Pipeline Update 1-2012 by DNV GL (old account)

X-Stream deepwater pipeline concept

Nord Stream offshore pipeline

Risk assessment outlook for pipelines

pipeline update

News from DNV to the pipeline industry

No 01 2012

contents

04 X-Stream deepwater concept

10 ››

Nord Stream offshore pipeline

Taking deepwater pipelines to the X-Stream...............................................................4 New revision of the DNV pipeline standard..................................................8 Nord Stream: the world’s longest offshore pipeline..........................................................10 Time to re-think risk...................................................13 Assessing the metallurgical attributes of vintage pipe.......................................14 The new risk assessment outlook for pipelines....................................................................18 West African gas pipeline..........................................21 Constructing an auditable framework..........22 Forensic engineering and failure investigation ….............................................................28 Observations of onshore pipeline regulatory trends......................................................32 Challenging gas fields in Australia......................................................................34 the DNV pipeline committee....................................36 Taking the pipeline industry forward..............38 2 | pipeline UPDATE NO. 1 2012

18 ››

Risk assessment outlook for pipelines

pipeline update We welcome your thoughts! Published by DNV Maritime and Oil & Gas, Communications. Editor: Eva Halvorsen Design and layout: Coor Media 1208-051 Front cover photo: DNV/Nina Rangøy Please direct any enquiries to DNVUpdates@dnv.com 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

››

editorial

Asle Venås Global Pipeline Director asle.venås@dnv.com

Pipeline Update – a new DNV magazine This is the first edition of DNV Pipeline Update, a magazine with a focus on new technology, trends and stories from the global pipeline industry. It will cover all phases of both onshore and offshore pipelines. We aim to issue this magazine on a regular basis. DNV will celebrate its sesquicentennial in 2014. Our 150-year history as an independent foundation is noteworthy: the fact that we have no shareholders makes us unique, allowing full transparency. The fact that we have no shareholders to take the profit also enables us to invest most of our profit in research and development for the benefit of our customers. DNV invests 6–7% of its revenue in R&D every year.

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

In 150 years, we’ve expanded our focus from strictly maritime issues to include sectors such as energy, healthcare, food safety, management systems and transportation. As diverse as these sectors are, our services still have one common thread; our continuous efforts to manage risk in order to safeguard life, property and the environment. DNV pioneered the North Sea’s deepwater pipeline and facilities technology in the mid-1970s, and we’ve now expanded our reach in the pipeline sector to all corners of the globe. Pipeline-related services have become one of DNV’s most important business segments and are DNV’s largest area within the oil and gas sector. The enclosed articles are authored by respected industry personnel at the various DNV locations from which we operate. I hope you find them interesting.

pipeline UPDATE NO. 1 2012 |

Innovation

Taking deepwater pipelines to the X-Stream DNV has a safe and cost-effective concept in the pipeline The deepwater gas transportation market will experience massive investments and considerable growth over the coming years as operating companies go even deeper to find and recover new resources. Text: Asle VenĂĽs, DNV Global Pipeline Director

This will result in a number of new technical and operational challenges as we face a future where operators are forced to push the frontiers of exploration in order to meet energy demand. The industry is delving into deeper and more remote fields and new exploration activities are also heading for ultra-deep waters. These fields are often located several hundred kilometres from land, in water depths in excess of 2,000 metres. We also see several gas pipeline projects that are under planning of crossing deeper and deeper sea passes, e.g. GALSI (2,824m water depth), SouthStream (>2,000m water depth) and SAGE (Middle East to India, 3,400m water depth). Deepwater pipelines pose a number of challenges and in particular long distance gas transportation in deep water is an increasing issue due to its cost. The safe and cost-effective transportation of oil and gas in pipelines from deep and ultra-deep water is a growing challenge worldwide and safe and new solutions are needed. DNV has developed a new pipeline concept, called X-Stream, which can significantly reduce the cost of deepwater

4 | pipeline UPDATE NO. 1 2012

and ultra-deepwater gas pipelines while still complying with the strictest safety and integrity regimes. This long-distance gas transportation concept can reduce the wall thickness of deepwater gas pipelines by utilising a unique system to control the differential pressure. X-Stream can reduce both the pipeline wall thickness and time spent on welding and installation compared to deepwater gas pipelines currently in operation. The exact reduction in the wall thickness depends on the water depth, pipe diameter and actual pipeline profile. Typically, for a gas pipeline in water depths of 2,500m, the wall thickness reduction can be 25â&#x20AC;&#x201C;30% compared to traditional designs. This could save in the order of 10% of the installation cost. There are also other advantages. E.g. the concept can allow a larger diameter with the same wall thickness and also reduce the consequence of a potential accidental flooding of the pipeline during installation. Implications for industry TheÂ production cost of pipelines in the X-Stream

concept decreases as less steel is required in the construction of the pipe. The reduced thickness also means that manufacturing in higher grade steel will be possible. Installation costs are slashed by the reduced welding times and the new method also results in increased lay rates. The concept can have significant implications for projects around the world. In particular X-Stream will be highly applicable to the recent finds in pre-salt fields offshore from South America. Located 330km from the coast, these pose a number of exploration and gas transportation challenges which can be alleviated through the new concept. It is also relevant to deepwater developments in the Gulf of Mexico, Eurasia and West Africa, as well as any gas trunk lines crossing deep sea passes. The X-Stream concept can also represent an alternative to the current solution of deploying floating LNG plants combined with LNG shuttle tankers for such fields. X-Stream is based on field-proven technologies which have been innovatively arranged to provide a new solution. The integral principal of X-Stream is the

Innovation

››

Velit esse molestie consequat, vel illum dolore eu feugiat nulla Lorem ipsum dolor accumsan et iusto odio dignissim qui blandit praesent

››

“By controlling the pressure differential between the pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25–30%,” says Asle Venås, DNV’s Global Pipeline Director.

pipeline UPDATE NO. 1 2012 |

Innovation

constant internal pipeline pressures. The concept is based on a combination of already established technology, inverted High Pressure Protection System (i-HIPPS) and the development of inverted Double Block and Bleed valves (i-DBB). More than 20 subsea HIPPS systems are currently in use worldwide to prevent sudden pressure rises in pipelines. DNV is inverting this well-established system to prevent too large differential pressure for the duration of the pipeline’s lifespan. DNV ran a concept risk analysis to identify the major threats and mitigate the risk of the concept and one significant issue was identified. In order for the concept to function effectively, there is a requirement for 100% internal leak tight i-HIPPS valves, at least for the secondary HIPPS valves. The result of this was the development of i-DBB. By utilising i-HIPPS and i-DBB, the X-Stream system immediately and effectively isolates the deepwater pipe if the internal pressure starts to fall. In this way, the internal pipeline pressure can be maintained above a critical level for any length of time. Implementing X-Stream The challenge is to avoid pipeline collapse over hundreds or thousands of kilometres, caused by the loss of internal pressure through a leak or rupture of the pipe during operation. Current deepwater gas pipelines have traditionally been built with very thick walls using large quantities of steel and specialised equipment for milling. Due to quality and safety requirements, the number of pipe mills capable of producing this type of pipe is limited. They also use extremely thick and costly buckle arrestors. When installing pipelines, the heavy weights are difficult to handle and the thick walls are challenging to weld. Given the more demanding composition of current deepwater pipes, the number of pipe-laying vessels capable of handling this kind of pipeline is limited too. Demand is expected to increase for the few specialist milling and laying facilities for deepwater

6 | pipeline UPDATE NO. 1 2012

pipelines, which will drive costs up further in conventional methods. During installation or operational shutdowns, gas pipelines at such extreme depths have to withstand high external pressures without imploding. X-Stream has introduced a new method to deal with this pressure problem without relying purely on material thickness to ensure the integrity of the pipeline to stop the collapse of the pipe wall. By controlling the pressure differential between the pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25–30% or even more compared to today’s practice and depending on the actual project and its parameters. The X-Stream concept fulfils common pipeline codes such as ISO and DNV-OS-F101, ensuring that safety is not compromised. During installation of the new pipeline concept, it is necessary to fully or partially flood the pipeline to control its differential pressure. Then cleaning and gauging of the pipeline can commence as normal and it can then be dewatered and dried for operation. The i-HIPPS and i-DBB systems ensure that during operation, the pipeline’s internal pressure can never drop below the collapse pressure – plus a safety margin. This maintains the certain minimal internal pressure in the pipeline during the entire life of the pipeline. X-Stream consists of a series of valves and temperature transducers linked to a control system. The main i-HIPPS valves are located above water to ensure easy access for maintenance, inspection, testing of the valves etc. The main i-HIPPS system will activate on a low pressure signal from the pipeline. This will ensure the minimum internal pressure at all times as long as the pipeline is free from leak or rupture above the collapse critical area. If the pressure continues to fall due to an internal leakage in main i-HIPPS valves, and the pressure is getting close to the critical collapse level, the i-DBB system is

activated and the pipeline is isolated by a viscous substance or gel consistency that is pumped under high pressure into the space between the i-DBB valves to stop leaks from the higher pressure side. This is a central component to the X-Stream concept which ensures the integrity of the pipeline. What is termed as the ‘collapse critical area’ is the depth at which the external pressure can compromise the pipeline. If leakage or rupture of the pipeline occurs above this level at the rig or near the shore, then the secondary i-HIPPS system will be activated. The secondary i-HIPPS system is located below collapse critical area. If disaster strikes, and there is a leakage or rupture of the pipeline in shallow water, the pressure will fall and the i-HIPPS valves will close. i-HIPPS activates on a low pressure signal to prevent pressure in the pipeline from dropping below the pre-determined minimum and immediately isolates the deepwater pipe if the pressure begins to fall. This ensures that the internal pipeline pressure is maintained above critical level and protects the pipeline from collapse due to excessive external pressure. When the trigger is activated then the valves and actuators close to maintain pressure within at all times. The below water i-HIPPS valves are placed below the collapse critical depth. Should they have an internal leak and the internal pressure reach a critical level a small bleed valve is opened to the surrounding water and the seawater will flood the void between the i-DBB valves. The seawater pressure here will ensure that the pressure will never drop below the critical level. Leakage or rupture below the critical collapse depth limit will not be collapse critical because the high external pressure will prevent loss of internal pressure below the critical level. If there is leakage, it will result in an in-flow of water rather than gas leaking out, the same as would happen with a traditional gas pipeline in deep water. It will also be important to maintain the minimum pressure in the pipeline

