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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 6 | JUNE 2021

03. Comment Access all areas

COATINGS Q&A 23. Q&A on pipeline coatings

05. Pipeline news

Winn & Coales (Denso) Ltd, a member of Winn & Coales International Ltd.

The aftermath of the Colonial Pipeline hack, plus news from Siemens Energy, Aegion and Vallourec.

CORROSION PROTECTION 28. Checkmate to corrosion

REGIONAL REPORT 10. Expanding to new horizons Against a backdrop of global economic recovery, Dr Hooman Peimani discusses Russia's most prominent pipeline projects and their increasing supply of gas to Europe.

Giorgio Dones, Corrosion Protection Manager, and Davide Marchesi, Pipeline Equipment Manager, TESI S.p.A., Italy.

o win the game against corrosion, you need to stay focused, and know the ‘rules’ of the phenomenon. You need to play the right moves, prevent as much as you can and keep the situation monitored. With over 30 years of experience, TESI gained deep knowledge of corrosion phenomena applied to pipelines and carefully followed developments of material technology for corrosion protection, until becoming an official distributor of Covalence® products by Seal for Life. But that’s not all. Studying corrosion phenomena in detail, discovering insights day by day, project by project, TESI developed its own highly automated and user-friendly machinery that ensures high quality preparation and application of corrosion protection coatings. Finally, its successful history led TESI to invest in Industry 4.0, growing its productivity of corrosion protection coatings, in order to support large pipeline projects.

Giorgio Dones, Corrosion Protection Manager, and Davide Marchesi, Pipeline Equipment Manager, TESI S.p.A., Italy, explain how to put together a comprehensive strategy against pipeline corrosion.

Against a backdrop of global economic recovery, Dr Hooman Peimani discusses Russia's most prominent pipeline projects and their increasing supply of gas to Europe.

021 may not necessarily be a significantly better year than the last year for the Russian pipeline industry, which did reasonably well in 2020, taking into consideration the expanding global recession. The substantially lower demand for energy – particularly oil and, to a lesser extent, gas – as a result of the extensive COVID19 lockdowns and decreasing industrial activities, on the one hand, and the uncertainty about the date of restoration of pre-pandemic normalcy, on the other, created doubt about the wisdom of investing in new pipelines when fossil energy prices were in free fall. Piped gas prices reflected this trend to a lesser extent compared to oil ones, as, for various reasons, demand for piped gas, but not LNG, remained close to that of the pre-pandemic era during the first year of the COVID-19 pandemic. That prevented a huge reduction in their prices, as experienced by oil prices. Against a background of a major economic recovery in the world’s largest energy consumer (China) and containing the pandemic in some of the major economies of the Asia-Pacific region (e.g., Singapore, Taiwan, Australia and New Zealand), the availability of various vaccines at the end of 2020 and the following vaccination programme against COVID-19 created confidence in restoring economic and social normalcy in the following year to require a steady incremental demand for energy, particularly oil and gas.

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PAGE 10

REMOTE SENSING 34. Storytelling for the digital age

EPC 16. Thinking smarter and broader with repeatable design Ryan Hiestand, MBA, Project Manager, Burns & McDonnell, USA.

Dr. Eran Inbar and Eitan Elkin, Prisma Photonics, Israel.

PIPELINE STEELS AND NDE 39. Colour-coded pipelines Ollie Burkinshaw, ROSEN Group UK, and Simon Slater, ROSEN Group USA.

PRECOMMISSIONING SERVICES 43. Precommissioning: ticking every box

Ryan Hiestand, MBA, Project Manager, Burns & McDonnell, USA, discusses the benefits of repeatable design for the pipeline industry and outlines the seven steps of the design standardisation process.

and scope, which helps capture and optimise schedule, cost and value for pipeline projects. This approach is critical given the increasing industry pressures to make smart investment decisions for public and private infrastructure systems, new and ageing alike. For teams designing, creating and operating pipeline facilities,

Carey Aiken, Online Electronics Limited, UK.

HYDROGEN PIPELINES 47. The perfect blend?

Figure 1. Pipeline standard design.

Michael Kasch, ILF Consulting Engineers, Germany.

53. Materials testing for a greener future 16

ON THIS MONTH'S COVER

Julien Mouli-Castillo, the University of Edinburgh, Derek Muckle, Radius Systems Ltd, and Angus McIntosh, SGN, UK.

Reader enquiries [www.worldpipelines.com] Volume 21 Number 6 - June 2021

Winn & Coales International Ltd has specialised in the manufacture and supply of corrosion prevention and sealing products for over 90 years. The well-known brands of Denso™ and Premier™ offer a cost-effective and long-term solution to corrosion on buried or exposed steel or concrete, pipes, tanks and structures. In May 2021, Winn & Coales International acquired the global Viscotaq™ business including Amcorr Products and Services Inc., manufacturer of viscoelastic protective coatings. For more information visit www.denso.net

™

ISSN 1472-7390

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VISCOTAQ ™ TAPE SYSTEMS: VISCOELASTIC, SELF-HEALING TECHNOLOGY FOR THE OUTSTANDING PROTECTION OF VITAL INFRASTRUCTURE

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have been reading about the democratisation and gamification of investing: it is now easier than ever to trade as an individual, due to the existence of robo-advisors, trading apps and digital wealth management programmes. Historically a person needed formal advice and a large capital sum to start investing, but the advent of ‘plug and play’ trading platforms and open banking practices has revolutionised the way individuals can interact with the stock market. Just look at Gamestop Corp. for an example of how individuals can have a huge impact on the market. A group of activist investors, informed by threads on Reddit and other social media sites, used the Robinhood trading app to co-ordinate a buying frenzy of Gamestop stock early in 2021, in order to enact some sort of social justice on hedge funds. These so-called ‘retail investors’ succeeded in causing Gamestop’s (a US video game, consumer electronics and gaming merchandise retailer) share prices to soar, resulting in a short squeeze. If you have watched the 2015 film The Big Short, then you can skip to the next paragraph as you’ll be familiar with short stocks, but if not: the short squeeze puts stock traders in a very sticky situation. Investopedia puts it best: “Short-sellers borrow shares of an asset that they believe will drop in price in order to buy them after they fall. If they’re right, they return the shares and pocket the difference between the price when they initiated the short and the actual sale price. If they’re wrong, they’re forced to buy at a higher price and pay the difference between the price they set and its sale price. Because short sellers exit their positions with buy orders, the coincidental exit of these short sellers pushes prices higher.” A short squeeze therefore accelerates a stock’s price rise as short-sellers bail out to cut their losses. Retail investors have tried to anticipate a short squeeze and buy stocks that demonstrate a strong short interest, hence the attention given to Gamestop (a bricks and mortar retailer) and others such as AMC Entertainment (an ailing US movie theatre chain).

As I write, shares for Gamestop and AMC Entertainment are soaring again. Retail investors buy shares and post about it online, using hashtags in the hope that the trades start to trend. #AMCSTRONG and #AMCSqueeze trended on Twitter at the end of May, which helped to attract US$209 million of new inflows into AMC shares in the last week of May. The motivations behind this (totally legal) type of investing go beyond profit; to the investors it’s a game, a way of hitting the system where it hurts. Do you sometimes get the feeling that the world is increasingly run by people sitting in their homes on laptops? For good or for bad, we are interconnected in a million ways: we have access to all manner of services and applications online. In the early hours of 7 May, a cyberattack was discovered on a pipeline owned by Colonial Pipeline in the US. Within an hour, Colonial had shut down the pipeline, which is the nation’s largest fuel pipeline, delivering about 45% of the gasoline consumed in the east coast. Colonial then paid a reported US$5 million ransom in consultation with experts who had previously dealt with DarkSide, the group that rents out ransomware to hackers. The ransom was paid in cryptocurrency, and exchanged for the software decryption key required to unscramble its own data network. The malware providers maintain that they act for financial gain, and not from a desire to disrupt the system. A statement from DarkSide said: “Our goal is to make money, and not creating problems for society. From today we introduce moderation and check each company that our partners want to encrypt to avoid social consequences in the future.” A new bipartisan bill is expected to direct the US Cybersecurity and Infrastructure Security Agency (CISA) to create a special cyber programme to test the defence systems of critical infrastructure. The Cyber Exercise Act would also require CISA to assist state and local governments and private industry to assess the safety and security of critical infrastructure. Cybersecurity expert Trevor Morgan, Product Manager at comforte AG, data security services company, says: “As ongoing incidents and these responses demonstrate, the unthinkable is quickly becoming the highly likely for organisations at all levels.”

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An online conference focusing on operational technology, servicing and maintenance for oil and gas pipelines 20th October 2021 - 14:00 (BST) With presentations covering: Servicing and maintenance Repair and rehabilitation Monitoring and data management Control rooms Safety and security Protecting the environment Digital transformation & more...

WORLD NEWS Colonial Pipeline hack prompts new US cyber security bill In an Executive Order published on 12 May 2021, entitled: ‘Improving the Nation’s Cybersecurity’, US President Joseph Biden declared an intention to “make bold changes and significant investment” in protecting against cyberattacks. The Executive Order includes nine areas of change: policy; removing barriers to sharing threat information; modernising federal government cybersecurity; enhancing software supply chain security; establishing a cyber safety review board; standardising the federal government’s playbook for responding to cybersecurity vulnerabilities and incidents; improving detection of cybersecurity vulnerabilities and incidents on federal government networks; improving the federal government’s investigative and remediation capabilities; and national security systems. The Order states that “the prevention, detection, assessment, and remediation of cyber incidents is a top priority and essential to national and economic security.” As noted in the administration’s accompanying Fact Sheet, the Executive Order is a direct response to recent high-profile cybersecurity incidents. The executive action follows the Colonial Pipeline ransomware attack, in which the oil pipeline system was targeted by a criminal cybergroup encrypting its system and demanding a ransom. Although the attack was aimed at business technology, it caused Colonial Pipeline to shut down operations on a major pipeline serving the Northeast, leading to gas shortages and panic buying.

US government prepares to boost pipeline cyber protections The Biden administration is reportedly working with pipeline companies to strengthen protections against cyberattacks following the Colonial Pipeline hack. The Transportation Security Administration (TSA), a unit of the Department of Homeland Security (DHS), “is co-ordinating with companies in the pipeline sector to ensure they are taking all necessary steps to increase their resilience to cyber threats and secure their systems,” reports Reuters. The TSA is also reported to be collaborating with another branch of DHS, the Cybersecurity and Infrastructure Security Agency. DHS said it will release more details “in the days ahead,” without providing particulars. Representative Bennie Thompson, Chair of the Homeland Security Committee in the House of Representatives, called the move “a major step in the right direction towards ensuring that pipeline operators are taking cybersecurity seriously and reporting any incidents immediately.”

GlobalData: Colonial attack will concentrate government and operators’ minds on ransomware threat Following the disclosure of the cyberattack on the Colonial Pipeline, David Bicknell, Principal Analyst, Thematic Research at GlobalData, a leading data and analytics company, offers his view: “The economic impact wrought by this cyberattack will bring home to government and energy operators the vulnerabilities in critical infrastructure. “This is not the first ransomware cyberattack on an oil and gas utility – and it won’t be the last – but it is the most serious. It is also potentially one of the most successful cyberattacks against US critical national infrastructure. “Although cyberattacks have typically targeted corporate IT systems, the risk of those jumping across to operational technology (OT) systems has become much more prevalent. “The security industry must find a way to help organisations especially utilities - develop both defensive measures to prevent these attacks and the requisite best practice for responding to them.”

ISACA survey: IT security experts share insights In the aftermath of the Colonial Pipeline attack, global IT association and learning community ISACA polled more than 1200 members in the US and found that 84% of respondents believe ransomware attacks will become more prevalent in the second half of 2021. The Colonial Pipeline attack resurfaced preparedness for ransomware attacks as a front-burner topic for enterprises around the world. Colonial reportedly authorised a ransom payment of US$4.4 million. In the ISACA survey, four out of five survey respondents say they do not think their organisation would pay the ransom if a ransomware attack hit their organisation. Only 22% say a critical infrastructure organisation should pay the ransom if attacked. “In a vacuum, the guidance not to pay makes total sense. We don’t want to negotiate with criminals,” said Dustin Brewer, Senior Director of emerging technology and innovation at ISACA. “But when you need to get your business back online, a cost/benefit analysis is going to come into play, and a company is going to do what it needs to do to have continuity. Good cyber-hygiene has to be a focus to avoid getting to this point.” Among the survey’s other findings: ) 85% of respondents say they think their organisation is at least somewhat prepared for a ransomware attack, but just 32% say their organisation is highly prepared. ) Four in five respondents say their organisation is more prepared

for ransomware incidents now than four years ago, when the WannaCry, Petya and NotPetya attacks inflicted major damage. And two-thirds of respondents expect their organisation to take new precautions in the aftermath of the Colonial Pipeline incident. ) Nearly half of respondents (46%) consider ransomware to be the

cyberthreat most likely to impact their organisation in the next 12 months.

