World Pipelines April 2022

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Volume 22 Number 4 - April 2022

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POWER

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CONTENTS WORLD PIPELINES | VOLUME 22 | NUMBER 4 | APRIL 2022 03. Editor's comment 05. Pipeline news

37. Avoiding cable failures

Harvey Hancock, Gripple Limited, UK.

Updates on TAP transport, global oil and gas contracts activity, and Russia relations.

PIPELINE COATINGS 43. Coatings Q&A

KEYNOTE ARTICLE: REGULATIONS AND COMPLIANCE 10. Don’t gamble with your audit

Steve Crawley, Group Technical Director and Andrew Stuart, Sales & Marketing Director, Winn & Coales (Denso) Ltd.

Carin Meyer, Regulation Compliance Programme Specialist, Atmos International, USA, talks through a holistic view of what pipeline operators need to consider for passing a pipeline leak detection audit.

HDD 46. Safe and successful horizontal directional drilling

PIPELINE

Raelison Novaes, Michels Corporation, USA.

Though horizontal directional drilling (HDD) is considered the most effective pipeline installation method, Raelison Novaes, Michels Corporation, USA, suggests there are still significant risks to address.

L

eak detection is a vital consideration for running a pipeline safely, though regulation compliance is not always an easy aspect of pipeline integrity management (PIM) to navigate. The regulations are unique for each country and in the US, compliance requirements may differ even from state to state. The challenges surrounding audits have been further complicated in recent years by the COVID pandemic. With the emergence of virtual audits or information requests, posing risks to the audit due to difficulties in communication and information interpretation without the face to face discussions. Here we’ll cover the essential considerations of a pipeline leak detection regulation audit. We’ll explore: ) The purpose of an audit.

C

reated in 1956 by construction of the Garrison Dam on the Missouri River, Lake Sakakawea is part of a flood control and hydroelectric power generation project in North Dakota. With a length of 285 km, an average width of 3 - 5 km and a maximum width of 23 km, Lake Sakakawea limits the ability to transport natural gas takeaway from the Bakken Formation in northwest North Dakota to pipeline interconnects to the southeast. As a result, the existing infrastructure was not sufficient to meet transportation needs for the natural gas produced during the crude oil extraction process. Faced with costly and inefficient options of building hundreds of kilometers of pipeline around Lake Sakakawea or transporting liquid natural gas around the lake in tanker trucks, much of the

) Having the right documentation. ) Preparation and human considerations. ) Why the stakes are so high. ) How the right pipeline compliance service partner can help.

Preparing for an audit can be daunting for pipeline operators, considering these areas regularly will help embed compliance into your organisation’s culture, as required to meet the regulations.

The purpose of an audit

natural gas was safely burned as a flare to prevent release of hydrocarbons directly into the atmosphere. Already transporting half of the natural gas produced in the Bakken region, WBI Energy, Inc. (WBI), a subsidiary of MDU Resources Group, Inc., contracted Michels Corporation in 2021 to build the transmission pipeline and trenchless segments of its North Bakken expansion project. Michels is an energy and infrastructure construction company based in Brownsville, WI and serves customers throughout the world. According to WBI, the North Bakken expansion project was designed to provide up to 250 000 dekatherms per day (Dth/d) of firm transportation service from receipt points in the Williston Basin of northwest North Dakota and near WBI’s existing Tioga

Audits are designed to assess a company’s compliance with legal and regulatory requirements. Pipeline leak detection audits help to ensure that pipeline operators are compliant with the stringent safety requirements of liquid and gas pipelines. The requirements help to protect people and the environment from the potential damage caused by pipeline leaks and ensure that the right systems and processes are in place. Audits often consist of three stages: ) Pre-site visit activities. ) Onsite activities. ) Post-site activities.

These stages require pipeline operators to gather the right information, complete documentation (such as audit checklists) and where required, provide additional information at the auditor’s request.

Carin Meyer, Regulation Compliance Programme Specialist, Atmos International, USA, talks through a holistic view of what pipeline operators need to consider for passing a pipeline leak detection audit.

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INTEGRITY SYSTEMS 15. When the data aligns

Felipe Freitas (Senior Integrity Engineer), Marcilio Torres (Senior Application Specialist), Taylor Campsey (Pipeline Integrity Engineer), ROSEN USA.

PAGE

Figure 1. Completing a 4702 m horizontal directional drill required a 24/7 effort and the pilot hole intersect method.

