Pipeline Update - 2013 (DNV)

SliPIPE – new pipeline concept

Pipelines in Poland

Internal corrosion health check

pipeline update

News from DNV to the pipeline industry

No 01 2013

BBL Company and DNV in Joint Industry Project:

Pipeline operations on moveable seabed

contents

08 SliPIPE – new pipeline concept

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Pipelines in Poland

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pipeline update Addressing pipeline operations on moveable seabed ...... 4 Best student paper award at the IPC in Calgary................ 7 SliPIPE – new pipeline expansion concept.............................. 8 VeriFIcation of onshore pipelines�� 11 Reflecting on Poland’s plans for energy security......... 12 Revised revision of DNV-OS-F101.............................................. 14 Pipeline Days............................................................................... 15 DNV RP revisions........................................................................ 16 Fitness-for-service assessments............................................ 18 Welding of FIeld segmented induction bends and elbows for pipeline construction...................................... 23 Internal corrosion health check advised for liquid and gas pipeline operators....................................... 24 Integrity management of pipelines subject to stress corrosion cracking................................................................ 28 Dr John Beavers to receive NACE International’s Speller Award............................................................................ 31 Fully subscribed Pipeline Day in London........................... 32 Update on DNV-managed Joint Industry Projects relevant for pipelines ........................................................... 34

2 | pipeline UPDATE NO. 1 2013

We welcome your thoughts! Published by DNV Maritime and Oil & Gas, Communications. Editor: Eva Halvorsen Design and layout: coormedia.com 1301-070 Print: coormedia.com, 200/02-2013 Front cover photo: Getty Images/Kirill Putchenko Please direct any enquiries to [email protected] Online edition of pipeline update: www.dnv.com/pipelineupdate DNV NO-1322 Høvik, Norway Tel: +47 67 57 99 00 © Det Norske Veritas AS www.dnv.com

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editorial

Asle Venås Global Pipeline Director asle.venå[email protected]

Will we soon know everything we need to know? A pipeline is in principle a very simple structure. It is normally made up of a piece of steel with a hole in it. The hole has to be fairly round and the outer diameter has to be bigger than the inner diameter. The question is, how do we make sure this is fulfilled throughout the pipeline’s lifetime? When I started working with pipelines almost thirty years ago, I was very surprised at how such a simple structure could be so complicated to design, construct and operate. At that time, DNV did some sporadic R&D work for customers; we assumed that we would soon know everything there was to know about pipelines, and therefore wondered what we would do in the future as pipeline engineers.

Read Pipeline Update on your tablet! To view this update in PDF format on your tablet, scan the QR code or go to www.dnv.com and download the PDF manually.

www.dnv.com

Luckily for the industry, developments have continued. DNV and many other companies have maintained and even increased their R&D activity over the past few years. The more advanced we become and the more we learn, the more we realise how little we know – so the need for R&D is greater than ever! DNV realises the value of joining forces to reduce the cost of R&D and we therefore promote JIPs as the main means for R&D. We see an increased interest in our pipeline JIPs and are therefore going to publish a regular column about our ongoing and planned JIPs in the DNV Pipeline Update.

pipeline UPDATE NO. 1 2013 |

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BBL Company

BBL Company and DNV in Joint Industry Project:

Addressing pipeline operations on moveable seabed Pipeline companies operating on moveable seabed have long struggled with existing pipeline standards which are not tailored to these conditions. As a consequence, frequent and costly free-span corrections have been carried out, sometimes causing more harm than good. Pipeline operator BBL Company and DNV are now joining forces to explore the pipeline reality in these conditions and reinforce DNV’s recommended practice with tailored standards. This could mean significant savings for pipeline operations on moveable seabed.

Photo: DNV/Marianne Wennesland

Text: Marianne Wennesland, DNV

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Hans Boersma, Manager Offshore Assets and General Affairs, BBL Company V.O.F. and initiator of the BBL DNV Joint Industry Project.

A hypothesis based on an extensive CFD (computational fluid dynamics) analysis – conducted by Dutch pipeline operator BBL Company V.O.F. and Danish CFD expert Lloyds ODS – raises questions about existing standards for free-span corrections, indicating them to be too conservative. Hans Boersma, Manager of Offshore Assets and General Affairs, BBL Company, describes their findings which indicate that a majority of today’s free-span


interventions on moveable seabed are in fact superfluous. “On moveable seabed, free spans occur temporarily as part of the pipeline’s self-lowering process. Our analysis shows that in most cases these will correct themselves naturally in due time,” he says. “Scour trenches may also provide qualities similar to those of man-made trenches when it comes to protection against vortex-induced vibrations.” According to existing standards, pipeline operators are frequently

recommended to either reduce vortexinduced vibrations by installing spoilers on free-spanning pipelines, or correct the free spans by building rock berms, trenches or gravel stitches. “These measures often end up creating more problems than they solve,” argues Boersma. “For example, installing a rock berm often results in scouring on each of its ends, creating two new free spans.” In addition, all interventions may pose unwanted interference with local eco-system and fishing activities.

Photo: DNV/Marianne Wennesland

BBL Company

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BBL Company is located in the Gasunie Building (Groningen), considered to be one of the most beautiful office buildings in the Netherlands.


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Boersma calls for an industry practice that works with the natural processes of moveable seabed instead of trying/failing to overcome them. In 2012, he approached DNV’s Pipeline Director Asle Venås and proposed a joint industry project to explore free-spanning pipelines on moveable seabed and related vortex-induced vibrations. About to be launched, the JIP aims to expand knowledge, establish accurate calculation methods and reinforce DNV’s RP by including standards tailored to pipeline operations on moveable seabed. “Knowledge is our weapon,” says Boersma, pointing out that any knowledge-based standard builds in safety factors to account for the unknown. “The only way to get accurate parameters in place of such safety factors is to expand our knowledge and prove it sound.” The JIP’s further development of applicable CFD analysis with predictive value will be validated by thorough laboratory testing at Deltares institute for applied research in the Netherlands. Boersma hopes the JIP will create cooperative networks and enhance performance across the industry. He believes the end results will involve better solutions, significant cost reductions and reduced risks. “We need the best possible industry practice and a recommended practice to document it,” he says, pointing out that pipeline operators answer not only to regulators and authorities, but also to society at large. “Standards tailored to the actual reality of moveable seabed could mean a significant reduction in the number of free-span interventions. This would be beneficial to all users of the ocean.” BBL chose DNV as a collaborative partner because of its objective third-party role, existing RP on free-spanning pipelines and experience of running joint industry projects. This spring, additional partners will be invited to participate in the JIP with their experiences, questions, survey results and pipeline cases for CFD modelling. The project is expected to start this summer. 


Illustration: BBL Company

BBL Company

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A typical free span in a trench along the BBL pipeline. ROV based Multi Beam image from the 2011 survey.

JIP & Partners • BBL Company operates the Balgzand-Bacton Line, transporting natural gas from the Netherlands to the UK. Operational since 2006, the 235-km-long and 36-inch diameter BBL pipeline is laid on sandy seabed in fairly shallow water; it can supply 20% of the UK gas demand. • In 2012, BBL Company approached DNV and proposed a joint industry project to explore the hypothesis that DNV’s recommended practice for free-spanning pipelines (DNV-RP-F105) is too conservative for pipeline operations on moveable seabed. This is with regard to pipelines in trenches, particularly due to the suppression of in-line vortex-induced vibrations. • The general lack of standards tailored to pipeline operations on moveable seabed has led the industry into frequent and costly free-span interventions, often creating more harm than good. BBL and DNV are now initiating a JIP on Vortex-induced vibrations of free-spanning pipelines in scour trenches. This aims to expand knowledge, develop calculations/analyses with predictive value and reinforce DNV’s RP for free-

spanning pipelines with standards tailored to these conditions. • DNV key deliverables: DNV brings to the table its world-leading recommended practice for freespanning pipelines (DNV-RP-F105), the software Fat Free, and vast experience on free spans. As an experienced joint industry partner, with other free span JIPs on its résumé, DNV will facilitate and manage the JIP. The company will provide the project manager and project sponsor, along with experts and advisors. • BBL key deliverables: BBL brings to the table a significant body of already conducted research and state-of-the-art CFD analyses. The company will provide a manager for the JIP’s continuing cooperation with Lloyd’s ODS on further CFD analysis development, and a manager for the cooperation with Deltaris on modelling in their test tanks. Hans Boersma will take on the responsibility of chairman of the JIP steering committee. • New partners will be invited to participate in the joint industry project in the spring 2013. The project is expected to start in the summer of 2013.

IPC award

Best student paper award at the IPC in Calgary Erica Marley is a second-generation DNV employee, and her paper at the International Pipeline Conference (IPC) won the award for Best Student Paper. This is the world’s premier pipeline conference, attended by 1,465 delegates from 45 countries.

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Erica Marley, Engineer, Pipeline Technology, DNV, whose paper on “Assessment of Recent Experimental Data on Collapse Capacity of UOE Pipelines” won the award for Best Student Paper at the International Pipeline Conference (IPC).

There were eight finalists presenting for a panel of judges at the conference. Erica Marley’s paper, “Assessment of Recent Experimental Data on Collapse Capacity of UOE Pipelines,” is based on her Master Thesis at the Norwegian University of Science and Technology. Erica Marley has worked as Engineer in the Høvik-based unit Pipeline Technology since fall of 2011. She has written her Project- and Master’s thesis in cooperation with the same unit. Her experience includes:

Photo: DNV

Photo: DNV

Text: Kristian Lindøe, DNV

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Jake Abes is President of DNV Canada and is one of the key people in the IPC, and responsible for DNV’s participation in the conference: “DNV has been a strong supporter of the IPC since its inception in 1996, and we actively participate at all levels of the IPC organisation.”