JUNE 2021 / World Pipelines

WORLD NEWS IN BRIEF USA Medallion Pipeline Company, LLC has announced that it has launched a non-binding open season for its capacity that is leased on EPIC Crude Pipeline, LP’s crude oil pipeline system. The open season started on 24 May, 2021 and will close on 25 June, 2021 at 4:00 p.m. Central Daylight Time.

BRAZIL Gas infrastructure company Fluxys and institutional investor EIG Global Energy Partners have completed the announced transfer of EIG’s minority stake in Brazilian gas transmission system operator TBG (Transportadora Brasileira Gasoduto Bolívia-Brasil). TBG owns and operates the 2600 km Brazilian section of the Bolívia-Brazil gas pipeline.

USA Chevron Corporation (Chevron) and Noble Midstream Partners LP (Noble Midstream) have announced that the companies have completed the previously announced acquisition, which resulted in Noble Midstream becoming an indirect, whollyowned subsidiary of Chevron.

ASSOCIATION NEWS IPLOCA’s Annual Convention that was scheduled to take place from 13 to 17 September 2021 at the Hilton Prague hotel, Czech Republic, has been postponed. The new dates for the Prague Convention are now confirmed for 19 - 23 September 2022.

Siemens Energy announces cybersecurity collaboration with ServiceNow Siemens Energy has announced a collaboration with ServiceNow to create a unified software service offering enabling energy companies to monitor, detect and respond to cyber threats targeting digitally connected critical infrastructure. The new solution brings together Siemens Energy’s artificial intelligence (AI)based software from its Managed Detection and Response (MDR), powered by Eos.iiTM, service to provide visibility and context across industrial operating environments with ServiceNow’s Operational Technology Management (OT Management) systems to connect cyber threats and digital workflows that allow analysts to quickly assess, prioritise and act against events in the field. The unified software solution creates a detection engine and workflows that streamline operations for cybersecurity analysts to monitor anomalous or malicious behaviour in Security Operations Centres (SOC), and energy plant operators to act on credible threat intelligence at machine speed.

“Most energy companies struggle with the complex technological and economic challenges involved in monitoring, detecting and preventing cyberattacks on critical infrastructure. Our MDR, powered by Eos.ii, solution, is the first AI-based platform built to provide visibility and context across the energy industry’s digital operating environment in time to stop attacks,” said Leo Simonovich, head of Industrial Cybersecurity at Siemens Energy. “Leveraging Eos.ii’s monitoring and detection software with ServiceNow’s digital workflows will help turn cyber threat intelligence into action so plant operators can respond to incidents with precision defence at machine speed.” “The ability to quickly turn data into action is critical to being able to proactively, reactively and remotely mitigate cyberattacks targeting critical infrastructure. Yet, this is one of the biggest challenges for industrial innovation,” said Marshall Tyler, Vice President of Industry Solutions at ServiceNow.

Aegion completes transaction with affiliates of New Mountain Capital Aegion Corporation, provider of infrastructure maintenance, rehabilitation and protection solutions, has announced the successful completion of the previously announced transaction under which affiliates of New Mountain Capital, LLC acquired all outstanding shares of Aegion for US$30.00 per share in cash. As a result of the transaction, Aegion has become a private company and its common stock will no longer be listed for trading on the Nasdaq stock market. Robert (Rob) M. Tullman has been appointed President and Chief Executive Officer of Aegion Corporation, effective 18 May 2021, following

the planned retirement of outgoing President and Chief Executive Officer Charles R. Gordon. Mr. Tullman commented, “The completion of this transaction represents the exciting first step in advancing Aegion’s compelling near- and long-term growth prospects as an industry leader and a protector of communities and the environment. I look forward to working with the dedicated teams as we leverage our differentiated portfolio of technologies and delivering transformational solutions to maintain, rehabilitate and protect critical infrastructure around the world.”

USA

Vallourec announces its 2021 Open Innovation Challenge

The Shell Robert Training and Conference Centre in Louisiana has established a new partnership with Maersk Training, which will see the global safety specialists deliver enhanced training to the Gulf of Mexico offshore workforce.

Vallourec has launched its 2021 Open Innovation Challenge around additional levers for value creation: new energies, new businesses, field and remote services, smart pipes and pipelines and Industry 4.0. The Group is launching three calls for projects to start-ups, laboratories and companies:

World Pipelines / JUNE 2021

) New power generation: marine energies

such as waves, thermal differences and floating offshore wind. ) Pipe and pipeline re-use: to extend pipe

usage’. ) Automatised and digitalised pipe yard:

to optimise inventory, inspection, and all other yard activities.

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CONTRACT NEWS EVENTS DIARY 23 - 25 August 2021 Canada Gas & LNG Exhibition & Conference 2021 Vancouver, Canada https://canadagaslng.com/

NEW DATES: 13 - 16 September 2021 Gastech Exhibition & Conference 2021 Singapore https://www.gastechevent.com/

NEW DATES: 21 - 23 September 2021 Global Energy Show 2021 Calgary, Canada https://www.globalenergyshow.com/

18 - 19 October 2021 Transportation Oil and Gas Congress 2021 (TOGC 2021) Zurich, Switzerland https://togc.events/

20 October 2021 OpTech 2021 ONLINE CONFERENCE https://www.worldpipelines.com/optech2021/

NEW DATES: 8 - 11 November 2021 Abu Dhabi International Petroleum Exhibition & Conference 2021 (ADIPEC) Abu Dhabi, UAE https://www.adipec.com/exhibition/

NEW DATES: 5 - 9 December 2021 23rd World Petroleum Congress Houston, USA https://www.wpc2020.com/

7 - 9 December 2021 15th annual GPCA Forum Dubai, UAE www.gpcaforum.net

World Pipelines / JUNE 2021

Bilfinger awarded €40 million inspection contract by Total E&P Denmark Bilfinger will perform inspection services on the offshore assets of Total E&P Denmark (Exploration & Production). The €40 million contract will be booked under Bilfinger’s Engineering & Maintenance Europe segment. Commencing in July 2021, the contract will run for five years with two x one-year extension options. With a focus on advanced nondestructive testing (ANDT) techniques, Bilfinger will provide a comprehensive range of services on all of Total E&P Denmark’s assets. The contract will be managed from Bilfinger’s office in Esbjerg, Denmark. “With this major contract from Total, Bilfinger continues on its growth path in the strategic business area of inspection services,” says Duncan Hall, Chief Operating Officer of Bilfinger. “Our skilled team

Taproot to expand midstream infrastructure in DJ Basin Taproot Energy Partners LLC has announced that its affiliate, Taproot Rockies Midstream LLC (Taproot) has been awarded an acreage dedication for crude gathering by Confluence Resources (Confluence) for its Platte River position. The in-service date for the pipeline is expected to be 1 July, 2021. The Confluence acreage dedication brings Taproot’s current dedicated acreage to over 325 000 acres from five producers. “We look forward to providing worldclass midstream services and solutions to Confluence as it develops its very attractive, productive DJ Basin acreage position. As our system expands, so does producer access to crude gathering pipelines, eliminating the need for trucking and providing the safest, most environmentally friendly transportation from the wellhead,” said Garrick Brown, Taproot CCO. “The growth Taproot has accomplished in the DJ Basin since its inception in 2018 has been remarkable. We are excited to continue our record of on-time and underbudget projects as we construct the Confluence pipeline, and providing exceptional midstream service thereafter,” said Kevin Sullivan, Taproot CEO.

contributes to ensuring the integrity of Total E&P Denmark’s assets. The award follows two recent contract successes in Denmark, making Bilfinger one of the largest local providers of offshore non-destructive testing inspection services just three years after the set-up of our local branch.” In March 2021, Bilfinger Salamis UK was awarded a multi-million pound inspection contract by Altera Infrastructure Production AS. The three-year agreement sees Bilfinger extend its existing service delivery with Altera Infrastructure, providing a range of conventional and advanced nondestructive testing (ANDT) services on assets operated by Altera in the UK.

THE MIDSTREAM UPDATE •

Winn & Coales International acquires the global Viscotaq business

•

Hydratight and Henkel partner for pipeline and vessel repair

•

Ocean Inﬁnity acquires Abyssal

•

Energy Transfer celebrates 25 years

•

Q&A: Effective ways of getting your ESG message out

Against a backdrop of global economic recovery, Dr Hooman Peimani discusses Russia's most prominent pipeline projects and their increasing supply of gas to Europe.

non-OPEC oil exporter, to push prices up by decreasing supplies in the global markets, while the prospect for a global economic recovery was becoming more realistic, helped a steady rally for oil prices fluctuating around US$70/bbl and slightly higher prices for piped gas in early 2021. As the world’s largest gas exporter and second largest oil exporter, Russia was the major loser of the global recession in 2020. The recession was surely triggered, but not caused solely, by the pandemic after approximately a decade of a global poor economic performance, exceptions asides (primarily China). Various US-led initiatives contracting the global economies – such as trade wars with Canada, China, India, Japan, the European Union, Russia and Turkey – and the imposition of economic sanctions on some of the world’s major oil exporters, such as Iran, Venezuela and Russia, contributed to that outcome. In particular, the US pressure directly affected Russia’s gas exports and, therefore, its international pipeline construction. The primary case was the nearly-finished Nord Stream 2 (NS2). The project was halted in December 2019 when Swiss-based Allseas, the company laying the pipeline’s last short stretch passing through the Danish exclusive economic zone (EEZ), ended its operation, as the Trump administration threatened imposing sanctions on any company completing the project. The threat deterred all the potential pipelaying companies, forcing Russia to use its own pipelaying vessels to resume the operation in January 2021. Reportedly, work on the very short remaining part of the pipeline’s German section connecting the Danish stretch to Germany is also underway. While Russia is determined to finish the pipeline this year and has the support of its European beneficiaries, including EU heavyweight Germany, it is uncertain whether this will actually happen, at least in the mentioned timeframe. This is due to the sustained US pressure under the Biden administration, as the continued opposition of the ten EU members (e.g. Poland) has practically ignored by the EU heavyweights backing the project (France and Germany). Apart from its political dimension (i.e. preventing further expansion of Russian influence in Europe as its single largest oil and gas supplier), opening the market for American LNG exports is the major factor behind the US opposition to NS2, which has become more diplomatic under the Biden administration in appearance, but not the content. It is reflected in US Secretary of State Antony Blinken’s late March statement on the pipeline’s fate during his CNN interview, cited by Reuters, following his earlier remark on his talk with his German counterpart to the effect of “US sanctions against the pipeline from Russia to Germany were a real possibility and there was ‘no ambiguity’ in American opposition to its construction.” Thus, “ultimately that is up to those who are trying to build the pipeline and complete it. We just wanted to make sure that our [...] opposition to the pipeline was well understood.” The sustained commitment of all the pipeline’s consortium members, which, except for Russia, are all EU members (Austria, France, Germany and Netherlands) is, in itself, a major achievement for Russia. This reality indicates a growing schism in the Western alliance by revealing that these

World Pipelines / JUNE 2021

Western countries’ pursuit of national interests has taken precedence over their ‘ideological’ commitments to the USA. Likewise, the completion of the Bulgarian section of the Balkan Stream and Russia’s beginning its gas exports to Bulgaria via this spur of the TurkStream in January 2021 was also a clear success for Russia. Commissioned in January 2020, the TurkStream practically replaced Russia’s South Stream gas pipeline shelved by Moscow in 2014 due to various barriers erected by the EU to its construction. Russia started feeding Turkey with gas in January 2020 through one of its pipelines while preparing for gas exports to a number of EU (e.g. Bulgaria and Hungary) and non-EU (e.g. Serbia) countries through the other, as their respective sections become operational. Russia has also extended its eastern gas pipeline systems for domestic consumption (Sakhalin-Khabarovsk-Vladivostok) and to increase its gas exports to China via the Power of Siberia pipeline. In short, Russia’s pipeline construction has been quite active despite the ongoing pandemic, as a reflection of the importance of its energy exports to continue in the foreseeable future despite the growth of renewable energy. Within this context, the major Russian projects are discussed.