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PIPELAYING AND VESSELS 50. Energising ROV capabilities

Mark Wood, Technical Sales Manager, ROVOP.

23. Corrosion challenges

Doug Sinitiere, Carboline, USA and Holly Tyler, Specialty Polymer Coatings Inc., USA.

27. Maintaining integrity of your ‘hidden assets’

Iain Rennie, Operations Director, Asset Guardian Solutions Ltd, UK.

DAMAGE AND DEFECT ASSESSMENT 31. Enhancing the efficiency of pipeline mapping Nicholas Duggan, Chief Technology Officer, The Carto Group, UK.

PIPELINE SERVICES 33. More savings, no emissions

Rolf Gunnar Lie, Regional Business Development Manager, T.D. Williamson, Asia Pacific.

®

Volume 22 Number 4 - April 2022

For over 30 years, 3X ENGINEERING (3X) has been a world leading company specialising in pipeline maintenance using composite technology. Mainly operating in the oil and gas industry, 3X expertise also extends to the power and construction sectors. As developer, manufacturer, seller and installer of our products, we offer to our clients a complete, integrated service. From our head offices in Monaco, we operate worldwide, in any environments (onshore, offshore and subsea), thanks to our large qualified distribution network of over 60 partners. For more information, visit www.3xeng.com

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Introducing the Palladian Energy Podcast Series 1: Digitalisation in the oil and gas sector


EDITOR’S COMMENT CONTACT INFORMATION MANAGING EDITOR James Little james.little@palladianpublications.com EDITORIAL ASSISTANT Sara Simper sara.simper@palladianpublications.com SALES DIRECTOR Rod Hardy rod.hardy@palladianpublications.com SALES MANAGER Chris Lethbridge chris.lethbridge@palladianpublications.com DEPUTY SALES MANAGER Will Pownall will.pownall@palladianpublications.co PRODUCTION MANAGER Calli Fabian calli.fabian@palladianpublications.com EVENTS MANAGER Louise Cameron louise.cameron@palladianpublications.com DIGITAL ADMINISTRATOR Leah Jones leah.jones@palladianpublications.com VIDEO CONTENT ASSISTANT Molly Bryant molly.bryant@palladianpublications.com ADMIN MANAGER Laura White laura.white@palladianpublications.com Palladian Publications Ltd, 15 South Street, Farnham, Surrey, GU9 7QU, UK Tel: +44 (0) 1252 718 999 Website: www.worldpipelines.com Email: enquiries@worldpipelines.com Annual subscription £60 UK including postage/£75 overseas (postage airmail). Special two year discounted rate: £96 UK including postage/£120 overseas (postage airmail). Claims for non receipt of issues must be made within three months of publication of the issue or they will not be honoured without charge. Applicable only to USA & Canada: World Pipelines (ISSN No: 1472-7390, USPS No: 020-988) is published monthly by Palladian Publications Ltd, GBR and distributed in the USA by Asendia USA, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid New Brunswick, NJ and additional mailing offices. POSTMASTER: send address changes to World Pipelines, 701C Ashland Ave, Folcroft PA 19032

I

n late March, the US Federal Energy Regulatory Commission (FERC) announced a change of direction in relation to two recent policy statements on natural gas pipelines and infrastructure. The policy statements in question, which were issued in February, were set to change how natural gas pipelines are approved by the commission. The commission would be required to determine whether a project is needed SENIOR EDITOR Elizabeth Corner to meet the energy demands of a given elizabeth.corner@palladianpublications.com region, and whether it is in the public interest. The statements essentially brought additional climate and environmental scrutiny to new fossil fuel projects. Now, FERC has voted unanimously to change the status of these policy statements (by downgrading them to drafts) and will solicit input and consider changes to the policies. FERC has also agreed that any changes that are ultimately made to its policy statements will not be applied to projects that are already pending, and it also approved three pending pipeline projects. In support of the changes, the American Gas Association said that “left unrevised, the 2022 policy statements will actively discourage the development of pipeline infrastructure, reduce reliability, raise consumer costs and create deep uncertainty that will destabilise the competitive markets.” Nations all over the world are faced with re-evaluating their energy security in the wake of Russian aggressions in Ukraine. US Senator John Barosso said: “America and our allies need more, not less, natural gas and natural gas infrastructure. President Biden and his appointees should be working to make it easier to develop and deliver this critical resource. FERC’s decision to step back from its destructive natural gas policy statements is a first step.” The US seems to be hailing domestically-produced natural gas as its trump card. The US Department of Energy (DOE) announced in early March that natural gas is 3.4 times more affordable than electricity and significantly more affordable than several other residential energy sources for the same amount of energy delivered. Looking outwards, the US has announced its willingness to supply the European Union with up to 15 billion m3 of additional LNG by the end of 2022. Europeans must wean themselves off Russian gas, and American gas producers and exporters of LNG could fill that gap. With 14 LNG projects federally approved but not yet built, the US industry could roughly double its exports without the need for major regulatory approval. These projects are awaiting a final investment decision from developers, so some investment is still needed. The European Commission published a proposal to reduce dependence on Russian energy on 8 March, which included plans to increase LNG imports from countries other than Russia, and to increase usage of renewable energy. European nations will need to act quickly to build the necessary infrastructure to receive the gas. Germany has announced plans to fast-track the construction of two LNG import terminals, since placing the Nord Stream 2 pipeline project indefinitely on hold. Europe will look beyond the US though: Qatar is planning an LNG expansion project to be completed by 2025, and Denmark has issued a new environmental permit for the Baltic Pipe gas pipeline (after suspending it last year). The pipeline will transport gas from the Norwegian North Sea to Poland via Denmark.


