiality requirements. The experience from this work is reflected in the generalrecommendations given in the report.

2

TABLE OF CONTENTS

1 INTRODUCTION .................................................................................................................3

2 OBJECTIVES ........................................................................................................................3

3 MARTENSITTIC STAINLESS STEEL FOR PIPELINES..............................................3 3.1 Super martensitic alloy grades .........................................................................................3 3.2 Properties of super martensitic stainless steels.................................................................4

3.2.1 Tensile properties ..............................................................................................4 3.2.2 Hardness ............................................................................................................5 3.2.3 Welding metal chemical composition ...............................................................6 3.2.4 Corrosion properties..........................................................................................6 3.2.5 Fabrication, installation and operation of S13Cr pipelines ...............................8

3.3 The historical background for selecting S13Cr line pipe materials ...............................10 3.4 ”First users”....................................................................................................................11 3.5 Joint Industry Project initiative on SMSS, 1998 ............................................................12 3.6 SINTEF strategic funding ..............................................................................................13 3.7 EU project JOTSUP .......................................................................................................13 3.8 Recent initiatives ............................................................................................................13

4 FAILURES OF SUB SEA PIPELINES .............................................................................14 4.1 Vital properties for design of pipelines ..........................................................................14

4.1.1 Hydrogen embrittlement .................................................................................14 4.1.2 Local geometry and stress concentration ........................................................15 4.1.3 Welding and post weld heat treatment ............................................................15 4.1.4 Tensile properties and temperature .................................................................15

4.2 Subsea failures of pipelines on the Norwegian continental shelf...................................16 4.2.1 Åsgard and Tune reeling incident and Tune hyperbaric repair weld failures .16 4.2.2 Gullfaks failure................................................................................................17 4.2.3 Fracture at anode pads, Åsgard .......................................................................17 4.2.4 Failure of Åsgard Hub’s..................................................................................17

4.3 Failure caused by high temperature corrosion ...............................................................18 4.4 Summary of the subsea failures......................................................................................19

5 UTILISATION OF RESEARCH IN THE OFFSHORE INDUSTRY ...........................19 5.1 Fracture toughness and high strength steels ...................................................................19 5.2 Corrosion history and related R&D ...............................................................................21 5.3 Environmental Assisted Cracking..................................................................................21

6 QUESTIONNAIRE TO THE OFFSHORE INDUSTRY ................................................23 6.1 Summary of the questionnaire........................................................................................23

6.1.1 Knowledge gaps ..............................................................................................24 6.1.2 Increased robustness by improving the completeness of operational design..25 6.1.3 Technical management of pipeline construction projects and pipeline operation.........................................................................................................................26

7 DISCUSSION .......................................................................................................................26

8 REFERENCES.....................................................................................................................27

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1 INTRODUCTION Over the last three years the Norwegian Petroleum Directorate (NPD) has expressed some concern about the situation with respect to material selection and safety, triggered by recent experiences in the North Sea. During the period 1996 to 2002, 220 gas leakages (>0.1kg/s) have been reported on the Norwegian shelf /1/. Of the 220 gas leakages, 6 are connected to different types of failures on subsea pipelines, all involving through pipe wall fractures. The consequences of such failures are significant. The total cost (including the loss of income) of the five failures is estimated to some 5-10·109 NOK. The impact on environment and human health and safety has not been significant in these cases. Most of the 220 incidents are smaller topside gas leakages. Luckily none have set on fire. As background for mapping the development of risks with respect to failures/accidents within the offshore industry, NPD has desired an investigation with respect to robust material selection (RMS) on line pipe materials with emphasis on super martensitic stainless steels (S13Cr steels). A parallel study is performed on flexible risers and the common denominators of these to offshore applications are reported in the main report of the project. The basis for the selection was a meeting with the Norwegian Petroleum Directorate after delivery of the pre-project report /2/.

2 OBJECTIVES The objective of the present project is to summarize trends in material selection procedures in larger oil & gas companies. The work is based on the use of existing knowledge in SINTEF and NTNU and their industry network. The work will focus on a combination of industry experience and research experience.The outcome of this project is to prepare for a RMS methodology.

3 MARTENSITTIC STAINLESS STEEL FOR PIPELINES

3.1 Super martensitic alloy grades Common for all stainless steels is a minimum content of 11% Chromium. S13Cr steels have typically 11-12% Chromium. The microstructure is austenitec at temperatures beyond ca 900°C. Rapid cooling suppresses the formation of ferrite and martensite is mainly formed. With higher contents of Chromium than 12%, Nickel (and/or Manganese) must be added to be able to form martensite. Some remaining austenite and ferrite is typically present after cooling. The amount of remaining austenite is part of controlling the strength of S13Cr line pipe materials. Increased amount of remaining austenite reduces the strength. For the low strength S13Cr steels (yield strengths between 500 and 600MPa) it is assumed approximately 15-25% remaining austenite. Increased alloying with Molybdenum increases the corrosion resistance. The low content of carbon is the main contributor for the weldability. Super martensitic stainless steels are normally divided into three types /3, 4/:

1. Lean grade, 11Cr2Ni 2. Medium grade, 12Cr4.5Ni1.5Mo 3. High alloyed grade, 12Cr6Ni2.5Mo

Typical chemical composition for the three grades is outlined in Table 1. In the development of this steel type, several alloy sequences have been designed to meet requirements to an increased stress corrosion cracking resistance in the presence of H2S. In Table 2, major alloying sequences to meet targeted corrosion resistance are summarized. In addition to these environmental factors,

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sufficient low temperature toughness is required. In order to meet toughness specifications the ferrite content should be minimized. Hence, the ferrite forming elements such as Cr, Mo and Si must be counterbalanced by austenite stabilisators. In practice, this means Ni since both C and N levels should be lowest possible to maintain the optimum weldability through reduction of hardness. As rough approximations, Schaeffler type of diagrams can be used, although these were developed to predict the microstructure of weld metals. An example of this philosophy is the following set of Cr and Ni equivalents (elements in wt%): Creq = Cr + 1.37 Mo + 1.5 Si + 2 Nb + 3 Ti (1) Nieq = Ni + 22 C + 14.2 N + 0.31 Mn + Cu (2) When 13% Cr steels are selected, it should be noticed that service behavior also will strongly depend on the consumables employed.

Table 1: Typical chemical composition of supermartensitic 13% Cr stainless steels /3/.

Alloy grade Element 11Cr2Ni

(lean) 12Cr4.5Ni1.5Mo

(medium) 12Cr6.5Ni2.5Mo

(high alloyed) C (max.%) 0.015 0.015 0.015

Mn (max.%) 2.0 2.0 2.0 P (max.%) 0.030 0.030 0.030 S (max.%) 0.002 0.002 0.002 Si (max.%) 0.4 0.4 0.4 Cu (max.%) 0.2-0.6 0.2-0.6 0.2-0.6

Ni (%) 1.5-2.5 1.5-2.5 1.5-2.5 Cr (%) 10.5-11.5 11.0-13.0 11.0-13.0 Mo (%) 0.1 1.0-2.0 2.0-3.0

N (max.%) 0.012 0.012 0.012

Table 2:Alloy design to meet target corrosion resistance /4/.

Alloy grade Environmental parameters 11Cr2Ni

(lean) 12Cr4.5Ni1.5Mo

(medium) 12Cr6.5Ni2.5Mo

(high alloyed) T 20-100°C 20-100°C 20-100°C

P (CO2) 10 bar 20 bar 20 bar P (H2S) - 0.005 bar 0.050 bar

pH 3.5-4.5 3.5-4.5 3.5-4.5 Cl− 600-100,000 ppm 600-100,000 ppm 600-100,000 ppm

3.2 Properties of super martensitic stainless steels

3.2.1 Tensile properties 550MPa is the typical minimum specified yield strength (SMYS) of S13Cr line pipe steels. Experiences at SINTEF show that the yield strengths normally are between 600 and 730MPa. However, SMYS for the TUNE field was 640 MPa with a specified maximum of 760 MPa. The relatively large scatter is probably a result of the manufacturing process (i.e. thermo mechanical history). The results indicate that increased wall thickness normally is connected to reduced

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strength. This may be connected to a lower cooling rate of heavy walled pipes, giving less martensite. For S13Cr line pipe steels it is observed that the yield strength increases with increasing temperature /10/. From room temperature to approximately 150°C the yield strength increases 50 to 90MPa. The larger increase is found on low strength S13Cr, which indicates that increased amount of remaining austenite is connected with increased ability for martensite transformation. The transformation is believed to be induced by deformation and that increased test temperature increases the degree of transformation. This assumption is based on the observation of reversal to original tensile properties after heating and cooling. Testing between 150 and 200°C shows that the yield strength stabilizes. Above 200°C the tensile properties are reduced. It should also be mentioned that the tensile strength is reduced with almost the same magnitude as the yield strength increases. This will clearly affect the ability of strain hardening at elevated temperatures.

3.2.2 Hardness Prior to the large qualification work of the 13Cr steel class in the late 90-ties, a preliminary programme was carried out to study the relationship between the weld thermal programme (cooling rate, peak temperature, subsequent tempering) and heat affected zone (HAZ) mechanical properties (Charpy V notch toughness, tensile strength and ductility, hardness), using the weld simulation technique. Here, a wide range of martensitic steels was included, ranging from the “older” class with relatively high carbon content (~ 0.1% C) and no alloying with exception of Cr, to the new so-called “supermartensitic” grades with improved weldability, based upon low carbon (<0.02%) content and balanced additions of alloying elements such as Ni and Mo to improve the corrosion properties and to maintain the microstructure balance. This work was kind of a pioneer study, and was reported already in 1995 /11/. The results obtained showed that the “old, traditional” 13Cr steels contain too high carbon content, which give a very high hardness level of about 500kg/mm2. This is far beyond an acceptable level, even when applying tempering. With a hard martensite present, the steel will be very susceptible to hydrogen cracking, and expensive operations like preheating and postheating may be necessary, together with certain precautions regarding welding consumables and shielding gas moisture must be taken. In addition to the very high hardness, high carbon steels will inevitably give low Charpy-V impact values in the as welded condition. It was also shown that toughness varied substantially with the chemical composition of the steel. The toughness seemed to be impossible to predict from chemical composition only, whether it is high, medium or lean alloy. On the other hand, this early work showed that the toughness is nearly independent of the weld cooling rate (∆t8/5). Finally, it is interesting to note that the alloys with the best toughness had a very similar composition as those steels now being commercially available. One important observation is that it is possible to calculate the Ms temperature. In practice this is very important, since it may control the phase transformation start, and hence, the tome available for hydrogen diffusion during welding, and build up of weld residual stresses. This equation is as follows (discussed in ref./12/): Ms (°C) = 539 – 423 (%C) – 30.4 (%Mn) – 12.1 (%Cr) – 17.7 (%Ni) – 7.5 (%Mo) (3)

According to NACE MR-0175 the hardness requirement for weldable martensitic stainless pipeline steels is set to HRC=22 (HV10=249) for sour service applications (i.e. H2S partial pressure >3.5 mbar). This is practical impossible without reducing the strength considerably. Normal thermo mechanical procedures applied for S13Cr steel pipes give a hardness in the range 290-320 HV10 in the base material. Even for a so-called low strength material (YS=520MPa)

6

tested for the Tangguh development in Indonesia, the hardness was in the range 270-280 HV10 in the base material /10/. In the heat affected zone the hardness is increased to 340-360 HV10. Applying post weld heat treatment for 5 minutes at 620-650 °C has shown to be beneficial and decreases the hardness of the heat affected zone by 10-20 Vickers. Today the martensitic steels are welded using duplex/superduplex consumables. To avoid precipitation of sigma phases, reducing the mechanical and corrosion properties of the weld metal, a longer post weld heating time is not recommended. However, going for matching consumables this may be an option.