Nord Stream 2 (NS2) The NS2’s fate is uncertain because of the sustained US opposition to the project, kept in place despite the January change of US administration. Mirroring the operating Nord Stream, the joint venture of Russia’s Gazprom (51%), Austria’s OMV, Germany’s E.ON and BASF/Wintershall and Royal Dutch Shell (10% each) and France’s ENGIE (9%) consists of twinoffshore pipelines buried under the Baltic Sea’s seabed (each about 1200 km; 27.5 billion m3/y; 48 in.) passing through the EEZs of Finland, Sweden, Denmark and Germany. The gas pipeline system connects the Russian gas network near Narva Bay in the Kingisepp district of Russia’s Leningrad region, to Germany’s gas network in the northern German coast near Greifswald to feed Germany and other EU countries. Over a year after the mentioned US threat of sanctions stopped the pipeline’s construction, the Danish Maritime Authority announced the resumption of the work on the approximately 120 km Danish section on 15 January 2021 involving “preparatory work and tests before pipe-laying started”, as reported by Reuters. Russia’s pipelaying vessel Fortuna reportedly began its work “in the construction corridor in the Danish EEZ, ahead of the resumption of the Nord Stream 2 construction” later in that month. The construction of Germany’s offshore connecting part of approximately 30 km in its Baltic Sea waters to build the NS2’s section “before its entry at the northern German coastal town of Lubmin, near Greifswald” started in the same month, according to Reuters. Despite the continued US opposition and its associated threat of sanctions, the work on the Danish section continued in February as Reuters quoted Danish Maritime Authority on the continued “pipelaying work […] at the south and south-west of Bornholm island using the Fortuna pipelaying vessel with assistance from the

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construction vessels Baltiyskiy Issledovatel, Murman and other supply vessels.” Reportedly, another Russian vessel, Akademik Cherskiy, was dispatched to the Danish waters to help the project, when the constructing consortium was quoted as announcing the completion of 94% of the pipeline project in the Baltic Sea, leaving only 138 km of it for completion. The project progressed in April when reportedly 95% of it was completed with almost 121 km left for completion. As cited by TASS news agency and reported by Reuters in April, Russian Deputy Foreign Minister Alexander Grushko stressed Russia’s confidence in completion of the project despite US opposition by saying “we have complete confidence that the project will be completed”. In fact, he reiterated Gazprom’s Board Chairman Viktor Zubkov’s March expression of confidence in completion of the project in 2021, as cited by the TASS news agency. Yet, in 2Q21, the NS2 completion date is still unclear.

Balkan Stream As the TurkStream’s extension designed to facilitate Russian gas exports to the EU region, the Balkan Stream is now fully operational. Fed by one of the two strings of the TurkStream, the spur connecting Turkey to Serbia via Bulgaria was completed in December 2020 to enable Russian gas exports to Bulgaria and eventually to other EU members. Being operated by Bulgartransgaz, the Bulgarian section (474 km; 47 in.; 20 billion m 3/y; €1.1 billion) was completed in December 2020 followed by the inauguration of its Serbian connection (403 km) on 1 January 2021 by Serbian President Aleksandar Vučić, connecting Bulgaria to Hungary via Serbia. As planned, Hungary and Slovakia will eventually import Russian gas via the pipeline as well as the rest of the Central European countries, provided the absence of any EU opposition to the resulting increase in Russia’s share of the EU gas market when Brussels is seeking the opposite. Replacing the ill-fated South Stream, the TurkStream, which went onstream on 8 January 2020, consists of two parallel pipelines (each 930 km, 32 in.; 15.75 billion m 3/y) of which one is for feeding Turkey and another for feeding the European countries via Turkey with Russian gas. They run through the Black Sea from the Russkaya CS near Anapa, on the Russian coast, and come ashore on the Turkish coast some 100 km west of Istanbul, near the village of Kiyikoy. From there, one of them connects to the existing Turkish gas network at Luleburgaz while the other one continues to the Turkish-Bulgarian border. Apart from its obvious importance as a gas supplying pipeline, the Balkan Stream’s significance lies in its enabling Russia to bypass particularly Ukraine, with which it has had major political and security disputes now seeking EU and NATO membership, but also Belarus having a history of political disagreements with Russia, though at a much smaller scale compared to those of Ukraine. Both neighbours of Russia have had disputes with Moscow over the volumes and fees of Russian gas supplied to them, and transiting via their territories to the EU countries.

World Pipelines / JUNE 2021

The Nord Stream, the NS2 and now the Balkan Stream are all meant to enable Russia to bypass its two neighbours for supplying energy to the EU countries, the single major reason for the opposition of these countries to the mentioned Russian projects.

Power of Siberia Gazprom is undertaking the expansion of the Power of Siberia designed to supply consumers in Russia’s Far East and also China, as the feeder of the Russia-China gas pipeline known as the East Route gas pipeline (ERGS), which went online on 2 December 2019. Consisting of Russian and Chinese pipeline systems, the ERGS is the pipeline system for the world’s single largest energy deal made in 2014. This is the US$400 billion undertaking of Gazprom and CNPC to supply China with Russian gas (38 billion m 3/y) for 30 years. Passing through the Irkutsk and Amur Regions and the Republic of Sakha (Yakutia), the Power of Siberia (3000 km, 1420 mm, 38 billion m 3/y) supplies gas from the Chayandinskoye field in the Yakutia gas production centre to the consumers in Russia’s Far East and to China. According to Gazprom, in late 2022, it will start to receive gas from another field (Kovyktinskoye) in the Irkutsk gas production center. The ongoing extension line (803 km) will link the Kovyktinskoye field to the Chayandinskoye field, as reported by OGJ.

The Sakhalin-Khabarovsk-Vladivostok gas transmission system (GTS) Among Russia’s ongoing domestic pipeline projects, the GTS’s expansion is noteworthy. The pipeline system consists of the Sakhalin-Komsomolsk-on-Amur and the Khabarovsk-Vladivostok lines (around 1350 km in total) and the Komsomolsk-on-Amur-Khabarovsk line (472 km; 700 mm). Gazprom is expanding the Komsomolsk-on-AmurKhabarovsk line in Russia’s Far East. Towards this end, more than 300 km (48 in.) of pipes, accounting for more than “75% of the new leg’s overall length” was welded by February, as reported by OGJ. Reportedly, the new leg will supply gas to consumers in Khabarovsk Territory once it is operational and “establish new connections for consumers receiving gas via the Okha-Komsomolsk-on-Amur gas pipeline, which is slated for potential decommissioning.” The Sakhalin-Khabarovsk-Vladivostok GTS is the first interregional GTS in eastern Russia intended to deliver gas produced on the Sakhalin shelf to consumers in the Khabarovsk and Primorye Territories, according to its operating company, Gazprom. It provides for expanding the gas grid system in the mentioned territories and ensuring the availability of gas supplies to the Asia-Pacific region. Passing through the Sakhalin Region and the Khabarovsk and Primorye Territories, the construction of the gas pipeline (1800 km; 1220 mm; 5.5 billion m 3/y) began in July 2009 and its “first start-up complex” went onstream in September 2011, to let gas flow to Vladivostok, according to Gazprom.

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Ryan Hiestand, MBA, Project Manager, Burns & McDonnell, USA, discusses the benefits of repeatable design for the pipeline industry and outlines the seven steps of the design standardisation process.

here is new excitement among pipeline design leaders and across the larger pipelines industry now that the development and use of consistent designs is widely available. Also known as repeatable design, design standardisation for pipeline facilities effectively aligns project stakeholders, objectives and scope, which helps capture and optimise schedule, cost and value for pipeline projects. This approach is critical given the increasing industry pressures to make smart investment decisions for public

and private infrastructure systems, new and ageing alike. For teams designing, creating and operating pipeline facilities, and for those charged with delivering the safety, efficacy and efficiency of each connective system, this is a test of whether they can shake free from traditional, timeconsuming ways to get to someplace smarter. “Collaborative pipeline facility projects using repeatable design principles are providing results to owners by reducing schedules from conception to startup and driving down costs across the lifecycle of assets. Burns & McDonnell

Figure 1. Pipeline standard design.

sites are evaluated for construction and commissioning, and lessons-learned logs help with the change management process.

The seven steps of design standardisation 1. Understand possible variations The first step of design standardisation is for select project stakeholders to participate in a facilitated process to understand possible variations of their infrastructure needs. These are likely to include factors such as pipe diameter, size and quantity of equipment, and geographic locations, among other considerations. Figure 2. Identifies the design standard process for design standardisation. Efforts are made to consolidate iterations, as well as to document and publish the list of possible variations to be shared continues to push the boundaries of repeatable design with the team. This early stage of information intake and programming, having just conducted our latest iteration of engagement informs a later stage focused on identifying standardising pipeline facility development in 2020,” says where standardisation could work. If it is determined at this Jason Hetherington, Managing Director of Logistics and first step that repeatable design is not a good fit, traditional Midstream at Burns & McDonnell. custom design approaches and optimisation are likely a more feasible approach. Design standardisation may be applied What is design standardisation? to portions of a project as long as there are at least two Application of design standardisation comes through the repeatable systems. design and use of standard ‘blocks’ of grouped equipment, 2. Align stakeholders piping and instrumentation in varying arrangements Once the consolidated and published iterations based on for a programme of similar projects. When feasible to possible variations have had a full owner review, it is time for spend additional time on upfront design and stakeholder the second step, to align stakeholders. Considerable emphasis alignment, the design of these blocks can be established is placed on gaining feedback and total buy-in from each of and locked early in the programme. The blocks then can be the many key stakeholder groups. This new approach allows arranged to meet site conditions and space requirements, 100% of the customisation of the blocks to occur before the and yet the contents of the blocks are not changed from site-specific design stage. Input provided much later in the site to site. process can increase project cost and hinder schedule savings. Since every design is the same through the design This process emphasises early alignment of stakeholders to standardisation process, each valve responds the same way, optimally define standardisation of the specific layout and all of the pump stations operate the same, and procurement scope of work. of major equipment and commodities can be negotiated and Typically, leaders from each of the key stakeholder groups awarded early for fabrication in controlled manufacturing have a say in the design. They should include: environments. Operations compliance officers appreciate ) Operations and maintenance. repeatable design, where the issues of quality assurance and quality control (QAQC) are addressed and the integrity of ) Engineering subject matter experts. manufactured components is maintained. Also, compliance officers rarely turn down the chance to optimise for exterior ) Procurement. conditions. Stakeholders welcome that time and cost savings are increased because drawings are only issued once. ) Construction co-ordinators. The bedrock of successful design standardisation is a comprehensive planning process that actively engages ) Compliance officers. with key stakeholders from the beginning and consistently throughout, and which brings forth a deep understanding and ) Commercial. communication of the variations of the project. A seven step design standardisation process is the most To provide accurate design standard alignment, key sound, with stakeholders invited to review and consider stakeholders need to be included in the review of the how a pipeline facility will be designed and built and where standardisation process early and often. Each key stakeholder the blocks could be located. Topography and layout of

World Pipelines / JUNE 2021

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Who are the beneficiaries of design standardisation? Those who benefit most from standardising the design of pipeline facilities are the owners of the infrastructure, as well as their teams in engineering, procurement, construction, and operation and maintenance. Engineering team benefits: ) Decreases quantity of modified deliverables. • Ease of updating all blocks across different project sites

based on varied site conditions. • Each system will respond to the same adjustments. Figure 3. Identifies boundaries of ‘blocks’ (blue outlines) utilised on a recent pump station programme.

) Automates updates to deliverables, which improves quality

group also needs to identify important milestones when input is to be received before moving forward, and they should have the opportunity to share their contributions.

) Reduces design schedule.

3. Identify blocks

Procurement/construction team benefits: ) Increases opportunity for shop fabrication in controlled manufacturing environments.

Driven by the iterations of possible layout variations, the project team and key stakeholders take the third step: identify blocks. Based on the previous steps, decisions are made about which pieces of equipment or piping layouts can be standardised. There are considerations of where blocks will start and stop and additional details are addressed, such as how to handle numbering, naming and tagging of blocks and components. All engineering systems should be considered when defining block start and stop points for each discipline.

and repeatability of design.

) Reduces design cost.

) Improves purchasing options and allows for a more regional

or global approach. ) Decreases requests for information (RFIs) and field delays,

and improves efficiencies due to crew familiarisation with design across sites, as well as from stakeholder input throughout the process.