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WORLD NEWS GlobalData: Long-term uncertainty over Russian oil and gas supplies will sustain high energy prices Moscow’s decision to escalate its eight year conflict in Ukraine has sparked a global energy crisis, says GlobalData’s MEED. The leading data and analytics company notes that the impact of this conflict echoes the 1970s oil crisis that launched the Gulf’s first major economic boom. Richard Thompson, Editorial Director at GlobalData’s MEED, comments: “While the Gulf’s oil producers are keen to avoid taking sides in the Ukraine conflict, long-term uncertainty about Russian oil and gas supplies will sustain high energy prices for a prolonged period and create a renewed focus on Middle East hydrocarbons that will underpin a new economic and projects boom in the Gulf.” The immediate impact of Russia’s invasion of Ukraine was to trigger massive volatility in global capital markets and a spike in commodity prices that has added to the inflation fears already threatening the global recovery. However, the strategic impact of the crisis is to expose Europe’s overdependence on Russian energy, particularly its gas. As a result, the coming months and years will see a strategic realignment of global energy and a European diversification away from Russian oil and gas supplies to alternative sources such as renewables, coal, nuclear and Middle East hydrocarbons.

Thompson says: “In the longer term, unless a peace settlement is reached soon, Moscow’s actions in Ukraine will see Russian oil and gas exports reduced or even blocked altogether from the global energy supply chain. “The scale and pace of the reductions will be shaped by the extent of Western embargoes on Russia’s oil and gas sales, which will further expose Europe’s dependence on Russia.” The mere prospect of oil and gas sales from the world’s third-biggest oil producer and second-biggest producer of natural gas being removed from the international market saw oil prices surge to nearly US$138/bbl on 7 March — their highest mark since 2008, and some 45% higher than at the start of the crisis. High energy prices will be maintained for as long as the conflict continues and Moscow is sanctioned, and for as long as Europe is dependent on Russian energy. In the short term, the surge in oil prices delivers a financial windfall to Middle East oil producers, who will use the money to accelerate post-pandemic stimulus infrastructure in 2022. Over the longer term, with rising inflation creating huge economic headwinds for the global economy, Middle East oil and gas will become increasingly vital to stabilise the energy markets.

DTEK Group calls on Western companies to stop cooperation with Russia in the fuel and energy sector DTEK Group, NJSC Naftogaz of Ukraine and NPC Ukrenergo called on the international business community to stop buying Russian energy resources and stop any supplies of components and technologies for the fuel and energy sector to Russia in an open letter. “We call on all Western companies to stop any cooperation with Russia in the fuel and energy sector. Refuse to buy Russian energy resources and ban the supply of components and technologies there. This applies to all: gas, coal and electricity, as well as the production of engines, turbines, mine and other power equipment,” the appeal says. “Ukrainian energy companies stressed that the Russian Federation has unleashed the bloodiest war on the European continent in the past 80 years. This war claimed the lives of thousands of civilians, including over a hundred children. Some 6.5 million Ukrainians have been forced to leave their homes due