Innovation

››

Dr Henrik O. Madsen, DNV’s CEO (right), and Asle Venås, DNV Global Pipeline Director, launched the X-Stream Concept in London early in 2012.

during pre-commissioning. This can be done using produced gas separated from the water in the pipe by a set of separation pigs and gel. This technology is not new to the industry as this method has already been initiated as standard practice by several oil companies. From concept to reality DNV has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over the past decades. Today, more than 65% of the world’s offshore pipelines are designed and installed to DNV’s offshore

pipeline standard. The organisation has also been involved in several deepwater projects over the past years, e.g. Oman to India, Bluestream, Perdido and Ormen Lange. A global team of highly skilled engineers combining youth and experience, headed by DNV in Rio de Janeiro, Brazil, and including Oslo, Houston and Cape Town, is behind X-Stream. The new concept has been launched following significant research, development, engineering and industry input. The DNV study is a concept, and a basic and detailed design will need to be carried

out before the X-Stream concept is realised on a real project. DNV is working with the industry to refine and test the concept. DNV is confident that, by further qualifying the X-Stream concept, huge financial savings can be made for long distance, deepwater gas pipelines without compromising their safety and integrity. 

pipeline UPDATE NO. 1 2012 |

dnv pipeline standard

New revision of the DNV pipeline standard The DNV Offshore Standard for Submarine Pipeline Systems, DNV-OS-F101, is probably one of the most used, studied and discussed DNV standards. The latest revision will provide significant improvements based on solid feedback from the industry; close to 1,000 comments were received during the consultation process. Text: Leif Collberg and Sigbjørn Røneid

This will be the third revision of the Offshore Standard in its present format, which itself was based on three earlier revisions of the DNV Pipeline Rules. The trigger for the revision has been to align the standard with the new ISO 3183 on linepipe and the new ISO coating standards. In addition, DNV has gained a lot of experience and received quite a bit of feedback from the industry; we wished to incorporate this into the standard.

››

“We’re impressed about the effort put into the consultation process by the industry in connection with the revision of the DNV pipeline standard,” say DNV’s Leif Collberg and Sigbjørn Røneid (top).

8 | pipeline UPDATE NO. 1 2012

Three main changes Although there are significant improvements in the new revision, most of these involve restructuring and clarifications. The three main changes are as follows: Firstly, the concept development and design premises section has been reorganised into a more chronological order. The part on pressure control systems has been slightly restructured and generalised – restructured in the sense that pressures are defined and generalised in that the control system is no longer limited to pressure alone but has been extended to all critical operational parameters, such as temperature, content and minimum pressure, and the term operating envelope has been introduced for this purpose. The second main change is in the installation section, which is now termed

“Construction – Offshore” as it includes pre-installation as well as post-installation (e.g. pre-commissioning) activities. This is based on several workshops with Statoil, and the section is now more balanced with respect to the extent of the activities and is organised in chronological order. In addition to the reorganisation, de facto changes in this section relate to marine operations and equipment qualification. The third main change relates to nondestructive testing (NDT) and automated ultrasonic testing (AUT). As this has been a less mature area in terms of technology compared to other parts, the experience gained over the past five years and from the new DNV-RP-F118 on the qualification of AUT systems was expected to necessitate some updates. Shall, should or may Numerous minor editorial changes have also been included. One worth mentioning is the ever ongoing process of aligning the requirements to shall, should or may. One result of this is the change of expressions such as “Unless otherwise agreed, xx shall fulfil …” to “XX should fulfil …” as should is defined as the preferred solution if the requirement can be deviated from if agreed in writing between the contractor and purchaser.

dnv pipeline standard

››

The American Society of Mechanical Engineers (ASME) gave DNV the Global Pipeline Award in 2009. This is the industry’s most prestigious global award, emphasizing the status of DNV’s pipeline standard.

DNV Code Manager Covering almost all aspects of pipelines, the standard includes many disciplines. A ‘core team’ of 10–15 persons has performed most of the work, but has had important support from probably twice as many people. No resting on laurels So when will DNV start on the next revision? DNV now has a web-based tool that allows it to record changes for the next revision on a continuous basis as well as to include background discussions, reports, etc. DNV-OS-F101 is a pilot code for this so-called DNV code manager. Feedback can be performed at meetings with customers, for instance. Why not invite DNV to a meeting to discuss and propose changes for the next revision? 

DNV’s standards and recommended practices (RPs) are based on industry experience, best practices and research. Through Joint Industry Projects, standards and RPs are regularly updated to reflect new technology and knowledge. A need to keep track of these revisions and the reasons behind them has been identified. Objective: • To manage expertise • To make revisions more effective

Benefits: • Administers experience feedback, both internal and external • Allows reference to background documents • Ensures a uniform response to our customers in interpretations • Improves quality in that all feedback is stored • Companies can ask for and give interpretations of requirements • Allows discussions among users • Reduces the cost of revisions

In the future: • External clients may subscribe to this service and obtain company-specific notes – e.g. outlining the company’s use of the standard • It may also be used actively as part of a revision of the standard • It may be applied to other codes

pipeline UPDATE NO. 1 2012 |

Nord Stream

Nord Stream:

the world’s longest offshore pipeline A milestone of the energy partnership between the European Union and Russia, Nord Stream is a twin pipeline system through the Baltic Sea transporting natural gas from Russia to Europe. Text: Maud Hanitzsch

Natural gas plays a key role in the European Union’s energy mix and is expected to gain importance as back-up fuel for variable electricity generation in the years to come. The Nord Stream pipeline, a “project of European interest” according to the European Union’s TEN-E (Trans-European Energy Networks) guidelines, represents a key element in the development of the EU’s internal energy market, reinforcing economic growth and the creation of employment. The project is a substantial step forward in achieving the EU’s energy supply goals, such as the diversification of the energy mix and increase of import capacity with additional supply routes. Nord Stream consists of 48-inch twin pipelines which transport natural gas over a distance of 1,224km through the Baltic Sea. It has been planned and built by a consortium consisting of the majority shareholder Gazprom together with Wintershall, E.ON Ruhrgas, Nederlandse Gasunie and GDF Suez to enhance long-term energy security and help achieve climate change goals in Europe. The two pipelines link vast gas reserves in Russia to the energy markets in the European Union and are capable of transporting 55 billion cubic metres of gas annually – enough to supply 26 million households in Europe.

10 | pipeline UPDATE NO. 1 2012

“DNV’s strong reputation adds as much to our project as DNV’s highly skilled professionals and their independent assessments. One main step for the success of the Nord Stream project was the selection of an independent certification organisation in an early phase. With DNV we found a very competent and experienced partner.” Henning Kothe, Project Director at Nord Stream AG

Pipeline certificate by DNV DNV started supporting the project at an early stage – when it involved Nord Stream’s predecessor North European Gas Pipeline in the late 1990s. During the conceptual phase in 2005, DNV verified the Nord Stream conceptual/FEED study for Gazprom. Since 2007, DNV has been hired by Nord Stream AG to verify that the design, fabrication and installation meet the governing standard DNV-OS-F101: Submarine Pipeline Systems. Adherence to this internationally accepted standard of safety for submarine pipeline systems safeguards the integrity of offshore pipeline projects, helping ensure public safety and environmental protection. Henning Kothe, Project Director at Nord Stream AG, confirms: “One main step for the success of the Nord Stream Project was the selection of an independent Certification Organisation in an early phase. With DNV we found a very competent and experienced partner for our requirements, with a high level of reputation in the offshore industry. This gave us a strong support during all project phases in talks with suppliers, shareholders, banks and the media – they all know DNV and have a high regard for the company and its independent assessments.”

Nord Stream

DNV’s expertise and experience, which stem from the development of the standard since it was first issued in 1976 and the independent verification of most major offshore trunkline projects, have been important for confidently ensuring quality and integrity at all stages of a project that is pushing limits in terms of pipeline length and diameter. Nord Stream utilised DNV’s full range of multidisciplinary technical competences and provision of comprehensive and independent technical quality assurance to manage all the high-risk elements. Risk-based verification according to DNV-OSS-301: Certification and Verification of Pipelines has involved state-of-the-art methods and tools at each stage, from design verification to manufacture control and independent construction inspection. Many challenges The project’s challenges included the development of the heaviest ball and gate valves ever produced as well as risks specific to the Baltic Sea environment, such as corrosion control in brackish waters, pipelaying on an irregular seabed with soft soils, and interference with fishing activities and ship traffic – the Baltic Sea has some of the world’s busiest shipping routes with around 2,000 sizeable ships sailing on it at any time. The size of

››

The Nord Stream pipeline from Russia to Germany.

››

From left to right, first row: French Prime Minister Francois Fillon; German Chancellor Angela Merkel; Dutch Prime Minister Mark Rutte; Russian President Dmitry Medvedev; and European Union Energy Commissioner Günther Oettinger turn a wheel to symbolically start the flow of gas through Line 1 of the Nord Stream twin pipeline system this Spring.

pipeline UPDATE NO. 1 2012 |

Nord Stream

››

Construction of the Nord Stream Pipeline started in the Swedish Exclusive Economic Zone of the Baltic Sea early in April 2010. The vessel Castoro Sei (C6) began offshore pipelaying near the island of Gotland, a distance of 675km from the pipeline’s starting point near Vyborg, Russia.

the fishing equipment compared to the pipeline diameter is very different to the neighbouring North Sea, and fishing in the vicinity of a subsea pipeline is a new experience for local fishermen. In addition, the fact that the Baltic Sea contains obstacles such as sea mines from the First and Second World Wars and shipwrecks posed installation risks. For DNV a project of this size comes with peculiar challenges; altogether more than 7,000 were reviewed, and there were days when more than 20 documents arrived for review by specialists in different disciplines; a well-attuned, committed team is required to handle this amount of information consistently, reliably and on time. From a geographic point of view, DNV’s strong global presence was a great advantage: for example in the fabrication subproject alone, verification work took place at four plate fabrication sites, three pipe mills, two concrete coating yards and the production sites for valves, anodes, buckle arrestors, bends, pig traps, anchor flanges and bends, in many countries ranging from the US to Japan, Russia, Italy,

12 | pipeline UPDATE NO. 1 2012

the UK and many others. Having stations with experienced surveyors all working to the same global standards allowed DNV to mobilise personnel at short notice too, ensuring that verification work had no impact on the overall project schedule. Not finished yet Gunn Stirling, DNV’s project manager, says: “When the first of the Nord Stream pipelines became operational last year, it was an important milestone and many expected the project to start approaching the end. However, final verification completion is not reached until both pipelines are fully commissioned. The project team must see that all elements are properly closed and documented, and that the 50-year operations are also planned so as to keep the integrity intact. Therefore, the DNV experts cannot be fully released until we have provided Nord Stream AG with the final Pipeline Certificates for Line 1 and Line 2. We are also looking into extending our cooperation with regard to verifying the integrity for the operational phase too, but that will be a separate DNV project.” 