4. Block design and review stage In order to transform the conceptual design into a concrete plan, the next step – the block design and review stage – incorporates comments from stakeholder leaders. After this stage the block design is locked and will not be modified during the project.

) Increases quality.

5. Site-specific design

Operation and maintenance team benefits: ) Standardises spare parts across assets.

During the fifth step of the process, site-specific design, blocks are arranged by defined project layout standards based on geography, topography, tie-in locations, proximity to other equipment and maintenance access.

) Decreases schedule. ) Improves safety.

) Establishes consistent operations procedures. ) Improves safety.

6. Lessons learned For the next step, the team is likely to facilitate lessons learned summits with key stakeholders, which should take place after all procurement and construction contracts are awarded, post startup and commissioning, and/or following one year of service.

7. Management of change process Lessons learned serve the final step, the management of change process, and inform future project block design and review stages, where blocks may be reconfigured and locked in again. The team is able to identify the lessons learned that will be applied to future sites and methods of deployment. These process improvements allow all involved to get smarter every time.

World Pipelines / JUNE 2021

) Reduces downtime related to problems.

Why deploy repeatable design? There are three main reasons why repeatable design is worthwhile to deploy. The most compelling reason is that the schedule to get a pipeline into service is reduced. The second reason is the decrease in cost for design and construction of the project and future operations. The third is that this process allows for stakeholder participation and buy-in, which results in a smarter, fully informed configuration. In addition, and perhaps equally important, design standardisation is an effective new approach. Burns & McDonnell recently completed a repeatable design case study on a pipeline system from Wyoming to Texas involving 25 pump station

sites with four block variations, and with five blocks on each site. The team reached an average of 70% of typical ISOs that were repeatable and not redesigned, more than 80% of typical electrical and instrumentation (E&I) drawings, and significant total installed cost (TIC) reduction. The owner was very satisfied, having reduced its overall design cost and schedule by 50%. At the conclusion of construction, Burns & McDonnell was able to report that throughout the different phases of the project, the team was able to produce more drawings and give the owner more deliverables so that the scope could be better communicated while simultaneously reducing cost and schedule.

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Burns & McDonnell is not alone in its findings about the value of design standardisation. The Construction Industry Institute (CII) reported a study in 2020 of 45 implementations of repeatable design for upstream, midstream and mining (UMM) projects, and the result of implementing this approach was 10% average savings in TIC, 15% in average schedule savings and 25% average savings over the lifecycle of the projects. Due to equipment conformity, cost savings were considerable in the UMM team’s ability to make the same changes at all repeatable project sites. By working together with stakeholders, it also discovered that in many cases some modules were more amenable to design standardisation. It was determined that while there need to be at least two repeatable systems, the site layout does not need to be 100% standardised. Additionally, the UMM team found that utilising the assets of all stakeholders involved in the project built more knowledge, yielded smarter decisions and resulted in statistically positive improvements across all systems and responsibilities.

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Conclusion US energy demand has doubled every 20 years, and infrastructure spending is likely to increase dramatically in the range of trillions of dollars over the next decade. For the pipelines industry, innovative methods such as repeatable design undertaken by leading-edge facility owners and stakeholders will safeguard the design, construction and maintenance of the infrastructure needed for present day and future demand. Rather than the traditional, custom approach for all pipeline facility and pump station components, design standardisation offers proven cost and schedule savings, as well as a verified process for unified effort that improves safety and quality. This moment offers the industry the opportunity to get smarter, faster and to do more with the resources entrusted to us for stewardship.

coatings

coatings World Pipelines asks some questions in relation to oil and gas pipeline coatings.

STEVE CRAWLEY, Technical Director, and ANDREW STUART, Sales & Marketing Director Winn & Coales (Denso) Ltd, a member of Winn & Coales International Ltd Steve Crawley is the Technical Director for Winn & Coales (Denso) Ltd. He joined the Winn & Coales International Group 28 years ago as a Chemist in 1993, and has extensive technical knowledge including product formulation, intellectual property and commercial approvals and technical sales. Andrew Stuart is the Sales & Marketing Director for Winn & Coales (Denso) Ltd. He joined the Winn & Coales International Group 31 years ago in 1990 and has broad and extensive experience in technical sales of field joint and mainline coatings.

Which product or service do you provide in the coatings arena? How and when is it specified in pipeline projects? STEVE CRAWLEY & ANDREW STUART, Winn & Coales (Denso) Ltd Winn & Coales (Denso) Ltd provides a range of coatings for all pipeline elements, barrels, field joints, valves, and fittings. We serve the oil, gas, water, and utilities sectors and supply both field-applied and factory-applied coating systems. Our aim is proven, long lasting systems, with the optimal Total System Lifetime Cost. We focus on supplying coatings but work closely with coating applicators to support their training and knowledge transfer requirements. We operate both via independent expert coating specifiers and by offering coating recommendations direct to clients. It varies depending on the arrangements in place on the particular pipeline project. Clients often approach us for

coating system recommendations either directly or via our worldwide network of distributors. In either case, we have a ‘technology neutral’ way of thinking. That means we do not believe there is a ‘best technology’ that suits all circumstances. On the contrary, different coating systems have different advantages and disadvantages and helping clients make the right choices for their particular circumstances is a journey we make together. The first step of that journey is ascertaining the facts relating to the project. A well thought out specification will take account of conditions of application, mechanical stress on the coating, operating temperature, and surface preparation constraints to name just a few factors.

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Discuss a recent technological development that has benefitted your pipeline coatings products and/or coating services capabilities STEVE CRAWLEY & ANDREW STUART, Winn & Coales (Denso) Ltd The pipeline industry exists in a state of perpetual unease because it is always striving to maintain integrity and ensure safe and undisrupted use of pipeline systems. So, performance of pipeline coatings is a shared concern. But practical performance in the real world is what matters when the realities of challenging environments and application conditions take effect. We recognise that in some situations the precautions normally used to ensure preservation of the coating during pipeline installation are not always, or cannot always, be employed. As a result, additional mechanical protection of the coating is required.

Denso Bore-WrapTM protects field joint coatings and factory applied pipeline coatings from the abrasion stresses and scarring of directional drilling, HDD and boring. It is an abrasion resistant, sacrificial outer laminate that protects preapproved field joint coatings and mainline coatings such as epoxies, shrink sleeves, and FBE. Denso Bore-Wrap combines our experience of protective material with a deep understanding of severe pipelining conditions. This approach has led to a remarkably effective and reliable system which complements the other coating systems within our current range. And helps ensure protection of the primary coating when you need it the most.

Discuss current limitations of pipeline coatings, and how they might be overcome. What is driving innovation in the field? STEVE CRAWLEY & ANDREW STUART, Winn & Coales (Denso) Ltd Increasing concern and awareness of environmental sensitivity and installation of pipelines in high consequence areas has highlighted the benefits of trenchless pipe installation. However, whilst trenchless installation is on the rise in the oil and gas and water sectors, many of the pipe coating systems in use today have limitations in meeting the soil stress, gouge, impact, and flexibility requirements that are unique to trenchless pipe installation. Unfortunately, not all protective systems employed in

pipe coating protection have been developed specifically for trenchless application. Harder systems (FBE, epoxy) can become too brittle and inflexible and will chip and break when hitting rocks and disbond due to bends in HDD installations. Softer systems (3LPE, Tapes, HSS) are more prone to damage from gouge or shearing forces. Denso Bore-Wrap addresses these limitations by using omni directional glass to resist gouging, woven material to provide circumferential and compressive strength to resist shearing, compressed resin and glass combination to combat abrasion, and a fast-curing porous resin to increase flexibility and resistance to impacts.

How important is surface preparation and/or application, and how are these processes reviewed and regulated? STEVE CRAWLEY & ANDREW STUART, Winn & Coales (Denso) Ltd

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Very important. Across the industry a wide variety of pipeline coatings are used. Why is that? Well sometimes that is driven by performance, sometimes by cost, or personal preference but it is always informed by the surface preparation and application requirements. Refurbishment of a water pipe valve is a very different situation to a gas pipe field joint. The highest levels of surface preparation are not always an option because of the constraint of abrasive blasting. It is important to firstly consider the features and constraints of your specific application as that informs the generic type of coating that is most suitable.

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Outline the scope of a recent pipeline coating project (or upcoming one) for oil/gas pipelines STEVE CRAWLEY & ANDREW STUART, Winn & Coales (Denso) Ltd DUSUP (Dubai Supply Authority) supplies the energy needs of a number of key utility and industrial companies in Dubai, supplying natural gas to DEWA, Dubal, Dugas, ENOC and Dubai Petroleum for their power generation, desalination and other industrial needs. DUSUP specified Denso Protal 7200TM liquid epoxy coating for a buried gas pipeline project in Dubai, UAE for 24 in. diameter block valves and straight pipe lengths. Both were coated on site with the ProtalTM Air Cartridge Gun which offers quick and effective application with minimal equipment maintenance and material wastage. Denso was also asked to provide additional systems for the 2 in. diameter connecting

valves and pipe tie-ins. The smaller connecting valves were protected with the tried and tested DensoTM Petrolatum Tape system that is ideal for the long-term corrosion prevention of irregular shapes with minimum surface preparation. The pipe tie-ins were done with the reinforced Densopol 60HTTM PVC Bitumen backed pipeline tape, this transitioned from the Protal 7200 Epoxy coated pipe onto the existing 3 LPE coating of the pipeline. The tape was applied by a DensomanTM hand wrapping machine, ensuring the correct overlap and tension required. Three different applications, requiring three different solutions from Denso, that will offer long term corrosion protection in some of the most demanding conditions.

What changes have happened to your business as a result of COVID-19? How are you adapting to current norms? STEVE CRAWLEY & ANDREW STUART, Winn & Coales (Denso) Ltd

Like most organisations we are now adjusting to working via online platforms which have transformed For Denso the business impact of this pandemic our methods of internal communications and allowed has been mitigated by having widespread manufacturing colleagues to collaborate in new and exciting ways. But and operating facilities around the world. We have seen external communication is more challenging. The industries COVID-19 sweep around the globe but thankfully the that we serve have traditionally favoured a practical, adverse effects on the business, and more importantly the hands-on approach. After all, both corrosion and corrosion welfare of our people, has been very slight. prevention are physical issues which demand a physical presence in person. And it is that personal interaction with users, specifiers, and contractors that generates a clear understanding of requirements and capabilities. Often, there is no substitute for face-to-face contact. And that close dialogue between suppliers and users is something we can fully expect to resume when the time is right. We have enjoyed delivering online training and webinars and those platforms will continue to be useful. But to all our clients and partners worldwide, we look forward to being able to meet and shake your hand once again when the time is right. Let us WINN & COALES (DENSO) LTD: 24 IN. DIAMETER BLOCK VALVES AND STRAIGHT PIPE LENGTHS hope it is soon. COATED WITH PROTAL 7200TM ON SITE, USING THE PROTALTM AIR CARTRIDGE GUN.

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Giorgio Dones, Corrosion Protection Manager, and Davide Marchesi, Pipeline Equipment Manager, TESI S.p.A., Italy, explain how to put together a comprehensive strategy against pipeline corrosion.

The enemy’s behaviour Corrosion is the biggest enemy of metals. It comes about when metal reacts with oxygen and moisture under the influence of the temperature. If it is under an insulation layer, it is difficult to detect and counteract. This ‘corrosion under insulation’ (CUI) poses a serious threat to the stability of the metal. It is not until a critical stage has been reached that it becomes visible on the surface. The insulation layer is not the cause of the corrosion. At most, it creates a space where oxygen and moisture can accumulate. In some cases, the insulation layer intensifies the corrosion, for example when it is made of a material that absorbs a lot of moisture or when chlorides and acids leach out of the insulation layer.

Studying a strategy against corrosion

Figure 1. Protection coating damaged by corrosion under its layer.