to the continuous bombing of peaceful cities, shelling of residential areas and outright terror. “The only way to stop this war is to deprive the aggressor country of the means to finance it. “A country that deliberately drops bombs on orphanages with children cannot use the technical and intellectual achievements of the civilised world. Every dollar paid to Russia leads to new casualties and destruction,” the letter says. “On behalf of hundreds of thousands of workers in the fuel and energy complex, we urge you to stop supporting the Russian economy until this country stops the barbaric war against Ukraine,” the appeal says. The letter to Western companies has been signed by DTEK CEO Maxim Timchenko, Chairman of the Board of NJSC Naftogaz of Ukraine Yuriy Vitrenko and Chairman of the Board of NPC Ukrenergo Volodymyr Kudrytsky.”

Report: US oil supply likely to increase Enverus Intelligence Research, a part of Enverus, the leading global energy data analytics and SaaS technology company, has released a new report examining the likely responses by US oil producers, both public and private, to high oil prices and increased concerns about energy security in the wake of Russia’s recent invasion of Ukraine. Included are regions that are likely to boost output and identifies the barriers and costs of adding production. “The E&P industry can grow while remaining profitable and environmentally responsible. Private operators have been and will continue to take advantage of the outsized returns, and Enverus believe continued drilling activity increases

from large US independent are likely and warranted,” said Farzin Mou, Lead Report Author and Vice President at Enverus Intelligence Research. Jen Snyder, Co-Author, Managing Director and Head of North America Macro Intelligence Research, added, “Once operators lock in new long-term midstream and services commitments, they are handcuffed with off-balance-sheet leverage during a price downturn. The trajectory of the 2024 - 25 WTI strip therefore will be an important driver of operators’ 2022 - 23 capital commitments even if wells earn attractive returns by year-end 2023.”

APRIL 2022 / World Pipelines

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WORLD NEWS IN BRIEF

TAP transports first 10 billion m3 of natural gas to Europe

Fraser Well Management (FWM) and Fraser Integrity Management (FIM) have been awarded a contract to provide well and pipeline operator services by Bridge Petroleum for its Bardolino field. The new contract adds to FWM’s expanding well operator portfolio and is FIM’s debut pipeline operatorship appointment.

The Trans Adriatic Pipeline AG announces that a total of 10 billion m3 of natural gas from Azerbaijan has now entered Europe via the interconnection point of Kipoi, at the Greek-Turkish border, where TAP connects to the Trans Anatolian Pipeline (TANAP). Out of these 10 billion m3, approximately 8.5 billion m3 have been delivered to Italy. Luca Schieppati, TAP Managing Director, said: “10 billion m3 is a symbolic, but an important milestone. A little over a year after the start of commercial operations, we have provided efficient, reliable and continuous transportation services to our shippers, making an important contribution to Europe’s energy security and supply diversification. We are currently able to reach the full transport capacity of 10 billion m3/yr. On top of this, we can add further capacity via short-term auctions.” Marija Savova, TAP Head of

GERMANY

Wintershall Dea writes off financing of Nord Stream 2

CANADA TC Energy Corp. has announced signing of option agreements to sell a 10% equity interest in the Coastal GasLink Pipeline Limited Partnership to Indigenous communities across the project corridor.

UK

The German government has decided to fast-track works on two regasification terminals as it embraces US LNG imports in a bid to reduce dependence on Russian pipeline gas. Chancellor Olaf Scholz said the terminals would be in Brunsbüttel and Wilhelmshaven – for the latter Uniper was asked to revive plans, shelved in 2020. In addition, Hanseatic Energy Hub will seek planning permission for the Stade LNG project.

AUSTRALIA Australia’s oil and gas industry has welcomed the election of Peter Malinauskas’ Labour team, saying it looks forward to working with the new incoming government towards South Australia’s cleaner energy future. The Australian Petroleum Production & Exploration Association (APPEA) has urged the new administration to recognise the role gas would play in the future decarbonised energy mix and to focus policy efforts on protecting the state’s positive investment environment.