Nord Stream facts Length: 1,224km (two parallel lines) Maximum water depth: 210m Pipeline joints per pipeline: 101,000 Pressure segmented design: Three pressure sections (220, 200 and 177.5 bar) and pipe wall thicknesses (34.4, 30.9 and 26.8 mm respectively) Amount of raw materials used in the concreteweight-coating plants: 1,5 million tonnes of iron ore, 500,000 tonnes of aggregate, 430,000 tonnes of cement, 43,000 tonnes of wire Amount of steel used: 2,424,000 tonnes Weight of four gate valves at the landfall locations: 102 tonnes each Capacity: 55 billion cubic metres per year (27.5 bcm per line) Nominal diameter: 1,220 millimetres (48 inches) Shareholders: OAO Gazprom (Russia, 51%), E.ON Ruhrgas AG (Germany, 15.5%), BASF SE/ Wintershall Holding GmbH (Germany, 15.5%), N.V. Nederlandse Gasunie (Netherlands, 9%), GDF SUEZ S.A. (France, 9%) Total investment: 7.4 billion euros Start of gas transportation (line 1): November 2011; Pipelaying completed (line 2): April 2012 Environmental monitoring programme: appr. 1,000 survey locations – 16 parameters DNV’s key deliverable: Pipeline Certificates for Line 1 and Line 2 based on verification of design, manufacture and construction.

risk management

Time to re-think risk We have been reminded several times over the past few years that major accidents happen and that external events can have a significant impact on our lives, our industry and our business. The question is not whether we are exposed to risks and uncertainty, but how we can manage them, and how we can maximise our opportunities and rewards while minimising our exposure. Text: elisabeth H. tørstad

and long-term consequences of an accident. Indeed, barriers have critical functions to safeguard life, property and the environment.

Managing risk is now a buzzword, and boards and managers everywhere are looking for effective risk management solutions. Risk management should be an integral part of an organisation, something that influences behaviours and decisions every day. And the efficiency of risk management methods should be measured by well-defined parameters to enable us to learn what is working and stop what does not lead to improvements. Both the offshore oil and gas industry and the maritime industry have demonstrated significant improvements in occupational safety, safe and healthy working conditions for men and women, over the past decade. That job will never end but, overall, we can say that occupational safety is improving and that current best practices are effective. Attention to major accidents, such as the prevention of fires, explosions, navigational errors, collisions and similar accidents, is a different story. The earlier risk management thinking was that reducing the frequency of accidents would lead to a positive correlation to a reduction in the more severe accidents. However, we have no indications that this has happened. Managing risk is the core of DNV’s business and we are continuously working to stay at the forefront of the development

››

Elisabeth H. Tørstad Chief Operating Officer, Division Americas

of methodology and practices, in order to be even more effective in preventing accidents and mitigating their consequences. Today, barrier management has been identified as an effective way of preventing major accidents. The methodology considers scenarios and threats that may lead to major accidents. Then, for each threat, barriers – technical, physical, operational procedures, management and decision making – are developed and implanted to remove the threat, prevent it from occurring or mitigate its consequences. Barrier management is also well-suited for managing both the immediate, or short-term,

However, analyses of most major accidents show that barriers have been in place but that the failure of these barriers has led to accidents or failed to control the consequences. Why? Barriers are not typically monitored during operations, operators are not aware of the significance of barriers or decisions are made without regard to barrier status. Barrier management includes addressing the deterioration of a barrier over time, usually in operating practices, and a rapid response in order to maintain barriers, including decisions to shut down if a barrier is not functioning. As we move forward, let’s remember that a key element of successful risk management is monitoring changing threat and hazard conditions, especially the status of the barrier designed to control them to prevent accidents. The risk picture in our industry continues to increase in complexity and we need to take a giant leap, make a big step change, in how we manage process risk. 

pipeline UPDATE NO. 1 2012 |

Pipeline maintenance

Assessing the metallurgical attributes of vintage pipe Historically, the primary focus of direct examination (commonly referred to as “bell hole inspection”) was to assess coating condition and describe the attributes of mechanical damage or corrosion – in addition to verifying wall thickness, diameter and perhaps seam type. With recent regulatory emphasis on verifying the accuracy of pipeline data, the role of in-situ nondestructive determination of metallurgical attributes becomes increasingly important. Text: Bill Amend

››

Bill Amend, DNV senior project manager

North American pipeline systems currently in operation can consist of piping manufactured up to a century ago. Not surprisingly, documentation related to the manufacture, installation, testing, maintenance and inspection of vintage a pipeline is often incomplete, unreliable

14 | pipeline UPDATE NO. 1 2012

or even non-existent. While some aspects of pipeline integrity management rely on knowing specific mechanical properties or the metallurgical characteristics of piping, the relevant data are often unavailable in pipeline files. Although the data can often be generated from analysis of hot tapped coupons or scrapped cylinders of pipe, hot tapping represents a significant expense and potential safety issue (welding and tapping pipe with questionable metallurgical characteristics) while scrap pipe is not always available. Further, a single tapped coupon or pipe cylinder may not be representative of the range of metallurgical characteristics or properties in a long pipeline segment and obtaining multiple pipe samples for destructive testing can be impractical. However, visual examination and interpretation of specific surface features supplemented by non-destructive metallurgical analyses can provide a wealth of information to supplement and confirm pipeline records in support of integrity management decisions.

The value of comparative analysis To a trained inspector, visible features on a pipe surface can reveal details about manufacturing methods, installation and inspection – details easily overlooked if the focus is merely on characterising in-service degradation. For example, one type of seam is commonly mischaracterised as a product of a an early submerged arc welding process when in fact it is a unique type of seam manufactured only by A.O. Smith using two different types of seam welding processes (~ 1928–1932). The seams are commonly found to have planar flaws on the ID surface and weld metal solidification cracks on the OD portion of the seam. As another example, specific types of surface textures (“spellerizing”) are uniquely associated with lap seam pipe. Lap seam pipe is one of the oldest forms of seamed pipe and was not described by API Specification 5L after the eighteenth edition released in 1960. Furthermore, the specific pattern of the spellerizing was unique to each lap seam pipe manufacturer, so characterizing the spellerizing can

Pipeline maintenance

››

While some aspects of pipeline integrity management rely on knowing specific mechanical properties or the metallurgical characteristics of piping, the relevant data are often unavailable in pipeline files.

help confirm records indicating the pipe manufacturer. Girth weld joint designs and weld metal appearance are not consistently characterised during direct examination but they can be significant from the standpoint of assessing likely resistance to large axial loads such as those associated with ground deformation. For example, fillet welded bell & spigot joint designs were largely abandoned in the early 1930s in part because of the relatively low axial strain capacity of the fillet welds. In comparison,

the slightly newer bell-bell-chill ring (BBCR) joint designs were found to have much better strain capacity, even when workmanship was imperfect. One typically overlooked feature of early girth welds is the consistency of the weld metal ripple pattern that indicates the direction of weld progression. Early pipeline construction techniques included the practice of making several girth welds while pipe was rolled underneath the welding arc or torch. Segments of welded pipe were then welded together in the more

challenging fixed position. As a result, long pipeline segments can have two (or more) distinctly different populations of girth welds, each having different workmanship quality and mechanical properties but in recognisable patterns that are readily repeatable along the length of the pipeline. Other readily visible surface features can be indicative of the use of refurbished pipe, in-situ mechanical testing performed (as a weld quality assurance measure), or the use of early radiographic inspection procedures.

pipeline UPDATE NO. 1 2012 |

Pipeline maintenance

KEY STEPS

DESCRIPTION

Preassessment

Verify that the pipeline segment is a single population of pipe that meets the boundary conditions

Procedure qualification

Prove that the field procedures generate the same hardness data as a standard lab procedure CRTD - VOL. 19

Technical qualification

Calibration, Surface prep, Hardness measurement, Data QA, Statistics

Prove that the technician can follow the procedure

Measure hardness of a random sample of pipes, count samples, calculate mean hardness, std. dev. FIELD CHECKLIST

Adjust the hardness result to compensate for statistical uncertainty and sample size

Estimate YS using calculated lower bound hardness for the pipeline segment

16 | pipeline UPDATE NO. 1 2012

Coverage factor (k) Subtraction factor (SF) a, a*

Per CRTD Vol. 57

Analysis methods and tools to augment visual examination TheÂ table correlates specific pipeline attributes with non-destructive technologies that can supplement visual examination. Each of the technologies can be used on operating, pressurised pipelines and require no special treatment or repair of the pipe surface (other than re-coat) after completion of the analysis. Some of the analyses can easily be performed by pipeline company technicians while other methods are more commonly subcontracted to specialized service companies. In most cases, results are available immediately. In the case of spectrographic analysis of steel filings or examination of metallographic replicas, results are available shortly after analysis of the filings or examination of the replicas in a supporting laboratory. Proper testing methods and tools Attention to detail and understanding the capabilities and limitations of each analysis method improves the likelihood of obtaining accurate data. For example, when performing chemical analysis of steel filings by either field portable spectroscopy or by laboratory analysis, results most indicative of prevalent wall thickness are obtained when at least 0.01 inches (0.25 mm) are removed from the pipe surface to minimise any decarburized layer present on the steel surface. Because carbon content is typically related to hardness, it is good practice to remove the same thickness (0.01 inches) of steel prior to using hardness test results as a means of estimating steel strength. ItÂ should be noted that except in the case of very thin wall pipe, the removal of 0.01 inches prior to analysis and the subsequent removal of additional thickness in the course of obtaining filings for chemical analysis has no significant effect on pipe pressure capacity when the thickness reduction occurs over a small area. Field-portable spectrographs can be deceptively quick and easy to use but users should recognise the importance of proper maintenance and calibration

Pipeline maintenance

››

Pipeline Attribute

Assessment Technology

Application

Steel composition

Portable spectroscopy Laboratory spectrographic analysis of steel filings

Support selection of optimized welding procedures for hot taps and repairs Provide an indication of joint-to-joint variability in pipe properties

Yield strength and tensile strength

Portable hardness testing Automated ball indentation (ABI) testing

Determine the lower bound yield strength of a pipeline segment at a selected confidence level per ASME CRTD Vol. 91, or the estimated strength of single pipes or components

Hardness

Portable hardness testing

Determine the acceptability of “hard spots” and weld heat affected zones

Microstructure

Replication metallography/ Field portable metallography

Differentiate between ERW seams having high temperature versus low temperature post weld heat treatments

Crack morphology

Replication metallography/ Field portable metallography

Determine the origin of planar flaws (manufacturing flaw, fatigue crack, high-pH SCC, or near neutral pH-SCC)

Pipeline attributes with corresponding relevant technologies for non-destructive analysis

in addition to the importance of steel surface preparation. When looking for a service provider or an instrument to provide field portable spectrographic analysis, care should be taken in specifying OES (optical emission spectroscopy) technology rather than XRF (x-ray fluorescence) technology. XRF alloy analyses will not measure carbon content of steel. Several types of field-portable hardness testers are available for measuring hardness (for determining acceptability of hard spots), weld heat affected zones, or for determining the lower bound expected yield strength. However, each hardness tester has its own strengths and limitations. For example, results from some hardness test methods are significantly influenced by technique, material thickness, surface curvature and surface preparation and may even be affected by residual magnetism, vibration, or temperature. Converting measured hardness into estimates of yield strength is based on empirical data and requires strict adherence to boundary conditions (pipe size, age, etc.) to ensure that the established relationship of hardness to strength is applicable.