That gives rise to the question of how moisture gets under the insulation layer. Two causes can be identified. ) The first is when moisture seeps through small leakages in the watertight covering of the insulation layer. This gives rain, production water, steam or groundwater the chance to reach the metal surface. These leaks could in most cases have been prevented. They are often the result of poor design, poor fitting of the insulation, poor use of the material or poor maintenance. Moisture under the insulation layer can also be caused by the forming of condensation. If the temperature of the metal surface is lower than the atmospheric dew point, condensation forms on the surface. This possibility must be considered as early as possible during the design of an item so that the appropriate type of insulation can be chosen. ) The corrosion process can be intensified by dirt. Here too,

Figure 2. Onshore pipeline construction project where TESI supplied heat shrinkable sleeves, induction coils powered by induction heating generators (over 800 generators built and spread all over the world).

cracks in the insulation layer can result in the penetration of moisture. Chloride, acid and salt pose a special threat to the metal. These substances are sometimes even present in the insulation layer itself. If the insulation layer comes into contact with the moisture, these subjects can leach out and corrode the underlying metal. The dirt concentration increases sharply if the moisture evaporates when the temperature rises. Temperature is a factor that contributes to corrosion. Although evaporation reduces the duration of contact between the moisture and the metal, the higher temperature intensifies the corrosion. That in turn reduces the metal’s life span. There is a good chance of corrosion occurring at temperatures between -4˚C (25˚F) and 175˚C (350˚F). At a lower temperature the metal is protected against corrosion by the cold, at higher temperatures the heat keeps the metal dry. There are few objects with a temperature that remains constantly below or above the critical point. This is because of variable operation, temperature variations in parts of the object or different temperatures of parts connected to the object.

Pain points CUI can occur under all types of insulation, but especially insulation where: ) The insulation contains salt that leaches out. ) The insulation easily absorbs moisture or moisture

penetrates through the top layer. ) The insulation contains foam with chloride and acid

residues, which react with moisture. Insulation which absorbs the least moisture and dries the quickest offers the lowest chance of corrosion occurring. Bear in mind that cheaper insulation is not necessarily the most economical choice viewed over the entire lifecycle.

Experienced solution Figure 3. Heat shrinkable sleeve application in an onshore pipeline construction project.

World Pipelines / JUNE 2021

For instance, a perfect combination to achieve consistent corrosion protection when restoring the insulation on the

welded joints of a gas pipeline, utilising factory coated 3LPE pipes, would include: ) Suitable choice 3-layer heat shrinkable sleeve, to replicate the characteristics of the line coating. ) Metal preparation grit blasted to SA 2 ½. ) Roughening of the lateral overlaps to the factory PE

coating. ) Right preheating of the area, to be obtained by

induction heating. ) Application of primer onto the metal surface. Figure 4. Covalence® heat shrinkable sleeve half applied on a pipeline joint.

) Wrapping of heat shrinkable sleeve with preinstalled

patch closure. ) Manual or automatic shrinking at 120˚C, until visual

change of the dimples onto the backing.

The best option

Figure 5. Automatic finishing machine for Industry 4.0 located in TESI Corrosion Protection Division’s workshop.

Ausonio Zubiani, the owner of TESI, has inherited a considerable experience in the field of corrosion protection, starting from the initial collaboration with Raychem in the late 1970s and continued with Canusa for over 30 years. Nowadays TESI is the official distributor of Covalence® products. Covalence® (formerly ‘Raychem’) – the original heatshrinkable technology – was invented in 1957. The product line consists of a series of multi-layer sleeves that have high electrical resistance and low permeability, making them the optimal solution for corrosion prevention and mechanical protection of field joints for steel pipelines and pre-insulated piping systems. The products consist of a radiation crosslinked and stretched polyolefin backing with an adhesive laminated on in order to form the basic product. The adhesive may be either visco-elastic based mastic or co-polymer hot melt adhesives to match up with in-service performance requirements: ) Systems conform to all pipe diameters. ) Mastic or hot melt-coated sleeves balance performance,

economy and ease of installation. ) Excellent resistance to cathodic disbonding, hot water

immersion, thermal ageing and soil stress at maximumrated operating temperature. ) Dimpled pattern provides a ‘permanent change’ indicator

for proper heat applications.

Figure 6. Offshore pipeline construction project where TESI supplied heat shrinkable sleeves, induction coils powered by induction heating generators (the latter is not shown in the picture).

World Pipelines / JUNE 2021

Covalence® is a trademark of Seal for Life Industries, a group of a closely associated companies manufacturing multiple technologies of products focused on corrosion prevention, fire and temperature protection, and cathodic protection for pipeline, oil, gas and water infrastructure and industrial applications.

Industry 4.0 and big projects In order to achieve the highest standards of quality and continuous improvement of lead time to its customers, TESI Corrosion Protection Division has designed and implemented an automatic finishing machine, interconnected and remotely manageable (Industry 4.0). This exclusive system, in addition to ensuring maximum compliance with the tolerances imposed, works in a fully traceable process of cutting to size, pre-attachment of the closure patch, packaging and labelling, all in compliance with the most stringent regulations of ISO 9001 quality and safety. This innovative machine went into operation at the beginning of 2019. It is able to produce heat shrinkable sleeves for every pipe diameter request and at high production rate, several tens of thousands of sleeves in a short time. The capabilities of this machine meant a huge step ahead for TESI, with the certainty of results in terms of quantity and quality. The first big project where TESI used this brand new machine was in the second half of 2019, for the SNAM project “Interconnessione TAP” (TAP Interconnection Gas Pipeline). It was the provision of over 4000 heat shrinkable sleeves for this natural gas pipeline DN1400, running along southern Italy for around 55 km with a design pressure of 75 bar.

All in one solution Through the synergy between its Corrosion Protection Division and Pipeline Equipment Division, TESI can nowadays supply a complete package against pipeline corrosion, made of corrosion protection coatings, rental or sale of machinery for field joint sand blasting and field joint coating, factory training or on-site training, and remote or on-site support with a supervisor.

TESI’s history in manufacturing equipment for the pipeline construction industry began 20 years ago, firstly with only induction heating generators and induction coils for filed joint coating application with heat shrinkable sleeves, then, after huge investments made in the engineering department, with a wider portfolio which includes multiple machines, and not only with anticorrosive coating application purpose. The latest equipment consists of: AutoBLAST high efficiency automatic blasting machine, AutoCOAT high efficiency automatic coating machine (FBE), automatic induction coil for coating/ welding pre-heating (S-Lay and J-Lay), induction generators in multiple configurations such as rotative generators (diesel/electric), static generators (inverters), containerised induction heating and coating solutions for the offshore industry, and much more. All the field equipment has been designed with a high level of automation but without exasperation, leaving the possibility for operators to operate even in semi-automatic mode and to carry out on-site maintenance in a simple way. Another fundamental of TESI equipment is the renowned capability to handle the most severe conditions in term of environment and cycle time, typical of the pipeline projects, in particular offshore. Another strength is the after-sale service. TESI has several service centres located in strategic points of the world, (USA, Europe, Middle East) and multiple field teams that support customers with training sessions rather than during commissioning or pre-qualification tests. All of TESI’s equipment is supervised remotely, so that the team can guide operators in real time during emergency situations to minimise breakdown times. A further article about pipeline construction equipment and services will be released soon.

Dr. Eran Inbar and Eitan Elkin, Prisma Photonics, Israel, describe unlocking pipeline digitalisation with next-generation fibre sensing.

Figure 1. Testing for multiple intrusions in a small area.

rom afar, it looked like a ballet: two digging machines and a single person. The person was trying to sneak his way through, trying to fool the pipeline monitoring system. The system, based on nextgeneration fibre sensing, registered all three of them. Since none of them was an immediate threat to the pipeline buried underneath, it just noted the activity as three possible risks to follow. It continued working, monitoring

the entire length of the pipe, leaving the three to continue their intricate drill (while keeping an open eye if they come closer to the pipeline). This event took place near a buried gas pipeline, testing the capabilities of PrismaFlowTM, a next-generation fibre sensing solution. Using the pre-deployed optical fibre, it detected all activities remotely from the operations centre, tens of kilometers away. The fibre – a regular

telecom optical fibre – had been buried along with the pipeline a long time ago. Similar fibres have been placed alongside pipeline infrastructure for the last 20 or so years. All it took was hooking up a PrismaFlow sensing unit to an end of the fibre in a valve station, and tens of kilometers of pipeline infrastructure were immediately able to be monitored.

Figure 2. Internal representation detecting human and excavator individually.

Data pipelines and digitalisation Most pipeliners will have a satisfied look on their faces looking at a well-operated pipeline, thinking of the product flowing smoothly inside. Operation managers will have a similar look, thinking of the data that flows smoothly through this same pipeline. Data and smart use of it are becoming a top priority in today’s oil and gas companies. Whether it is to improve on operations and performance, prevent product loss and theft, or enable emerging commercial models – data and the digitalisation of the pipeline are key. Driven by regulatory pressure or required internally to improve and perform better, oil and gas companies understand the need to gather, correlate and glean information from all the data they can get from the infrastructure they operate. But not all data is created equally, as not all petroleum products are equal. There is a matter of quality. The data needs to be of high quality and detailed enough to provide actionable insights, information that will guide forward and fit the needs of advanced algorithms and machine learning models. Think of an old 1990s phone camera image compared to the latest smartphone photos. High-resolution data with enough details can open up a new age of pipeline digitalisation. Digitalisation is a data-centric concept. It’s all about unlocking the power of Big Data, smart sensors, and emerging technologies to enable the intelligent, realtime management of assets and products. Furthermore, digitalisation will also support the proliferation of new business models through increased innovation in the market. At the source of digitalisation are next-generation sensing technologies that are able to supply machine learning-quality data and details.

Sensorless monitoring, all along the pipeline

Figure 3. Alert showing on PrismaFlow user interface.

Figure 4. Confirming alert information in the field.

World Pipelines / JUNE 2021

PrismaFlow is Prisma Photonics’ next-generation fibre sensing solution for pipeline operators. Even for those acquainted with traditional fibre sensing technologies, PrismaFlow opens a new level of data and monitoring abilities. Its Hyper-Scan Fibre SensingTM technology is a far cry from existing fibre sensing. PrismaFlow uses the pre-deployed optical fibres along pipelines, whether they sit directly on the pipeline or inside a conduit in the pipeline’s vicinity. These fibres can be interrogated optically to sense abnormal events. As the fibres are already there, deployed with most pipelines, fibre sensing offers superior and more cost-effective monitoring abilities than point sensors. From a deployment perspective, the fact that measurements are evenly distributed along the asset means that monitoring is more accurate than using point sensors such as pressure gauges in stations, and acoustic or electric sensors installed directly on the pipe. Think of it as a sensor that is always there, at all places, at all times, and in any condition without any installation hassle. Most traditional fibre sensing technologies offer limited data granularity, indicating, with some success, pipeline leaks, and third-party intrusion events. PrismaFlow can detect and generate highly detailed data, monitoring assets for hundreds and even thousands of kilometers.

It also employs machine learning models that accurately classify events in context. It features accuracy with nearzero false alarm rate (FAR) for leak detection, third-party intrusion, and distributed integrity check (along the entire length of the pipeline). The data richness and high signal to noise ratio (SNR) enable PrismaFlow to use storytelling techniques, making sure that only actual events raise the alarm. This is the real value of an asset monitoring system – the ability to alert on true events and avoid false alerts that are a nuisance and lead to a shutdown of such a system.

Weaving data into stories to avoid false alarms Let us get back to the opening scene, where various excavators and people are moving near a buried pipeline. PrismaFlow has detected several sets of activity as depicted in the internal system representation seen in Figure 2. On the right, we can see the footsteps of a walking person, and on the left side, the image shows the engine and digging bucket of an excavator starting to scrape the ground. The activities are not blended into one big blob; the high resolution of the data allows distinction. Using its machine learning-based classification, PrismaFlow understands that these are a person and excavators and starts to build a story. A story is made out of many steps: an excavator arriving at the area, movement along the asset, the initial scrape on the ground, etc. The alertness of this location is heightened as suspicious activities may occur there. Only when the person or excavator starts digging (consecutive hits to the ground with a shovel or the digging bucket) will an alarm be raised in the operations centre (or any other connected application) with the location and all the needed details – in real-time. Storytelling is the key to a low false alarm rate. It is made

possible by highly detailed data, enough for the machine learning models to classify it and identify what happens and where. It could be a farming machine passing by, a train, a busy road – all these will not trigger an alarm as they lack all the steps of an actual intrusion. The humanmachine interface, the UI, will present the real alarms and may (if configured to do so) show the unfolding stories and other events that are taking place but do not require attention yet. These events are displayed and may (or may not) evolve into a real threat to the pipeline integrity and operation.