3.2.3 Welding metal chemical composition Girth welding of supermartensitic 13% Cr steels is frequently performed with mechanised GMAW process or manual GTAW, frequently with superduplex wire /15/. The weld metal strength has been shown to be very sensitive to the microstructural phase balance, the yield strength being fully controlled by minor amounts of soft austenitic and/or ferritic constituents /16/. The impact properties of weld metals are strongly dependent on the oxygen content. A sharp drop in toughness, from about 160 to 60 J, has seen when the oxygen content increased from 150 to 250 ppm. In practice, the properties of pipeline girth welds will thus be influenced by the welding process, the shielding gas, the welding consumables and the welding performance, see Fig.1, which contain data from GMAW, GTAW and SAW.

3.2.4 Corrosion properties Since the new weldable martensitic stainless steels were introduced in the mid 90'ties, the understanding of potential degradation mechanisms has increased their application limits. Also the way of testing and qualification has slightly changed with the new knowledge. Findings have also given input to revising standards as European Federation of Corrosion standard 17 specifying testing of corrosion resistant alloys and also input to change of company specifications. It has also had valuable input to revising the NACE TM 0177 standard and given input for the new ISO standard. Corrosion degradation mechanisms that have had special focus and may limit the use of these materials are:

• General corrosion at low pH's • Sulphide stress corrosion (SSC) • Stress corrosion cracking (SCC) and high temperature intergranular corrosion (HTIC) • Hydrogen embrittlement (HE) or hydrogen induced stress cracking (HISC) and its impact

on fracture mechanics behavior. These environmental assisted mechanisms are briefly discussed in the following

3.2.4.1 General corrosion at low pH In the first qualification program for the Gullfaks satellites and the Åsgard field, SINTEF reported high general corrosion for all samples tested for sulphide stress corrosion (room temperature, both on simulated condensed water and simulated formation water). This resulted in large discussions and an enlarged test program was executed in several labs. Early in the discussions SINTEF explained this type of corrosion by the use of Pourbaix diagram showing that these materials could turn active under a certain pH. Later research has shown that this pH limit is in the range 3.7-4.0. However, it is also discussed by Drugli et. al. that this corrosion will depend on the buffer capacity in the solution, temperature, H2S and flow conditions /6/. At low buffer capacity solutions as condensed water and moderate flow rates acceptable pH will be lower due to increased pH at the

7

surface during service, caused by the corrosion reactions. It is also shown that the passivity is improved at elevated temperature.

3.2.4.2 Sulphide stress corrosion (SSC) Welded S13Cr steel, type 12-13Cr/4-4.5Ni/1-1.6Mo, was tested with constant load testing (load ~90% of YS) in a buffered 5% NaCl solution with start at pH 3.5. The results were drawn from 720 hours testing. All welds failed in the buffered solution at pH 3.5 with 0.01 bar H2S and the one test with 0.004 bar H2S. At pH 5, a forge weld did not fail at 0.01 bar H2S while a TIG weld failed at 0.1 bar H2S. The results indicated that the tested alloy-range has threshold values of H2S between 0.1 and 0.01 bar H2S at pH 5 in a 5% NaCl solution and below 0.004 bar H2S at pH 3.5. The threshold values will also depend on the chloride content, partial pressure of H2S and pH besides of the alloying of the material. Published data for higher grade S13Cr steels type 13Cr/4-6Ni/0.7-1.5Mo and 13Cr/4-6Ni/2-2.5Mo have been gathered and the data indicate threshold values of 0.001-0.01 bar H2S at pH 3-3.5 and 0.01-0.03 bar H2S at pH 4.5-5 for both materials. Most data are for base materials, only a few for weldments. Different test methods are involved as slow strain rate, 4-point bend and constant load. A martensitic consumable with matching strength to the base material is of most interest. Consumables have been developed the last years and data have been published by SINTEF during the involvement in an EU project /7/. The results show similar values as indicated above.

3.2.4.3 Stress corrosion cracking (SCC) and high temperature intergranular corrosion (HTIG) Multipass welding has shown to sensitise the martensitic structure by precipitations along the prior austenite grain boundaries in the coarse grained heat affected zone /8/9/10/13/. These precipitations have been shown by Ladanova et.al. to consist of CrC (Cr23C6) /14/. Adjacent to these precipitates a narrow zone with depleted Cr occurs. The depletion zone is sensitive to corrosion. It is also found that these precipitates are mostly of TiC type for the Ti alloyed S13Cr steels. A short post weld heat treatment procedure at 650 °C for 5 minutes has shown to be beneficial and a healing of the depletion zone is shown to take place. Intergranular corrosion has not occurred on post weld heat treated samples. A time aspect in testing is highlighted especially after the NAM failures of lean grade materials, see section 4.3. The NAM failures show that corrosion of depletion zones may take time to initiate and the corrosion rate will be dependent on the test conditions. No systematic study has been undertaken to define the borderline conditions for this type of corrosion. The corrosion will depend on pH, buffer capacity, chloride level and temperature besides of the material quality (i.e. alloying).

3.2.4.4 Hydrogen embrittlement (HE) or hydrogen induced stress cracking (HISC) and its impact on fracture mechanics behavior In air, S13Cr and duplex steels have a CTOD (Crack Tip Opening Displacement) fracture toughness of about 0.7-1mm. Through fracture toughness characterizations on a high grade S13Cr steel, performed in the Fram Vest project, it was demonstrated a drop of CTOD to <0.02mm under normal cathodic protection (i.e. -1050mV SCE) at 4°C /17/. The cracking mechanism is stepwise brittle fracture. This has been further verified in an ongoing Joint Industry Project. The same mechanism is observed on super duplex and duplex steels, which drops to a CTOD value <0.03mm. These effects were unknown in 1995. In standard tensile specimen slow strain rate testing, several factors for the ratio (area reduction or time to failure) between environmental testing and testing in air, ranging from 0.5 to 0.9, have been suggested. However, for typical S13Cr steels the ratio ends up with values <0.1. The industry has argued that this method with slow deformation until fracture, is giving a high degree

8

of plasticity and unrealistic stresses. Therefore, they argue, that the slow strain rate method is not considered proper to evaluate the materials in specific environments. Other methods as constant load testing and 4 point bend were considered more appropriate with a given load/stress/strain and the results were more understandable and less conservative. These effects were known in late in 1995 and published by SINTEF in 1997 /18/. In fracture mechanics tests, a very sharp defect is simulated by a pre-fatigue crack. The stress intensity at the crack tip during loading represents high local deformation and builds up of hydrostatic pressure (i.e. stress tri axiality and plain strain). Large deformations are also reflected in slow strain rate tests of smooth tensile specimens. The fracture toughness is reduced by a factor of >35 times. This is even more than what found in a simpler test as slow strain rate (10-20 times reduction in the ductility). However, both test methods show that the material is extremely sensitive to hydrogen induced cracking during normal cathodic protection and high local stress and strain. Hydrogen embrittlement is increasing at low sea water temperatures.

3.2.5 Fabrication, installation and operation of S13Cr pipelines For the girth welding of pipes, welding procedure qualifications regarding mechanical and corrosion properties are well specified. More often the offshore standard OS F-101 (DnV 2000) makes the basis for the extent of the qualifications. Testing is performed on as welded test specimens and on specimens that are deformed to simulate the installation process. The latter is also artificial aged to simulate aging of line pipe material during operation. Testing of deformed and aged material is related to operational issues. For installation purposes the none deformed and aged condition (i.e. as received or "as welded" condition) is evaluated to match the actual properties. However, the deformation during the different stages of an installation process implies variations of the mechanical properties. This will affect the evaluation of where in the installation process criticality regarding maximum defect size is obtained. This is also linked to the circumferential position on the pipe, as the mechanical properties depend on the deformation history. The fracture mechanics test matrix would have been too extensive to be accepted by the industry if all property states should have been fully accounted for in an engineering critical assessment analysis. A simple and less time consuming approach is to simulate the different stages of installation by tensile tests. The tensile stress-strain curve of a material makes the basis for the failure assessment diagram, which limits the accepted range of maximum allowable defects. Experience gained through engineering critical assessments of pipeline construction projects has been a major approach to tailor-make engineering critical assessment analyses for safe utilization of pipelines. Deformed and aged material has shown to be more sensitive to brittle fracture compared to the as welded condition. The sensitivity is dependent on the strain amplitude of the deformation cycle, the number of deformation cycles (i.e. accumulated strain) and the aging. The strain amplitude is normally based on calculations considering the pipe dimensions and bending curvatures during installation. The number of deformation cycles is dependent on the installation method and considerations of reversed installation for repairs etc. The sensitivity to brittle facture is often related to the properties of the weld deposit and the fusion boundary. Carbon steels are more sensitive than S13Cr steels and duplex steels. This is believed to be connected to the increased marking of the upper yield strength after deformation and aging of carbon steels. All steels show elevated yield strength, reduced strain hardening (less Rm/Re ratio) and some reduction of the ductility after cyclic deformation and aging. The installation process (c.f. J-laying and reeling) apply roughly the opposite deformation of the 12 o'clock and 6 o'clock positions. The 12 o'clock positions complete the deformation cycles typically in a compressive state and the 6 o'clock position typically in tension. For input to a

9

fracture mechanics analyses, the properties of the 6 o'clock position has shown to be most critical. Evaluations of criticality related to deformation history and artificial aging are lacking in todays specifications and the knowledge on deformation and aging is not fully understood and quantified. Traditionally the properties of the 12 o'clock position are used. Eventual weld defects are detected and measured by means of automatic ultrasonic testing during fabrication. The lower bound limitation of the ultrasonic equipment used is normally a defect height of 2mm (accounting for the uncertainty of the test method). The equipment can detect much smaller defects, but the accuracy becomes quite limited. This type of equipment has shown to increase the level of detections and increase the applicability (as it measures/quantifies defect size) for girth welding of pipes compared to other methods. Normally girth weld defects are extended in the circumferential direction. Typical defects are interpass lack of fusion and extended pores. The engineering critical assessment is performed to predict the maximum allowable defect during installation. Due to the resolution of the ultrasonic equipment used today, the maximum allowable defect size must normally be larger than 2mm height. This requirement is normally associated with a 50mm length of the defect. For girth welded line pipe steels, with ductile behavior during the fracture mechanics testing, the experience is that the maximum allowable defect height ranges between 3 and 5mm (x 50mm length). The JIP guideline is established for installation methods introducing plastic deformation. Operational issues are not fully accounted for. As mentioned in section 3.2.4.4, the fracture toughness is significantly reduced under normal cathodic protection due to hydrogen embrittlement. Recent research in the ongoing JIP indicates the same effect on crack growth rates during fatigue loadings. This has clearly impact on the operational limitations and the prediction of lifetime. Moreover it indicates that the criticality to maximum allowable weld defects size could be moved from the installation process to the operational static and fatigue loadings.