Metallographic examination using either field-portable microscopes or surface replication methods can be invaluable for differentiating between surface anomalies associated with manufacturing flaws and stress corrosion cracks (SCC), or, for determining if SCC is related to high-pH or near-neutral-pH SCC. However, proper polishing and etching techniques and interpretation of replicated surfaces is a key to success. Maximizing your excavation efforts In summary, direct examination offers the opportunity for learning much about the metallurgical characteristics of an exposed pipeline in addition to characterizing in-service damage and coating degradation. Careful visual examination by technicians trained to identify and interpret specific features, coupled with one or more non-destructive analysis techniques, can help pipeline operators validate uncertain or incomplete pipeline records and provide important data in the pipeline integrity management process. 

››

This unique embossed pattern on the outside of the pipe identifies the seam type as a lap seam, but its ‘fingerprint’ also lends itself to identifying a specific manufacturer.

››

Areas of two adjacent pipes prepped for hardness testing to determine lower bound yield strength.

pipeline UPDATE NO. 1 2012 |

Risk management

The new risk assessment outlook for pipelines W. Kent Muhlbauer recently joined DNV to augment the company’s pipeline risk management service offerings. Mr Muhlbauer is a globally recognised authority on pipeline risk management. His published works include the Pipeline Risk Management Manual, now in its 3rd edition, and largely considered the ‘go to’ source for pipeline risk management.

PHMSA (the U.S. Pipeline Hazardous Materials & Safety Administration) has recently expressed criticism regarding how Integrity Management Plan (IMP) risk assessment (RA) for pipelines is being conducted. Do you also see problems?

regulatory requirements. The second category was costly and ill-suited for long, linear assets like pipelines.

There is a wide range of risk assessment practice among pipeline operators right now. Some risk assessment is admittedly in need of improvement – not yet meeting the intent of the IMP regulation. However, I believe that is not due to lack of good intention, but rather incomplete understanding of risk. Risk is a relatively new concept and it’s not easy to fully grasp. To address PHMSA’s concerns, we as an industry need to improve our understanding of risk and how to measure it.

They’re really neat – intuitive, easy-toset up, and vastly more informative than either of the previous approaches. By independent examination of key aspects of risk and the use of verifiable measurement units, the whole landscape of the risks becomes apparent. That leads to much improved decision-making.

What’s new in the world of pipeline risk assessment? In the past few years, the emergence of the US IMP regulations has prompted the development of more robust risk assessment methodologies specifically designed for pipelines. Even though PHMSA and others have identified weaknesses among some practitioners, much progress has been made. Previous methodologies fell into two categories: 1) scoring systems designed for simple ranking of pipeline segments, and; 2) so-called quantitative risk assessments (QRAs) used in more

18 | pipeline UPDATE NO. 1 2012

What are the new methodologies like?

How can they be both easy and more informative?

››

“In the past few years, the emergence of the US IMP regulations has prompted the development of more robust risk assessment methodologies specifically designed for pipelines. Even though the U.S. Pipeline Hazardous Materials & Safety Administration and others have identified weaknesses among some practitioners, much progress has been made,” says W. Kent Muhlbauer who has joined the DNV team.

robust applications, often for certain industrial sites and for certain regulatory and legal needs. The first were popular among the pre-IMP voluntary practitioners, but were limited in their ability to accurately measure risk and to meet IMP

More informative since they produce the same output as the classic QRA. Easy because they directly capture our understanding of pipelines and what can cause them to fail. The word ‘directly’ is key here. Previous methods relied on inferential data or scoring schemes that tended to interfere with our understanding. If they do the same thing as QRA, why not just use classical QRA? Several reasons: classic QRA is expensive and awkward to apply to a long, linear asset – can you imagine developing and maintaining event trees/fault trees along

Risk management

every foot of every pipeline? Classical QRA – at least how its practiced by many – relies heavily on historical failure frequencies. I often hear something like “we can’t do QRA because we don’t have data.” I think what they mean is that they believe that databases full of incident frequencies – how often each pipeline component has failed by each failure mechanism – are needed before they can produce the QRA type risk estimates. That’s simply not correct. While such data is helpful, it is by no means essential to RA.

But if I need to estimate (‘quantify) how often a pipeline segment will fail from a certain threat, don’t I need to have numbers telling me how often similar pipelines have failed in the past from that threat? No, it’s not essential. It’s helpful to have such numbers, but not necessary. Note that the historical numbers are often not very relevant to the future – how often do conditions and reactions to previous incidents remain so static that history can accurately predict the future? Sometimes, perhaps, but caution is warranted. With or without historical comparable data, the best way to predict future events is to understand and properly model the mechanisms that lead to the events. Why do we need robust results? Why not just use scores? Numerical estimates of risk – a measure of some consequence over time and space, like ‘failures per mile-year’ – are the most meaningful measures of risk we can create. Anything less is a compromise. Compromises lead to inaccuracies; inaccuracies lead to diminished decision-making, leading to misallocation of resources; leading

pipeline UPDATE NO. 1 2012 |

Risk management

Risk assessment that follows our Essential Elements guidelines avoids the pitfalls that befall many current practices. W. Kent Muhlbauer, DNV pipeline risk management expert

to more risk than necessary. Good risk estimates are highly valued. If you can get the most meaningful numbers at the same cost as compromise measures, why would you settle for less? Are you advocating exclusively a quantitative or probabilistic risk assessment? Terminology has been getting in the way of understanding in the field of risk assessment. Terms like quantitative, semiquantitative, qualitative, probabilistic, etc. mean different things to different people. I do believe that for true understanding of risk and for the vast majority of regulatory, legal, and technical uses of pipeline risk assessments, risk estimates in the form of consequence per length per time are essential. Anything less is an unnecessary compromise. What about the concern that a more robust methodology suffers more from lack of any data? (i.e. “If I don’t have much info on the pipeline, I may as well use a simple ranking approach.”) In the absence of recorded information, a robust risk assessment methodology forces SMEs to make careful and informed estimates based on their experience and judgment. From these estimates reasonable risk estimates emerge, pending the acquisition of better data. Therefore, I would respond that lack of information should drive you towards a more robust methodology. Using a lesser risk assessment approach with a small amount of data just compounds the inaccuracies and does not improve understanding of risk. It sounds like you have methods that very accurately predict failure potential. True?

20 | pipeline UPDATE NO. 1 2012

Unfortunately, no. While the new modelling approaches are powerful and the best we’ve ever had, there is still huge uncertainty. We are unable to accurately predict failures on specific pipe segments except in extreme cases. With good underlying data, we can do a decent job of predicting the behavior of numerous pipe segments over longer periods of time. That is of significant benefit when determining risk management strategies.

actually a close estimate to what the realworld risk is.’ Another ‘catch’ is the one we touched on previously. Rare events like pipeline failures have a large element of randomness, at least from our current technical perspective. That means that, no matter how good the modelling, some will still be disappointed by the high uncertainty that must be associated with predictions on specific pipeline segments.

Nonetheless, it sounds like you’re saying there are now pipeline risk assessment approaches that are both better and cheaper than past practice.

What’s behind the EE guideline document that DNV and you recently released?

True. Risk assessment that follows our Essential Elements* (EE) guidelines avoids the pitfalls that befall many current practices. Yet, we can still apply all of the data that was collected for the previous approaches. Pitfall avoidance and re-use of data makes the approach more efficient than many other practices. Plus, the recommended approaches now generate the most meaningful measurements of risk that we know of. Sounds too good to be true. What’s the catch? One catch is that we have to overcome our resistance to the kinds of risk estimate values that are needed. When faced with a number such as 1.2E-4 failure/mileyear, many have an immediate negative reaction, far beyond a healthy scepticism. Perhaps it is the scientific notation, or the probabilistic implication, or the ‘illusion of knowledge’, or some other aspect that evokes such reactions. I find that such biases disappear very quickly, once an audience sees the utility of the numbers and makes the connection – ‘Hey, that’s

We are advocating a degree of standardisation in pipeline risk assessment that will serve all stakeholders. This list of essential elements sets forth the minimum ingredients for acceptable pipeline risk assessment. Every risk assessment should have these elements. A specific methodology and detailed processes are intentionally not essential elements, so there is room for creativity and customised solutions. DNV’s recognition of the need for such a guideline, with its long history of technical risk consulting and solid reputation, demonstrates the seriousness of this effort. If regulators encounter too many substandard pipeline risk assessment practices, then prescriptive mandates might be deemed necessary. Such mandates are often less efficient than approaches that permit flexibility while prescribing only certain elements – hence, the benefit of the EE guidelines. 

*The Essential Elements of Pipeline Risk Assessment were first published by DNV and Mr. Muhlbauer in the May 2012 issue of Pipeline & Gas Journal. The Essential Elements were formulated in direct response to PHMSA’s Advanced Notice for Proposed Rule Making (ANPRM) of August 2011.

West Africa

West African gas pipeline The West African Gas Pipeline is an unusual example of cooperation in a difficult environment and on complex energy issues. Text: Peter Hamer, DNV

the emergent nations such as Ghana and the booming East African arena. Field lives are being continually extended beyond the planned life cycles and more complex analysis is being sought to provide confidence in these pipelines, which are revenue-critical assets. DNV Africa is now playing a strong role in providing local expertise with a global perspective and creating solutions on the ground with its local partners.  Peter Hamer, Director of Operations

››

Petrochemical processing equipment at oil refinery, Nigeria.