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World Pipelines / APRIL 2022

Wintershall Dea AG’s Management Board has decided not to advance or implement any additional gas and oil production projects in Russia and to write off its financing of Nord Stream 2, totalling around €1 billion. In a personal statement on 1 March 2022, Wintershall Dea’s Chief Executive, Mario Mehren, emphasised that the Russian President’s war of aggression against Ukraine

Commercial, added: “The delivery of the first 10 billion m3 of gas to Europe enhances liquidity in the gas markets and reinforces TAP’s role as a reliable transporter that can significantly contribute to the security of supply in Europe. TAP can double its capacity and expand in stages, up to 20 billion m3 within 45 - 65 months, as a result of requests to be received during the binding phase of a market test and the accumulated requests resulting in an economically viable outcome. The next binding phase is currently scheduled for July 2023. However, TAP can accelerate this timeline and launch the binding phase of the market test during 2022, provided that TAP receives interest for an earlier start in the ongoing public consultation. We invite all interested parties to take part in the ongoing market test.”

has shaken the foundations of the company’s work in Russia to the core. As a consequence, Wintershall Dea AG’s Management Board has decided not to pursue any additional gas and oil production projects in Russia, and to stop all planning for new projects. Payments to Russia will stop, and financing of Nord Stream 2 will be written off.

20% drop in Russia sentiment among Asia-Pacific companies With several Western peers halting Russian operations, there is a rising uncertainty around Asia-Pacific (APAC) companies’ stand on a Russian exit. As a result, the earnings call transcript sentiments of APAC-based companies were down by 20% in 1Q22 over 4Q21, reveals GlobalData, a leading data and analytics company. Rinaldo Pereira, Business Fundamentals Analyst at GlobalData, comments: “1Q22 sentiments have not reached the COVID-19 driven lows of 3Q20. The APAC companies seem sceptical of exiting Russian operations with their sentiments around Russia have been impacted by the Ukraine conflict and reached the medium range.” ‘Sanctions’ as a keyword only appeared 14 times in APAC earnings call transcripts so far in 2022. In comparison, North American

companies mentioned the word nearly 190 times, reveals GlobalData’s Filing Analytics database. Japan Tobacco Inc., Food Empire Holdings Ltd, Oil and Natural Gas Corp. Ltd, Glenmark Pharmaceuticals Ltd, IRC Ltd were some of the APAC companies with the most mentions of Russia in all filings during 2016 - 2022. Pereira concludes: “Most mentions do not necessarily mean the most exposure but indicate company discussions around the possibility of geopolitical risk on the production and sales or an indirect impact on their business. APAC corporates do recognise the gravity of the crisis but are more cautious in their approach around discussions while several Western counterparts directly comment on suspending or halting operations.”


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CONTRACT NEWS EVENTS DIARY 2 - 5 May 2022

Offshore Technology Conference Houston, USA https://2022.otcnet.o

2 - 6 May 2022

PLCAC annual convention Maui, USA https://pipeline.ca/

10 - 12 May 2022

Canada Gas & LNG Exhibition & Conference Vancouver, Canada https://canadagaslng.com/

23 - 25 May 2022 StocExpo 2022

Rotterdam, Netherlands https://www.stocexpo.com/en/

23 - 27 May 2022

World Gas Conference 2022 Daegu, South Korea https://www.wgc2022.org/

7 - 9 June 2022

Global Energy Show Calgary, Canada https://www.globalenergyshow.com/

5 - 8 September 2022 Gastech

Milan, Italy https://www.gastechevent.com/

22 - 23 September 2022

Subsea Pipeline Technology Congress (SPT 2022) London, UK https://sptcongress.com/

24 - 30 October 2022 bauma

Munich, Germany https://bauma.de/en/

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World Pipelines / APRIL 2022

Oil, gas contracts activity increased in 2021 due to higher crude prices Annual oil and gas contracts activity reported an increase of 9% in the number of contracts and a substantial increase of 51% in disclosed contract value in 2021, says GlobalData, a leading data and analytics company. Pritam Kad, Oil & Gas Analyst at GlobalData, comments: “Improved crude oil prices and COVID-19 subsiding provided a boost to contracts activity, with notable contracts such as Chiyoda Corp. and Technip Energies’ joint ventures US$12.242 billion EPC for over 32 million tpy Qatar Petroleum’s North Field East Project (NFE) LNG project and Saudi Aramco’s 16 contracts, with a combined worth of US$10 billion for the subsurface and EPC works for the