3.2.5.1 Operational engineering critical assessment In the following an example of operational engineering critical assessment is performed to show the interaction of design stress and operational limits. A 12 inch steel pipeline with wall thickness 15mm has been qualified for the J-laying installation method. In other words; the maximum allowable defect size is larger than 2x50mm. How is the integrity of the pipeline during operational conditions, including hydrogen embrittlement from normal cathodic protection? A normal design criterion for the offshore industry is to utilize the line pipe materials up to 70-80% of the yield strength during operation. This could be related to the specified minimum yield strength (SMYS) or the actual yield strength (YS). Both approaches have been used by the industry. In this case the minimum specified yield strength is used (i.e. most conservative) and a level of 75% utilization. It is presumed that the maximum allowable defect size for all cases is the lower limit (2x50mm), which is the most conservative starter crack for operation. During installation ductile crack growth extends the height of the defect with 1mm to a total defect size of 3x50mm. Possible interactions with other minor defects are estimated to add to an accumulated defect size of 3x60mm. Operational engineering critical assessments have been performed for X65 carbon steel (SMYS 450MPa), S13Cr steel (SMYS 550MPa) and duplex steel (SMYS 450MPa) with the dimensions as above. Residual stress from welding is accounted for by means of the relaxation model of BS7910. Stress concentrations from the weld toe and eventual pipe misalignments are not accounted for in the analysis. The fracture toughness of duplex steel and S13Cr steel are extracted from tests performed under normal cathodic protection at 1 atm pressure/4°C at SINTEF.

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Relevant results on X65 carbon steel are found in literature /19/. The results are presented in table Table 3.

Table 3: Results of the engineering critical assessments

Material SMYS

[MPa]

Max. design stress [MPa]

Actual YS

[MPa]

CTOD fracture

toughness [mm]

Defect size

a x 2c [mm]

Critical membrane

stress [MPa]

X65 carbon steel, BM 450 338 556 0.7 3 x 60 564 S13Cr steel, welded 550 413 648 0.02 3 x 60 371 Duplex steel, BM 450 338 630 0.03 3 x 60 419

The environmental impact on the carbon steel is very limited and the operational critical membrane stress is above the actual yield strength and well beyond the maximum design stress. The duplex steel is also considered safe in the assessment, but the safety of duplex steel is clearly limited compared to the X65 carbon steel. If the actual yield strength of the super duplex material was used as a design basis, the maximum design stress would have extended well beyond the calculated critical membrane stress. Such case is considered unsafe. For the S13Cr line pipe material the maximum design stress is clearly outside the range for safe operation. The critical membrane stress (i.e. 371MPa in Table 3) correlates well with results obtained on single edge notch tensile fracture mechanics tests under normal cathodic protection. A critical net section stress of 370MPa was found for initiation of hydrogen induced stepwise brittle fracture /21/. The performed analyses establish the critical stress level for fracture of the pipe during static loading. The maximum fatigue stress is lower than the stresses presented in Table 3. The fatigue crack growth rate is vital input for operational critical assessments. Such data are not published yet, but results are produced in an ongoing Joint Industry Project (see section 3.8).

3.3 The historical background for selecting S13Cr line pipe materials The last two decades have faced an increasing application of corrosion resistant alloys for pipings, pumps and valves in the production of oil and gas. Expensive high alloyed corrosion resistance alloys as the duplexes have been applied to a large extent, as an alternative to C-steel and inhibitors. In the search for less expensive solutions for field developments in the oil production industry, the oil companies are looking for cheaper materials with satisfactory mechanical strength and corrosion resistance. Delivery capacity was also a factor that was considered. In recent years, steel suppliers have developed new martensitic stainless steels with 12-13 % Cr and small amounts of Ni (5-6%) and Mo (1.5-2.5%). These steels are today more or less referred to as Super 13Cr or weldable (low carbon) martensitic stainless steels. These have significant increased corrosion resistance in sweet service compared to traditional martensitic grades, and satisfactory welding procedures have been developed. Extensive research has been conducted around the world to establish a better basis for evaluating their application for transporting unprocessed oil and gas. Cost benefitStainless steels are used extensively in the oil- and gas industry because of the hostile environmental conditions. The steels are mainly used in piping systems and especially flowlines. Candidates are in many cases a choice between duplex stainless steels, carbon steels and S13Cr steels. Selection of carbon steels requires the use of inhibitor. Duplex steels have excellent corrosion properties, but are rather expensive. The potential for savings can be illustrated by a simple example. The price relation between duplex and S13Cr is

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approximately 3:2. The yield strength of duplex is within the range 400-450MPa and 600-700MPa for S13Cr. The utilisation of the material is often related to the yield strength, and the total potential for cost reduction is 50-60% compared to duplex line pipe materials. The increased strength and good fracture toughness of S13Cr are relevant for installation methods involving larger plastic strains as reeling. Reeling is a widely used method today and represents cost and time benefits compared to traditional fabrication and installation techniques. Development of new fields The savings by use of S13Cr have contributed to more cost effective construction and installation compared to duplex line pipe materials. The operational savings are significant compared to carbon steel line pipes as well, if the costs related to the S13Cr pipeline failures are excluded. This is mainly caused by the removal of the inhibitor. These savings can be vital information when extensions of the number of fields that can be developed are considered. This is especially important today as the remaining fields on the Norwegian shelf are many in numbers, but are significantly limited in volume compared to the larger productions fields. It is also important that the Norwegian oil industry is in the front line in cost effective development and maintenance in order to be a preferred partner in the development of oil/gas projects on an international basis. Environmental aspects The higher strength of S13Cr compared to duplex steels will reduce the material consumption with 25-35%. This development will be positive from an environmental point of view, first of all because the consumption of steel is reduced, but also because the reduced weight makes it easier to transport and handle (e.g. pre-installation, installation and removal after final production/ lifecycle). Inhibitors are frequently used in pipelines made of carbon steels to control the corrosion behaviour. The use of inhibitors is, however, considered negative from an environmental point of view. By substituting carbon steels with stainless steels the pollution factor is removed.

3.4 ”First users” Hydro took the first initiatives on designing S13Cr as pipeline material for the mild sour and sweet environments, typical for the Norwegian shelf. In 1992 Hydro started a co-operation with Kawasaki Steel on optimising chemical composition and to develop welding procedures. Testing of corrosion resistance and mechanical properties was undertaken. Statoil took part in the development of S13Cr steels in 1994. Prior to the final decision to select weldable S13Cr for subsea pipelines, Statoil run a large programme to study the mechanical and corrosion properties of different weldable S13Cr steels. The programme was performed in the period 1994-1996. However, pipes and field welding were not available and heat affected zones were produced by weld simulation. The process converged to weldable low-carbon S13Cr steels of the same type used today, alloyed with Molybdenum and Nickel. See section 3.2 for typical alloying content and properties. First user was Statoil on Gullfaks Sør and the Åsgard field, using combination of duplex and super duplex filler material, based on prior experience of the fabricator Coflexip Stena Offshore Norway (today Technip Offshore Norway). The properties of the girth weld and adjacent pipe heat affected zone was focused as defects are normally concentrated in the weld and at the fusion line. The fusion line is in conjunction with the heat affected zone and the microstructure of the heat affected zone is normally most susceptible for corrosion and embrittlement mechanisms. The first laboratory tests on sulphide stress corrosion revealed that in simulated condensed water, all samples suffered from adhanced general

12

corrosion of the base material when tested according to existing specifications like EFC 17 and NACE TM-0177. The specifications at that time implied a strong buffer of NaAc (4g/l) and a pH of 3.5. More testing at Statoil, SINTEF and manufacturer showed the same results. More basic research studies at SINTEF, funded by Statoil, showed that this phenomenon was related to the strong buffer, which maintained a low pH at the surface. The electrochemical reaction will normally result in higher pH in low or non buffered solutions. The specification has been changed and a diluted buffer is applied today using 0.4 g/l NaAc /6/. See also chapter 3.1.4.1. The pre-qualification and qualification programs on Åsgard, using test methods from which experience had been gained on carbon steels, was promising. After the buffer adjustments mentioned above, the results showed acceptable corrosion resistance to relevant environments. The fracture toughness was improved compared to carbon linepipe steels, especially the risk of brittle fractures at low operational temperatures. In addition, the strength was significantly improved. After final adjustments on welding process and -wire (see section 4.2), the Åsgard pipeline project seemed to be a straight forward qualification programme. However, internal research at SINTEF indicated significant reduced ductility of S13Cr under conditions of normal cathodic protection. See section 5.2 and 3.2.4.4 for more details.

3.5 Joint Industry Project initiative on SMSS, 1998 S13Cr as pipeline material was installed on the Norwegian shelf in 1997/1998 on several projects. The results were considered positive on both a technical and economical basis. The projects had international focus and they gave the Norwegian offshore industry a positive promotion. A preproject was initiatied and financed through Stålmat Forum (forum for Norwegian steel users and fabricators /21/) with the purpose to establish a programme for further research and optimisation of S13Cr as a candidate for subsea pipelines. Stålmat Forum is sponsored by the member companies and the Norwegian Research Council through the VARP R&D programme. At that time, the most important tasks for the S13Cr research progamme were /22/: • Develop fabrication procedures where the welding process is optimized for the actual alloys • Develop acceptance criteria for mechanical properties and defect tolerances for pipes under

pipelaying and service conditions • Determine the corrosion properties in welds, HAZ and base material • Extend the application range of S13Cr materials

The proposed programme was a combination of applied and fundamental research with a time schedule of 4 years and a budget of 42 MNOK. 60% was intended financed by the industry (e.g. O&G companies, fabricators, consumable manufacturers, pipe manufacturers) and the remaining by the Norwegian Research Council. The Norwegian Petroleum Directorate emphasised the importance of the proposed S13Cr research programme and recommended the project for the Nowegian Research Counsil. However, the programme was not supported by the Norwegian Research Council due to low prioriety in materials technology and low budgets. The industry became reluctant and the JIP initiative terminated. Extensive pre-qualification and qualification programmes, based on traditional test and analysis techniques, and limited project R&D have partly compensated the planned investigations in the JIP, but the fundamental and systematic scientific approach is limited. The results are implemented in company- and construction project specifications, leaving especially three topics out: • few implementations of results in national or international specifications and standards

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• limited systematic testing, comparison and evaluation of matching S13Cr welding

consumables and duplex/super duplex consumables • limited research on fundamental understanding of degradation mechanisms (3 Ph. D.

candidates were proposed in the JIP) Investigations on fractured pipelines on the Norwegian shelf (see chapter 4.2) have exposed scientific areas with fundamental lack of knowledge. Through the failure investigations, it has for example been documented that hydrogen embrittlement can be very critical. Field experience and “first users” are vital for fully exposing critical parameters from pipe manufacturing, fabrication, installation and operational conditions. Even though the proposed S13Cr research programme contained the subtask “Hydrogen assisted cracking”, it is not evident that all the relevant mechanisms and sources of hydrogen would have been exposed as critical through the proposed programme.

3.6 SINTEF strategic funding Based on alarming results from slow strain rate testing on smooth S13Cr tensile specimens in 1995-1996, SINTEF Materials Technology decided in year 2000 to invest in new equipment for fracture mechanics testing under environmental impact. This was financed through internal strategic funding and included a R&D programme with a total of 2.5-3.0 MNOK. The results from this R&D programme is highlighted towards oil industry, engineering companis and steel manufacturer and and published /18/. The results has been discussed in several fora as the EFC working party on O&G.