››

The West African Gas Pipeline Company (WAGPCo) is a joint venture consisting of national interests, with Nigeria, Ghana, Togo and Benin partnering with Chevron to create a viable energy solution so that Nigeria’s gas production can meet its neighbours’ growing energy demands. The 678km West African Gas Pipeline (WAGP) links up with the existing Escravos-Lagos pipeline at the Nigeria Gas Company’s Itoki natural gas export terminal in Nigeria and proceeds to a beachhead in Lagos. From there it moves offshore to Takoradi in Ghana, with gas delivery laterals from the main line extending to Cotonou (Benin), Lome (Togo) and Tema (Ghana). The Escravos-Lagos pipeline system has a capacity of 800 MMscfd, and the WAGP system will initially carry a volume of 170MMscfd and peak over time at a capacity of 460MMscfd. DNV Ghana and DNV Cape Town’s pipeline experts met with WAGPCo in 2011 and discussed the various operational challenges facing this multinational joint venture. DNV’s local expertise was able to help define the joint venture’s core pipeline risk management needs and subsequently worked with WAGPCo to develop its asset integrity management plan. The asset integrity management of pipelines in West Africa is a critical element for the continued success of large projects in not only the established producing countries of Nigeria and Angola but also

pipeline UPDATE NO. 1 2012 |

Integrity management

Constructing an auditable framework Establishing MOP/MAOP through records verification On September 9, 2010, a high pressure natural gas pipeline ruptured in a residential neighborhood of San Bruno, California. The subsequent ignition resulted in eight fatalities and numerous injuries, destroying 38 homes while damaging 70. In part, the NTSB concluded that the operator’s integrity management program was deficient and ineffective because it was based on incomplete and inaccurate pipeline information, and did not consider the design and materials contribution to the risk of a pipeline failure. Text: Chris Pollard

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (H.R.2845) signed by the President in January of this year further confirms the direction U.S. regulators are taking with respect to pipeline security and safety. The Act, along with advisories from the Pipeline Hazardous Materials and Safety Administration (PHMSA), largely address the post-failure findings of the San Bruno, CA pipeline failure in 2010. The signed Act with a subsequent PHMSA Advisory reminds operators of covered pipelines to “ensure that the PHMSA’s Definitions Traceable – Records which can be clearly linked to original information about a pipeline segment or facility. Verifiable – Records in which information is confirmed by other complimentary, but separate, documentation. Complete – Records in which the record is finalized as evidenced by a signature, date or other appropriate marking.

22 | pipeline UPDATE NO. 1 2012

records accurately reflect the physical and operational characteristics of the pipelines … and confirm the established maximum allowable operating pressure …”. PHMSA directives stress that operators “… assure that all MAOP and MOP are supported by records that are traceable, verifiable and complete”. The Challenge for Pipeline Operators PHMSA made clear that audits starting in 2013 will focus on measures taken by pipeline operators to verify MAOP calculations. The clock is now ticking for operators to verify records by March of 2013, otherwise rely on another method to verify MAOP (as allowed for in 49 CFR 192.619 or 49 CFR 195.406). In late July, PHMSA confirmed that a ‘single, quality document’ does indeed suffice provided that the document is traceable and complete. Notwithstanding PHMSA’s clarification, the subject matter of this article pertains to issues related to the use of multiple pipeline records for verifying MAOP.

A Phase-out for Grandfathered Pipelines? Post-San Bruno, the National Transportation Safety Board (NTSB) recommended PHMSA consider lifting the so-called ‘grandfather’ clause [49 CFR 192.619 (a)(3)] and “require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test …”. PHMSA will be addressing this recommendation in a future rulemaking. For some operators with significant portions of their systems constructed prior to 1970 and without a pressure test at some point during its history, lifting of the clause will mark a ‘step-change’ as it relates to their integrity management programs and ease of compliance. A New Risk Outlook The prospect of losing the grandfather exemption for older assets coupled with the costs of verification by pressure testing, in-line inspection (ILI), or other means, can prove to be quite costly, time-consuming and operationally constraining. And pipeline

Integrity management

››

On September 9, 2010, a high pressure natural gas pipeline ruptured in a residential neighborhood of San Bruno, California. The subsequent ignition resulted in eight fatalities and numerous injuries, destroying 38 homes while damaging 70.

pipeline UPDATE NO. 1 2012 |

ÂŠ DNV

Integrity management

24 | pipeline UPDATE NO. 1 2012

Integrity management

“Records gaps cannot be identified if data can’t be readily trusted.”

systems targeted for acquisition will now potentially hold a much greater exposure to liability and potential non-compliance due to documentation (or lack thereof) of the targeted pipeline. Lessons Learned in Records Verification – DNV’s 5-Step Process DNV has been instrumental in the records verification process for several U.S. pipeline operators and we’ll share some of our experiences with you. A more detailed explanation of some of our findings can be found in the white paper, A Practical Approach to Pipeline System Materials Verification presented to the International Pipeline Conference (IPC) 2012 by DNV’s Andy Lutz and Dr Tom Bubenik. Though pertinent data capture alone can be a tedious task, we contend that the verification process is woefully incomplete until a digital, auditable records structure is devised. A structured framework is essential in supporting continual improvement while efficiently satisfying future audits. For sure, such a structure helps to establish the traceable component of PHMSA’s directives. We think most will find using the empirical approach of records verification will be preferred in verifying continued safe MAOP (vs. other testing methods to be proposed and/or developed). In some cases, a graduated approach will be necessary by using available documentation that is reliable but supplemented by other measures to close gaps. Though

functionally unique, the four steps of our process will at times be performed concurrently. As the documentation review and capture process can be quite laborious and time consuming, we have concentrated our efforts towards maximizing efficiencies. And finally, we’ve found that a ‘fresh set of eyes’ by a trusted 3rd party in the review process can better assure gaps and inconsistencies are more readily identified, with the added value of a pre-audit from the same critical perspective to be encountered in subsequent formal audits. STEP 1: DISCRIMINATE PERTINENT FROM NON-PERTINENT RECORDS Document Search, Collection and Tabulation The goal is to verify MAOP as early in the records review process as possible, realizing that the MAOP of the entire pipeline is based on its ‘weakest link’. DNV’s process will identify records gaps which may prevent ready verification. Pipeline attributes critical in establishing MAOP include pipe diameter, wall thickness, grade, seam type, component ratings and historic pressure test data. The first step in the process will identify records that are pertinent to the pipeline’s material properties and testing used to establish MAOP. Records targeted will relate to design, fabrication (i.e. purchase orders, mill certification records), construction (i.e. as-built drawings, alignment maps), maintenance (i.e. replacements,

repairs), and testing (i.e. pressure test records). Previous studies and analyses of class location and MAOP calculations performed during the line’s operational history will also be reviewed. Both paper and digital records are reviewed by a team led by an engineer familiar with pipeline construction and maintenance documentation and who holds experience with data mining for the auditing process. It’s important that the client designate a company representative to act as ombudsman to answer the inevitable questions that will arise during the search. This client overseer will have sufficient knowledge of the pipeline system and the organization allowing him/her to readily respond to queries or to recognize the subject matter expert (SME) who is able to formulate a response. In addition to the use of SMEs, interviews with operations and maintenance employees (current and past) may aid in the data collection process. During this phase, discrepancies, inconsistencies and omissions will be identified as gaps. Not surprisingly, we’ve found that older pipeline assets can generally be more prone to having gaps in design, construction and testing records. And changes made to a line during its operational life may not be properly documented, as well. Such problematic gaps can then be further compounded by multiple (non-continuous) owners and the lines’ susceptibility of incomplete records transfer during owner transition.

pipeline UPDATE NO. 1 2012 |

Integrity management

“Document precedence will establish a weighting in terms of accuracy, consistency, completeness and reliability.”

STEP 2: ESTABLISH A RELIABILITY INDEX FOR CAPTURED DATA Document Precedence Even pertinent records will come in varying degrees of accuracy and trustworthiness. Step 2 in the process is therefore one of the most important: document precedence, or, establishing a reliability index. The process involves placing a ‘weighting’ on the various records in the context of accuracy, consistency, completeness and reliability. For example, pipe grade documentation from purchasing records will be given a higher precedence (weighting) than pipe grade tallies taken from ILI questionnaires – where the information source as well as the credibility or authority of the person completing the form may be uncertain. To further assure reliable indexing, key operator employees are consulted to identify those records historically given more emphasis due to their contents’ inherent reliability. Creating a document reliability index, or document hierarchy, is essential for large-scale verification projects involving substantial volumes of data. Records gaps can’t be identified if data cannot be readily trusted; and, verification attempts in the absence of such an index can greatly add to inefficiencies and wasted effort. STEP 3: MAKE PERMANENT AND STRUCTURED RECORDS Digital Capture As document imaging is beyond DNV’s

26 | pipeline UPDATE NO. 1 2012

normal remit, we’ve partnered with 3SG, a respected imaging company strategically located adjacent to our Dublin, Ohio headquarters. Proximity is key when considering the close interaction required for capturing critical, sometimes one-of-a-kind data. As conclusions drawn from the records verification process must be traceable and subject to future audits, documents are captured digitally (typically in portable document format, PDF) as they’re identified as pertinent and a structure is put in place for referencing. A systematic and consistent file naming procedure is implemented for the database filing system to be used in Step #5, Auditable Reference. As the process can entail capturing huge volumes of data, we will usually perform the digital capture using mobile scanning hardware and a dedicated team brought to the operator’s site for the task-specific job, thus avoiding overwhelming the clients’ scanning equipment. On larger, more massive projects, it can make logistical sense to perform imaging at 3SG’s Dublin facility, where specialized, high capacity imaging equipment can be utilized.

newer systems. As for assets with a history of multiple owners, the seller’s pipeline records can be incomplete or inaccurate and the legacy brain trust of the seller – the intimate asset knowledge held by those who may have laid and/or operated the asset for years – is not necessarily passed on. Not infrequently, gaps will be a result of inadequate recording of material properties and testing for historical modifications, replacements or re-routes. The concern, for example, is that inadequately recorded pipe replacement opens the possibility of having a lower yield-strength pipe, perhaps due to a different wall thickness, grade or seam weld type, than the legacy pipe. Strategies must be formulated to make the verification process complete or to reestablish MAOP. Various strategies open to consideration by regulators are offered in varying degrees of conservatism to address such gaps: from wholesale replacement (most conservative) to pressure testing to engineering critical assessment/fitness for service assessment (less conservative). Such engineering assessments can be used to draw inferences from known results in order to answer the unknown.