Research on pipeline failure modes Finite Element Analysis ■■ Structural analysis ■■ Probabilistic calibration of design criteria for deepwater pipelines ■■ ■■

Erica Marley has also been involved with general pipeline issues such as local buckling, trawl interference, pipeline protection, global buckling, wall thickness sizing, on-bottom roughness, on-bottom stability, installation requirements and free-span analyses. 

About the IPC The International Pipeline Conference (IPC) is organised by volunteers representing international energy corporations, energy and pipeline associa tions and regulatory agencies. This is a non-profit conference; its proceeds support educational initiatives and research in the pipeline industry.


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SliPIPE

SliPIPE – new pipeline expansion concept Transporting oil and gas from high-pressure and high-temperature reservoirs through pipelines is a major challenge. SliPIPE is a new concept developed to deal with pipeline expansion TEXT: CHIA CHOR YEW, DNV


post-lay intervention work is costly and requires a long offshore time. Thus, a major challenge is to improve on the ways the pipeline end movements can be controlled – improvements which are simple, safe and cost effective. SliPIPE offers a new possibility.

Photo: DNV

Finding easy and conventional sources of hydrocarbons has become harder, while global demand for hydrocarbon products continues to grow. Oil and gas operators have turned to new geographical areas to tap new resources. These areas are challenging and can be remote, in harsh environments or in deep water, where high-pressure and/or high-temperature (HPHT) reservoirs are often found. Transporting the oil and gas by flowlines and pipelines from these HPHT reservoirs is a major challenge. SliPIPE is a new concept developed to deal with the end expansion of a rigid pipeline subject to HPHT. A pipeline laid on or buried in the seabed responds to high pressure and high temperature by expanding against the frictional resistance from the soil, resulting in axial displacement (also known as end expansion), lateral buckling, upheaval buckling, or a combination of these, depending on whether the pipeline is fully restrained or unrestrained. In some cases, pipeline walking may occur after the pipeline in operation is cooled down, for example in a shutdown, and heated up for operation and then the thermal cycles are repeated. These pipeline movements can cause failures in the midline or at the tie-ins connected to the pipeline end and are

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Chia Chor Yew, Senior Principal Engineer/ Manager, Subsea, Structures and Pipelines, DNV, Singapore.

critical to the integrity of a pipeline. When a pipeline is subject to high pressure and high temperature, its ends expand longitudinally and exert forces and bending moments onto adjacent tied-in structures connected to it. The tied-in structures must be designed to withstand these expansions and loads. Dumping rocks along the pipeline has conventionally been adopted to reduce end expansion. A giant spool installed at the pipeline end is another alternative. They are often used in combination to eliminate end expansion when it is very large. However, such

CONCEPT SliPIPE works to reduce the wall force exerted at the tie-in by absorbing the end expansion through sliding within itself and simultaneously reducing or eliminating the effective axial compressive force in the pipeline. SliPIPE consists of an outer pipe connected alongside to a pressure chamber and an inner pipe that can slide inside them. Seals are placed at the contacts between the pressure chamber and the inner pipe. The inner pipe slides in or out of the outer pipes in response to an axial stress that can either be more or less than a certain value. This value is pre-determined in the SliPIPE design and causes an axial tension in the pipe wall to develop, which opposes the effective axial compressive force component arising from the inner fluid pressure. The axial tensile pipe wall force is produced by letting fluid pressure in, through holes in the inner pipe, to one side of the pressure chamber, separated from the

Illustration: DNV

SliPIPE

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SliPIPE consists of an outer pipe connected alongside to a pressure chamber and an inner pipe that can slide inside them. Seals are placed at the contacts between the pressure chamber and the inner pipe.

other side of the pressure chamber by an annular partition wall. As the pressure in that side of the chamber freely builds up, it pushes against the partition wall and the pressurised end of the chamber in opposite directions to one another until an equilibrium is reached. This in turn develops a tensile force in the pipe wall which can be scaled to a desired value by pre-sizing the cross-sectional area of the pressure chamber. Between the outer pipe/pressure chamber and the inner pipe of the SliPIPE are two main seals, a partition wall seal, an

environmental seal and a scraper seal. Each main seal consists of a pair of chevron seals and T-seals with backup rings, capable of preventing a single failure from causing the loss of both barriers. Other equivalent double barrier seals may be used. Around the rim of the annular partition which moves within the pressure chamber is a set of double T-seals. Each T-seal is reinforced with backup rings on either side and these provide efficient resistance to extrusion of the seals. The seals are made of materials that allow them to function at high temperatures of up to

150°C and pressures between 100 and 400 bar. Chevron seals are made of thermoplastic while T-seals are made of elastomer. Environmental seals and scrapper seals remove marine growth and other contamination on the surface of the inner pipe before it makes contact with the main seal. Before use, all seals must first be qualified for HPHT conditions and to ensure the long-term reliability of the seals to function under the frequent two-directional sliding of the surfaces that come into contact with them.


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SliPIPE

Several practical issues that will influence the operation of the SliPIPE were studied and feasible ways to overcome them looked into, such as: ■■

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The double seals at the annular partition wall are relied upon to keep the differential pressure between the nonpressurised compartment and the pressured compartment of the chamber. To safeguard against the pressures on either side of the partition wall equalising over time, a one-way relief valve, suitable for underwater application, can be installed at the far corner of the non-pressurised compartment through which any builtup pressure in the compartment can be vented out into the sea. Alternatively, a small pipe connecting the non-pressurised compartment to a faraway existing flare-off facility, if available, will produce the same effect. Assembling the components and seals together to create the SliPIPE is feasible by casting, forging, welding and assembling the components in a certain production sequence. Damage to the seals from the heat generated by welding parts together can be avoided by careful selection of the welding locations. The seals can be inspected after the final factory-acceptance test by modifying the free end of the pressure chamber to create a pair of flanges with a metal seal between them, one flange connected to the chamber body and the other connected to the chamber end. The flanges can be unbolted to disassemble the components so that the seals can be inspected. The metal seal located between the flanges is then replaced with a new one before the SliPIPE is reassembled. In order for the main seal to hold against leaks, it is crucial that the environmental and scraper seal can be relied


upon to clean the surface of the inner pipe that comes into contact with the main seal. This can be improved by extending the free end of the pressure chamber using external tubular housing that has a tight-fit end and is long enough to shield the contactable innerpipe surface from fouling. INSTALLATION A SliPIPE used for absorbing end expansion may be preinstalled on a PLET which is then transported and installed offshore on the end of the pipeline, lowered onto the seabed and connected to a manifold or riser via a short tie-in spool. A misalignment flange may be included. Alternatively, a direct tie-in (without a PLET and short tie-in spool) is also feasible with the use of a suitable installation guide currently available on the market, e.g. Subsea Installation Guide (SIG). The SIG is placed on the subsea structure close to the connection point and guides the pipeline end towards the hub on the subsea structures until they are separated by a small gap. The SliPIPE is then allowed to slide until the small gap is completely closed and the connectors clamped together. No post-installation metrology, fabrication of the short spool, additional spool installation or subsea tie-in need be performed. In the direct tie-in method, SliPIPEs have to be locked to restrict any uncontrolled movement and the lock released before tie-in. A SliPIPE must be designed to have at least the same capacity as the adjacent linepipe, which has already been designed to resist the maximum tensile forces and bending moments. APPLICATION SliPIPE is a concept wellsuited for installing tie-ins between a submerged rigid pipeline and a subsea well, subsea structure or riser, typically from 10.75 to 24 inches (273 to 610 mm) in diameter, with operating temperatures up

to 150°C and a pressure range from 100 to 400 bar. Compared to a giant tie-in spool, SliPIPE is a relatively simple yet effective alternative means to eliminate the effects of end expansion on tie-in structures. Key advantages: ■■ SliPIPE avoids the fabrication and complicated installation associated with giant spools. ■■ SliPIPE minimises costly post-installation subsea intervention work. ■■ SliPIPE is space-efficient and ideal in areas congested with many subsea facilities, as are often encountered in brownfield modification work, where safeguarding the facilities’ integrity during intervention work can be a formidable task. DNV has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over the past few decades. Today, more than 65% of the world’s offshore pipelines are designed and installed to DNV’s offshore pipeline standard, including several recent ones laid in deep waters. SliPIPE is conceptual and will require refinement and engineering through basic and detailed design before it can be realised in an actual project. A global team of experienced engineers from Singapore, Oslo, Perth and Groningen, combining youth and experience and headed by DNV in Singapore, has developed the concept. The team has also taken into account comments received from the offshore pipeline industry. Besides a university professor, the personnel consulted are from two major installation contractors and a seal company. 

VeriFIcation of onshore pipelines

Veriﬁcation of onshore pipelines DNV has launched a new service specification for the verification of onshore pipeline systems.

Historically, onshore pipeline systems have not usually been subject to independent verification. However, with changing regulatory environments and industry norms requiring greater scrutiny of hazardous installations in public areas, pipeline operators increasingly need to involve an independent verifier to provide the required level of confidence that their facilities comply with regulatory requirements, recognised codes and standards and project specifications. DNV’s new service specification, DNVDSS-316, outlines DNV recommendations for the scope and depth of involvement by a verification body in onshore pipeline systems. The standard provides criteria for, and guidance on, the verification of complete onshore pipeline systems and the integrity of parts or phases of a pipeline system. Risk-based verification Similar to other DNV service specifications, DNVDSS-316 follows a risk-based approach. The level of verification activity is differentiated according to the risk. If the risk associated with the pipeline system is higher, the level of verification involvement is higher. Conversely, if the risk associated with the pipeline is lower, the level of verification activities can be reduced without any reduction in their effectiveness. Benefit Third-party verification of onshore pipelines has the benefit of giving the stakeholders confidence that:

Photo: DNV

Text: Ali Sisan, DNV

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Ali Sisan, DNV UK Head of Pipelines and Subsea.