When dealing with product theft, there is always a series of such stories. Even a single person on foot with a drill and a welder can be detected. The classification stages are essential to identify friends or foes. Since pipeline right-of-ways often pass through public areas, there are certain innocent behaviours and/or wildlife activities that must not trigger an alert. A monitoring system that raises an alarm (and a response team) for the movement of a few boars will not be considered reliable. For a pipeline operator to establish a higher-level view of the assets, classified events and alarms can be integrated and sent further up, feeding an aggregated view and unifying information from several sources. The data from PrismaFlow, generated by Hyper-Scan Fibre Sensing and classified by machine learning, can be merged, using data fusion with input from other monitoring systems, to create a comprehensive view or be kept for further analysis.

Data fusion for leak detection Leak detection is another primary example of pipeline monitoring systems. Such leaks are a nightmare for any oil and gas company. PrismaFlow has proved outstanding product leak detection abilities. In testing, gas leaks of 200 standard litres per minute (SLPM) were detected in about one minute from the moment the leak started. Liquid leaks as low as 20 litres per minute (LPM) were detected, which is about 0.02% of a change in the flow. The detection was carried out without using a

momentary and transient effect such as a negative pressure wave, only Hyper-Scan Fiber Sensing. Many operators require a dual-solution mechanism. This level of monitoring is often dictated by governmental regulations while also providing the most effective leak detection with complementing systems. This is where the digitalisation of the pipeline really shines through. The aggregation and correlation of all monitoring data can grant an operator peace of mind that they have a reliable solution in place that will alert on time and only when needed.

Conclusion Digital technology and large amounts of data are not new to the oil and gas industry. The sector has been using seismic survey data and underground modelling for years. However, for the data to be used for better decision making, optimised operations and monitoring, it needs to be detailed and machine learning grade. Next-generation fibre sensing can offer this level of data, pushing pipeline digitalisation further. PrismaFlow is an example of where detailed data meets real-time machine learning analytics to respond to safety, preventive and predictive maintenance, and safety scenarios. Pipeline digitalisation will reach every oil and gas company operating in this market. Operators will embrace it, responding to regulations or their own needs to remain competitive. Big Data and machine learning technology, reliable and affordable sensors, and scalable platforms that can process and analyse data: all these define a new digital age for pipeline operators.

Ollie Burkinshaw, ROSEN Group UK, and Simon Slater, ROSEN Group USA, discuss a combined ILI and data integration approach to determine the material properties of undocumented pipeline sections.

aterial properties and attributes play a key role in the safe operation of pipelines. Over the life of an asset, records of material properties and attributes may be lost, or traceability of the documents may become uncertain. This is particularly likely for older assets, where original records only existed as hard copies and many factors may have led to reduced confidence over time, including changes in pipeline ownership or operator, office moves and staff changes. Even for pipelines where original records are thought to be complete or reliable, operators may have lost track of the various changes that have accumulated on the pipeline over time, such as repairs and replacements, re-routings, taps and so on. Material verification is a general term for the process of re-establishing or confirming properties and attributes, including diameter, wall thickness, seam type, pipe grade and toughness. These parameters directly influence the design pressure and safe maximum allowable operating pressure (MAOP) of a pipeline. They are also critical inputs when calculating remaining strength and predicted failure pressure (PFP) for metal loss and crack-like features.

In the US, PHMSA recognised the importance of complete and accurate knowledge of material properties in new regulations that became effective in July 2020. These new regulations require operators of gas transmission pipelines to verify material properties where they are not evidenced by traceable, verifiable and complete (TVC) records to support MAOP and integrity assessments. The new regulations have sparked development of numerous novel technologies and processes that have made material verification approachable and cost-effective. Operators in other regions, outside the US, are following this lead and beginning to leverage these techniques in an effort to increasingly focus on gathering accurate material properties in support of safe pipeline operation.

A data integration approach to material verification Material verification activities should be structured and targeted so that they will provide a useful input into safe operation and integrity management (IM). By bringing multiple datasets together within a data integration approach, efforts can be focused to collect the specific properties that are needed in the right

locations. The key elements of this approach can be summarised as follows: ) Define pipe populations with shared properties and attributes. ) Determine the status of existing material property data for each

materials may exist in the pipeline. For unpiggable pipelines, significant effort must be placed on the records search, and operators may be left with significant gaps. For piggable pipelines with missing or unreliable records, the best solution is one based on inline inspection (ILI).

population.

Inline inspection solutions ) Align existing integrity threats and susceptibility along the

ILI delivers up-to-date data on every pipe within the pipeline. By integrating multiple datasets from ILI, populations can be robustly identified. Changes in diameter or wall thickness and the presence ) Implement testing to verify the missing data required for each or absence of a seam weld will directly reveal different pipe population. populations. However, many different pipe materials could still be present, with a wide range of grades or toughness properties. This approach will be discussed in this article, alongside To overcome this problem, ROSEN developed the RoMat illustrative figures taken from a recent case study. PGS inline inspection service. It employs sensors based on a pre-magnetised eddy-current technology that is sensitive to Pipe populations metallurgical changes of parameters such as chemical composition The first and perhaps most critical step to verifying material and microstructure. By incorporating this dataset with other properties and attributes is to establish the different pipe parameters measured by ILI within a data integration approach, materials present and their locations in the pipeline. These different pipe materials can be identified – down to each different pipe materials can be grouped into ‘populations’, a individual pipe. Each pipe within the inspected pipeline section term that defines pipes with equivalent material properties and can be grouped into a population. attributes. Once established, these populations mean the task Figure 1 shows an example of a completed population of material verification becomes structured and manageable, in assessment centered around the RoMat PGS service, where each contrast to a ‘blind’ approach of collecting data and attempting to data point represents the strength value determined for each pipe, piece it together without context. and populations are colour-coded. The power of incorporating Establishing these populations can be challenging where strength data into the population assessment is seen in the construction records have been lost, meaning unknown pipe section between 120 000 m and 150 000 m: two pipe populations have been mixed together during construction, but each pipe can now be accurately separated into the correct population. This finding was only made possible by the incorporation of strength data from ILI. Because the metallurgical factors that determine the sensor response are also key determinants of pipe strength, the RoMat PGS service is able to use algorithms to determine yield strength (YS) and ultimate tensile strength (UTS) values for each pipe. In Figure 1, the reported strength values from each pipe can be immediately compared against the expected pipe grade of X52 (L360) to identify areas that Figure 1. Measured yield strength by log distance, colour-coded by population. clearly exceed requirements – as well as areas on which to focus additional testing and inspection. By considering the distribution of strength values within each population, a single ‘bestfit’ pipe grade can be assigned to each pipe population. For unknown or undocumented pipe populations, doing so provides valuable information without having to conduct excavations or remove pipe for destructive testing. pipeline.

Integrating integrity threats

Figure 2. Features reported by EMAT-C, aligned with RoMat PGS populations.

World Pipelines / JUNE 2021

By integrating feature data reported by ILI with information about the assigned populations, trends may be identified with respect to each population’s susceptibility to different integrity

threats. Susceptibility to certain integrity threats may be a function of the pipe population, depending on, for example, the deployed steelmaking and manufacturing processes or the seam type. Secondary factors such as coating type and quality may also be linked to different populations. In this case study, the locations of crack-like features determined by ILI (circumferential EMAT) are shown in Figure 2 by dashed lines, overlaid and colour-coded to match the pipe population within which they are Figure 3. Annotated locations of completed material verification testing. contained. The vast majority of cracklike features are located within the blue and orange populations, and it is Testing and inspection therefore critical to establish accurate toughness data for these Although multiple parameters and material properties are populations. Conversely, other populations contain no features, generally grouped under the term ‘material verification’, different so removing pipes from service for testing would provide little approaches are necessary to verify each of these. This is why it is benefit. essential to first understand what properties must be collected Other integrity threats such as metal loss can also be and in what locations. aligned. By overlaying all integrity threats, susceptibility can ILI provides the only solution for measuring data on every be defined in terms of specifically affected populations. This pipe, making it an essential tool for deployment in piggable means an optimiSed strategy for testing and inspection can be pipelines. The use of ILI to measure diameter and wall thickness implemented to close out gaps in the data required to support a is well-established. The use of ILI to measure pipe grade is fully representative assessment of these features.

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a novel technology, and the extent of validation required is dependent on a number of factors. Whether the pipe is seamless or welded can be identified reliably by ILI, but if the specific weld type must be identified, then validation is required for each undocumented population. Populations, material properties and attributes determined by ILI can be used as standalone data where appropriate. Where required, the ILI data can be refined and supplemented using testing and existing data from records. Non-destructive testing techniques that can be used to measure properties and attributes in excavations are now established technologies, including the measurement of YS and UTS. The most established techniques (Frontics IIT and MMT HSD) provide yield strength measurements that have proven accuracy evidenced in literature and joint industry studies. Although destructive testing will always be the most accurate method, these non-destructive techniques are extremely valuable in establishing pipe grade where removing pipes from service is impractical. There is currently no commercially available non-destructive technique able to measure toughness, but there are active efforts in the industry to realise this technology.

Bringing it all together Maximum value is obtained when considering testing and inspection data with respect to the pipe populations. In this way, efforts are most efficiently directed to risk reduction instead of duplicated or misplaced. With respect to this case study, in Figure 2 it was established that the blue and orange populations contained numerous crack-like features, with two features

reported in the green population and no features identified in other populations. Destructive and non-destructive testing was implemented opportunistically at locations shown in Figure 3. Non-destructive data was used to characterise and evidence the differences between the different pipe materials. Destructive data was collected at locations shown by the black squares; by collecting data from only three locations, toughness data was established to support the populations that contain all crack-like features detected in the pipeline. Tensile testing was also used to validate that each of these three populations, which constitute the vast majority of the pipeline length, exceeds the expected grade of X52 (L360). Leveraging the population approach has significantly improved pipeline knowledge and reduced risk with only three data points. Continued testing over time will further establish the distribution of properties within each population.

Summary Through a combined approach using records review, ILI, population assessment, alignment of integrity threats and testing, an optimised approach can be implemented to verify pipeline material properties and attributes. For piggable pipelines, significant advancements can be made in the understanding of the pipeline and its material properties using ILI combined with only a handful of tests at excavations or from cutouts. Building on this foundation, further testing gathered opportunistically over time can lead to the attainment of in-depth knowledge and data supported by a defined statistical confidence for critical pipe populations and, where applicable, the achievement of regulatory compliance through an efficient and optimised strategy.

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Carey Aiken, Online Electronics Limited, UK, explains how the utilisation of monitoring, testing and logging technologies at each stage of the precommissioning of a subsea pipeline can provide assurance, mitigate risks and ensure that vessel time and schedule is maintained.

s we know, when it comes to subsea pipeline precomissioning, maintaining vessel schedule is key to a successful campaign and mitigating unforeseen project costs. It is vital that a successful operation or test is quickly confirmed, allowing the contractor to proceed to the next stage. There is also the potential for setbacks to occur – how quickly these setbacks are identified and resolved will determine the impact they have. Therefore, it is vital that real-time

information and data is available, to allow for informed decisions to be made and for the precommissioning to be carried out on schedule.

Online Electronics Limited has been supporting subsea pipeline operators and contractors for 25 years with technology designed to provide and collate the necessary data at each of the stages explored in this article.

Flood and clean

Figure 1. 4000SD Subsea Magnetic signaller deployed on an ROV cradle.

Figure 2. Electromagnetic receiver software facilitates the pig locating process.

Figure 3. EMRx Subsea – diver or ROV held multifrequency receiver.