STEP 4: IDENTIFY/RECONCILE GAPS Verify or reestablish MAOP The U.S. is home to some of the oldest pipeline systems in the world, as this is where the industry is rooted. Records for vintage pipeline systems will typically be more prone to deficiencies than with

STEP 5: BUILD FROM A TRACEABLE, AUDITABLE AND GIS COMPATIBLE FRAMEWORK Risk-informed, Sustainable, Auditable Reference Verifying or re-establishing MAOP is of course the primary point of the

Integrity management

“Inferences from the known can help reconcile the unknown.”

verification process. A secondary goal is to establish an easily accessible and navigable data structure to facilitate (on-going) records management and for reference in audits. Certainly, a single system of record for all parameters affecting MAOP calculations and related data will aid in achieving that goal. DNV has found that a linear format associated with pipeline footage or stationing is a practical form of spatial alignment, easing integration, navigation and user visualization of the entire pipeline as it traverses its route. With a linear spatial alignment, installations such as pipe type, valves and other applicable features can be made to appear in the data as they appear (spatially) on the pipeline. It’s important to couple the construction of this reference listing with sufficient revisions to company procedures to ensure that pipeline changes (i.e. re-routes, pipe replacements, etc.) are dutifully recorded in this central listing. Such measures help ensure that the data remain traceable, verifiable and complete through the pipeline’s continuous operation. Reconciling Records Gaps The Role of In-line Inspection (ILI) and Materials Testing Our ILI SMEs are exploring new applications of existing technology in efforts to reconcile some records gaps. For example, if replacement spools were used in a maintenance program with less than adequate records, ILI results can act as a supplement

to as-built records by providing a ‘fingerprint’ of the pipeline’s make-up. ILI can identify exactly where such spools were installed, as ILI will typically identify wall thickness changes and general seam type. If pipe grade is in question and the replacement spools can be grouped with a degree of certainty as a single pipe type (from the ILI results), then a single excavation with perhaps a single cut-out for metallurgical testing can offer a rational inference that all identical spool pieces hold the same properties. Though such reconciliation may be far from ideal in terms of effort, it will almost certainly transcend alternative actions such as wholesale replacement or pressure testing. The concept of extracting more information out of ILI devices and their data has recently been the focus of the Interstate Natural Gas Association of America (INGAA) and by the Pipeline Research Council International (PRCI). Among other things, these industry groups are interested in the pipeline ‘fingerprint’ concept for showing pipe changes. And research is being considered for possibly expanding ILI capability to better identify material properties from pig data.

information will now play a central role. For grandfathered pipelines, it remains to be seen how future rulings will further affect the risk landscape. Regulators have yet to rule on methods to be used for closing records gaps. It’s quite possible that at least some field investigations (i.e. in the ditch verification and testing) will be required to augment deficient information. In such cases, elements of this 5-step verification process will help identify and prioritize locations to excavate by means of a risk-based approach. At any rate, use of a rational, systematic approach to identify and mitigate records gaps will help operators produce verifiable materials results and should therefore aid in meeting regulatory requirements while improving pipeline safety. This approach will help ensure that MOP/MAOP calculations are supported by traceable, verifiable and complete records, and pipeline safety will ultimately be improved. 

Going Forward Few will argue that there won’t be continued, if not increased, emphasis on records to verify the calculated MOP/MAOP of U.S. pipelines. Where gaps heretofore were largely (and simply) defined by virtue of ‘known’ vs. ‘unknown’, reliability of that

pipeline UPDATE NO. 1 2012 |

Failure investigation

Forensic engineering and failure investigation The purpose of a forensic engineering investigation is to determine the cause or causes of failure in order to improve performance or life of a component, prevent a similar failure and promote lessons learned and safe operating practices, or to establish a root cause analysis of the failure. Text: Dr Neil G. Thompson and Dr John A. Beavers

Forensic engineering is the investigation of materials, products, structures, or components that fail or do not operate or function as intended; causing personal injury, damage to property or environment, or a loss of productivity. Forensic and failure investigation also deals with retracing processes and procedures leading to accidents in operation of equipment, machinery, vehicles, and other assets. The term forensics is applied most commonly in legal cases, although the same cause analyses apply more generally to failure investigation. Important to the field of forensic engineering are the process of investigating and collecting data related to the materials, products, structures or components that failed, and the documentation of records, evidence, and documents received. This involves inspections, collecting evidence, measurements, developing models, analysing exemplar products, and conducting tests and simulations. Root cause analysis Forensic and failure analyses can take many forms and levels of activities. Many failure investigations focus on the immediate failure cause; i.e., for metals, the metallurgical or technical aspects of the failure. Laboratory tests are performed to determine whether or not a material meets the applicable mechanical and chemical specifications.

28 | pipeline UPDATE NO. 1 2012

Metallurgical analyses are performed to determine whether the failure was associated with an overload, fatigue vibrations, corrosion, or any of a number of other causes. Going further, basic causes such as operational issues can be examined, e.g., a review of technical literature, such as corrosion and integrity management protocols, is performed to determine what aspects of the operations and maintenance contributed to the failure. A true “root cause” analysis takes the investigation one step further. The root cause analysis considers what management decisions were made, or not made, that contributed to the failure. By tracing the cause of the failure back to failures of management systems or processes, it becomes possible to prevent similar failures from occurring in the future. This improves performance by avoiding lost production time and repair or clean-up costs, providing a safer environment for employees and the public (for assets such as pipelines), and preventing costly environmental damage (for assets dealing with hazardous liquid and gases). A good root cause analysis is dependent on a complete and accurate basic and intermediate cause analysis. Understanding the chain of technical events and management decisions leading up to a failure allows one to “reverse

engineer” and reconsider decisions and operational processes. Ideally this leads to recommendations that are implemented by management. There are many tools that can be used to assist in the root cause investigation. Some of these tools are commonly used project or program management techniques. Others are highly specialised, and designed to focus specifically on root cause analysis and failure investigation. General tools include various statistical analysis techniques, charts and diagrams. Most engineers and managers are familiar with histograms, scatter charts, tree diagrams and fault tree analyses. Many are familiar with “cause-and-effect” diagrams (also known as “fishbone” or “Ishikawa” diagrams), which can be invaluable in clarifying the different components or processes that may have contributed to a failure. The best root cause analysis tools force one to consider aspects of the failure that may not be obvious to the casual observer. DNV has developed an approach that is specifically designed to perform root cause analysis. This approach is the Systematic Causation Analysis Technique (SCAT), which is a structured application of the Loss Causation Model (LCM). The LCM is based on the concept that a loss of management control can ultimately lead to a failure. The loss of control leads to a

Failure investigation

››

Forensic engineering is the investigation of materials, products, structures, or components that fail or do not operate or function as intended.

basic cause of a failure, which leads to an immediate cause of a failure. By tracing the appropriate chain of events, one can identify and correct the loss of control that contributed to a given failure. The SCAT approach begins with a collection of all available evidence. This will include the findings of the failure analysis, as well as interviews with key personnel involved in the incident and a review of applicable documentation. The evidence is used to develop a timeline of events that led to the failure. Key events may include: lack of inspection, inadequate response to inspections, lack of control of operating parameters, operating outside of design envelope, etc. Most industrial accident/ failures can be attributed to a chain of events. It is important to understand how and why each event occurred and how it led to the next event in the chain. An analysis of barriers is performed following development of a timeline of key events. Barriers are any components or systems that are put in place to prevent failures. Physical barriers include pressure and temperature control systems and other similar barriers. More “abstract” barriers

to consider are the training of personnel, communication procedures, and quality assurance protocols. It is the failure of these barriers that leads to the events that make up the chain preceding the failure. Each one of the events in the chain must be analysed separately to understand how and why the barriers in place to prevent them failed. For each one of the events, one must consider the immediate, basic, and management control contributions. The failure only occurred because all of the barriers failed. Once the analysis has identified the true root cause of the failure, it becomes possible to make recommendations to prevent future failures. As most failures are the result of the failure of several barriers or several human errors, it is likely that several corrections could be implemented into the operational procedures or management systems to correct the root cause. This may include re-training of staff or additional review of designs and procedures. New safety systems or operational processes can be implemented as necessary. Prevention of future failures is the real value of a root cause analysis.

DNV forensic investigation service DNV has the ability to follow up its forensic investigation with operational and management reviews to implement lessons learned. DNV has developed the International Safety Rating System 8th Edition (ISRS8) as an accumulation of best practice experience in safety and sustainability management. ISRS8 has been developed over 30 years and is regularly updated to reflect changes and improvements in safety management. The 8th edition of ISRS was issued in 2009 with added elements of process safety management as well as updates to reflect the changes in international standards such as OHSAS 18001:2007, ISO 9001:2008 and Global Reporting Initiative 2006. ISRS8 is designed to ensure the health of industrial processes, drive continuous improvement and ensure effective risk management. ISRS8 takes strategy and policy, planning, implementation and operation, monitoring and measurement, management review, and continual improvement and combines these efforts into one procedure that can be used to manage any industrial process.

pipeline UPDATE NO. 1 2012 |

Failure investigation

â&#x20AC;şâ&#x20AC;ş

Many failure investigations focus on the immediate failure cause; i.e., for metals, the metallurgical or technical aspects of the failure.