3.7 EU project JOTSUP The JOTSUP project started in January 2000 and was terminated in January 2003. In this project focus was put on high production welding and little on corrosion. From Norway Statoil and SINTEF were partners with a budget of 550-600 KEURO each and 50% was funded by EU and the 5th framework. The other 50% was sponsored by Statoil and SINTEF themselves. Focus here was put on materials developed in Europe (Industeel) and new matching consumables developed by ESAB and Bøhler Thyssen. Corrosion verification was limited to sulphide stress corrosion limits undertaken at SINTEF /7/. However, one important finding in the JOTSUP project was that hydrogen may strongly influence the fracture stress and ductility /19/. Here, matching consumables were used in terms of a Thermanit 13/06 Mo MIG wire from Bøhler Thyssen and a metal cored OK Tubrod 15.55 wire from ESAB. The results showed the fracture stress was remarkably reduced as the weld metal hydrogen content increased, i.e., from 800-900 MPa for 4 ppm to 400-500 MPa for 15 ppm hydrogen. Similar reduction in fracture ductility was observed. For low weld metal hydrogen content, the fracture appearances were ductile with typical dimples. At high hydrogen concentration, th fracture surfaces consisted of dimples and cleavage facets (fish eyes). The fish-eyes observed had diameters up to 80 µm, and represent a strong indication of hydrogen embrittlement. By performing heat treatment (225ºC for 24 hours) of the weld metal deposited with full moist shielding gas, with subsequent tensile testing, an increase in the fracture stress from 300 MPa to 1050 MPa was obtained. This means that the weld properties may be restored by the use of hydrogen diffusion treatment.

3.8 Recent initiatives In 2003 a Joint Industry Project was initiated on hydrogen embrittlement and pipeline integrity. The project is supported by Hydro and STATOIL and is executed as a collaboration between DNV (Det Norske Veritas) and SINTEF. The experiences from previous R&D projects and failure

14

investigations are summarised /25/. The basis for a wider international Joint Industry Project is established through this work. The content of the future project has focus on closing knowledge gaps by: • develop test methodology within the area of environmental assisted fracture mechanics • use of the new test methods to establish critical limits for actual pipeline materials as S13Cr

steels, duplex steels and carbons steels under operational conditions • optimise material specification and utilisation • optimise welding procedures and evaluate matching consumables for S13Cr • addressing fundamentals related to mechanisms of hydrogen embrittlement for pipeline

materials as a major scientific task (combined research institute work and Ph.D. student programs)

The content of the project has most probably international interest. This assumption is made on a basis that not only S13Cr steels have shown significant reduced properties under cathodic protection, but duplex steels as well. Duplex steels as line pipe materials are from most operators looked at as a robust and safe selection. This situation is now changed. It is also known that hydrogen has impact on high strength carbon steels. The proposed programme have the intensions to study carbon steel grades representing line pipe grades from X80 to X110. In Norsk Hydro's development of the Ormen Lange field, it is decided to use duplex/superduplex for the manifold and pipes from manifold and carbon steel mainline. The recent experiences have lead to an initiative from Norsk Hydro to verify the robustness of these materials with respect to hydrogen induced cracking. A project has been started in 2004 executed by SINTEF and DNV in cooperation.

4 FAILURES OF SUB SEA PIPELINES

4.1 Vital properties for design of pipelines

4.1.1 Hydrogen embrittlement Hydrogen embrittlement is normally associated with cathodic protection in conjunction with welds, more specific heat affected zones. The weld toe, or similar surface offsets, will act like a stress concentration area and the microstructure of the heat affected zone is likely more sensitive. In addition, the residual stress from welding adds on the local stress level. Cracking usually initiates at the fusion line or close to the fusion line in the heat affected zone. Cracking or failures have been documented to be caused either by • hydrogen from the welding wire or moisture in the shielding gas or condensation on the

pipe/groove surface • by hydrogen uptake and diffusion from cathodic protection. Based on diffusion measurements, the critical surface concentration of hydrogen from cathodic protection seems to be between 1.3ppm and 9ppm, corresponding to hydrogen obtained at -900mV and -1050mV SCE respectively. Long duration tests have shown that the hydrogen level in martensite can build up to 10-15ppm when saturated, which is far above the critical level needed to embrittle typical S13Cr line pipe materials. The critical local hydrogen concentration where cracking takes place may be much higher. As the areas that are susceptible to cracking are local, an exact value of the hydrogen level is very difficult to measure. Through diffusion, hydrogen may also be increased at the fusion line and adjacent heat affected zone due to the high content of hydrogen that can be dissolved in the duplex/superduplex weld metal.

15

4.1.2 Local geometry and stress concentration Critical stress concentration is the second important factor. Global stresses well below the material yield strength could, because of local geometry, increase beyond yield and apply local plastic deformation. Typical geometries that affect the local stress are: -material strength mismatch -pipe misalignment -counterbore -surface irregularities/defects -transition at weld toe -transitions to other pipe dimensions -attachments on the pipe like anode pads Operational shut downs, shut ins, pressure testing (RFO), tie in, vibrations, free spans and tides will add on with fatigue on the pipeline. A critical event is most probably obtained when the local strain breaks the chromium oxide by repeated loadings or by increased accumulated deformation. The breaking of the chromium oxide will lead to a significant increase of local hydrogen uptake. Cathodic protection at a potential of -1050 to -1100 mV SCE (normal sacrificial anode potential), polarize the corrosion resistant alloys to a potential were the materials are in the immune area. That means that surface oxides that are removed will not be reformed.

4.1.3 Welding and post weld heat treatment Few comparable tests have been performed comparing S13Cr weld metal and duplex weld metal on S13Cr pipeline. A few slow strain rate tests on round sub sized cross weld tensile specimens have been performed and the results showed that the S13Cr weld metal gave a large scatter on ductility compared to the duplex weld metal when cathodic protection was applied. The reason for this can not be explained based on the existing data. Less investigation has been conducted on S13Cr filler and the effect of post weld heat treatment. If post weld heat treatment has a beneficial effect, longer holding times can be applied compared with todays practice on duplex welds, since the microstructure of S13Cr is not as sensitive as duplex regarding precipitation of sigma phase. Sigma phase reduce the corrosion properties and fracture toughness of duplex. In addition the S13Cr weld metal has a favourable higher strength, causing less deformation of the weld. The effect of post weld heat treatment has not been fully documented regarding hydrogen embrittlement. So far, it is indicated a slightly decreased sensitivity with post weld heat treatment. More investigations are needed to confirm this statement. On the other hand post weld heat treatment is recommended for increased resistance to internal corrosion in the heat affected zone, as the post weld heat treatment most probably reduces the depletion of Chromium carbides at the grain boundaries /14/.

4.1.4 Tensile properties and temperature The yield strength of duplex and super duplex steels decreases with increasing temperature which is normal for metallic materials. S13Cr is the opposite. The yield strength increases with approximately 50-90MPa if the test temperature is increased from room temperature to 120ºC /5/. This means that evenmatching weld metal (which is the normal case of super duplex welds on S13Cr pipes) at ambient temperature will change to a significant undermatch situation at typical service temperatures. If high loads are present on a pipe section during operation, significant deformation of the duplex weld metal can occur. During shut in with increased temperature and increased internal pressure, both addressing an expansion of the pipeline, a significant undermatch situation can lead to increased risk of buckling with subsequent cracking. The unfavourable undermatching of duplex welds will probably be avoided by applying S13Cr fillers. Still work has to be done to increase the ductility and fracture toughness of the S13Cr welds. Investigations

16

regarding the alloying of the welding wires, type of welding method, welding process and post weld heat treatment are needed.

4.2 Subsea failures of pipelines on the Norwegian continental shelf Approximately 320km of S13Cr pipelines are installed on the Norwegian continental shelf. Most of these pipelines are girth welded approximately every 12m, giving a total of 27 000 to 30 000 girth welds. Within the next few years it is indicated the total length will be increased to approximately 500km of S13Cr pipelines on the Norwegian continental shelf. The following failures on subsea pipelines on the Norwegian shelf have been investigated: • fracture of Åsgard pipeline during reeling. Detected during reeling on, 1998 • anchor damage Åsgard. Internal pitting corrosion detected during post-incident investigations,

1998 • fracture of the TUNE pipeline during reeling on/off. Leakages detected during subsea pressure

testing, 2001 • fracture of the TUNE pipeline after hyperbaric repair welding. Detected during subsea

pressure testing, 2001/2002 • fracture of Åsgard HUBs (not S13Cr). Initially detected during pressure testing and later

during operation, 2001 • two fracture in conjunction with anode pads on the Åsgard field. Detected during operation,

2002 • fracture of Gullfaks pipeline at towhead. Detected during operation 2003 • fracture of superduplex at Garn-Vest. Detected in June 2003. The common denominator of all the failures listed above is hydrogen embrittlement or hydrogen induced stress cracking, except the anchor damage at Åsgard. The internal corrosion found during the investigation of the anchor damage is considered irrelevant and is not commented further. But the high temperature internal corrosion experienced by NAM in Holland is presented (see section 4.3). In the following the failure investigations are shortly discribed and discussed /25/.

4.2.1 Åsgard and Tune reeling incident and Tune hyperbaric repair weld failures Leakage and failure have been obtained for both duplex and matching S13Cr welding consumables (Åsgard reeling incident and Tune, respectively). But the sequence of cracking is probably different, due to the inherent large difference in hydrogen diffusion ability between the two cases (i.e. much lower diffusion rate of hydrogen in duplex). The Åsgard reeling incident was explained by diffusion (release of hydrogen) from the duplex weld metal into the S13Cr heat affected zone during subsequent coating and thermal insulation process (at approximately 100-150°C) resulting in fusion line cracking. By contrast, weld metal cracking was found in the Tune case. Investigations have shown that diffusion of hydrogen in ferrite-austenite is slow, but most studies focus on base metal microstructures, which are very different from those formed during low heat input multipass welding. Here, more investigation is needed to verify the suggested mechanisms. The Åsgard reeling incident concluded that duplex consumables for S13Cr pipeline welding shall be heat treated (so called baked) and delivered with maximum 3ppm Hydrogen. This requirement is today implemented in internal company specifications. Implementation into national and international specifications is recommended.

17

The Tune hyperbaric repair welding clearly demonstrated that moisture in the shielding gas during welding of S13Cr is unfavourable. The repair welds fractured in a brittle manner, and it was concluded that the moisture arose from the subsea transport hoses of the shielding gas. The Tune flowline was replaced with a carbon steel line pipe material.