Fugro signs four year global framework agreement with Heerema Marine Contractors Fugro has signed a four year global framework agreement with Heerema Marine Contractors for survey and positioning support services onboard Heerema’s heavy lift crane vessels. Fugro’s worldwide reach and technology offers Heerema a solid support base for their global project portfolio, ensuring optimised offshore operations that minimise environmental impact. Fugro will use its innovative vision technologies, such as QuickVision®, 3Direct® and InclinoCam®, combined with remote services and expert teams to optimise Heerema’s offshore installation and decommissioning campaigns across Europe, the Americas, Middle East, and APAC regions. Fugro’s survey geo-data and positioning support will assist Heerema in identifying seabed structures and debris while providing centimetre level precision for installation projects. Real-time touchless inspection and monitoring technology offers a much safer, more efficient, and sustainable solution to offshore operations. Remote support will also enable Heerema to monitor their operations in real-time leading to faster and more informed decision making as their projects progress.

development of the Jafurah shale gas field in Saudi Arabia. According to GlobalData’s latest report, ‘Annual Global Oil & Gas Industry Contracts Review - 2021’, the number of contracts increased from 5750 in 2020 to 6263 in 2021 and the disclosed contract value also showed a substantial increase from US$115.42 billion in 2020 to US$174.21 billion in 2021. In terms of single scopes, operation and maintenance (O&M) represented 44% of the total contracts in 2021, followed by contracts with procurement scope with 20%, and multiple scopes, such as construction, design and engineering, installation, O&M, and procurement, accounted for around 17%.

THE MIDSTREAM UPDATE •

Lloyd’s Register announces AllAssets 3.0

Equinor to stop trading in Russian oil and oil products

OPITO and ETZ Ltd partner to support All Energy Apprenticeship

Ukraine joins ENTSO-E

Oil could hit US$240/bbl if more Western countries join US embargo

Southern Gas Association announces winners of the Innovative Tech Forum

Follow us on LinkedIn to read more about the articles linkedin.com/showcase/worldpipelines


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L

eak detection is a vital consideration for running a pipeline safely, though regulation compliance is not always an easy aspect of pipeline integrity management (PIM) to navigate. The regulations are unique for each country and in the US, compliance requirements may differ even from state to state. The challenges surrounding audits have been further complicated in recent years by the COVID-19 pandemic. With the emergence of virtual audits or information requests, posing risks to the audit due to difficulties in communication and information interpretation without the face to face discussions. Here we’ll cover the essential considerations of a pipeline leak detection regulation audit. We’ll explore: ) The purpose of an audit. ) Having the right documentation. ) Preparation and human considerations. ) Why the stakes are so high. ) How the right pipeline compliance service partner can help.

Preparing for an audit can be daunting for pipeline operators, considering these areas regularly will help embed compliance into your organisation’s culture, as required to meet the regulations.

The purpose of an audit Audits are designed to assess a company’s compliance with legal and regulatory requirements. Pipeline leak detection audits help to ensure that pipeline operators are compliant with the stringent safety requirements of liquid and gas pipelines. The requirements help to protect people and the environment from the potential damage caused by pipeline leaks and ensure that the right systems and processes are in place. Audits often consist of three stages: ) Pre-site visit activities. ) Onsite activities. ) Post-site activities.

These stages require pipeline operators to gather the right information, complete documentation (such as audit checklists) and where required, provide additional information at the auditor’s request.

10


Carin Meyer, Regulation Compliance Programme Specialist, Atmos International, USA, talks through a holistic view of what pipeline operators need to consider for passing a pipeline leak detection audit.

11


At the end of the process the pipeline operator will receive an audit report, which will detail any findings.

Having the right documentation Reviewing documentation is a big aspect of preparing for an audit. It ensures that pipeline operators have the correct standard operating procedures (SOPs) in place and can also provide an audit trail of processes. Therefore, it helps to demonstrate compliance with pipeline safety regulations. The procedures and training or testing documents required may be used for multiple regulations. So, it’s vital to ensure they are kept current and comply with each individual regulation that needs to be met. One of the biggest challenges pipeline operators can face is that regulated versions incorporated in the law of a country or state, may not be the latest version approved by the regulatory body. We’ve seen clients fall into this trap with updated American Petroleum Institute (API) documents being released but not yet incorporated into regulations. It’s important to distinguish which version is required by law and what is required by the regulator. When preparing for an audit, both industry standards and best practice should be reviewed. It is vital to reference the governing documentation and official documents from regulators to ensure you align. In the US, the federal regulations are applicable to every state to ensure the protection of people, public and the environment. Some US states have adopted additional regulations or requirements, which makes it important to review both federal and state regulations that impact your organisation. It is important to review documents closely to ensure they are signed and dated if required. This is seemingly obvious but has been a pitfall for some pipeline operators. Not doing so could result in a potential finding and prolong the audit, causing the auditor to comb deeper through your SOPs. Another vital consideration is, if it’s written in the documentation, you must do it. For example, if the SOP states that the controller will shut down the pipeline after getting a leak alarm from the leak detection system (LDS), then this is what they must do. If the controller determines that it was in fact a false alarm and doesn’t shut down the pipeline, they are in fact in violation of the SOP, resulting in a potential finding. Well-thought-out procedures need to consider all angles and aren’t as straight forward to write as they might seem. It can therefore be useful to have someone external to your organisation to review important documentation. Documentation such as an operating manual should be created to govern procedures and then followed by supporting documentation that demonstrates consistent compliance with procedures. The need for this is heightened when regulations change, we know this is expected in the US for API RP 1130, API RP 1175 and the new Gas Mega Rule this year. Carrying out internal audits will help ensure that team members are aware of the correct SOPs and demonstrate consistent compliance with the procedures.