The onshore pipeline system has sufficient integrity to fulfil its specified requirements ■■ Risks to personnel and the environment associated with the onshore pipeline system are as low as reasonably practicable ■■

Additionally, it is good business practice to subject critical work to a third-party check as this minimises the possibility of errors remaining undetected. Third-party verification will ensure that the verifier has an independent view and perspective when performing this activity. Verification can also be used as a part of the project risk management when the failure of pipeline systems may expose the interested parties to various risks: safety, environmental, economic, regulatory, political and reputational.

Service overview DNV-DSS-316 outlines different levels of verification involvement to be selected by the customer, thus ensuring that the verification body’s scope is well defined. Further, by stating this level on the final verification statement, the recipients of the statement will also be informed of the scope. The standard describes DNV’s verification services for onshore pipeline systems and provides guidance for customers and other parties on the selection of the level of involvement of those carrying out the verification activities. Moreover, it provides a common communication platform for describing the extent of the verification activities. A verification process may relate to the following project phases: ■■ Conceptual design ■■ Front end engineering design (FEED) ■■ Detail design ■■ Construction

A Statement of Compliance can be issued by DNV on completion of each particular project phase, and will be based on a dedicated verification report. This service specification has been long awaited by the industry; it complements the series of offshore pipeline guidance, recommended practices and specification documents in use by many operators and pipeline supporting companies worldwide. Like other DNV rules and recommended practices, DNV-DSS-316 may be downloaded free of charge from www.dnv.com as from 1 April 2013. 


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energy security

Reflecting on Poland’s plans for energy security There are a number of measures being taken in Poland to ensure security of energy supply, not least the construction of a new terminal and investment in shale gas potential. Where does DNV fit?

Due to its insufficient natural deposits of oil and gas, Poland is developing pipeline construction and operation projects intended to ensure energy security, which will contribute to sustainable development in all regions in the country. One of the measures being taken is to diversify the natural gas supply and create an alternative to supply from Russia. In order to make that happen there is to be a LNG terminal built in Swinoujscie, which is a city and seaport on the Baltic Sea, located in the north-west of Poland. It is to be the largest terminal in the Baltic Sea with a capacity of five billion cubic metres (bcm) per annum, with a possibility to increase the dispatch capacity to 7.5 bcm per annum. The terminal, which is designed to off take and re-gasify liquefied gas has an investment of more than one billion euro. A key stakeholder, Polskie LNG, a subsidiary company of one of the largest Polish oil and gas companies with a sales revenue of 5,300 mEUR, has chosen Saipem (Eni Group) as an Engineering, Procurement, Construction (EPC) company to build the terminal.


Photo: DNV

Text: Jan Talaska, DNV

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Jan Talaska, Head of Department, Advisory Services in DNV Poland

On 28 September 2011, DNV signed an agreement with Polskie LNG for complex verification of the terminal. The scope of work included verification of management system status, people and competence, terminal equipment readiness, commissioning & start-up plan & methods, readiness to operate & maintain, shipping & jetty operations, and emergency response capability. DNV UK is involved and supporting DNV Poland in the project. Polskie LNG is to adopt a management system based on the 8th edition for the ISRS™ (Inter national Safety Rating System) and use DNV as its verifier. Moreover, DNV is to evaluate the capability of competencies of the personnel.

The development of shale gas The Polish Geological Institute has estimated Poland’s recoverable shale gas reserves at 346–768 billion m3 and the calculation is widely perceived to be conservative. This is 2.5–5.5 times more than the resources of the documented conventional deposits (145 billion m3). Together, both sources would meet Poland’s demand for gas over 35–65 years. Exploration and recovery of shale gas is not only being pioneered by the largest Polish NOCs, but also by the world’s shale gas industry leaders, mainly from the USA and Canada. Companies such as BNK, Chevron, Marathon Oil, Total, Nexen, and ConocoPhillips are vying for the lucrative shale plays in Poland. DNV Poland is focusing on developing a team to provide verification services, in order to support the growing need for services to support the shale gas revolution. At a Warsaw shale gas conference in November 2012, DNV launched its new recommended practice DNV-RP-U301 – Risk Management of Shale Gas Developments and Operations. The standard attracted much interest from the many

Photo: GAZ Sysstem

energy security

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LNG terminal in Swinoujscie on the Baltic Sea, in the north-west of Poland.

companies attending the conference. Key themes concerning the extraction companies are environment protection and social responsibility, and the RP was positively received as a benchmark to help minimise risk. Profiling DNV pipeline services There are 13,860 km of gas and 1,384 km of oil pipelines in Poland, most of which are aged 30 years and over. Gaz System, a

state-owned transmission systems operator, has stated that two billion euro will be invested between 2012 and 2015 for the enhancement of the internal grid which includes more than 1,000 km of new pipelines, including the construction of the Poland–Czech Republic interconnection, the upgrade of the Poland–Germany interconnection, and the LNG terminal.” Last year, DNV Poland organised several seminars in Gdynia and Warsaw to inform

the industry about the pipeline and LNG related services. The DNV p ipeline integrity and risk assessment services meet the production companies’ needs. The advantages of these services will hopefully gain recognition, and DNV will grow in Poland accordingly. 


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Offshore standard

Revised revision of DNV-OS-F101 A new revision of DNV-OS-F101 was successfully launched in August 2012. After the revision, it was discovered that, for some applications, Appendix A implied unintended increased conservatism.

Photo: DNV

Text: Sigbjørn Røneid and Leif Collberg, DNV

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An invitation to all members of the DNV Pipeline Committee, and two other companies, resulted in an impressive turn-out of 16 professionals as well as a massive DNV team.

The main changes to DNV-OS-F101 were: ■■ Adjustments to the new revision of ISO 3183 (DIS) ■■ The incorporation of new ISO standards on coating (ISO 21809 series) ■■ The restructuring of Section 3 Concept and design premise development ■■ Updates to the structure and content of Section 10 Construction – Offshore ■■ General updates reflecting general feedback As part of the general updates, Appendix A was revised with the intention of giving credit for more detailed analyses. After the discovery that, for some applications, Appendix A implied unintended increased conservatism, it was decided to take action.


This issue was discussed at the DNV Pipeline Committee meeting in November, where several of the members presented the implications of this increased conservatism. It was agreed to arrange a workshop at the beginning of January to provide a “quick fix” to this appendix. Impressive turn-out An invitation to all members of the DNV Pipeline Committee, and two other companies, resulted in an impressive turn-out of 16 professionals as well as a massive DNV team. The workshop took place at DNV’s head office at Høvik outside Oslo and lasted for almost nine hours. Discussions were very fruitful, and the main challenge was to get the 20 fracture specialists to stick to a “quick fix”

solution without talking about future R&D needs … The workshop resulted in a revised Appendix A in February. This is being circulated among the participants before being sent on an external hearing to all interested parties before Easter. The hearing will only apply to Appendix A, although a very few other revised paragraphs will also be included. A new revision of DNV-OS-F101 is therefore expected in the middle of this year. The few changes in addition to Appendix A will be clearly marked as revisions. David Baxter from DNV’s Aberdeen office has coordinated this revision. 

Pipeline EVENTS

Pipeline events First Pipeline committee meeting in Singapore During the recent two-day Pipeline Committee meeting in Singapore, members presented and discussed topics such as pipeline operation, local buckling checks, pipeline R&D, joint industry projects, engineering critical assessment, fracture mechanics and fatigue assessments and reeling. DNV also presented updates to the 2012 edition of DNV-OS-F101. Text: Chia Chor Yew and Adeline Yap, DNV

More than thirty members gathered in Singapore for the Committee’s 25th meeting, held in DNV’s office. This was the Committee’s first meeting in Asia, breaking its practice of holding its meetings in Europe. All Committee members were invited, and a higher-than-expected number turned out for the two-day meeting. “Although the members are from diverse backgrounds, they have a common interest in pipelines,” said Chia Chor Yew, manager, Subsea, Structures and Pipelines at the DNV Deepwater Technology Centre.

First Pipeline innovation day in Rio To present the new designs and trends in the global pipeline market, DNV invited key Brazilian pipeline community representatives to participate in the first Pipeline Innovation Day in Rio de Janeiro. Text: Gisella Francisca, DNV

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25th DNV Pipeline Committee meeting, a first of its kind held outside Europe.

The participants came from many countries and represented national authorities, operators, EPCI contractors, manufacturers, engineering companies and universities. Three permanent Committee members from Høvik were joined by four colleagues from the DNV Singapore office, participating as invited guests. Ernst Meyer, DNV’s Regional Manager for South East Asia and Pacific, welcomed the participants, and the Committee Chairman, Colin McKinnon from J P Kenny, went through the agenda for the meeting. Singapore University The National University of Singapore (NUS) and DNV also took the opportunity to organise a

joint Pipelines Open Day at the NUS, at which speakers from the pipeline industry, NUS, DNV and the University of Western Australia, as well as participating Committee members, spoke on various topics. The audience, which consisted of pipeline industry personnel and NUS lecturers and students, enjoyed the presentations and exchange of views during the event. “This is a rare opportunity for us to learn about some of the latest pipeline technology developments from the pipeline experts, and to interact with them. I’m also pleased to hear some of the overseas participants say that they now know more about DNV in this part of the world,” said Chia Chor Yew. 

The event featured a special lecture by the Petrobras Sector Manager of Underwater Pipeline Engineering, Alexandre Lagoa, who spoke about the challenges facing Petrobras in future pipeline projects, providing an overview of the offshore large-diameter pipeline scenario up to 2020. Some of those challenges are being addressed by DNV’s CE projects and Joint Industry Projects (JIP). Petrobras designs most of its offshore pipelines in accordance with DNV-OS-F101 and DNV recommended practices.

Asle Venås, the global head of DNV's Pipeline Segment, came to Brazil especially for the event. As keynote speaker, he presented the latest DNV Pipeline Segment’s extraordinary innovation projects as well as research projects – including JIPs – and the updated DNV-OS-F101 standard, used in 65% of subsea pipeline projects worldwide. Feedback from the participants was very positive, and they expressed interest in taking part in innovative projects in cooperation with the industry. 