World Pipelines / JUNE 2021

During the flooding and cleaning of a newly laid pipeline – in addition to how efficiently and effectively the line is cleaned and prepared for the hydrotest – it is vital that the chosen pig train design allows for uninterrupted travel through the pipeline and into the subsea receiver. Strategically placed pig signallers and a suitable pig locating and tracking system ensure that you can quickly, and with confidence, identify when the pigs have been launched, received or, in the worst-case scenario, locate a stationary (lost) pig at an unknown location, thankfully not such a common occurrence during pipeline pre-commissioning. The most frequently carried out pig locating operation during precommissioning is confirming the pig train has been successfully launched and then received. This can be achieved by installing a magnetic pig signaller at the pipeline receipt end. Online’s range of magnetic signallers use a two stage detection algorithm, which provides additional assurance that the pig has safely passed the location in question – it does not signal a PIG PASSAGE until the required flux level has been detected and has dropped by a preset amount. This can be critical to ensure all pigs are launched or received, thus preventing lost time in over pumping or having to use other means to identify where a pig is. If the receiver is subsea, a magnetic subsea signaller with an acoustic link allows the vessel to ‘listen’ for the pig receipt, meaning an ROV does not need to be positioned at the receiver, providing both assurance and cost saving flexibility. In certain circumstances, pre-deployment testing should be carried out, for example where the design of the pig, due to pipeline geometry, means that comparatively small (and consequently less powerful) magnets are fitted and/or the wall thickness of the pipeline is particularly ‘heavy’. This can be performed simply by using a mandrel with the appropriate magnets fitted (or even the pig without the discs) and then pushed/pulled through a pipe section. The user can set up the correct threshold using Online’s data review capability and thus maximise the equipment capability for the task at hand by optimising the settings for use. For an added level of confirmation, the exact location of individual pigs can be confirmed using a pig locating system such as Online’s EMTx Multi-frequency Transmitters and EMRx range of receivers and associated software, allowing the operator to promptly move on to the next stage of the precommissioning process. Confirming a stationary pig in the receiver is a relatively routine task but locating a pig at an

unknown location, although not commonplace, is more problematic and could have severe cost implications, particularly for subsea operations. With an EM system, detectability can be improved by considering, prior to project commencement, factors such as pipeline diameter, wall thickness and pig design and transmitter parameters such as output power, pulse rate and length and frequency. These parameters can all influence the detection envelope of the transmitter and the time taken to locate the pig. In a recent project, Online was able to trial a five pig train in a 13 m, 36 in. nominal bore pipeline with a wall thickness of 31.8 mm. The five EM transmitters were installed inside a dummy pig mandrel within the pipeline and each transmitter was configured with a different frequency. The main objective was to guarantee the maximum signal levels at the launcher and receiver, and prevent signal loss in case the transmitters were required as a contingency. With the optimum frequency arrangement, customised pulse rates and power output and the battery life being equal throughout, the receiver was able to detect the maximum signal level without turning the gain too high and running the risk of saturation or noise interference.

Gauging During flood, clean and gauge operations a gauging pig is often used to evidence the pipeline is laid according to the relevant standard. A standard gauging pig will advise you of the presence of a pipeline ‘intrusion’ – likely due to a problem experienced during lay, or a freespan that could lead to the necessity of running a caliper pig to obtain additional information on the position and type of defect before you can perform the necessary repair. Unscheduled operations of this nature are clearly expensive and all mitigation methods possible should be considered. In the event of no pipeline intrusion, the gauging pig still must be recovered to obtain this information, an operation that requires valuable vessel time. An alternative and potentially more cost-effective solution is to run a gauging system that includes a connection to an acoustic pinger or electromagnetic transmitter such

as Online’s Gauging Run Integrity Data (GRID®) system. The GRID transducer monitors the condition of the gauge plate and reports this information remotely by transmitted coded pulses. These pulses are decoded using dedicated software and will provide information on whether the gauge plate is a ‘PASS’ or ‘FAIL’ along with the time that any defects occurred. When compared with pumping data, this can give an approximate position of the defect without the added time and expense of a caliper pig run. Additionally, this assurance can be received without having to recover the pig to inspect the gauge plate, meaning that the operator can immediately start the hydrotest.

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Another advantage of using a pressure and temperature logger is that a successful hydrotest can be confirmed by one of the methods discussed above without needing to recover the unit.

Dewatering

Figure 4. 6000SD displaying status of a 24 hour hydrotest.

Figure 5. MEG ARTS Analyser and Sampler – confirm successful pipeline conditioning in real-time.

Hydrotest As is the case with the flood, clean and gauge phases, the aim during the hydrotest is to receive assurance of a successful test and to quickly move on to the next stage, whilst minimising vessel time and costs. Online’s 6000SD monitors, displays and records pressure and temperature data that can be observed for changes by an ROV or diver viewing the display, or by remote communication using an acoustic pinger, data transducer or strobe. In this way a vessel does not have always have to be on-hand but can still monitor the progress of the hydrotest. As the unit is logging the pressure and temperature information, the ROV, vessel or diver can perform associated tasks in parallel. This results in accelerated completion of work and potential cost savings and project flexibility. Additionally, the 6000SD can autonomously examine the data obtained in a set ‘test period’ such as 24 hours and display the time and date at which the hydrotest passed. Recent advances in technology mean that the data is continually monitored by the 6000SD firmware to match the client’s acceptance criteria, whether that is the pressure has remained above the threshold (for the expected time period), or that less than the permissible pressure decrease has occurred over the selected time period.

World Pipelines / JUNE 2021

Critical pipelines, typically those that transport gas, are often dried and conditioned with monoethylene glycol (MEG) in readiness for hydrocarbons. Obviously, a pipeline is only conditioned correctly if conditioned throughout. Verifying this can be a time-consuming process and it is often close to the start-up of hydrocarbon production and transportation, hence real time assessment of, and confidence in, dryness is critical. A lack of real-time readings and the reliance on theoretical data and/or analysis of sampled MEG carries associated vessel time and cost. Online’s MEG ARTS® Analyser and Sampler measures the density of flowing MEG (or other chemicals) at the receipt end of the pipeline and displays and logs this data along with pressure and temperature. This provides a real-time account of the progress of the dewatering operation and conformance with project purity, dryness or hydrate suppression requirements. Most importantly it verifies that MEG has conditioned the entirety of the pipeline, providing assurance that the planned pipeline integrity programme can commence once hydrocarbon transportation commences. The operator may still wish to receive samples for an additional level of validation or as supporting evidence alongside the logged data. Up to seven samples can be taken by ROV from specified positions in the train with a single switch, without the need to move between different valve locations. When practical, there is an opportunity to reduce costs further by taking automatic samples at predetermined density levels. This eliminates the need for a vessel at, or transit to, the receipt location.

Assurance By definition, assurance means ‘a positive declaration intended to give confidence; a promise’. In time critical schedules with multiple challenging activities ongoing simultaneously, assurance is more important than ever. Using as many positive assurance steps as possible in any process is sensible, however they must be practicable and a good use of time. Recent and imminent developments in equipment for subsea precommissioning have met this challenge. Each project has its own conditions and requirements, occasionally needing custom designed solutions to achieve the necessary level of assurance. With an experienced in-house R&D team and a commitment to continual innovation, Online Electronics has the capability to undertake bespoke projects and the flexibility to modify existing equipment to suit client specific needs.

Michael Kasch, ILF Consulting Engineers, Germany, explores an example study demonstrating the impact of hydrogen blending on the transport capacity of natural gas pipelines.

ipelines can be optimally designed for transport of pure hydrogen. Existing pipelines can be redesigned and modified to meet the requirements for transporting pure hydrogen. If the available quantities of hydrogen do not match the dimensions of existing long-distance pipelines or backbones of distribution networks for simply replacing natural gas by hydrogen, the alternative option is blending hydrogen into the gas stream. This article outlines results and conclusions of numerical investigations on the transport capacity of high-pressure gas pipelines if hydrogen blends up to 30 mol% are conveyed. The following example pipeline (Figure 1) was used to cover typical and partly challenging conditions

like offshore sections and substantial alterations of elevation. Fluid flow through pipelines is determined by the three conservation laws for ‘mass’, ‘momentum’ and ‘energy’. Combined with equations describing the physical properties of the fluid, these conservation laws form a set of equations to be solved simultaneously

Figure 1. Pipeline elevation profile.

Figure 2. Transport capacity loss with increasing hydrogen fraction.

World Pipelines / JUNE 2021

for the calculation of pressure, temperature and flow profiles along pipelines. The additionally required fluid properties are ‘density’, i.e. a thermodynamic equation of state (EOS), ‘specific heat capacity’ (c p), and ‘viscosity’. All three of these parameters are functions of pressure and temperature (for given gas composition) showing significant real-gas behaviour at pressures and temperatures usually required for efficient transportation of natural gas through pipelines. Furthermore, the characteristics of the conduit (pipe, coatings) and its ambient (e.g. soil, water currents, air) as well as the elevation profile have substantial impact on the thermohydraulic state of gas flow through pipelines. The fictive example pipeline profile depicted in Figure 1 is a 200 km pipeline of 0.9 m external diameter, 20 mm wall thickness and with internal (epoxy) and external (HDPE) coatings yielding an effective radial heat transition coefficient of 3.9 W/K m 2 everywhere, i.e. no specific parameters for varying hydrological and geological conditions onshore and offshore considered here. It is only the ground temperature that varies from section to section in this example (see Figure 3). For all numerical calculations of this example the boundary conditions were given by an inlet pressure of 100 bar(g), inlet temperature of 40˚C (313.16 K) and an outlet pressure of 50 bar(g) at pipeline end. The intention of this paper is to investigate transport capacity losses under heavy load conditions on a highpressure gas pipeline carrying hydrogen blends. For the 200 km pipeline the selected pressure differential of 100 bar(g) down to 50 bar(g) represents challenging boundary conditions. Transport capacity is here defined as the maximum norm volume flow rate that occurs for given inlet and outlet pressure and given inlet temperature. An alternative definition for capacity losses would be the norm volume flow rate multiplied by the (net or gross) calorific value of the gas mixture. Norm conditions were chosen as atmospheric pressure and 0˚C (273.16 K). All thermodynamic parameters were taken from ‘Physical Properties of Natural Gases, N. V. Nederlands Gasunie, Groningen (1988)’. This includes a real-gas equation of state after Benedict, Webb and Rubin, as well as real-gas specific

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heat capacity and viscosity for natural gas mixtures. Flow-induced friction was calculated after Colebrook and White with a roughness of 6µm. More details of the numerical model or a more sophisticated equation of state are not important for this article, as the intention is to demonstrate principle aspects of the limiting factors on pipeline transport capacity for hydrogen blends with natural gas.

Findings and conclusions

Figure 3. Temperature profiles (pure nat. gas vs. blend of 30 mol% with/without cooling).

Figure 4. Joule-Thomson inversion curves relative to the p-T operating regime.

World Pipelines / JUNE 2021

Two natural gas types were investigated to demonstrate the impact of gas composition on the transport capacity: typical Russian natural gas (RU), rich of methane, and typical Groningen (NL) natural gas with weigh less methane due to approximately 14 mol% of nitrogen. The blue curves in Figure 2 show the capacity gap between RU and NL natural gas for the given boundary conditions. The capacity gap between RU and NL natural gas turns out to be 7% for pure natural gas to 6% at 30 mol% hydrogen fraction. The capacity loss caused by hydrogen blending of 30 mol% was found to be approximately 8% for both gas types. The reduction of transport capacity with increasing hydrogen fraction is on the one hand a direct consequence of the generally reduced density of hydrogen blends relative to pure natural gas. But this is emphasised by the fact that the temperature along the entire flow path remains higher with hydrogen blends than for pure natural gas, which leads to even lower density. Figure 3 shows the temperature profiles of the example pipeline (Figure 1) for pure RU natural gas (blue curve) in comparison with a blend of 30 mol% (red curve). Increasing outlet temperatures with successively growing hydrogen fraction are illustrated in Figure 2. Just to get an idea of what this means in terms of energy transport; in this example the loss of transport capacity with 30 mol% of hydrogen relative to pure RU natural gas turns out to be 133 380 Nm3/h (or 383.2 t/h) which corresponds to a reduction of delivered calorific energy of 4.826 GWh/h (4.208 GWh/h net), obviously worth being regained. A combination of the energy and the momentum equation yields the basis for calculating the temperature profile of a pipeline. Mainly three effects determine the gas temperature profile along the pipeline: the general tendency of the gas temperature equilibrating with the ambient due to radial heat exchange; frictional heat production; and the Joule-Thomson effect. For ordinary natural gas under usual pipeline operating conditions