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World Pipelines / APRIL 2022

Preparation and human considerations Preparing for an audit is made even more challenging when you consider the COVID-19 pandemic. During its height, many pipeline leak detection compliance audits were completed virtually with no face-to-face time at all. Although virtual audits can help overcome logistical and cost constraints, they can be troublesome due to the fact that: )) It’s hard to build a rapport with the auditor. )) Information and documentation requests can be easily

misinterpreted. )) Technology can be a barrier to clear communication.

Though some audits are going back to being face-to-face depending on the regulatory body, for some, virtual audits will become the new normal. There have also been headcount changes in regulatory bodies, due to the pandemic and the increased demand in the industry. Pipeline safety personnel that complete audits are typically from an engineering background. The high demand for these skills means that auditors are notoriously difficult to recruit and retain. The Pipeline and Hazardous Materials Safety Administration (PHMSA) in the US announced that they would continue to implement hiring initiatives. Audits can be performed by PHMSA or state designated local authorities. In California, for example, the auditors are part of the fire marshal’s office and they have been able to increase their staffing’s. Headcount changes like this in turn means that pipeline operators are faced with new auditors on a regular basis. This poses several challenges, such as the auditor being unfamiliar with the pipeline operator or systems used. With all these factors considered, it is vital to ensure you only have one point of contact who handles the audit. Having a large number of people involved throughout, only muddies the water. Bringing in additional people only when they can add value will help the audit to remain on focus and avoid miscommunications. It is recommended to only provide the specific information that’s being requested as part of the audit. Providing too much information can do you a disservice. It is important for you to review the documentation several times to ensure you are providing what’s being asked. If you’re unsure, ask for clarification on what is required rather than sending unnecessary pieces of information.

Why the stakes are so high Not passing an audit can carry some significant (ever-increasing) financial repercussions for pipeline operators, plus the reputational damage inflicted on the organisation. In the US, if the pipeline regulator perceives that violations exist, a report is used to calculate risk-based penalties. These are civil penalties and the amount is dependent on the severity of the violation. For audit considerations that cover records, activities and equipment or facilities, for example, the penalty could range from US$1728 up to US$8640 just for this one section of the audit.


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Pipelines in Canada are regulated based on jurisdiction. The Canada Energy Regulator (CER) is an independent agency created by the Canadian government in 1959. The CER regulate all pipelines that cross inter-provincial or international boundaries. Pipelines that are only within one province are regulated by that individual province. Pipeline operators can be prosecuted for certain violations of the Canadian Energy Regulator Act. They can range from US$100 000 to US$1 million and could carry prison sentences of up to five years. There’s also a risk of getting caught out by Administrative Money Penalties, these can apply to individuals or companies for infractions and the fines range from US$25 000 to US$100 000 per day per violation. The Pipelines Safety Regulations (PSR) 1996 is one of the regulations that pipeline operators need to adhere to in the UK. Audits, usually carried out by the designated local authority span various aspect of the pipeline operations and its construction. Breaches to the regulations can result in fines of over £100 000, dependent on the non-compliance. It’s safe to say, the stakes are high. This places a lot of pressure on the controller who oversees the audit.

throughout the business. This means regularly reviewing documentation, training new and existing employees, reviewing SOPs against best practice and regulations and internal audits. Having an external partner can help demonstrate compliance with regulations by providing unbiased feedback, unless there is someone within the organisation dedicated to compliance. In most oil and gas companies the employees are fully occupied to perform their day-to-day duties, so adding audits to their list will increase their workload and cause stress. An external partner will therefore help to take the pressure off the pipeline operator who oversees the audit and avoids the loss of knowledge that occurs when people leave the organisation. External partners can help manage the audit process, reduce stress and influence further employee collaboration. It also gives the opportunity to ask the right questions to an auditor so that the desired outcomes are achieved from the audit. The return on investment can be very high if it means efficient programme improvement.