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DNV recommended practices

DNV RP revisions The DNV recommended practices DNV-RP-F101 ‘Corroded Pipelines’ and DNV-RP-F116 ‘Integrity Management of Submarine Pipeline Systems’ have both been developed in close cooperation with the industry to support decision-making processes related to maintaining the integrity of pipeline systems. Both RPs have had Joint Industry Projects (JIPs) ongoing since 2011; based on this work, new revisions will be issued during 2013. Text: Felix Saint-Victor, DNV

conservative. The assessment procedure will be revised based on findings and documentation established in the recently completed JIP on Mixed Types of Interaction (MTI) headed by Petrobras. It is foreseen that the inherent conservatism in the current assessment procedure will be reduced.

DNV-RP-F101 was first issued in 1999 and the plan is to issue a fourth revision in 2013. Eleven companies have contributed so far in connection with the first three revisions. The current JIP has the following participants: ConocoPhillips, DONG, ExxonMobil, Petrobras, Statoil, Total and Woodside.

The objectives of this JIP are to:

■■

Improve guidance on how to account for system effects. A methodology has been developed for assessing the capacity, including system effects, of pipelines that have experienced corrosion over a substantial length (river bottom and/or top of line corrosion). In addition, more general guidance for including system effects in assessments will be included. Improve guidance on how to perform a probabilistic assessment. The current issue of the RP gives a short introduction to the probabilistic assessment of pipes with metal loss defects for information purposes only. It will be updated to include the actual limit state used to calibrate the safety factors of Part A. This limit state is more complex than that given in the current version of the RP and provides less conservative results.


Photo: DNV

■■

■■

››

■■

■■

Felix Saint-Victor, Principal Engineer, DNV

Include new assessment methodology for pipelines with long axial corrosion. The complex shaped-defect methodology in the RP requires longitudinal wallthickness profiles as input to the calculations. The new revision of the RP will include an assessment of detailed inspection data and estimate of the corrosion rates for this type of corrosion. Reduce the conservatism in the method for interacting defects. The assessment procedure for interacting defects given in DNV-RP-F101 is considered very

Achieve full compliance with the DNV Standard DNV-OS-F101 “Submarine Pipeline Systems”. Relevant issues include system effects, pressure definitions, supplementary material requirements, hoop stress formulation and target safety levels.

DNV-RP-F116 was first issued in 2009, based on a Joint Industry Project involving eight participating companies/organisations. A second revision is planned to take place in 2013. Current JIP participants include ConocoPhillips, DONG, Gassco, GDF Suez, HSE, PSA and Woodside.

The objective of the DNV-RP-F116 JIP is to update the RP in order to: ■■

Improve guidance on how to perform risk assessments for the purpose of integrity management planning. When assessing risk, a three-level approach is

DNV recommended practices

››

Revised Recommended Practices will benefit the oil and gas indsutry in terms of access to improved guidelines.

recommended by the current issue of DNV-RP-F116: from level 1 (screening level) to level 3 (fully probabilistic). However, detailed guidelines were not presented. The work carried out by the current DNV-RP-F116 JIP has provided further guidance on such a levelled approach. For example, flow charts have been developed for the following threats for level 1 assessments: internal and external corrosion, trawl interference, anchoring, dropped objects, vessel impact, global buckling (exposed pipeline), global buckling (buried pipeline), on-bottom stability and free spanning. Guidelines for levels 2 and 3 have also been developed. ■■

Provide guidance on integrity management review and potential key performance indicators. A set of review statements has been developed to generally evaluate integrity management as a whole based on the existing DNV-RPF116 with a focus on the core integrity management process. In addition, a set of potential KPIs will be presented based on a combined integrity-management and barrier-philosophy mind-set. The presented set of potential KPIs can be used as input when choosing indicators to be included in existing or planned company KPI systems for following up actual pipeline systems in more detail.

Photo: DNV

Addressing the above issues will benefit the oil and gas industry in terms of access to improved guidelines which may allow: ■■ Extended in-service operation for a corroded pipeline ■■ Avoidance of unnecessary costly repairs and replacements ■■ Planning of activities with input from risk assessments based on balanced evaluations of both technical and nontechnical issues ■■ Continuous improvement of integrity management systems. 


17

Fitness-for-Service Assessments

Fitness-for-service assessments identify integrity concerns and help operators restore normal operations Aged pipelines that contain corrosion, cracking, and deformation anomalies are occasionally subject to pressure reductions to ensure safe operation. Sometimes these reductions are voluntary, but they are often imposed by a regulatory agency following a release or other incident. Pressure reductions imposed by a regulatory agency can typically be lifted once the pipeline operator completes corrective actions outlined by the agency. Text: Clifford Maier, DNV

Photo: DNV

Trans-Northern system is critical Corrective actions commonly for delivering gasoline and diesel involve a more detailed engineerfuel to the metropolitan Toronto ing analysis – i.e. fitness-for-service area. Clearly, the system plays a assessment – to identify anomavital role in satisfying the energy lies that threaten the integrity of needs of southern Ontario and the pipeline, and to demonstrate Quebec. whether the pipeline is suitable In response to a release in for continued service under the 2010, Canada’s National Energy intended operating conditions. Board (NEB) issued an order to The Integrity Solutions section Trans-Northern requiring a presin DNV’s Dublin (Ohio) office has ›› Clifford Maier, Senior Engineer, DNV sure reduction. The order also performed fitness-for-service assessrequires a fitness-for-service assessments for numerous pipeline operment prior to a return to service at the full operating ators, including Trans-Northern Pipelines Inc. (Transpressure. Since the order was issued, Trans-Northern Northern) that has been in operation since 1952 and has been working to complete actions necessary to lift is owned equally by Suncor Energy Inc., Shell Canada the pressure reduction; as part of this effort, it turned Limited, and Imperial Oil Limited. to DNV to perform fitness-for-service assessments to Trans-Northern owns and operates evaluate whether the pipeline segments are suitable a system of refined product pipelines in s outhern for operation at the intended maximum operating Ontario and Quebec, with a total length exceeding pressure (MOP). 800 km and nominal diameters ranging from eight DNV evaluated fitness based on anomalies reportto 20 inches. Stretching from Montreal to Nantied by metal loss magnetic flux leakage (MFL), crack coke (Ontario), the system transports a range of detection ultrasonic crack detection (UTCD), and products including diesel fuel, jet fuel, f urnace oil, geometric (caliper) in-line inspection (ILI) surveys. gasoline, and naphtha. The system connects with DNV’s assessment work scope did not consider integpipelines from other operators and is the sole jet rity threats involving incorrect operations, weather, or fuel provider for the Dorval (Montreal) and Pearson outside forces. (Toronto) international airports. Additionally, the



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Pump & Meter Station Pump Station Meter Station Trans-Northern Pipeline

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Assessment overview DNV’s assessment involved checking the quality of the inspection data, determining which features are unacceptable, and recommending investigations of those features deemed unacceptable. Although DNV evaluated metal loss, crack-like, and deformation features using feature-specific criteria, the overall process was similar for each. Inspection Data Quality Inspection quality can be impacted by a variety of factors, including pipeline cleanliness, tool speed, and sensor reliability. Poor inspection quality can cause significant defects to be misclassified, undersized, or not detected at all. DNV’s process was designed to evaluate basic data quality of the in-line inspections.

Regardless of which inspection technology was used, a comparison of ILI data and construction records (i.e. as-built drawings) was performed. The purpose of this comparison is to identify basic quality issues with the ILI data and possibly drawings that need to be updated. Items evaluated included the number of valves and tees, segment length, pipe wall thickness, speed excursions (where flaw detection and sizing accuracy could be affected), and coverage (whether there were significant areas of missing data). When data discrepancies were identified, DNV recommended following up with the ILI vendor or assessing the need to update drawings (depending on the nature of the data discrepancy). Discrepancies such as missing data or segment

length are best addressed by the ILI vendor, whereas discrepancies in the number of valves and tees are commonly just a result of outdated drawings. Identifying Unacceptable Features The purpose of the fitness-forservice assessments was to identify which features reported by the ILI would cause an integrity concern at the pipeline’s pre-reduction MOP. DNV evaluated the acceptability of ILI-reported features using a modified Canadian Standards Association (CSA) compliance assessment and by assessing the most recent ILI survey data. DNV worked with Trans-Northern to develop acceptance criteria, which consists of criteria from CSA Z662 (CSA Z66211, Oil and Gas Pipeline Systems, Canadian


19


Modified CSA Z662 Acceptability Criteria Criterion number

Criterion description

Notes

Corrosion / Metal Loss 1

Corrosion metal loss depth ≥75% of the nominal wall thickness.

2

Corrosion metal loss with a depth <75% and >10% of nominal wall thickness and a Predicted Burst Pressure <139% of MOP based on Modified B31G method.

3

Corrosion metal loss with a depth <75% and >10% of nominal wall thickness predicted to grow to a depth ≥75% of the nominal wall thickness and/or a size corresponding with a Predicted Burst Pressure <139% of MOP based on Modified B31G method within three years.

4

For those lines known to be susceptible to internal corrosion, at the discretion of the integrity specialist, Segment assumed to be not susceptible to additional criteria may be adopted which can take into consideration whether the features will grow to internal corrosion based on products being a depth of 75% of the pipe wall thickness within three years. transported and TNPI experience. Deformation

5

Any dent/ovality with a stress concentrator (gouge, groove, arc burn, or crack) or metal loss1.

6

Any dent/ovality ≥6% of the OD for pipe with an OD >101.6 mm.

7

Dents within one diameter of another dent.

8

Topside dents (or unconstrained bottomside dents) with a depth ≥3% and <6% (pipe body).