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the Joule-Thomson factor is positive. Thus, the gas stream is being cooled while the gas is flowing towards lower pressure. However, with increasing hydrogen fraction the Joule-Thomson factor of the blend is changing sign, thus heating up the gas stream in flow direction (cf. Figure 4). All three effects are superposed. Depending on the conditions the long-distance equilibrium temperature can therefore be distinctly above or below the ambient temperature. Figure 3 shows two such cases. The long-distance temperature of pure natural gas is distinctly below, whilst the temperature of the 30 mol% hydrogen blend is everywhere above the ambient temperature. One option to improve the transport capacity for hydrogen blends would be increasing the density of the gas stream by cooling. Considering two intermediate coolers, one at 110 km, the second one further down at 160 km, and applying the rule of thumb that the electrical power to feed the cooler can be estimated at 1% of the thermal power that has to be extracted from the gas stream, they would need approximately 100 kW and 60 kW of electrical power for cooling down to 5˚C. Not to forget the cooler at the inlet (km 0) which would require an additional 180 kW of electrical power to cool the inlet gas stream down to 15˚C instead of 40˚C. Of course, all cooling temperature values in this example may not be achievable under all regional and seasonal ambient conditions. In total the example values used here would result in 0.34 MW of electrical cooling power. Compared to the uncooled case of the 30 mol% blend we would regain transport capacity of 5765 Nm3/h or 46.4 MW net calorific power (50.8 MW gross). Thus, even electrical cooling would pay off, at least from the OPEX point of view. The Joule-Thomson factor itself is pressure and temperature dependent. The curves with markers in Figure 4 are the Joule-Thomson inversion curves, i.e. those tuples ‘p,T’ where the Joule-Thomson factor is zero: µJ.T. = 0. Left of each inversion curve we find normal Joule-Thomson behaviour of decreasing temperature with decreasing pressure (µJ.T. > 0), i.e. cooling the gas stream in flow direction. Right of each inversion curve is the region where the Joule-Thomson factor is negative (µJ.T. < 0) which causes raising temperature with decreasing pressure, i.e. heating up the gas stream in flow direction. The magenta dotted frame shows the operating envelope (of this example) with respect to pressure and temperature along the pipeline. The curves inside this frame are temperature profiles, not plotted as usual against distance but against the pressure values along the pipeline, starting at 100 bar(g) down to 50 bar(g), from the right to the left. The curves with equal colour belong together. The blue (30 mol% H2) and the red (20 mol% H2) p,T-curves are entirely located right of the blue and the red Joule-Thomson inversion curves. This means that the Joule-Thomson factor is negative (µJ.T. < 0) along the entire flow path. Thus, the temperature tends to be high. The green (10 mol%) p,T-curve intersects with the green inversion curve. Only that portion of the green p,T-curve left of the green inversion curve

World Pipelines / JUNE 2021

experiences the ‘usual’ Joule-Thomson behaviour. Obviously, the temperature is not further increasing like the blue and the red p,T-curves do there. Finally, the magenta p,T-curve (5 mol%) is entirely left of the inversion curve of the 5 mol% blend. Thus, at 5 mol% the gas stream experiences normal Joule-Thomson behaviour all the way down the pipeline. Obviously, the temperature profile close to the outlet points downwards as usual. The lower the pressure range the lower is the capacity loss for given hydrogen fraction. If a pipeline is e.g. operated at medium pressure, e.g. 5...25 bar(g), the hydrogen fraction of the blend may be higher than 10 mol% without capacity loss caused by the inverted Joule-Thomson effect; the capacity loss due to the a priori reduced density remains, of course. This becomes obvious when shifting the dotted frame to the left and adjusting the pressure range to, in this example, 5…25 bar(g). The whole frame is then left of the inversion curve of 10 mol% and the thermodynamic behaviour of the blend is as usual. The higher the pressure, the stronger the adverse impact of hydrogen blending on transport capacity.

Summary High pressure is necessary to establish cost efficient transport through gas pipelines. Where transport of pure hydrogen is no option, e.g. if the existing pipelines shall be used but are not optimally dimensioned for the available quantities of hydrogens, blending with natural gas can be an option. However, such gas mixtures may cause substantial capacity losses in terms of throughput and energy delivery. Increasing hydrogen fraction is directly reducing the mass density and the energy density of the blend. The effect turns out to be more and more pronounced with increasing hydrogen fraction and even more the higher the operating pressure of the pipeline is. One way out of this dilemma would be utilising all opportunities for natural cooling of the gas flow along the pipeline. Otherwise, the capacity losses can be so significant that even additional technical cooling (e.g. electrical coolers) would pay off. All sensible options of cooling the gas stream should be considered. Design of pipelines for transport of natural gas blends with hydrogen should include prudent analysis and evaluation on the intended pressure and temperature regime relative to the specific Joule-Thomson inversion curves of the blend to be conveyed (as presented in Figure 4). The same applies to design calculations for gas processing, such as pressure reduction through control valves or vent lines and silencers. Whenever isenthalpic processes are involved the designer should be aware of where in the p-T plane the process is to take place relative to the individual Joule-Thomson inversion curve of the blend. As long as the Joule-Thomson coefficient is positive, everything will behave as usual. If parts of or the entire operating regime are located in areas of the p-T-plane where negative Joule-Thomson coefficients occur we might experience unusual thermal behaviour of the gas stream.

Julien Mouli-Castillo, the University of Edinburgh, Derek Muckle, Radius Systems Ltd, and Angus McIntosh, SGN, UK, detail an investigation into time dependant failure modes in polyethylene systems used for hydrogen gas distribution.

educing greenhouse gas emissions associated with domestic heating is a challenge. Many countries, such as the UK, Germany, Russia and the USA, rely heavily on natural gas as a source of domestic heat (Staffell et al., 2019). In 2018, natural gas contributed to over 20% of the global CO2 emissions.1 It is therefore imperative to reduce the emissions from the domestic heat sector to meet international and national decarbonisation targets. SGN is a UK Distribution Network Operator transporting gas to nearly 5.9 million homes and businesses across Scotland, the south of England and Northern Ireland. SGN are undertaking a world leading project ‘Hydrogen 100’, seeking to demonstrate that hydrogen can provide a safe, reliable, and affordable way of decarbonising domestic heat with minimal disruption for the end user. The project aims to deliver hydrogen for heating and cooking to 300 households via a purpose-built new polyethylene hydrogen distribution network. Hydrogen is considered as an essential part of the decarbonisation strategy in the UK and Europe, with many government and industry roadmaps including some degree of conversion from natural gas to hydrogen. A key aspect of achieving a successful conversion to hydrogen is to determine and understand how existing polyethylene pipes and materials react to hydrogen. H100 encompasses a broad safety assessment programme investigating this very aspect, along with other essential ones such as hydrogen odorisation and detection. The outputs from this extensive experimental programme will feed into risk assessments underpinning the safety case for the project. In this article the results from the time dependent failures of polyethylene pipes and materials are reported.

Polyethylene lifetime assessment One of the core aims of the programme is to demonstrate that a reliable lifetime of at least 50 years can be achieved with polyethylene pipe systems distributing hydrogen gas. To achieve this aim the programme tested polyethylene pipes and methods of welding, such as butt and electrofusion techniques. To this end, a unique test facility was constructed to perform accelerated ageing tests over an 18 month period to simulate a minimum asset life of 100 years.

A unique test facility At the outset of the study it was clear that facilities did not exist for the testing of pipe and fitting assemblies with intent to determine lifetime failure characteristics, specifically with hydrogen as the test medium. A bespoke facility has therefore been designed, built and commissioned to enable failure of pressurised pipe samples to be safely managed – containment of hydrogen gas as pipe samples fail at high pressure and random time intervals. Safety being a key aspect, risks arising from the facility were mitigated by performing successive levels of oversight. These include the Health and Safety Laboratory being involved in the test rig design team to embed safe work procedures

in the design; PHY and KIWA Gastec, both independent hydrogen equipment experts, performed a peer review of the design developed by Radius Systems. Affected stakeholders, primarily emergency services, were informed and liaised with during the development of the facility.

Time dependant failure modes As a viscoelastic material, polyethylene is subject to a range of failure modes which depend on time, temperature and stress applied to the material. The three main time dependant failure

Figure 1. Pipe sample.

modes occurring in pipeline systems cover ductile rupture, environmental slow crack growth and oxidation. Ductile rupture occurs when there is too much pressure in a pipe. This leads to the material stretching and yielding. There is a slight reduction in the strength of material over the lifetime of the material due to the polymer chains moving in response to the applied loads. At lower stress (lower pressure) and longer times, small defects in the material’s structure can lead to slow growing stress cracks developing. Finally, after much more time has elapsed, and independently of the applied stress, oxidation will occur. For natural gas systems, oxidation is not expected until at least half a millennia into the future. One characteristic of polyethylene is that increasing temperature results in a reduction in applied stress and time needed to create failure. The effect also satisfies a well proven Arrhenius principle which allows elevated temperature testing in short times to predict performance at lower temperatures over much longer times, the principle of accelerated lifetime tests. Using Arrhenius principles, and shift factors, testing over 1 - 2 years at 80˚C can inform performance at 20˚C some 50 - 100 years into the future. These failure modes are applicable to pipes, butt fusion welding and electrofusion welding. Butt fusion welding is the process whereby two portions of pipes are welded together by having their edges melted and pressed together using specified temperatures and pressures. Electrofusion welding on the other hand, involves two pipes being welded together by inserting both pipes into a sleeve through which an electric current is applied, welding the sleeve to the pipes. It should be noted that gas industry assets are never operated close to the failure points identified during testing. Knowledge of failure is used to establish safety factors and ensure assets operate reliably and predictably.

Method of assessment

Figure 2. Venting of individual hydrogen pods.

Figure 3. Test rig pod set up. Contains heated water control and gas pressure and flow control.

World Pipelines / JUNE 2021

Failure by ductile rupture and stress cracking is evaluated by an experiment performed on samples composed of a 32 mm pipe section of 2018 manufacture, complying with GIS/PL2 requirements. An electrofusion fitting is added at one end of the pipe, and a butt fusion joint at the other. Furthermore the butt fusion joints have been purposefully offset and the electrofusion fitting welded using the minimum weld energy allowable. This ensures that worst case conditions are assessed. A spigot fitting is also present to allow the pipe and fittings to be pressurised with hydrogen. This entire system is placed inside a metallic containment tube with water between the two elements. The metallic tube is the placed inside a test pod which contains a water bath allowing for controlled temperatures of either 20, 60 or 80˚C. Oxidation is evaluated by oxidation induction time (OIT) tests. OIT is a measure of the resistance of a material to oxidising actions by the transported fluids. Testing has been conducted on baseline samples not exposed to ageing, on samples aged in water, and samples aged in the presence of hydrogen. All tests are performed to assess the bore of the pipe which is the most affected area. The tests include a comparative assessment in which some of the samples were pressurised with water, when others were pressurised with hydrogen. This provides a benchmark.

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The tests carried out provide encouraging results that show the strength of polyethylene pipe systems are not degraded by exposure to hydrogen. This conclusion is reached after testing with hydrogen at temperatures of 20˚C and 80˚C for periods in excess of 5000 hrs (simulating lifetimes in excess of 50 years). The tests are conducted at pressures and durations that ensure hydrogen has fully permeated into the structure of the pipe and fittings used for the tests. Initial findings from testing at the two temperatures have been assessed using a method known as ‘bi-directional shift factors’ to extract the long-term preliminary findings. Further testing at a third temperature in the future will provide additional confidence in the findings. Nonetheless, the strength of the polyethylene pipe has been at a least the same as that measured by the benchmarks performed with water, and in some cases it appears to be perhaps stronger in the long term when considering the surviving samples still on test. These results hence provide the first evidence to confirm that with the application of existing safety factors, the preliminary calculation for pressure rating of polyethylene pipes and fittings would be equivalent to natural gas-based installations. From a design lifetime perspective, the results from testing for 5000 hours at 80˚C complemented by an analytical assessment using ‘shift factors’, show that no change to a brittle like slit defect (i.e. stress cracking) would be expected as a result of exposure to hydrogen. This provides the second conditions to support and evidence a finding that a minimum reliable operating lifetime of at least 50 years can be expected, not just for the pipe but also for butt fusion welds and electrofusion fittings. In relation to the third stage failure, onset of oxidation, evidence from related studies showed no detectable reduction in oxidation stabilisers after 4 years exposure to hydrogen. It would be expected that in the long term, for example more than 100 years, that some measurable degradation would take place. It is clear, and evidenced in the test work performed, that some degradation takes place using accelerated tests. By comparing test results achieved in tests with hydrogen, to baseline samples in chlorinated water, it is clear that the hydrogen samples can reasonably be expected to be measured in hundreds of years before failure onset due to oxidation.

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The data presented is the first of its kind to explore the likely longterm performance of polyethylene pipes and their welded joints subject to constant exposure to hydrogen. Within this analysis there is evidence to support the anecdotal opinions of experts in this field, together with confidence that a long reliable lifetime can reasonably be expected. The work reported relates to materials currently used for mains replacement programmes in the United Kingdom and is used as quantitative evidence to support a safety case for construction of new networks to carry hydrogen. In the future though, the methods and facilities developed can be used to assess older materials to support the need for an evidential approach to repurposing older, existing, networks.

Reference 1.

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World Pipelines June 2021

Articles inside

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Checkmate to corrosion

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Precommissioning: ticking every box

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