30 | pipeline UPDATE NO. 1 2012

Failure investigation

CASE STUDY: Seam weld failure in a petroleum pipeline There are more than 2.5 million miles of oil and gas pipelines in the United States. These pipelines typically contain longitudinal seam welds in each pipe joint and girth welds that connect the individual joints to form the pipeline. Both types of welds are prone to failure from time independent and/or time dependent failure mechanisms. While some smaller diameter pipelines are seamless, most pipelines are manufactured by forming flat plate or skelp into a tubular form and completing a longitudinal seam weld. Both submerged arc welding and autogenous welding processes are used for weld completion. Submerged arc welded line pipe is manufactured by first forming a flat plate or skelp into a tubular shape (can) in a set of presses, followed by weld completion. Prior to forming the can, the edges are typically beveled. Historically, single submerged arc welding (SSAW) and double submerged arc welded (DSAW) processes have been used but, currently, the DSAW process is the only submerged arc welding process that is approved in API 5L. In SSAW line pipe, the edges are joined by a single pass submerged arc weld made from the outside surface onto a backing shoe located at the ID surface. DSAW line pipe is formed in a similar manner except one pass is made from the OD surface followed by a pass from the ID surface, or vice versa. Filler weld material is used in both processes. One variation of this process is used to produced spiral welded DSAW line pipe; in which skelp is helically wound and welded to produce a spiral weld. Historically, there have been several different autogenous welding processes for longitudinal seam welds including furnace lap welding, furnace butt welding, electric flash welding (EFW) and electric resistance welding (ERW). ERW currently is the dominant autogenous welding process for pipe manufacturing. ERW line pipe is manufactured by forming plate or skelp into a tubular shape and heating the two adjoining edges with electric current and forcing them together

mechanically. An autogenous bond is formed between the molten edges. Upset material at the weld is trimmed on the OD and ID surfaces. Various types of defects can be produced in these welds and the defects typically are unique to the specific welding procedure. Some of these defects are too small to be detected in the mill and are never an integrity problem for the pipelines. Other defects that are not detected at the mill can fail during the initial hydrostatic test of a pipeline, or grow in service by fatigue, stress corrosion cracking, or other mechanisms, resulting in a service leak or failure. Because of differences in the metallurgy at the weld and the base metal of the pipe, the welds can also be prone to environmentally induced failure mechanisms such as preferential corrosion. This case study describes a rupture of seam weld during a hydrostatic pressure test. The pipeline that failed was comprised of 16-inch diameter by 0.312-inch wall thickness, API 5L X52 line pipe that contained an ERW longitudinal seam. The pipeline transported refined petroleum products. The maximum operating pressure (MOP) on this line segment was 1,408 psig, which corresponds to 69.4% of the specified minimum yield strength (SMYS). The failure occurred during initial pressurization at a test pressure of 1,390 psig, which corresponds to 98.7% of the MOP and 68.5% of the SMYS. The normal operating pressure at the failure location ranged from 1,000 to 1,100 psig (71.0 to 78.1% of MOP). The pipeline was installed in 1965 and was externally coated with coal tar. The coating was not intact near the failure. The pipeline had an impressed current cathodic protection system that was

commissioned around 1965. This pipeline segment was previously hydrostatically tested in the fall of 1965. The hydrostatic test lasted 24 hours and the maximum pressure was 1,760 psig (125% of MOP and 86.8% of SMYS). The pipe section was visually examined and photographed in the as-received condition. Transverse base metal and cross weld samples were removed from the pipe section for mechanical (Charpy V-notch and tensile) testing. Samples for chemical analysis of the steel were removed from the base metal. Magnetic particle inspection (MPI) was performed where the coating was removed to identify defects at or near the seam weld. Transverse metallographic samples were removed from the seam, at and away from the failure origin. The samples were mounted, polished, and light photomicrographs were taken to examine the morphology and steel microstructure. Samples were removed from the failure origin to analyze the morphology of the fracture surface in the scanning electron microscope. The results of the analysis indicated that the rupture initiated at an ID connected pre-existing hook crack. This and all hook cracks are slightly offset from the bond line of the ERW seam. No evidence of in-service growth by fatigue was found, although the quality of the fractography was poor as a result of corrosion of the fracture surfaces that occurred after the rupture. The tensile properties of the line pipe steel and the steel chemistry were typical of the vintage and grade and met the API 5L specifications in place at the time of manufacture. The microstructure and Charpy toughness properties of the steel also were typical for the vintage and grade. ď&#x201A;Ł

pipeline UPDATE NO. 1 2012 |

Onshore regulations

Observations of onshore pipeline regulatory trends Anything to learn for an offshore operator? A decade has passed since the Pipeline Safety Act of 2002 was passed by the US Congress. With stiffer regulations pending for the offshore pipeline industry, what can offshore operators learn from their onshore counterparts’ experiences?

Text: Chris Pollard

››

Chris Pollard, principal consultant.

In the case of onshore pipelines, a few notable incidents at the turn of this century brought pipeline safety into the public spotlight and resulted in a series of reactive, mostly prescriptive measures to improve pipeline integrity management. Similarly, offshore operations (pipeline or otherwise) now face a new degree of scrutiny also due to a few recent, highly visible incidents. One might argue that there is a huge difference between onshore pipeline operations and the vast domain of offshore operations. Though literally true, the various sectors are often seen as a single entity by a cynical public – all with the help of

32 | pipeline UPDATE NO. 1 2012

media headlines and a 24-hour news cycle. It may be helpful for US offshore operators to study the effects of onshore pipeline failures on subsequent reactive legislation. These effects are illustrated by the Code of Federal Regulations (CFR) Parts 195 (liquids) and 192, Sub-part ‘O’ (gas). Through Integrity Management Programme (IMP) ‘rules’, the DOT directs pipeline operators to establish and follow a detailed IMP. The main elements of the rules are briefly as follows. Risk Assessment Federal regulations now require a formalised risk assessment as part of an overall IMP for ‘High Consequence Areas’ (HCAs) that would, were they to fail, have significant adverse effects on population, property or the environment. The first phase of the completed IMP rules called for identifying HCAs and corresponding threats and establishing integrity assessment timetables. Integrity Assessment Some view the overall rules as an integrity assessment regulation. This part of the IMP rules calls for the establishment of HCA baseline assessments followed by assessments at regular, prescribed intervals. The assessments are to be aimed at those specific risk factors identified as affecting the integrity of the HCA segment.

Acceptable assessment methods include in-line inspections (ILI), pressure tests, direct assessments, or the use of other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. Onshore operators encountered considerable problems in making their lines piggable for ILI. However, most of the time, their biggest problems merely involved the installation of traps. Indeed, onshore pigging issues pale in comparison to offshore challenges: e.g. space limitations, heavy walls, unpiggable connections, extreme geometry and complex operations. Considerable capital outlays can be anticipated if lines are to be made piggable. Repair/Mitigation The rules prescribe a timetable for addressing integrityaffecting anomalies depending on their severity or proximity to pipeline features or interacting defects (i.e. deformation near seam welds, mechanical damage). Documentation Though much emphasis is placed on integrity assessment, this is only part of a grander vision to improve overall pipeline safety by ensuring that all the data is accurate, verifiable and complete. It should be noted that some onshore efforts are further hampered by an issue that is not so common offshore:

Onshore regulations

vintage pipelines. Some US in-service pipeline assets are many decades old, built using early construction methods and materials – with as-built records often inaccurate or missing entirely. A recent, very visible natural gas pipeline failure in San Bruno, CA illustrates the danger of insufficient records: the operator experienced a long weld seam failure when records stated that seamless pipe had been installed. With the attention that San Bruno brought to material properties and their documentation, new measures are under way to ensure that the maximum allowable operating pressure (MAOP) and supporting documentation can be properly verified. Integration/Reconciliation Not far down the Potomac from Washington, D.C. is Piney Point, MD. On 7 April 2000, a fuel oil pipeline ruptured, spilling approximately 140,400 gallons of fuel oil into the local wetlands; this fuel oil eventually made its way into the Patuxent River and caused damage of more than USD 71 million. The incident illustrates one reason why integration was a hot topic when current onshore regulations were being prepared. In that instance, an ILI mistakenly identified a harmless ’tee’ before the rupture correctly revealed that the ‘tee’ indication was actually a buckle (with a resulting fracture). In another landmark liquid product pipeline failure, NTSB investigators found that the operator had misinterpreted ILI data. Had an ILI been fully reconciled with right-of-way activity, it would have revealed with higher certainty that the ILI anomalies were in fact mechanical damage as a result of adjacent municipal construction. This failure, which took place on 10 June 1999 in Bellingham, WA, resulted in the ignition of a creek, took three lives and caused over USD 45 million in property damage. Few if any other single incidents have had more impact on US pipeline safety regulations than the one in Bellingham. These not-so-happy integration stories can be countered with a happy one from

interacting or interdependent threats. More in-depth considerations relating to such threats are currently pending action by regulators and the industry.

››

Onshore ILI Pig Launch.

‘Pipeline Tee’ incorrectly identified by ILI.

one GoM operator. When ILI identified a harmless ‘bend’ that the operator knew did not exist, the ‘bend’ in question turned out to be a profound, integrityaffecting buckle. This operator’s timely and proper reconciliation of data helped avoid imminent subsea failure. Indeed, there are many ILI success stories that can be chronicled to counter some of the notso-flattering ILI examples. Interdependent Threats A driving force for proper data integration can be found in the new focus being placed on

Continuous Improvement Although onshore pipeline failure statistics appear to be improving, the industry still seems to be experiencing significant and unexpected catastrophic events that no one, including the operator, wants ever to happen. Such events have been termed by DNV’s subject matter experts (SMEs) as occurring within ‘super HCAs’: highly sensitive pipe segments where the occurrence of a failure might ultimately bankrupt the operating company. Some thought the loss of the Deepwater Horizon in April 2010 had the potential to fit that category. The continuous improvement and management of change methodologies help recognise those pipeline segments and minimise the probability of such an occurrence. Going Forward The pipeline failures listed here, and others, have forced industry regulators to take a stronger stance, as evidenced by new IM rules, the elimination of some grandfathered exemptions, the requirement of records not previously required, etc. No one will disagree that offshore operations face similar challenges and more. Certainly, many of the same factors profoundly affecting regulatory change in onshore pipelines now exist in the offshore environment as well. Are there lessons to be learned? DNV is a logical choice for integrity needs, both offshore and onshore. DNV’s pipeline business unit has been involved in the post-failure response to virtually every major US pipeline failure over the past quarter of a century. Grounded in the applied science of our research laboratories, we have the depth and breadth of subject matter expertise to cover the entire spectrum of materials research, testing and degradation, mechanical integrity and risk management. 

pipeline UPDATE NO. 1 2012 |

australia

Challenging gas ﬁelds in Australia The Ichthys (Inpex) and Wheatstone (Chevron) gas fields in Australia are extraordinarily large investments, and the engineers on both projects have been given the challenge of composing the most suitable systems to bring the gas from reservoirs far offshore to LNG plants on a demanding coastline. Text: Fredrik Myrland and Olav fyrileiv

The oil & gas environment in Australia has witnessed almost ecstatic growth, with mega-size gas field developments impacting on the industry, society and work market in Perth, Western Australia. The economic impact is also huge in the remote north-west part of the state, where much of Australia’s gas resources are located. The management of these fields, and a lot of the engineering, is performed in Perth, where DNV has a relatively new oil & gas office. Applying DNV’s offshore standards A complex infrastructure involving large units in the fields and LNG plants is all tied together by a network of pipelines and chemical supply lines which are being built to the DNV-OS-F101 standard due to Australia’s national standardisation body adopting this DNV standard for submarine pipelines (with minor amendments).