9

Topside dents (or unconstrained bottomside dents) with a depth <3% and ≥2% (pipe body).

10

Topside dents (or unconstrained bottomside dents) with depth ≥0.5% OD but <2% OD (pipe body).

These features are subject to an engineering analysis.

11

Any dents with predicted remaining life <10 years.

This criterion is only applied for dents subject to the engineering analysis from criterion 10.

12

Any dents with a calculated strain >6%.

This criterion is only applied for dents subject to the engineering analysis from criterion 10.

13

Dent on a mill or field weld:2 ≥0.5% OD but <2% OD deep for pipe with an OD >323.9 mm OR <6mm for pipe with an OD ≤323.9mm.

These features are subject to an engineering analysis.

14

Dent on a mill or field weld:2 ≥2% of the OD for pipe with an OD >323.9 mm OR a depth ≥6mm for pipe with an OD ≤323.9mm.

15

Wrinkles with a maximum vertical height of any wave, measured from the average height of two adjoining crests to the valley, >3% OD, a wavelength to height ratio ≤ 12, or a circumferential extent ≥120° of the pipe’s circumference.

Standards Association, Mississauga, Ontario, June 2011) supplemented with more stringent criteria jointly developed by DNV and Trans-Northern. The criteria combine CSA Z662 requirements with sound engineering practices (the reason for characterizing the assessment as “modified”). DNV assessed the inspection data to identify any features that meet the criteria. DNV and Trans-Northern developed separate criteria for metal loss, crack, and geometry features. Most of the criteria were used to identify unacceptable features


outright, although two of the geometry criteria were used to identify features requiring a more detailed evaluation. The table summarizes the criteria used by DNV (compiled for all three feature types). As shown, the criteria consider corrosion growth (for metal loss features) and fatigue growth (for crack-like and certain geometry features). For metal loss features, the corrosion growth rate is based upon a statistical comparison of features reported in consecutive inspections and

This criterion can only be applied based on field observations and not ILI results.

a manual review of inspection signal data to confirm corrosion growth. The fatigue assessment for cracks incorporates the Paris Law fatigue crack growth model and fatigue crack growth data, while the fatigue assessment for geometry features is performed in accordance with Part 12 of the API 579-1/ASME FFS-1 fitness-for-service standard (API 579-1/ASME FFS-1, Fitness-forService, American Petroleum Institute, Washington, D.C., June 5, 2007) (a safety factor of 10 was applied to dents on welds, per the Pipeline Defect Assessment Manual


Modified CSA Z662 Acceptability Criteria Criterion number

Criterion description

Notes

Cracks3, 6 16

Crack-field and crack-like features (including surface-breaking laminations) with predicted depth ≥40% of the nominal wall thickness (include notch-like and weld anomalies if their depths are reported).

17

Crack-field, crack-like, notch-like, and weld anomaly features (including surface-breaking laminations) with a predicted burst pressure <139% of MOP4.

18

Preferential seam weld corrosion > 40% of the nominal wall thickness or assessed as a crack with a predicted burst pressure <139% MOP.

19

Crack-field and crack-like features (including surface-breaking laminations) located in a dent (include notch-like and weld anomalies if their depths are reported).

20

Crack-field and crack-like features (including surface-breaking laminations) predicted to grow to a depth ≥40% of the nominal wall thickness or a size corresponding to a predicted burst pressure <139% MOP4 within three years (include notch-like and weld anomalies if their depths are reported).

21

Laminations which run into either the longitudinal weld or girth weld5.

22

Laminations determined to be blisters.

23

Corrosion metal loss containing cracks.


Other 24

Gouges, grooves, and arc burns.

None identified in the inspection data.

25

Any weld containing an imperfection that fails an engineering assessment.


26

Any other condition which, in the opinion of the ILI specialist, requires remediation.

Case by case.

1

To meet criteria, metal loss, cracking or stress risers must be interacting with a dent. Interaction is defined as any metal loss, cracking or stress riser that overlaps with a dent after the tool tolerance (length and width) has been applied to both the stress riser and the dent. This method identifies both axial and circumferential interaction.

2

Dents must be within +/–50 mm of a girth weld or +/–50 mm of a longseam weld.

3

Preferential seam weld corrosion shall be assessed as a crack.

4

The length of crack-field and crack-like feature(s) to be used in the critical flaw calculations shall be the “maximum interlinked crack length” reported by the in-line inspection vendor, if provided, otherwise it shall be the “total length of the crack.

5

The laminations/inclusions reported near (within 25 mm of) longitudinal seam weld and girth welds.

(PDAM)). Dent strain acceptability is based upon acceptability limits provided in ASME B31.8 Appendix R (ASME B31.8-2007, “Gas Transmission and Distribution Piping Systems”, November 2007) (for dents in the pipe body) or ASME B31.8 (for dents located on a mill or field weld). Additionally, a probability of exceedance (POE) assessment was performed to determine which metal loss features, if any, could compromise the pipeline integrity prior to the desired five-year re-inspection. The POE assessment takes into account

the potential sizing inaccuracies of the ILI and the results of the statistical corrosion growth assessment to evaluate the severity of the reported corrosion features as a function of time. The predictions are used to develop possible repair and re-inspection scenarios. The optimal repair and re-inspection scenario is identified based on a net present value (NPV) analysis. Ultimately, the POE results could identify features for repair that were not considered as “unacceptable” by the modified CSA compliance assessment.

Investigation Recommendations DNV recognized that some features would cause an integrity concern when the pipeline operates at the intended maximum operating pressure, while other features are less severe and would not preclude the pipeline’s operation at that pressure. Thus, DNV recommended features for investigation in two categories: ■■ prior to operations at the intended maximum operating pressure, and ■■ prior to the next re-inspection.


21


Previous Survey

Current Survey

››

Comparison of in-line inspection Magnetic Flux Leakage (MFL) signal data (previous survey vs. current survey) used to verify corrosion growth.

‹‹

Ultrasonic Crack Detection (UTCD) in-line inspection tool used to identify crack-like flaws.

Features that warrant investigation prior to the pressure increase include those that are predicted to have a depth >75% of the pipe nominal wall thickness or a predicted burst pressure <139% of the intended maximum operating pressure within the next three years. Other unacceptable features were recommended for investigation prior to the pressure increase as well, if DNV determined they pose a considerable risk under those operating conditions (e.g., crack-like features or dents with relatively short calculated fatigue lives or dents with


high strain values). Less severe features that do not warrant investigation prior to the pressure increase would be recommended for investigation prior to the next re-inspection if DNV determined they pose a low risk while the pipeline operates at the intended maximum operating pressure. Acting on the Results As DNV completes the fitness-for-service assessments, Trans-Northern prepares and executes a repair/remediation program (based on DNV’s recommendations) to prepare the

pipelines for the return to service at 100% MOP. However, before the pressure can be restored, Trans-Northern must formally make an application to the NEB for removing the pressure restriction. DNV’s fitnessfor-service reports will be an integral part of the applications, as DNV has assisted many other operators in satisfying similar corrective action requirements. DNV has a favorable reputation with the NEB as being a competent, world-class pipeline consultant. 

Pipeline construction

DNV-led Joint Industry Project:

Welding of ﬁeld segmented induction bends and elbows for pipeline construction Recognizing the need to develop guidelines for the use of field-segmented induction bends and elbows for pipeline construction, Spectra Energy organized a joint industry project (JIP) that was conducted by DNV. The overall goal of the JIP was to develop practical guidelines for using segmented induction bends and long-radius elbows for onshore pipeline construction, and to identify practices which should be avoided.

Besides Spectra, participation in the project included Alliance Pipeline, Kinder Morgan, CenterPoint Energy, NiSource, TransCanada, El Paso, Panhandle Energy and Williams. The sponsors agreed that sharing the project’s results was in the best interest of the industry and the general public. The need to use segmented induction bends and elbows can arise for a variety of reasons during construction of new pipelines or during pipeline repair and maintenance activities. For example, bends having a tighter radius than can be accomplished by cold field bending may be required to accommodate abrupt directional changes. While some tightradius directional changes can be accommodated by ordering induction bends with specific bend angles, the bend angles required are not always known prior to construction. The JIP had two main objectives carried out in two phases:

Photo: DNV

Text: Bill Bruce, DNV

››

Bill Bruce, P.E., Director, Welding & Materials Technology, DNV

1. To develop guidance regarding the specification and purchase of segmentable induction bends and elbows 2. To develop guidance for field construction practices Final reports for both phases can be found at www.dnvusa.com/resources/reports.

In Phase 1 of the work, the manufacturing methods, capabilities, and limitations of induction bend and elbow manufacturers were evaluated during visits to manufacturing facilities. Pertinent industry standards and related pipeline company specifications were reviewed. The information was summarized and used to develop examples of generic purchasing specifications for both segmentable induction bends and manufactured elbows. Annotations in the specifications describe the source of key content and highlight content specifically related to segmentability. In Phase 2, optimal methods for mapping, cutting, beveling, and transitioning induction bends and elbows were developed. Recommended practices for welding in the field and for a variety of related issues were also developed. The information was summarized and used to develop a generic specification for segmenting and welding of induction bends and elbows. 