4.2.2 Gullfaks failure The recent failure at Gullfaks indicates that hydrogen from welding caused cold cracking to take place /26/. The cracking was initiated in the transition girth-weld-toe to pipe-surface. The weld toe of the girth weld acted as a stress concentration on the pipe. The cracking extended from the weld toe/fusion boundary and into the S13Cr heat affected zone. The cracking could have been introduced by lack of degassing of the duplex consumables to reduce eventual unfavourable content of hydrogen, see section 4.2.1. There is also a possibility that moisture in the shielding gas or condensation on the pipe wall could have been the hydrogen source. To verify the source of hydrogen in this failure investigation is impossible without proven documentation of the welding wire and welding process. It is believed that the extension of the cold cracking did not penetrate the pipe wall. The through thickness fracture, giving leakage, was brittle with evidence of secondary cracking. Secondary cracking is typical for hydrogen embrittlement. Long term diffusion of hydrogen from the weld deposit could be the embrittlement mechanism of the final fracture, even though the measured levels of hydrogen were below critical values in the duplex weld and neighbouring S13Cr pipe. Hydrogen from cathodic protection is assumed to play a minor role as the coated and thermal insulated field joint, surrounding the area of the failed pipe section, is believed to have given sufficient bonding to the pipe, insulating sea water at least 300mm away from the fracture. Even though calculations on hydrogen diffusion have shown that hydrogen can diffuse far and increase the local hydrogen concentration to levels above critical levels for cracking, further studies are needed to document the diffusion in such cases.

4.2.3 Fracture at anode pads, Åsgard Operational pipelines are exposed to global loading that locally can exceed yield due to local stress/strain intensities caused by geometry and material mismatch. Calculation for the Åsgard anode pad gave a stress concentration factors in the range of 2-2.5, which implies that local plastic deformation has taken place /27/. This is a result from a sum of residual stresses from welding, local geometry and external loading. The fractures occurred in pipe sections with high global stress given by free spans of the pipeline. The seawater has penetrated through the thermal insulation following breaks/openings between the insulation and the pad-to-anode connections. Hydrogen from cathodic protection combined with local plastic deformation is believed to be the mechanism of the observed fractures.

4.2.4 Failure of Åsgard Hub’s Traditionally the transition pipe-to-flange (e.g. Hub) is made of heat treatment steels of typical carbon steel grade AISI 8630. Heat treatment steels are not the topic of this report. Still it is considered interesting as the failure analyses points at bi-material joints, residual stress, hydrogen embrittlement, microstructure/heat treatment and quality assurance. The heat treatment steel, which have a carbon content of approximately 0.3%, is considered not weldable for structural applications. To avoid the brittle heat affected zone of such high carbon steels, the fabricators build up a weld deposit on the end surface called buttering weld. Normally inconel 625 alloys (high strength austenitic stainless steel) are used. Heat treatment at 650°C/4 hours is performed to obtain acceptable toughness on the heat affected zone of the flange material. The buttering weld is

18

often an elongation of the internal clad weld of the Hub. Cladding is performed to sustain the internal corrosive environments. The failures of the Åsgard Hubs showed that the fractures were located at the fusion boundary between the buttering weld and the flange material /28/. The conclusions of the failure investigation were as follows: • unfavourable groove geometry (e.g. perpendicular to the loading axis) • the heat treatment has activated diffusion processes giving significant embrittlement of the

inconel side of the fusion boundary due to carbide precipitations and formation of martensite. The heat affected zone of the carbon steel (e.g. flange material) was embrittled by significant decarburisation, giving formation of coarse ferrite

• a significant local strength mismatch was experienced with micro Vickers hardness in the range 450-600 on the inconel side of the fusion line and ca 220-240 in the heat affected zone in the flange material

• cooling from the heat treatment temperature to room temperature has introduced significant hoop and radial residual stresses (in the magnitude of 300-600MPa through elastic finite element analyses)

• high levels of measured hydrogen at the fusion boundary indicates poor control of filler materials and/or welding process. It is indicated that cathodic protection could have increased the hydrogen concentration during operation

72 Hubs was replaced at the Åsgard field. Several thousands of other Hubs are located in subsea pipeline systems around the world… Later investigations showed that the mechanical properties are very sensitive to the heat treatment temperature /29/. It is indicated that heat treatment of buttered and cladded Hubs most probably is unfavourable regarding the microstructures on both sides of the fusion line and the residual stress. It is also clear that the qualification procedures for the buttering weld does not represent the same verification level as for load carrying girth welds of a pipeline system, even though the loading characteristics at the transition to the flange at least matches the loading of the pipeline. A new design developed by Statoil, using cladded weldable carbon steel type F65 to avoid the buttering weld, was mainly used in the replacements. The new carbon steel design also reflects the limited short term availability of large diameter forged qualities of duplex materials internationally. The duplex qualities of such dimensions are also often connected to unfavourable brittle sigma-phase precipitations, which will reduce the corrosion resistance and fracture toughness significantly.

4.3 Failure caused by high temperature corrosion Experiences by NAM in Holland have put attention to these materials susceptibility to high temperature corrosion. One case of lean grade (low alloyed) seam welded (laser welded) onshore pipeline showed intergranular corrosion after a few years in service, and recently two seamless pipeline (also lean grade) leaked after short time in service. All fields were sweet service and temperature below 80°C. The latter corrosion mechanism was pointed out by SINTEF as a possible problem first time at the Eurocorr 2001 /8/ and a summary was given at the supermartensitic 2002 conference /13/. Here also mechanisms were suggested and discussed in a paper by Ladanova et.al./14/. NAM decided to replace the pipelines with duplex stainless steels and has not considered S13Cr steels for sweet or sour service applications since.

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4.4 Summary of the subsea failures From the failure investigations it can be concluded that S13Cr was in the category “new material in known environment”. The corrosion properties and limits for S13Cr steel was focussed and other environments was neglected as a problem due to existing knowledge at that time on materials as duplex and super duplex stainless steels. The unknown environment was initially unfavourable hydrogen content in the welding consumables causing cracking on S13Cr and not on the duplex steels. Secondly it was humidity in the shielding gas or condensation during the welding process. Thirdly is was clear that normal cathodic protection systems, to protect the outside of the pipeline from corrosion, was a major source of hydrogen during operation. All these sources of hydrogen have showed to be detrimental for S13Cr. It is clear that the indications on hydrogen embrittlement on S13Cr from the research institutes and universities in the mid 90-ties was not targeted and understood by the offshore industry prior to the use of the new pipeline material. The Hub failures also points at unsatisfactory quality assurance and design. It should be clear for manufacturers of Hubs how their product is used in a pipeline system, and more specifically, that the buttering weld is loaded to stress levels similar or even higher than in the pipeline because of geometry constraints from the stiffer flange and the very high levels of residual stress. The qualification and requirements of such should therefore at least match the type and amount of testing required for qualification of pipeline girth welds. This was not the case. The lack of documentation should have been picked up by the operator, which in first place is responsible. And, as mentioned earlier, the design was poor by means of unfortunate material combinations, heat treatment and groove geometry. The anode-pads are a good example of poor design. Bringing a relative stiff body onto a rather flexible pipe will generate stress concentration. In addition, the connector between the anode and the pad is penetrating the pipe coating and thermal insulation. This has shown to be a weak link regarding the possibility of seawater access to the pipe wall. New designs are already implemented. Pipe failures linked to anode pads have occurred in conjunction with free spans (i.e. in highly loaded pipe section). Even with a poor pad design, the failures could have been avoided by better planning and control of the position of the pipe on the seabed to reduce the stress in the pipe, or planning of positioning of the anode pads outside highly loaded pipe sections.

5 UTILISATION OF RESEARCH IN THE OFFSHORE INDUSTRY

5.1 Fracture toughness and high strength steels The driving force for research regarding increased strength on offshore construction steels is not mainly focused on the strength itself. The fracture toughness of the heat affected zone from a weld has shown to be a limiting factor. Also the requirements of overmatching strength and acceptable fracture toughness of the weld deposit are vital parameters in the process of development of high strength offshore steels. The driving force for the development of fracture mechanics have been the need to design and operate safe nuclear power plants, where failure has to be avoided by all means. The standards for fracture mechanics testing and defect assessment is influenced by this way of thinking. Lower bound solutions are used so that the fracture mechanics testing and analyses becomes simple and safe for many situations. The negative side of this is that the analyses become very conservative and that they do not catch sensitive parameters for increased utilization.

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For many offshore applications the standardized defect assessment procedures become too conservative, and workmanship criteria that in some cases are less conservative than standard Engineering Critical Assessment analyses are used instead. The danger is that the workmanship criteria become too static. There is a continuous development of new welding procedures and pipeline steels. Workmanship criteria that do not reflect these changes in material properties are potentially dangerous to use when there is a rapid development in materials. Critical defect size in welds and at fusion boundaries for offshore applications have, for decades, been predicted through Engineering Critical Assessments, following the procedures of PD6493 (now BS 7910) and standard test methods for determination of fracture toughness (like BS 7448). It has been demonstrated, through large scale wide plate testing, that the assessments have been very conservative. The conservatism is mainly linked to the significant different constraint of planar defects in the construction compared to deeply notched standard test specimens. How residual stress interacts with the fracture toughness is not clearly understood. But it is clear that the approach used today is conservative (cf. BS 7910). Still these assessments are considered as vital input for design. However, it has continuously been called for procedures to limit the conservatism. Hence, we have to be aware that the historically high degree of conservatism in the testing and analyses may have been a main contributor to the robustness of the material selection and probably compensated for unexpected or unknown effects when such have occurred. The last years research have been performed to develop more tailor-made fracture mechanics testing procedures and defect assessment analyses for offshore pipelines. The methods is more accurate and is better suited to catch critical changes as a result of the development of new linepipe materials, welding procedures and pipeline geometries. More accurate methods are important tools to avoid unnecessary conservatism and to quantify safety. Today the conservatism of fracture mechanics assessments on pipelines is quite limited (e.g. for reeling and J-laying in particular, TWI/DNV/SINTEF JIP Report 2003; "Project Guideline for Pipeline Installation Methods Introducing Cyclic Plastic Strain" /30/). This JIP Guideline will be converted to an open DnV RP within year 2004. The guideline specifies several changes from the general standardized fracture mechanics test and assessment procedures, for instance the introduction of the new small scale fracture mechanics test specimen (Single Edge Notch Tensile specimen) that is tailor made for pipelines. The new test specimen geometry is specified. The new guideline is much more accurate than general standards for defect assessment procedures. The result is confidence to defect assessment analyses by the offshore industry. The use of defect assessment analyses of pipelines that can catch eventually critical combinations of defects, loading and material properties is important for a continuous development and safe use of new technology for offshore pipelines. Another important contribution for increased robustness of pipelines will be the new “Design Guideline for Offshore Pipeline" that is under preparation. This work is performed within the Joint Industry Project “Fracture Control of Offshore Pipelines". In this work the effect of internal and external pressure will be implemented, partial safety factors will be developed, and the format of design equations, developed for failure, will be on the same format as for other failure modes. This opens for increased use of fracture mechanics in the design phase of a pipeline construction project. As the fracture mechanics assessments of today predict the maximum allowable defect size close to the actual limits of the pipeline during installation, it is of main importance to take action and compensate for eventual reduced fracture toughness during operational conditions. If not, the operational assessments are clearly non-conservative. Today the fracture toughness obtained in air is often used for both installation and operation. This practice should change as lower bound data,

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representing the fracture toughness under worst case operational conditions, is available for some steels to day.