Olav Fyrileiv, a senior principal engineer with DNV and expatriate located in Perth, says: “I’ve had the pleasure of seeing us win new projects, and I’ve participated

34 | pipeline UPDATE NO. 1 2012

in several very interesting projects focusing on the pipeline aspects, such as the large verification contracts with Inpex and Chevron. These are great opportunities for DNV to assist the industry here through our broad offshore knowledge.”

export pipeline and the LNG plant. The 900km export pipeline brings the gas from the field, on which there is both a Central Processing Facility (CPF) platform and an FPSO, to the onshore plant which is in Darwin,” he says.

Gas-project validation The government safety authority in Australia (NOPSEMA) requires an independent third party to validate offshore developments, addressing the design of the safety-critical elements (confirming the use of appropriate codes and standards). In addition to the competent assessment required by the government, the operators tend to use external verification as a way of assuring the suitability and compliance of the various parts of the installations.

Another project, the Chevron Wheatstone project, is a similarly complex development with a dual-jacket-mounted Central Processing Facility offshore, and a 44-inch trunkline to shore. The calcareous soil conditions and the region’s exposure to cyclones mean stability design is a demanding exercise in which the cost involved for various stabilisation measures is substantial.

Fyrileiv explains the magnitude of one of the main verification projects currently being executed by DNV: “On the Ichthys project, we’re verifying the overall facilities, which include the entire field infrastructure such as floaters, subsea equipment, the flexible pipeline system, the

Global resources for pipeline verification The pipeline parts of the contracts involve verification of the design of the pipeline and flowline as well as fabrication and installation. DNV’s office in Perth facilitates the use of specialist expertise globally, at DNV’s offshore hubs and at manufacturing locations in the verification and validation projects. 

australia

Wheatstone

Perth

rt Gas expo

pipeline

to Darwin

Wheatstone and Ichthys fields

Project name: Chevron Wheatstone Upstream Project DNV project manager: Darren McFarlane (Perth) Location: North West Shelf, Western Australia Project CAPEX: $23 billion AUD Construction start: 3Q 2012 Commissioning scheduled: 1Q 2015 Wheatstone reservoirs: Wheatstone and Iago Fields Installations offshore: Subsea and flowlines tying into a steel gravity based structure with single integrated topsides. All processed gas is transferred through a 44-inch trunkline to the LNG plant at Ashburton (outside the upstream scope). Length pipeline to shore: 225km DNV contracts: Validation and verification services

Barrow Island

Karratha

Thevenard Island Gas plant

Onslow

Ashburton North

Da na mpie tur r t o al ga Bun sp ipe bury lin e

Connection to mainland

Ichthys Project name: INPEX Ichthys LNG DNV project manager: Cecilie Krokeide (Perth) Location: Browse basin LNG plant location: Blaydin Point, Darwin (NT) Project CAPEX: US$ 34 billion Construction start: 1Q 2013 Commissioning scheduled: Q3 2016 Ichthys reservoirs: Ichthys Field, expected to produce 8.4 million tonnes of LNG and 1.6Â million tonnes of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak. Installations offshore: Central Processing Facility (CPF) and Floating Production Storage Offloading vessel (FPSO). Gas will undergo preliminary processing offshore to remove water and raw liquids, including condensate. Processed gas exported to a two train LNG plant on Blaydin Point in Darwin. Length pipeline to shore: 889km DNV contracts: Verification and classification services

pipeline UPDATE NO. 1 2012 |

Pipeline committee

The DNV Pipeline Committee The DNV Pipeline Committee’s general aim is to discuss current needs in the subsea pipeline industry and help monitor the development of new codes and standards to reduce future risk. Text: Eva Halvorsen

With this in mind, a number of joint industry projects (JIPs) have been established over the years, and the committee reviews the progress of these as part of its work. The committee meets twice a year and from time to time guests are invited to discuss specific subjects. DNV’s first pipeline code was issued in 1976, since when DNV has created a number of internationally recognised standards and recommended practices for the pipeline industry. Based on its project experience, research and joint-industry development work, the company also issues a number of pipeline codes which comprise service specifications, standards and recommended practices and which are highly regarded within the international pipeline community. These are complemented by recommended practices (RP) which give detailed advice on how to analyse specific technical aspects according to DNV’s research criteria. DNV is proud to present its Pipeline Committee, which represents the whole industry, from operators to manufacturers and designers.

36 | pipeline UPDATE NO. 1 2012

The DNV Pipeline Committee: Chairman: Colin McKinnon (J P Kenny) Operators: BP BG ChevronTexaco Dong ExxonMobil Gazprom Gassco Maersk Petrobras Shell Statoil Total Woodside Regulators: PTIL (Norway) HSE GSI (UK)

University: NUS (Singapore) Manufacturers: JFE Steel Tenaris VM Tubes The Tata Group Europipe Contractors: Allseas Saipem Subsea 7 Technip Heerema Designers: J P Kenny IntecSea

Pipeline committee

“A forum for sharing lessons learned” Colin McKinnon is chairman of the DNV Pipeline Committee. He finds great value in the regular updates on R&D activities and JIPs that are provided. The committee often invites other R&D organisations to present their work and identify areas for collaboration, and the members are encouraged to identify areas for further technical development and R&D. Text: Eva Halvorsen

“The committee is intended as a forum to support and improve the design, construction, operation and abandonment of offshore pipeline systems, and is made up of companies involved in all phases of offshore pipeline systems,” says McKinnon.

›› Colin McKinnon is chairman of the DNV Pipeline Committee.

The committee’s main goals are: n To create an effective forum for discussing current and future challenges for companies involved in all phases of offshore pipeline systems n To provide experience feedback and a mutual exchange of knowledge n To identify new developments, trends and needs in the industry n To provide industry input to DNV’s process for making pipeline codes (standards and recommended practices) n To allow feedback on the quality and scope of DNV’s pipeline services n To advise and comment upon matters as requested by the secretary and chairman of the committee on behalf of DNV. How can the committee help to develop the DNV pipeline standard? “Selected pipeline design, installation, manufacturing and operating companies are invited to join the committee. The

committee members provide feedback on the application of the standard with regard to their area of application of the code. The committee members also identify industry hot topics for the code to address. Finally, the committee members provide comments on new drafts of the code.” Can you describe how and to what extent the standard is acknowledged and used in the pipeline industry? “DNV-OS-F101 is the leading offshore pipeline design code. It is widely used on subsea projects as the primary design code. The main competitors are the ASME code 31.4 and 31.8 and API 1111 in the USA and the Middle East. Most pipeline projects with specific challenges such as stability, spanning or HP/HP tend to use the DNV code.” What’s most important to you as chairman of the committee? “The committee provides a very effective forum for meeting key technical decision makers from the main design, installation and operating companies. I like to focus on holding DNV to account by its main users. Besides, DNV treats the members to a fine meal every time we meet.” 

pipeline UPDATE NO. 1 2012 |

Innovation

Taking the pipeline industry forward 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 projects are currently taking the industry one step further ahead. Text: Eva Halvorsen

Pipeline systems represent significant financial investment and constitute a key element of the industrial and public value chains. Two important aspects of pipeline systems are safety and reliability. DNV issued the world first offshore pipeline code in 1976. Since then DNV has created a series of internationally recognised standards and recommended practices together with the pipeline industry, and the DNV pipeline code has become the dominating code for offshore pipelines. Through all these years, close cooperation and involvement with the industry has been a cornerstone for the development of the DNV Pipeline Standard and for the success DNV enjoys in this field. DNV invests about 6–7% of its revenue in internal R&D and a lot of this is invested in pipeline related projects. Some of this funding is used on in-house R&D projects. However, DNV prefer to work together with the industry and the company’s main investment into pipeline R&D is through JIPs (Joint Industry Projects). Today, a wide range of R&D projects helps develop the standard and recommended practices further and makes them fit for tomorrow’s needs. Below is an overview of some recently completed, ongoing and coming R&D projects:

38 | pipeline UPDATE NO. 1 2012

Recently completed, internally funded projects n Pipelines for the future – pipeline technology for the next 10–15 years n X-Stream – cost-effective solution for deepwater gas pipelines n Residual stress/strain on pipeline girth welds under high strain (measuring residual stress) n Develop a method for the SENT (CTOD testing – under pure tension) test for sour service n Update of DNV-RP-106 – Factory-applied external coating n Update of DNV-RP-102 – Field joint coating and field repair of linepipe coating n Development of RP for AUT System Qualification n Update of DNV-OS-F101 Ongoing internally funded projects n Development of AUT workmanship style acceptance criteria n Standard for verification and certification – onshore pipelines n FloatPipe – solution for deep waters and uneven seabeds n SliPipe – solution for HPHT pipelines

Joint Industry Projects (JIP) managed by DNV n Recently completed projects: HIPPS system design n Residual stresses in ECA of girth welds n Ice pipe – Arctic pipelines n Spiral welded pipes for offshore US (phases 1 and 2 completed) n JIP Clad and lined pipes – phase 1–3 Ongoing projects n CO2 pipelines, phase 2 n Pre-commissioning of pipelines n Pipeline Integrity Management (including update of DNV-RP-116), phase 2 n HPHT pipelines (merger of Hotpipe and Safebuck) n Development of guideline for Horizontal Directional Drilling (HDD) n Development of Guidelines for ECA in Sour Service n Design of Rigid Spools n Fatigue of girth welds with defects n Corroded pipes (incl. update of DNV-RP-101) n Effect of Reeling on Sour Service Performance n On-bottom stability design of submarine umbilicals and cables n ART ILI tool development

Innovation

Planned projects n Spiral welded pipes for offshore US, phase 3 n Clad and lined pipes – phase 4 n Assessment of pipeline component requirements in DNV-OS-F101 n Design of pipeline concrete coating n Qualification of X-80 pipes for Sour Service Applications

Reliability based fracture mechanics approach for pipeline girth welds n Free span assessment in narrow trench n Installation design and analysis n CP insulation coupling for pipelines transporting electrical conductive liquids n Local Brittle Zones n

Projects not managed by DNV n MTI JIP – Corroded pipes with complex shape corrosion (completed) n NORSOK Lifetime extension offshore pipelines (completed) n Sintef Fracture control, phase 2 (ongoing) 

pipeline UPDATE NO. 1 2012 |

Global presence

DNV is a global provider of services for managing risk, helping customers to safely and responsibly improve their business performance. DNV is an independent foundation with presence in more than 100 countries.