23


Internal corrosion health check advised for liquid and gas pipeline operators Based on escalating regulatory emphasis on internal corrosion management, pipeline operators would be wise to anticipate increased oversight in this area. A look at recent history may provide clues on where new regulations are heading and insight on how to be prepared for the future changes. Text: Richard B. Eckert, DNV Reprinted from Materials Performance, December 2012, NACE International

Pipelines regulated under 49 CFR 192 and 195 must meet specific requirements when transporting potentially corrosive gas or liquids. In particular, operators must have adequate documentation to demonstrate that the pipeline is not in “corrosive” service, or that effective mitigative and preventative measures are in place to address corrosive conditions. Over the past twelve years, Advisory Bulletins issued by the Pipeline and Hazardous Materials Safety Administration (PHMSA) have repeatedly emphasized the need for pipeline operators to conduct periodic reassessments of their internal corrosion programs. New rules on the horizon An Advance Notice of Proposed Rule making (ANPRM) was issued by PHMSA in August, 2011, to solicit input on a


››

Richard B. Eckert, Principal Engineer, Internal Corrosion Management, DNV

number of issues where new regulations are being considered for gas transmission pipelines. In regard to internal corrosion, PHMSA is considering revising 49 CFR 192 subpart I to possibly include: ■■ Requiring periodic in-line inspection or sampling of accumulated liquids to

assure that internal corrosion is not occurring ■■ Requiring additional measures to prevent internal corrosion in gas transmission pipelines ■■ Changing the definition of corrosive gas to clarify that other constituents of a gas stream (e.g. water, carbon dioxide, sulfur and hydrogen sulfide) could make the gas stream corrosive ■■ Prescribing corrosion control measures with clearly defined conditions and appropriate mitigation efforts for high consequence areas (HCAs) and non-HCAs ■■ Requiring a periodic analysis of the effectiveness of operator corrosion management programs, which integrates information about CP, coating anomalies, in-line inspection data, corrosion

Photo: DNV

Photo: xx


››

An internal corrosion “health check” (or audit) is a systematic review and assessment of the internal corrosion threats posed to a pipeline system.

coupon data, corrosion inhibitor usage, analysis of corrosion products, environmental and soil data, and any other pertinent information related to corrosion management ■■ Requiring that operators periodically submit corrosion management performance metric data The focus on data collection and integration, and conducting regular assessments to evaluate internal corrosion threats and mitigation, is quite clear, based on the ANPRM. Most recently the Pipeline Safety Act, signed into law on 3 January 2012, provided enhanced authority to the DOT, increased the maximum penalty for violations, and required the DOT to evaluate whether integrity management rules

should be expanded to cover non-HCA pipeline segments. Given the historical and current level of political and regulatory attention, pipeline operators’ integrity management requirements can only be expected to increase. Management of internal corrosion threat identification, prevention and mitigation, and risk assessments will clearly be an important part of the future compliance picture. Internal corrosion “Health Check” An internal corrosion “health check” (or audit) is a systematic review and assessment of the internal corrosion threats posed to a pipeline system, and the operator’s programs to monitor and mitigate those threats. The primary objectives of the health check are to ensure that

all internal corrosion threats are identified and characterized, and to verify that adequate measures are in place to reduce the likelihood of pipeline failures resulting from internal corrosion. The results of the IC health check can also be used to support the operator’s risk management and integrity management programs. An internal corrosion health check provides the formal assessment and documentation required to ensure that the threat of internal corrosion is adequately considered, which also supports regulatory audits. Establishing a formal, documented process for periodic assessment of internal corrosion threats helps ensure consistency in the process and improves the reliability of the results. A documented process also makes subsequent assessments easier to perform, since data from


25


Examples of data elements used for internal corrosion threat assessment

earlier assessments will be maintained in a functional format. The typical steps used in conducting an initial IC health check include: 1. Defining assets to be assessed 2. Documenting the design and operating conditions 3. Assessing the present internal corrosion threats and their severity 4. Evaluating monitoring programs and effectiveness 5. Evaluating mitigation programs and effectiveness 6. Identifying program gaps 7. Identifying continuous improvement opportunities The first step is fairly straightforward; the boundaries of the pipeline assets to be assessed are identified. This step is particularly important in a complex pipeline network, as it will help in later segmentation of the system based on specific corrosion threats. The second step involves documenting relevant engineering, design and operational data for the assets being assessed. Direct information about the effects of corrosion on the pipeline comes from visual inspections, in-line inspection (ILI), failure analysis, and integrity assessment programs. Indirect information about corrosion mechanisms is obtained from gas/liquid composition data, microbiological testing, flow conditions, operating parameters, material and design records, pipeline maintenance records, and corrosion monitoring and mitigation history. Ensuring that adequate information is collected and validated is crucial to the final quality of the internal corrosion health check. Any assumptions made should be fully documented and justified. Typical data used to conduct the internal corrosion threat assessment are shown in the table. IC threat assessment is the third step,


Category

Data element

Design parameters

Material type and grade Diameter and wall thickness Fabrication methods Construction practices Coating or lining Elevation profile Connections, tie-ins MOP Pipeline appurtenances Liquid collection and separation Dehydration or other processing Capability for pigging Location of access fittings Hydro-test and commissioning

Operating parameters

Pressure (typical, variations) Flow rate (typical, variations) Temperature (typical, variations) Liquid/gas velocity (calculated) System upsets (type, frequency, volume)

Compositional data

Gas composition

Carbon dioxide, hydrogen sulfide, oxygen, organic sulfur compounds

Liquid composition

Water phase: pH, anions, metals, alkalinity, total dissolved solids, total suspended solids, dissolved gases, microbiological characterization, organic acids, scaling index Hydrocarbon phase: basic sediment and water, paraffins, waxes, asphaltenes, aromatics, total acid number, oxygen, sulfur, nitrogen, API gravity

Solid composition

Metals, anions, mineral compounds present, total carbon and sulfur, particle size and shape, organic vs. inorganic total, microbiological characterization

in which all potential corrosion threat mechanisms are considered and evaluated based on the data available. The level of susceptibility to various threats may be ranked for different parts of the pipeline system based on operating conditions or design. Verification of the corrosion threats can be performed based on actual observation, inspection or investigation. Verification of the corrosion threats helps validate the assessment and ranking of different threats. Internal corrosion threats that are typically assessed include corrosion associated with carbon dioxide (CO2),

hydrogen sulfide (H2S), or oxygen (O2); erosion-corrosion, flow assisted corrosion, underdeposit corrosion (USC), microbiologically influenced corrosion (MIC), galvanic corrosion (where dissimilar metals are joined), selective weld corrosion, and corrosion associated with corrosive chemicals (e.g. acids from well stimulation) that could enter the pipeline. The potential for interaction between different threats should be considered, along with the likely form of damage resulting from the threat, e.g. localized pitting, general wall loss, cracking, etc.


In the fourth and fifth steps of the IC health check. the corrosion monitoring and mitigation programs are evaluated and procedures verified. The purpose of these steps is to ensure that all internal corrosion threats identified in the third step are being adequately mitigated and that the monitoring program is appropriate to detect those threats. For example, if underdeposit corrosion was identified as a threat, monitoring using a weight loss coupon inserted directly into the product stream may not determine whether that threat is being controlled since it is unlikely that deposits will accumulate on the coupon. Likewise, if maintenance pigging is being used to remove solids to reduce the likelihood of underdeposit corrosion, the effectiveness of that mitigation must be measured, such as by monitoring the amount of solids recovered from each pig run. The sixth step is where data and/or knowledge gaps in the internal corrosion management program are identified. Perhaps more operating condition data are needed to ensure that liquid upsets are not entering a pipeline or better monitoring is needed to detect water upsets from a producer. Filling these gaps will improve the performance of the internal corrosion management program, reduce the impact of internal corrosion on the pipeline system, and increase the reliability of future threat assessments. In the final step of the IC health check, the results of the assessment are examined to identify ways to continuously improve the quality of the internal corrosion management process. ASME B31.8S Section 9.6 speaks to the need for continuous improvement in any pipeline integrity management program, based on the analysis of audit results and key performance indicators. The IC health check promotes improved management

of the internal corrosion integrity threat by providing important feedback to the IMP process. Periodic reassessment builds confidence Following completion of the standardized process for conducting the IC health check, the operator can produce a report documenting the threat assessment results and the effectiveness of the existing monitoring and mitigation programs. Annual or periodic reassessments require less time and effort after the initial health check is performed. The steps for conducting a periodic reassessment are similar; however, once the baseline information is established, the re-evaluation primarily looks for conditions that have changed since the last health check. This approach would be consistent with the guidance given in previous PHMSA Advisory Bulletins. Key performance indicators can also be drawn from and based upon the internal corrosion management actions identified for various threats in the IC health check. While the IC health check does not necessarily need to include risk assessment (i.e. considering consequences), the results of the health check can certainly feed into an operator’s risk management program. Where risk encompasses both likelihood and consequence, the IC health check may only consider likelihood and reducing likelihood of damage leading to a release. Conducting an IC health check on a regular basis helps an operator manage the threat of internal corrosion by providing several benefits. Direct benefits from thoroughly and adequately managing internal corrosion include: ■■ A clear understanding of the internal corrosion threats for each asset ■■ The ability to discern the potential for threat interaction

Accurate threat information for use in risk models ■■ Selection of effective and appropriate monitoring technologies ■■ The ability to optimize mitigation program; increasing effectiveness and reducing waste ■■ An auditable process with ability to detect creeping change. ■■

Benefits beyond compliance The need to manage the threat of internal corrosion is not only driven by regulatory compliance. Assuring that the threat of internal corrosion is adequately addressed also helps reduce the business risk to which hazardous liquid and gas pipeline operators are continually exposed. A review of pipeline accident statistics will quickly reveal that internal corrosion is a real threat – resulting in significant property damage, loss of service, environmental contamination and personal injury every year. Operators are liable for cleanup costs, regulatory penalties, and litigation expense; they may face criminal prosecution, congressional hearings and loss of reputation. The costs associated with pipeline leaks or spills can run to billions of dollars. Based on the potential business risk, internal corrosion cannot be dismissed as a threat simply because a pipeline has not leaked or ruptured in the past. While the coming regulatory changes affecting the pipeline industry remain to be seen, some observations can be made from historical regulatory advisories and from the rulemaking currently under consideration. Operators who are actively understanding and managing their integrity threats, following a clear process for assessing the performance of mitigative and preventive measures and documenting the results, are certain to be better prepared for the future. 