5.2 Corrosion history and related R&D Three major findings or problem areas with respect to corrosion and corrosion protection have been uncovered in the qualification and R&D of the S13Cr stainless steels. These are as discussed previously; 1) general corrosion at low pH caused by the use of strong buffer, 2) high temperature intergranular corrosion caused by sensitisising (Cr-carbide precipitation) of the heat affected zone by multipass welding and 3) hydrogen induced stress cracking caused by high local levels of hydrogen. The first mechanism was solved rather quickly and explained. It was more or less a result of standards for testing being adopted from carbon steel testing to stainless steel testing without a proper evaluation. The two last degradation mechanisms have caused more concern and resulted in significant research and development. Besides of studying the robustness in post weld heat treatment to heal Cr-depletion, a PhD study were undertaken to study the mechanism and under which welding conditions carbides were formed. All answers are not given and further research should progress, especially towards environmental limitation and welding procedures to avoid precipitations. The last uncovered degradation mechanism was the impact of hydrogen either from welding or from cathodic protection. To avoid hydrogen from welding has been overcome through better welding procedures as to avoid humidity/dirt/oil in any form and by using consumables that are degassed to reduce hydrogen uptake. Hydrogen from cathodic protection is more unforeseen because it depends on several other factors as the coating and coating damages. Some constructural matters can be and has been done with respect to design of anode pads and how to place anodes and also to reduce the polarisation by controlling the potential to a level where hydrogen is not produced (above -730mV SCE) and at the same time not exceeding the potential for corrosion (below -500mV SCE). The effect of hydrogen has shown not to be elucidated with traditional test methods, which has led to focus on fracture mechanics testing under environmental impact. The enabling of fracture mechanics analyses are more thoroughly discussed in the next chapter. A co-operation in this area has been established with NKK (JFE group) and a student from the Norwegian University of Science and Technology (NTNU) worked together with researchers at JFE during the Spring 2003. The cooperation is continued in 2004.

5.3 Environmental Assisted Cracking It has been demonstrated that the fracture toughness of duplex steels and S13Cr steels drops significantly under normal cathodic protection. Major impact is also indicated on the crack growth rate during fatigue. These parameters are of main importance for design criteria as;

• establishment of maximum applied operational stress for the pipeline • estimation of operational lifetime

To avoid hydrogen induced cracking on S13Cr pipelines, three possible designs can be applied:

• accept the lower bound fracture toughness and crack growth rates during normal cathodic protection accounting for them during operational design.

• controlling the galvanic potential to >-900mV SCE. The effect of the cathodic protection is probably neglectable. This is based on tests performed at 1 atm pressure. Sub sea effects with increased external pressure on the pipe surface must be investigated.

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• if waterproof coating is ensured, cathodic protection is not needed.

Several test methods have been applied in characterizing the susceptibility to hydrogen embrittlement:

• single edge notch tensile fracture mechanics test specimen (SENT) • single edge notch bend fracture mechanics test specimen (SENB) • slow strain rate testing on round tensile test specimens (SSRT) • four point bend testing on as welded surface and machined surface (4pb) • full scale testing with and without artificial surface flaws • constant load • others

Traditionally sensitivity to hydrogen embrittlement has been investigated by applying a given displacement onto a four point bending specimens with original pipe surface representing 90-100% of the actual yield strength or by applying a constant load on round smooth tensile specimen representing 90% of the actual yield strength. Loading this type of samples, with a sensitive microstructure/material present, to yield or even locally above yield (especially on four point bend tests) has shown not to be a representative test method for operational conditions. The loadings have been performed in air followed by submerging and cathodic protection. The factors should act simultaneously. This will prevent oxides to form subsequent to the loadings. However, most important is to have hydrogen charging when the material is plastic deformed because in these areas a higher and critical hydrogen concentration is achieved. Slow strain rate testing of typical round tensile specimens combines the above mentioned factors. And that is probably why this method exposed the sensitivity to hydrogen embrittlement in the first place. But the only measure to evaluate from a slow strain rate test is the fracture contraction (i.e. ductility measure). This could be a simple way to qualitatively compare and range materials. But converting a ductility measure to a relevant design acceptance criterion is difficult and must be supported by several empirical and analytical simplifications. From a fracture mechanics point of view, this would be the same as finding a parameter describing the fracture toughness of a material by means of the fracture contraction or fracture elongation from a standard tensile test. As a measure for design input, this is considered as an inadequate description of the fracture mechanics behavior of a material. Slow or constant load fracture mechanics testing by using the SENT or SENB test specimens have shown to be very sensitive to environmental impact in the same way as standard slow strain rate testing. And the advantage with fracture mechanics test specimens compared to slow strain rate specimens is that the data can be applied for fracture mechanics assessment. The crack growth rates show the same tendencies as the fracture toughness. These findings are very recent and are produced in an on-going Joint Industry Project on fatigue. Four full scale tests have been undertaken. Two of the tests were conducted with cathodic protection. One of the full scale tests and several standard small scale 4-point bend tests, loaded to specified stress levels around yield, were submerged into the ocean to 600m depth to simulate actual loadings and environment. However, no cracking was observed on any of the tests. Critical conditions with respect to cathodic protection, local loading/strain concentration and pipe movement have probably not acted simultaneously. From the above results it is obvious that testing has to reflect operational conditions in a reliable way. Taking the step forward to fracture mechanics testing under environmental impact a more

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reliable and representative test method can be developed. It is therefore important to understand and reproduce the expected local stress behavior during operation applying especially designed test geometry. As the properties are significantly reduced under cathodic protection, it is of main importance to increase the robustness by implementation of the actual properties in the design phase of coming pipeline construction projects. It is also vital to ensure that the actual loading on the pipe is within the design limits.

6 QUESTIONNAIRE TO THE OFFSHORE INDUSTRY Focus on industry experience is the main topic of the questionnaire. The questionnaire is mainly related to S13Cr pipeline integrity, but some of the questions have a more general approach. The questionnaire is outlined to get an acceptable basis for a systematic evaluation of risk. The basis for the questionnaire was meetings regarding robustness in material selection with Norsk Hydro and Statoil and questions presented in the pre-project report /2/ (Chapter 5.2). The intension of the questionnaire was to engage leaders/representatives of material groups/departments of larger oil & gas companies by answering the questions, providing relevant information on an open and free basis. To get an acceptable level of internal company information, it was in the introduction of the questionnaire emphasised that the information should be treated as confidential and reported anonymised (in general terms). The questionnaire was distrubuted to leaders/representatives of the material groups in the Oil & Gas divisions of the companies:

• Norsk Hydro • Statoil • BP • ExxonMobil • Shell • Total • NAM

In addition, the company Intetech Ltd by Dr. Liane Smith, was asked to comment the questionnaire. Norsk Hydro, Statoil and NAM replied on the questionnaire on all sections. Intetech gave comments where applicable. SINTEF is very grateful for the contributions. ExxonMobil answered 7 out of the 22 questions. The 7 answers are not included in the evaluation because of the very limited amount of relevant information. BP, Shell and Total did not respond on the questionnaire. The intension of evaluating the best international practice is therefore limited. Details of the questionnaire are presented in Appendix A. A summary is presented in the next chapter.

6.1 Summary of the questionnaire The answers of question 21 (see Appendix A) indicate that the industry would prioritise

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1. to improve the knowledge on failure mechanisms and new test methods 2. to improve the design basis 3. to increase the implementation of test results on S13Cr line pipe materials into standards and

specifications 4. to evaluate time schedules for pipeline construction projects more closely Priority 1 and 3 correlates well with actual activities on research of line pipe materials today (see section 3.8 and 6.1.1). Priority 2 is, from an industry point of view, clearly improved during the recent years by increased collaboration between design engineers and material specialists. However, it is emphasis that large potential on increased robustness can be gained by improvement of the design basis (see section 6.1.2). Priority 4 is related to management of pipeline construction projects and procedures for such (see section 6.1.3). Efforts of combining the answers of the questionnaire to the offshore pipeline failures and research experience are presented in the next sections.

6.1.1 Knowledge gaps The term "complete design" includes a complete understanding and quantification of all possible sources of environmental impact on the construction/structure during operation. However holes are still present today. This may be one of the major reasons why the predictions of lifetimes on S13Cr pipelines are questioned world wide. The design basis, the operational experience and operational monitoring/registrations are limited. The experience that has been accumulated through the last few years has shown that even if a S13Cr flow line has been fully qualified, failures have occurred in unexpected modes. These failures may likely be defined as a result of knowledge gaps. The recommendations are as follows: A. Close the knowledge gaps that are known and present today on pipeline systems. This requires establishment of new relevant test methods and extensive testing and verifications programs within the frame of environmental assisted cracking. As soon as a test method is critically evaluated and regarded acceptable for qualification purposes, it is of main importance to standardize the method. It is also vital to implement the test results in relevant standards and specifications. B. Bring the design analyses closer to completeness. See next chapter for more details. C. It is clear that fundamentals regarding environmental assisted failure mechanisms are not fully understood. It is recommended that more basic and long term research is initiated to provide a better understanding of these issues (research institute programs combined with Ph.D. programs). D. Strategic strengthening of the communities in the offshore industry, universities and research institutes on Environmental Assisted Cracking (Cracking, Fracture Mechanics, Fatigue etc.). Strategic investments on relevant equipment are also necessary to bring forward. Large volumes of laboratory work are connected to characterization and optimization of different materials exposed to different operational conditions. E. It is believed that closer collaboration between oil companies/operators, manufacturers/fabricators and research institutions/universities are likely an effective way of reducing knowledge gaps in the future. Increased communication, also inter disciplinary, is one way of identifying coming sources of failure.

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6.1.2 Increased robustness by improving the completeness of operational design Both SINTEF and the offshore industry consider the design basis for pipelines as insufficient. This is exposed through the answers of the questionnaire and more directly from evaluations of the investigations on pipeline failures. The pipeline failures show deviations between the actual stresses/loads on the pipeline and the maximum allowable design stress/loading. The actual stress on sections of the pipelines is often well beyond the design criteria. This is could be combined with wrong predictions of degradation- and failure mechanisms. It is recommended that tools for improved accuracy, by means of numerical simulations combined with monitoring during operation and field experience, should have more focus in the future. More effort on iterative design and verifications is emphasized. It is proposed that this can be realized through improved completeness of operational design through the recommendations listed below:

• take into account the strain history from installation on the properties of the line pipe material during operation. For installation, reeling and J-laying are commonly used. Both these methods apply plastic deformation to the pipe material. The mechanical properties differ, especially between the top-of-pipe and bottom-of-pipe positions. Through the recent year of pipeline qualifications and fracture mechanical assessments, it is indicated that installation deformations ending in tension are unfavorable regarding maximum allowable defect size during both installation process and operation.

• take into account environmental impact on line pipe material properties regarding fatigue crack growth and fracture if the pipeline is not ensured waterproof or the galvanic potential is not controlled. Fracture toughness and fatigue crack growth obtained under relevant environments are vital input for design and lifetime analyses.

• take into account the effect of internal general corrosion on pipe wall thickness and eventual local corrosion giving notch effects (stress concentrations). This is typical for carbon steels and not stainless steels.

• requirements on increased documentation of seabed topography along the planned route of the pipeline and how it affects the stress distribution on the pipe during normal operational conditions and shut downs. It is the interaction of seabed topography, fixation points of pipeline and burying/trenching etc. together with change of internal pressure and thermal expansion/contraction during shut downs that likely could produce critical local loadings on the pipeline.

• after installation and before operation, it is suggested to increase the documentation of the position of the pipe to verify whether the design criteria are met or not. If deviations are registered, re-design and evaluation of remedial actions are recommended. Remedial actions are in this context related to changing of support, fixation, burying etc. to reduce the local loading to an acceptable state according to the design criteria.