27

Integrity management

Integrity management of pipelines subject to stress corrosion cracking Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines. The pipeline industry responded to this threat by performing a comprehensive research program to determine the cause(s) of the failures and investigate various techniques for preventing future failures. A relatively concise list of discoveries has had a measurable impact on mitigation of the stress corrosion cracking threat. Text: John A. Beavers, DNV

Starting with the first recognized stress corrosion cracking failure in 1965, the intergranular form of cracking (also known as high-pH SCC) was investigated to identify the causative agent and the controlling metallurgical, environmental, and stress related factors. In the 1980s, a second, transgranular form of stress corrosion cracking (near neutral pH SCC) was discovered in Canada, resulting in a similar scope of research activities designed to develop mitigation methods for this form of cracking. The information developed in these research programs has been incorporated into pipeline integrity management programs. Three techniques There are three common techniques used for management of the integrity of pipelines subject to stress corrosion cracking and other time dependent threats; hydrostatic testing,


direct assessment, and in-line inspection (ILI). Directly following the initial stress corrosion cracking failures of gas transmission pipelines in the 1960s, hydrostatic testing was the primary tool used to confirm the integrity of the affected pipelines and prevent additional failures. The pipelines were pressure tested with water at pressures significantly higher than the operating pressure in order to remove any near critical flaws. This technique has a number of limitations. Very few, if any, stress corrosion cracking flaws are removed, and the pipeline must be taken out of service for testing. In dry climates, obtaining adequate sources of water can be a challenge, while freezing of the water can be an issue in winter months or northern climates. For liquid petroleum pipelines, the water must be extensively treated prior to discharge back into the environment. There also is a finite probability of a

phenomenon known as a pressure reversal occurring, where the failure pressure after a hydrostatic test is lower than the maximum test pressure, as a result of subcritical crack growth during the hydrostatic test. Alternatives to hydrostatic testing Because of these limitations, there has been significant interest within the pipeline community in the development of alternatives to hydrostatic testing. One alternative is SCC Direct Assessment (SCCDA). The first recommended practice for SCCDA was issued in 2004 (NACE Standard RP0204-2004). SCCDA is a structured process intended to assist pipeline companies in assessing the extent of stress corrosion cracking on buried pipelines, thus contributing to their efforts to improve safety by reducing the impact of external stress corrosion cracking on pipeline integrity. The term is somewhat

Photo: DNV


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Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines.

of a misnomer in that the process is much more extensive than simply examining the pipeline for evidence of stress corrosion cracking. The first step in the process (preassessment) involves the collection of existing information on the pipeline that can be used to assess the likelihood that the pipeline is susceptible to stress corrosion cracking. The applied research described above has formed the basis for establishing the critical information that should be collected. In the case of high-pH stress corrosion cracking, the initial selection of the most susceptible segments is based on five factors; operating stress (>60% of the specified minimum yield strength), temperature (>100°F), distance from compressor station (< 20 miles), pipeline age (>10 years) and coating type (other than fusion bonded epoxy (FBE)). In the case of near neutral pH SCC, there are four factors,

excluding operating temperature. Other types of information on the pipeline can be used for the selection of dig sites in the chosen segments. Again, much of this information is based on the applied research performed and includes factors such as topography, drainage, and soil type (near neutral pH SCC), the magnitude and frequency of cyclic pressure fluctuations, the specific coating type, including the girth weld coating, surface preparation for the coating, coating condition and prior history on the pipeline. A significant issue with SCCDA is that it is not capable of reliably identifying the location or locations of the most severe stress corrosion cracking on a pipeline segment. Accordingly, it is not necessarily a replacement for hydrostatic testing or in-line inspection in all instances. The pre-assessment phase of SCCDA may indicate that a particular pipeline segment is not likely to be

susceptible to stress corrosion cracking and therefore, other threats are of a more immediate concern. An example would be a newer pipeline with an FBE coating. On the other hand, ILI, hydrostatic testing, or even pipe replacement may be warranted if extensive, severe stress corrosion cracking is found. In-line inspection is the third technique used to manage time-dependent threats on operation pipelines. There is a long history of using magnetic flux leakage and, to a lesser extent, ultrasonic tools to address internal and extern corrosion threats on transmission pipelines. Around the time the NACE SCCDA recommended practice was being developed, there was a growing consensus within the pipeline industry that the new generation of crack detection tools would eliminate the need for hydrostatic testing or any of the elements of SCCDA. Integrity management would


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consist of four elements; find the cracks, size the cracks, assess the cracks and repair the cracks. Unfortunately, the experience with crack detection tools has not been as desirable as had been hoped. Over the past few years, there have been at least two service failures of pipelines in which the operators were using crack detection tools for integrity management. In the case of one failure in Carmichael MS, the cause and contributing factors could not be confirmed because of extensive fire damage to the failed pipe. A portion of the fracture did propagate along the seam weld and the pipeline had a history of seam weld defects. The pipe section that contained the failure also had been previously hydrostatically tested at a pressure much higher than the failure pressure. This information, taken together, suggests that a likely cause of failure was the growth of a seam weld defect in service. In the second case, a failure near Marshall MI, there was evidence that fatigue cracks grew from a colony of pre-existing stress corrosion cracks. Accuracy of crack sizing The problem with the current generation of crack detection tools appears to be related to the accuracy of crack sizing. The tools are very good at finding crack-like features, and the length accuracy for the features also typically is good. The problem is the depth accuracy. The feature calls are usually binned by depth into several depths; e.g. <15% of wall thickness, 15–30% of wall thickness, 30–45% of wall thickness and >45% of wall thickness. Currently, there does not appear to be sufficient accuracy in the binning process for integrity management purposes. The failure pressures in pipelines containing cracks are much more sensitive to depth than to length of the flaws. The problem could be related to the precision and accuracy of the tool, or the analytical process for analyzing the tool data. Because of these sizing issues, pipeline operators are sometimes required to


perform a confirmatory hydrostatic test on portions of their system to demonstrate the performance of the crack detection tool. In some cases, pipeline operators also may be faced with a situation where a large number (thousands) of features are found on a segment of a pipeline. The elements of SCCDA can then be used, in conjunction with the standard crack sizing, to identify which feature are most likely to be an integrity threat and should be excavated. These elements are also used to prioritize pipeline systems for in-line inspection. The point is that fundamental understanding of the SCC process, developed through applied research, is still of significant value in integrity management. As previously described, the information developed in the research programs is also used by pipeline companies to operate their pipelines in a way that reduces the risk of stress corrosion cracking failures. Where there is a risk of high pH SCC, after-coolers are installed at compressor stations to reduce outlet temperatures. Operators may control pressure fluctuations to reduce the risk of both forms of stress corrosion cracking. Cathodic protection systems are enhanced, monitored, and maintained to keep the pipe to soil potential out of the potential range for cracking. Finally, this research information is used by prudent operators in construction activities to reduce the risk of stress corrosion cracking in the future. Near white surface preparation procedures and coatings, such as FBE, are selected to minimize stress corrosion cracking initiation. Girth weld coating systems are selected to minimize shielding. The pipeline systems are designed to minimize operating temperatures and cyclic pressures. Future trends The detection and sizing capabilities of the crack detection tools will undoubtedly improve, but there will always be a need for elements of SCCDA, developed through applied research, to prioritize pipeline segments for inspection. Depending on the pace of improvements

in the precision and accuracy of these systems, there may continue to be a necessity, for the near future, to use elements of SCCDA to help identify which features are most likely to be SCC threats. Although not discussed in this article, there are other stress corrosion cracking threats to operating pipelines. Ethanol is used in almost all of the gasoline consumed in the United States as an oxygenating agent and octane booster. The current blend limit is 10% ethanol, but this may be increased to 15% in the near future. Denatured fuel grade ethanol is transported to terminals where it is blended with gasoline. Pipelines are the most efficient method to transport the ethanol but the threat of internal stress corrosion cracking has prevented general transportation via pipelines. Research is ongoing to address this threat. A new internal stress corrosion cracking threat from alcohol was recently identified. Methanol is sometimes used as a drying agent for pipelines directly following hydrostatic testing. In northern climates, neat methanol is also sometimes used for hydrostatic testing to avoid freezing. There is growing evidence that this methanol has caused internal stress corrosion cracking of some pipelines; research is ongoing to address this threat. 

NACE International’s Speller Award

Dr John Beavers to receive NACE International’s Speller Award We are pleased to announce that DNV’s Dr John Beavers is to be awarded the coveted Frank Newman Speller award at NACE International’s annual conference in Orlando, Florida in March. The award is presented by NACE International annually to an individual for significant contributions in the field of corrosion engineering.

Photo: DNV

Text: Chris Pollard, DNV

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Dr John A. Beavers is to be awarded the coveted Frank Newman Speller award at NACE International’s annual conference in Orlando, Florida in March.

Dr Beavers currently holds the position of Director, Failure Analysis and Chief Scientist with DNV’s business unit located in Dublin, Ohio. He has played an integral role in the post-failure investigation of a some of the most prominent pipeline failures in North America over the past quarter century. His research endeavors are vast, but he is particularly known for his advancements in the study of stress corrosion cracking

(SCC), both in near-neutral pH SCC and high pH SCC. His work in the latter led to the development of NACE’s Direct Assessment standard for SCC (SCCDA). His recent breakthrough work has dealt with the research of SCC in ethanol environments. Dr Beavers has held various committee positions with NACE in his more than 35 years in the corrosion control industry. In 2002, he was recognized by Pipeline

Research Council International (PRCI) with its Distinguished Researcher Award. In 2004, he was recognized as a NACE Fellow. Prior to joining DNV, he was a research scientist for Battelle Memorial Institute. He obtained his undergraduate and graduate degrees in metallurgy from the University of Illinois. We salute Dr Beavers for his many contributions to the industry we serve. 


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Pipeline Day

Fully subscribed Pipeline day in London The long-awaited Pipeline Day was held in London on 30 November 2012. This was the second such event, building on the success of the inaugural seminars held in 2011. The event was well attended, with 68 delegates representing 52 companies. Text: Ali Sisan, DNV

The event addressed a number of topics, ranging from current and upcoming research, development and joint industry projects, to recent developments in the DNV codes and recommended practices. They were covered by Asle Venås, DNV Global Pipeline Director, and Leif Collberg, Chief Pipeline Specialist, DNV Pipeline Technology Group. There were three external presentations from the White Stream Pipeline Company, Intecsea and the UK Health and Safety Executive. In addition, Jan Trass, a consultant with DNV KEMA’s Gas Infrastructure and Transport Section, talked about onshore pipeline operations and maintenance audits. Bente Helen Leinum, Head of Section Operations Technology, DNV, gave a presentation on how to ensure the integrity of pipelines. Ali Sisan, DNV UK Head of Pipelines and Subsea, spoke about the new DNV service specification for onshore pipeline verification. Graham Duff, Head of Section, Major Projects Group, DNV Aberdeen, talked about how to get more from an independent third-party specialist. Wide experience Asle Venås gave a talk on DNV’s wide pipeline experience; he told the audience that this segment is now one of DNV’s largest business areas, and that 65% of the world’s offshore pipelines are designed and installed according to DNV’s pipeline standard. His presentation


outlined the various research and development work currently ongoing and demonstrated the high-level experience that DNV has to offer. New developments in pipeline legislation Douglas Souden, Principal Pipelines Inspector, UK Health and Safety Executive, spoke about the current legislation, specifically in the UK and Europe. He reviewed the Pipeline Safety Regulations and the recent change proposals, such as the consideration of emerging issues and new European initiatives. He talked about onshore pipelines and Seveso, a study of the need for EU legislative action on the safety of onshore pipelines that was published in January 2012. The study found that the onshore conveyance of dangerous substances has a major hazard potential, but recognised that major pipeline accidents are not frequent. He commented: “The study concluded that there was limited value from additional EU legislation, but suggested that introducing reporting and benchmarking at EU level could help improve future decisions and help maintain the safety focus of operators.” He went on to discuss the actions that the UK and EC have taken following the Macondo incident, which resulted in eleven fatalities and released 4.9 million barrels of oil into the Gulf of Mexico. He

referred to the Maitland Report, an independent review of the UK offshore regulatory regime, that proposed six main areas for improvements. He commented: “On 9 October 2012, the Members of the European Parliament voted to follow an EU Directive route and not regulation,” and “The full pipeline position is not yet clear.” He concluded his presentation by reviewing the status of key performance indicator 4 (KP4), which concerns the ageing and life extension of assets, before pressing for backing for the Pipeline and Riser Loss and Containment (PARLOC) initiative, which was created following the Cullen Report. He urged: “The PARLOC initiative needs urgent support from pipeline operators and other industry stakeholders to ensure its survival.” Major pipelines in Europe Roberto Pirani, Chairman and Technical Director of the White Stream Pipeline Company, spoke about major gas pipelines in Europe; about the existing pipeline infrastructure and the diversity of supplies. He communicated the EU priorities reaching into 2020 and the desire to spread the risk in security of supply. Finally, he presented the different routes traversing Europe, such as Galsi, Nabucco, the Trans-Adriatic pipeline (TAP), White Stream and the EU section of South Stream.

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Douglas Souden, Principal Pipelines Inspector, UK Health and Safety Executive.

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Ali Sisan, DNV UK Head of Pipelines and Subsea.

Photo: DNV

DNV’s senior principal engineer Leif Collberg and pipeline segment director Asle Venås.

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Joost Brugmans, Intecsea, Project Engineer.

Working with verification bodies Joost Brugmans, Intecsea, talked about working with verification bodies, and DNV in particular, which is currently working with Intecsea on two projects – IGI Poseidon and the South Stream FEED studies. He presented an overview of the working relationship with DNV as a verification body, outlining the scope of work in accordance with the offshore Service Specification for the Certification and Verification of Pipelines (DNV-OSS-301). He provided a comprehensive and informative perspective on the project as well as a detailed section on lessons learnt.

Photo: DNV

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Photo: DNV

Photo: DNV

Pipeline Day

In conclusion, Mr Brugmans commented: “Our experience on IGI is that the third-party verification work has definitely resulted in improving the quality of the FEED deliverables, and has especially resulted in better documentation of the adopted design processes, including the assumptions made, and this is useful for the next engineering phase.” Recent developments in DNV codes and recommended practices Leif Collberg talked about the history and development of the Subsea Pipeline Systems standards and

introduced DNV-OS-F101:2012, which has been updated this year and aligned with ISO 3183. The document was submitted to 20 companies, and DNV received 1,005 comments. The uptake for attendance at this event was excellent and the feedback was very positive. The depth and content of the day’s proceedings and mix of internal DNV presentations and external contributions from the regulator and customers were key to the event’s success. 


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JIP update

Update on DNV-managed Joint Industry Projects relevant for pipelines The pipeline industry is constantly looking into cost-effective solutions. In addition, pushing into the new energy frontier poses great challenges for pipeline systems. As a pipeline technology leader, DNV is committed to continuously supporting the industry and a range of R&D and JIPs are currently taking the industry further ahead. Text: Asle Venås, DNV

DNV invests 6–7% of its revenue in R&D and a large proportion of this is spent on pipeline-related projects. DNV is well suited for pipeline R&D as we have run many JIPs, written many standards and guidelines, have a very highly educated and experienced staff covering all relevant pipeline disciplines and lots of experience from challenging pipeline projects all over the globe. We also have four laboratories to do associated experiments and testing. Our laboratories are located in: ■■ Høvik, Norway: large-size – full-scale testing laboratory ■■ Bergen, Norway: large-size – full-scale corrosion laboratory testing ■■ Singapore: large-size – full-scale testing laboratory ■■ Columbus, Ohio, USA: corrosion and H2S testing laboratory Some of the investment is in internally funded pipeline R&D projects: Eleven such projects have recently been completed and one is ongoing. Completed: ■■ Pipelines for the future – pipeline technology for the next 10 – 15 years ■■ X-Stream – cost-effective solution for a deepwater gas pipeline


SliPIPE – Solution for HPHT pipelines ■■ Floatpipe – Floating pipelines for deep water and challenging seabeds ■■ Residual stress/strain for pipeline girth welds under high strain (measuring residual stress) ■■ Developing a method for the SENT test (CTOD testing – under pure tension) for sour service ■■ Update of DNV-RP-106 – Factory-applied external coating ■■ Update of DNV-RP-102 – Field joint coating and field repair of linepipe coating ■■ Development of AUT workmanship style acceptance criteria ■■ Development of RP for AUT System Qualification ■■ Update of DNV-OS-F101 – Offshore Standard for Pipelines ■■

Ongoing: ■■ Standard for verification of onshore pipelines However, DNV prefers to work together with the industry and our main investment in pipeline R&D is through JIPs (Joint Industry Projects). During the past few years, we have seen an increase in industry requests to us to initiate and participate in pipeline-related JIPs.

R&D work through JIPs has many advantages. Apart from saving costs through sharing them, more experience is put on the table. The sponsors can influence the scope of the work and all sponsors obtain all the data and results gathered through the JIPs. Normally, the JIPs result in a guideline that is confidential to the partners and each partner is free to use it in their normal business. The confidentiality period is set by the steering committee (witch consists of one member per paying sponsor). After the confidentiality period, DNV sometimes converts the guideline into a recommended practice or a pipeline standard. However, all data, reports and results from the JIP will be confidential to the sponsors only. With the increased focus on JIPs, DNV will: ■■ Improve on utilising the best resources in the pipeline industry – this also includes subcontracting some work to other companies, and ■■ Professionalise its project management, including closer contact with the sponsors and shorter execution times DNV has recently completed, is currently running or is planning 31 pipeline-related Joint Industry Projects:

Photo: DNV

JIP update

Six recently completed JIPs ■■ HIPPS System Design ■■ Ice pipe – Arctic pipelines ■■ Spiral Welded Pipes for offshore use – phases 1 and 2 completed ■■ Clad and liner pipe – phases 1–3 ■■ On-bottom stability design of small diameter, submarine umbilicals and cables ■■ Treatment of residual stress in the ECA of pipeline girth welds under high plastic deformation ELEVEN ongoing JIPs ■■ CO2 pipelines, phase 2 ■■ Pre-commissioning of pipelines ■■ Pipeline Integrity Management (including update of DNV RP-116), phase 2 ■■ HPHT pipelines (merger of Hotpipe and Safebuck)

Development of guideline for Horizontal Directional Drilling (HDD) ■■ Development of Guidelines for ECA in Sour Service ■■ Design of Rigid Spools ■■ Fatigue of girth welds with defects ■■ Corroded pipes (incl. update of DNV-RP-101) ■■ Effect of Reeling on Sour Service Performance ■■ On-bottom stability design of submarine umbilicals and cables

Qualification of X-80 pipes for sour service applications ■■ Reliability-based fracture mechanics approach for pipeline girth welds ■■ Free-span assessment of pipelines in narrow trench ■■ Installation design and analysis ■■ CP insulation coupling for pipelines transporting electrical conductive liquids ■■ Local brittle zones ■■ Risk assessment of pipeline protection ■■ Study collapse of pipelines with D/t < 15 ■■ Anchor pipeline interaction ■■ Recommended practice for pipe-in-pipe concept

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14 Planned JIPs ■■ Spiral welded pipes for offshore use – Phase 3 ■■ Clad and liner pipe – Phase 4 ■■ Assessment of pipeline components for offshore pipelines ■■ Pipeline concrete coatings design

Several of our ongoing and all our planned JIPs are open for more sponsors. Interested companies can contact Asle Venås at [email protected] 


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Global presence

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Pipeline Update - 2013 (DNV)

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