• monitoring of pipe movements on selected pipe sections. On pipe section(s) that are considered as most critical (highly loaded, but within the design criteria) during operation it is suggested to monitor the pipe movement during Ready For Operation procedure and initial operation for comparison with design analyses. These movements can act as a good reference and verification of the global and local design stress analyses. improving the interaction between local and global stress analyses taking into account local geometry and material mismatch.

• more exact planning of the route of the pipeline, which improves the possibility of moving unfavorable geometrical stress concentrations outside highly loaded sections of the pipeline. It should be possible to predict the positions in the length direction more exactly (as well as other directions) when the exact route is planned. Together with the global design stress analyses, this opens for improved planning of the positions of geometry

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dependent stress/strain concentrations. This would improve the utilization of materials and the robustness of the design.

• improved monitoring of critical parameters on pipelines during operation. The confidence on operational design is dependent on verification of operational conditions. Increased focus on monitoring is suggested as one tool to increase the confidence. Today a limited number of well heads are instrumented for optimization of production. It is suggested to extend the experiences from well heads on operational monitoring of pipelines, including registrations of pipe wall loadings.

6.1.3 Technical management of pipeline construction projects and pipeline operation. Cost-benefit is in many cases a major driving force for pipeline design and material selection. This implies optimum utilization of the materials. To reduce time schedules on construction and installation is clearly a tool to reduce the costs of pipelines. For the management of pipeline projects, which differ between companies (cf. questionnaire), it is indicated that increased robustness can be obtained by

• taking responsibility for securing relevant competence and to secure interactions between fields of competence through all stages from design to operation.

• improving the use of "Best international practice". Technology transfer from one project to another should be outlined in written procedures.

• taking responsibility regarding the connection between design criteria, test data and operational conditions (i.e. elevate the accuracy of lifetime assessments, evaluation of risk of failure etc.). S13Cr as pipeline material is considered as new technology and the operational experience is too short to fully verify reliability and robustness.

• more detailed time schedules accounting for upcoming problems during construction projects. The oil companies are mostly satisfied with the time schedules regarding pipeline construction projects (cf. questionnaire). This is not the case looking closer on the fabrication schedules and how upcoming problems in this phase of construction have increased the risk of poor design and lack of evaluations.

7 DISCUSSION The implementation of S13Cr as pipeline material on the Norwegian continental shelf was initially believed to be within the category "new material in known environment". Failures during fabrication, installation and operation have shown that the S13Cr material faced unexpected "corrosion" behaviors. If S13Cr had been treated as "new material in unknown environment", the risk of meeting the number of failures experienced on the Norwegian continental shelf (and elsewhere) would probably have been reduced. A historic review of the publications and reports, related to how our knowledge on S13Cr materials has grown, shows clearly that nobody is perfect. This involves the operators/oil companies, the research institutes/universities and official authorities/Norwegian Research Council. What did we know and at what date? Why did we not do the right prioritizing? The development of new test methods is primarily based on simulating a specific degradation mechanism. This approach provides at least some understanding of the mechanisms. The history indicates that there are problems related to selection of test method approaches, which means that some failure mechanisms were not identified in advance of field experience. And field experiences could, in some cases, not have been anticipated. But it does suggest that the laboratory work may have been too narrowly focused. It is emphasized that traditional test methods for corrosion and mechanical characterization may not represent the actual case.

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Today the Norwegian O&G companies are in the forefront regarding research and development on typical pipeline materials. On S13Cr steels, they are also the users. The investigations on pipeline failures on the Norwegian continental shelf have clearly been the main contributor to developments within discipline Environmental Assisted Cracking and especially Environmental Assisted Fracture Mechanics. This is now a focused area of competence and larger research programs are supported by the industry. International engagement is expected as hydrogen induced cracking has shown significant impact on super duplex and duplex steels as well. These materials have been considered as a robust selection until recently. And super duplex and duplex steels are widely use abroad and are also planned for the Ormen Lange development. The pipeline failures have not only exposed knowledge gaps on degradation mechanisms. The failures indicate a need for improved interaction between global and local design. This is from the industry mainly linked to reduction of geometry dependent stress concentrations. SINTEF is in addition emphasizing improved utilization and robustness by including interactions with seabed topography in the design analyses. The planned route of a pipeline should be part of the design basis and deviations between the planned route and the actual route should be documented and evaluated. Finally, remote monitoring of relevant parameters on a pipeline could be a tool to avoid unexpected longer shut downs and repair/replacement, as it opens for evaluations of remedial actions to reduce the risk of failure and for continuous evaluations of remaining lifetime.

8 REFERENCES 1. Oljedirektoratet: Sammendragsrapport, "Utvikling av risikonivå – norsk sokkel" Fase 3 –

2002, April 2003 2. J.M.Drugli, C.Thaulow, J.Ødegård, T.Rogne, R.Stokke, S.Berge, J.Berget: Pre-project,

"Robust material selection in the offshore industry", SINTEF Report STF24 F03202, January 2003

3. J.J. Dufrane: Supermartensitic Stainless Steels 1999, Brussels, Belgium, 2002, Belgian Welding Institute, 19-24.

4. P. Toussaint, J.J. Dufrane: Supermartensitic Stainless Steels 2002, Brussels, Belgium, 2002, Belgian Welding Institute, 23-27.

5. T.Rogne, M.Svenning, H.I.Lange, S.Åldstedt, H.Fostervoll, "Testing of large diameter weldable 13%Cr steel pipes for the Tangguh Production conditions", SINTEF Report STF24 F00246, October 2000

6. J.M. Drugli, T. Rogne, M. Svenning, S. Axelsen and J. Enerhaug: ”The Effect of Buffered Solutions in Corrosion Testing of Alloyed 13 % Cr Martensitic Stainless Steels for Mildly Sour Applications”. NACE Corrosion ’99, Paper No 586, San Antonio, Texas, April 1999.

7. T.Rogne and M.Svenning: “Effect of chloride and partial pressure of H2S on the SSC susceptibility of martensitic SS”, OMAE 2003, Paper No 37191, Cancun, June 2003

8. T,Rogne at. al.: “ Elevated temperature corrosion/cracking of large diameter weldable 13% Cr linepipe”, Eurocorr 2001, Riva Del Garda, Italy, October 2001

9. T. Rogne et. al.: “ Elevated temperature corrosion/cracking of large diameter weldable 13% Cr linepipe”, 6th International pipeline conference & exhibition, Merida, Mexico, November 2001

10. T. Rogne et.al.:”Intergranular corrosion/cracking of weldable 13%Cr steel at elevated temperature”, NACE CORROSION 2002, Paper No. 02428, Denver, April 2002

11. O.M. Akselsen, M. Bjordal, T. Rogne, G. Rørvik: "A study of the properties of 13% Cr martensitic stainless steels", STF24 F95605, Nov. 1995.

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12. O.M. Akselsen, G. Rørvik, P.E. Kvaale, C. van der Eijk: “Study of properties of new 13% Cr

martensitic stainless steel”, Weld. J. (printing in progress, 2004) 13. T. Rogne and M. Svenning.:” Intergranular corrosion of supermartensitic stainless steel – a

high temperature mechanism?”, Supermartensitic Stainless Steel 2002, Brussel, 3-4 October 2002

14. Elena Ladanova, Jan Ketil Solberg and Trond Rogne.”Transmission electron microscopy investigation of precipitation reactions in coarse-grained heat affected zone in two 13%CR supermartensitc stainless steels”, Supermartensitic Stainless Steel 2002, Brussel, 3-4 October 2002

15. T. Håbrekke, P.E. Kvaale: OMAE 2001, Proc. Int. Conf., Rio de Janeiro, Brazil, June 3-8, 2001.

16. O.M. Akselsen, G. Rørvik, C. Van der Eijk, P.E. Kvaale: “Mechanical properties of experimental 13% Cr stainless steel weld deposits”, Paper presented at the Nordic welding conference, September 20-22, 2000, Iceland.

17. T. Rogne et.al.: “Evaluation of Hydrogen Embrittlement of S13Cr Stainless Steels Based on SSR and CTOD Testing”, NACE CORROSION 2003, paper No 03534, San Diego, March 2003

18. T. Rogne and M. Bjordal: "Testing of welded 13 % Cr grades martensitic stainless steels for sours service applications." NACE Corrosion '97, Paper No. 62, New Orleans, 8-14. March 1997

19. R. Aune, H. Fostervoll and O. M. Akselsen: OMAE 2003, Proc. Int. Conf.,, Cancun, Mexico, June 8-13, 2003.

20. N.Hagiwara, N.Oguchi, "Fracture toughness of line pipe materials under cathodic protection", NACE Corrosion Conference 1997, Paper No. 200

21. H.I.Lange:”SENT testing under constant load with cathodic protection – FRAM VEST project, 13%Cr pipeline”, SINTEF test report, project 240672.70B, 2002-10-18

22. Stålmat forum, http://www.sintef.no/units/matek/Stalmat/hovedside_2002_2.html 23. Project Proposal of Stålmat forum, "New martensittic stainelss steels for cost effective and

environment friendly transport of oil and gas", November 1998 24. R.Aune, H.Fostervoll and M.Svenning:”JOTSUP workpackage 1, Task 1.4

Environmental/corrosion requirements – IRC test of supermartensitic stainless steels with matching filler wires”, SINTEF report STF24 F03227, March 2003

25. T.Rogne et. al., "A State-of-art on Hydrogen Induced Stress Cracking of welded supermartensitic stainless steels – SINTEF experiences" SINTEF Report STF24 F03282, January 2004

26. Vigdis Olden, Ragnhild Aune, Andre Mikkelsen, Trond Rogne, Odd Magne Akselsen and Synnøve Åldstedt, "Gullfaks Satellite C2 Towhead leakage incident. Failure analysis of S13Cr steel weldment – revison 2", SINTEF Report STF24 F03274, November 2003

27. B.Nyhus, Z.Zhang, E.Østby and J.Ødegård:”Åsgard Anodeproject – Fracture Mechanics Assessment”, SINTEF report STF24 F03229, May 2003

28. H.I.Lange, S.Åldstedt, E.Østby, "Investigation of fractured weld connection on Hub No. AB-103, Ågard B. Revision 1", SINTEF Report STF24 F01283, November 2001

29. V.Olden, S.Åldstedt, W.Dall, M.Raaness, A.Hellesvik, A-K.Kvernbråten, "The Effect of PWHT on the Material Properties and Micro Structure in Inconel 625 and Inconel 725 Buttered Joints", SINTEF Report STF24F02321_rev1, January 2003

30. S.Wästberg (DnV), H.Pisarsky (TWI), B.Nyhus (SINTEF), "Project guideline for engineering critical assessments for pipeline installations introducing plastic strain. Revision 1", DnV Technical Report 2003-3135, July 2003

SINTEF Materials and Chemistry APPENDIX A A-1

QUESTIONNAIRE TO THE OFFSHORE INDUSTRY In the following, the questions and answers are summarized and commented:

1. In the first half of the 90-ties S13Cr was introduced as a new pipeline material. Does Your company have (or had) responsibility for a sub sea S13Cr pipeline? Could you please outline what pipeline (sector/area), the year of installation and the approximate amount of km.

-Total of about 350km S13Cr sub sea. -About 50km S13Cr/lean grade on shore. SINTEF comments: Today the Åsgard field is the largest user. In the coming years, large volumes S13Cr line pipe materials are planned used on the Norwegian shelf

2. Please describe your procedures (international standards, NORSOK specifications, DnV specifications, internal specifications, other specifications….) in material selection, step by step, from:

• the very early stage

-Procurement specifications -Input from the steel/pipe producers -NORSOK M-001 -Project specific Material Selection Report

• design/engineering -Project specification(s), DnV OS F-101, ASME/API • fabrication -Project specification(s), DnV OS F-101 • installation -Project specification(s), DnV OS F-101 • service/operation -Operation plans for inspection and maintenance SINTEF comments: Through post-failure investigations on fabrication and installation problems, it is believed that today's procedures for such are satisfactory regarding robustness. Still benefits can be obtained through more detailed registrations of sub-, but near, critical weld defects and more narrow dimensional tolerances to reduce stress/strain concentrations (see Chapter 6). It is believed that large potentials on increased robustness are found in the interaction between design and operation. How is it documented that the design criteria are fulfilled on an operating pipeline? How accurate is the design? How accurate are the positional registrations of the pipeline on the sea bed? This is more extensively commented in Chapter 6.

3. Who has the responsibility on each stage (oil company, engineering company, fabrication company, material manufacturers, consultants…)

• for decisions -Oil company together with partners • for accepting deviations

-Oil company -Company specific procedures

• for quality control -Oil company / project / fabricator / manufacturer • for accepting alternative/new solutions

-Oil company -All above -Company specific procedure

SINTEF Materials and Chemistry APPENDIX A A-2

SINTEF comments: It is proposed to gain robustness by bringing the best company experiences into official guidelines/specifications

4. Has there been a shift of responsibility from the oil companies to the delivery industry? Who is controlling/following up the contractors? Do the contracts focus too much on price/time and too little on material quality? Please outline the trends during the last 10 years.

• The implementation of the Norsok principles has increased responsibility for the overall quality, also for the suppliers

• Wider use of Engineering Procurement Construction Installation (EPCI) type contracts, where the contractor is responsible for procurement and follow up of the sub-contractors

SINTEF comments: Although it is seams clear for the oil companies that the final responsibility is laying on their shoulders, it should be emphasised that contracting out has resulted in less control, through: -leaner project groups -mismatch between official and actual competence of contractor/sub-contractor In one of the answers it was mentioned that a reversion of this trend was visible in the company!

5. Has the number of employees in the “material group” significantly changed the recent 10 years?

• Stable conditions are outlined in the answers. • If the amount of employees is reduced, it is partly connected to reduced number of projects. SINTEF comments: None of the "material groups" has increased in size even though the type of materials are continuously increasing in numbers, the utilization is increasing and the materials/material combinations get more specialized and sophisticated.

6. Does your “material group” have written plans for Yes Partly No

• the competence the “material group” should hold? V • the role the “material group” play in the company? V

• the role of the material specialist in pipeline construction projects? V V • how the “material group” serve R&D and external R&D on research institutes/universities? V V

SINTEF comments: As the answers diverge in the two last questions, it may be of importance to emphasise the relevance of well documented strategic plans and action plans for "material groups"

7. How do the plans (of question no. 6) match the actual situation?

• As shown in question 6 SINTEF comments: In other words; they all operate according to plan. Probably this is not the exact situation.

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8. How do you transfer knowledge from previous pipeline projects and operation/service to a new project? Please describe your systems and your philosophy.

• Revision of technical specifications. • The use and update of Best Practices • Teambuilding’s for experience transfers • Seminars and regular internal meetings • Project close out reports (regarding construction) SINTEF comments: Are there written plans and responsible persons for revisions and updates? It is vital to secure the distribution of important information.

9. Does your company monitor the international technology development on sub sea pipeline materials? If yes: How is this organised and who is responsible for the activity?

It seems like the technical organisation of the different companies has groups responsible for following up international R&D via publications/conferences/seminars. Networks are established for different technical disciplines. Responsibility is in some cases more diffuse. SINTEF comments: Like in other institutions and organisations, the material groups are divided into technical disciplines. How is inter-discipline transfer of technology secured?

10. Recent years, technology findings on S13Cr (and on other high strength C-Mn steels) have exposed significant sensitivity to Hydrogen (from welding, cathodic protection and internal H2S corrosion). What are your conclusions on these findings?

For the Norwegian O&G companies, progress on characterisation and understanding are focussed through: • establish better limitations for safe operation of S13Cr pipelines • external (sea water) environment: Focus on CP, robust anode connections, coating,

deformation/stresses during operation, installation method (= effect of plastic deformation) • internal environment: Establish better H2S limits (may not be suitable for even very mild sour

service condition). • investigations to understand how to mitigate internal intergranular cracking from sensitation

during welding • material, fabrication, welding and installation: More stringent requirement to base material,

fabrication+weld+PWHT+NDT and restrictions on installation methods might be imposed. • take one step backward summing up the S13Cr experiences SINTEF comments: The Norwegian O&G companies are the motors, driving the R&D of S13Cr line pipe materials. They are also the users, so far. Hopefully, a coming JIP will engage more of the international community. The intensions of the JIP are to close vital holes of lack of knowledge and to increase the understanding of the failure mechanisms, concluding with design limitations to S13Cr and other line pipe materials. Modifications of S13Cr are probably brought forward.

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11. Do you have procedures to secure communication of such conclusions (see question no. 10) to the “design/engineering group”?

The companies emphasise a change, by means of closer cooperation between material specialists and pipeline engineers today. SINTEF comments: This is a trend that probably will migrate to a higher degree of confidence between design stresses and actual stresses.

12. Do you use any tool/procedures on risk based material selection? If yes: Please comment with supplementary information.

• risk analyse based on sound safety calculation models, where material data is an input factor • sound engineering practice and present know how • go/no-go, based on predicted corrosion rates and lifetime SINTEF comments: The answers are likely calculation models on maximum design loading/stress combined with corrosion properties and predicted lifetime. No specific statistical tools or risk-models are mentioned.

13. When a pipeline construction project is established in your company, are you satisfied with the role you play and the time and resources you have available in accomplishing a pipeline construction project?

Based on proven technology for pipeline construction work, sufficient recourses are present to perform the work needed. Time could always be questioned. SINTEF comments: It is believed that this was not the situation some years ago. The O&G companies have gained experience on pipeline construction projects and the time schedules seem relevant. However, Sintef has observed lack of time in late stages of fabrication.

14. Contracting pipe construction projects involves transfer of responsibility. Do you have a system to secure the competence of the fabricator/supplier and that the actual personnel of the contract are present and are focussed on your project?

• follow verification plans, milestones • material lead engineer is monitoring/following the project • material lead engineer is responsible for all material activities in the project. • the material lead engineer is covered by an experienced engineer • hire personnel with special competence for special tasks SINTEF comments: None.

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15. Do you have comments/experience on using Engineering Procurement Construction contracts in pipeline projects involving technology development? How do you solve such projects on a contractual basis?

• technology development work is set out as a separate contract • O&G company taken the responsibility for technology developments • EPC's shall be based on proven technology SINTEF comments: None.

16. If the contractor gets problems following the time schedule, or you observe deviations in product

quality, or it is exposed lack of competence, how do you normally react? What do you do to compensate such cases?

• question nearly impossible to answer. Different actions may be necessary based on the problem using alternative solutions

• more manpower to solve the problem or assist the contractor to replacement of the contractor/supplier

• responsibility for field developments lies with the O&G company as the operator, and proper actions have to be taken in order to reduce the risk for any contractor to causing delays

SINTEF comments: None.

17. Increased utilisation puts stronger requirements on both material and design. How would you

describe the interaction with the “construction and design group” in pipeline construction projects?

• establishment of close cooperation between the pipeline design and material engineering • cooperation vital for limits for utilisation of both duplex and S13Cr steels in seawater • similar utilisation limits may also be valid for high strength carbon steels (>X80), however

further research is recommended SINTEF comments: The relation between design stress limits and actual operational stresses must be brought forward as one of the major knowledge areas to increased robustness on pipelines. Documentation of operational stresses by different type of registrations is needed.

18. Have you experienced that “late-production”, close to finalisation of a pipeline construction project (as f ex type and mounting method for sacrificial anodes, implementation of instrumented pipe segments, type of flange connections, transitions etc and the position of such on the pipeline (highly or low stressed sections)), could be more exposed to suboptimal design/material selection?

• all parts installed in a pipeline construction shall follow the same quality principles • solutions, including design and material selection shall be optimal • of course there have been such situations, in particular with respect to quality of line pipe

fittings SINTEF comments: It is believed that the two first answers purely focus on the ideal situation. Short cuts are almost inevitable when time schedules are hard to keep. Compromises occur. By bringing safety up front, it is clear that unfavourable compromises will be reduced. It must be better to sort out the problem

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during construction than creating a much bigger problem in some later operational stage.

19. Do you have any comments on the statement; “implementation of expert systems/electronic tools reduce technical overview”?

• no specific • there is no substitute for seeing yourself... SINTEF comments: Within the term "complete design" it is important to evaluate all materials and all different joints/connections throughout the pipeline system. It must be ensured that eventual poor designs and poor material combinations/joints are detected. Electronic design tools tend to remove the focus from the actual pipeline.

20. Are you sure that there will be NO future failures/leakages of the sub sea S13Cr pipelines you are responsible for (i.e. within the calculated lifetime of the pipeline)?

• none can give such guarantee, neither for S13Cr pipelines or any other pipelines! • it is impossible to give such guarantees • yes we have removed all S13Cr pipeline. The reason for removal being that we could not be

sure that the installed S13Cr lines would be safe to operate • S13Cr is not selected in any of mine construction projects SINTEF comments: None.

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If you are unsure about failures/leakages of your pipelines, could the uncertainty, seen from a material specialist point of view, be connected to: (please rate your opinion from 0 (not significant) to 3 (very significant))

21.

AVERAGESCORE:

A: Management of pipeline construction projects (3 answers) 1.0

B: Planning of pipeline construction projects (3 answers) 1.0

C: Economic resources (3 answers) 0.0

D: Competence of the owner or contractor (3 answers) 0.7

E: Authority of material specialists in the project (3 answers) 1.0

F: Time from material selection to fabrication of the pipeline (3 answers) 1.3

G: “Late-production” (see question no. 18) (3 answers) 1.0

H: Inexact, diffuse specifications/standards (3 answers) 1.7

I: Incomplete design (3 answers) 2.3

J: Lack of overview (3 answers) 1.7

K: Technology gap (lack of thorough understanding of failure mechanisms, i.e. lack of R&D, relevant test methods and documentation) (4 answers) 2.3

L: Monitoring of technology developments (4 answers) 0.5

M: Uncertainty connected to laboratory tests. Do they represent the actual case? (i.e. accelerated tests, small scale testing, sharp crack versus machined notch etc) (4 answers)

1.8

SINTEF comments: It is believed that question K and M are linked as uncertainty to laboratory tests are probably based on lack of thorough understanding of failure mechanisms. The scores show that the industry would prioritise:

1. improved knowledge on failure mechanisms and new test methods (question K and M) 2. improve the design basis 3. implement the experience on S13Cr pipelines into standards and specifications 4. more closely evaluate time schedules for pipeline construction projects

22. Do You have comments or additional questions/information?

No.