How the right partner can help

1.

Audits can be daunting, but they can be made less so with the right preparation. It is the responsibility of the pipeline operator to demonstrate compliance, through significant documentation, SOPs and training processes. We’ve already talked about having one point of contact for the audit, but it is also crucial to create a culture of safety

References 2. 3. 4.

https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2021-05/PHMSA%20 Report%20to%20Congress%20-%20PHMSA%20FY%202021%20Pipeline%20 Safety%20Staffing%20and%20Hiring%20Plan.pdf https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2022-01/Civil%20 Penalty%20Summary%201%2028%202022.pdf https://www.nrcan.gc.ca/our-natural-resources/energy-sources-distribution/ clean-fossil-fuels/pipelines/faqs-federally-regulated-petroleum-pipelinescanada/5893#h-4-1 https://www.nrcan.gc.ca/our-natural-resources/energy-sources-distribution/ clean-fossil-fuels/pipelines/pipeline-safety-regimes-canada/16440

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Felipe Freitas (Senior Integrity Engineer), Marcilio Torres (Senior Application Specialist), and Taylor Campsey (Pipeline Integrity Engineer), ROSEN USA, explore the digital future of successful asset management.

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lthough massive amounts of data should make asset integrity management easier, it can also make the information difficult to make sense of and interpret. Applying practical and easily applicable solutions to data allows operators to filter out the noise, focus on what is important and facilitate decision-making. NIMA is ROSEN’s cloud-based solution for integrity engineers to make informed decisions by integrating key elements to support operators’ integrity management plans (IMPs). This article shows an example and explains how data integration of key elements (such as pipeline properties, inspection data quality, reported features, integrity assessments and GIS) can be used to help manage the threat of cracking in pipelines. This article focuses on maximising value from inline inspection (ILI) utilising a crack-detection technology. It discusses how the NIMA platform can be leveraged to reduce the number of unnecessary reruns while also providing a holistic view and dynamic manipulation of datasets that can be correlated to pipeline properties, ILI results and integrity assessments.

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Pipeline Integrity Framework for cracking The Pipeline Integrity Framework for cracking provides an overview of all elements (laboratory testing, the latest ILI technology, software, consultancy and field work) and the relationships between them that are required to understand, quantify and safely manage the threat of cracking in pipelines. It is recognised that many operators will have most components of this framework already in place. The modular design enables an open discussion of what information and analysis is needed and allows the option of selecting individual elements depending on particular requirements. The framework has been developed through the consolidation of industry best practices gained through working with leading operators worldwide; it can be adjusted to meet local regulatory requirements and operators’ preferences. Figure 1 shows the key elements included in the framework for cracking.

Leveraging software as part of the Pipeline Integrity Framework for cracking The combination of a holistic view, dynamic data manipulation and an easy correlation to different datasets (pipeline properties, ILI results, integrity assessments, etc.) is essential for supporting pipeline operators with IMPs. ROSEN’s software NIMA is an intuitive and reliable platform that aids integrity engineers and operators in making integrity decisions. The benefit results from visually combining many of the elements of the Pipeline Integrity Framework. NIMA really excels in supporting gate points throughout the ILI stages and in the visualisations and correlations of the final results. One of the first elements in the Pipeline Integrity Framework is data gathering. The collected information can be easily uploaded to provide a friendly interface with the data. One example of this feature is the visualisation of the pipeline properties. Pipe books contain vital information about a specific pipe segment. This information is most likely stored in a tabular format that may require manipulation and some effort to get a good understanding of the pipeline. Ideally, this

Figure 1. Elements of the Pipeline Integrity Framework for cracking.

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information should be easily displayed in a few dashboards, providing the user a comprehensive overview of the entire segment. Figure 2 shows an example of selected pipe properties for a pipeline segment. Relevant information about the pipeline is readily available. The user can effortlessly determine the main properties of the pipeline (e.g. pipe manufactures, weld types, coating types, wall thicknesses, pipe vintage, coating types, pipe grades, etc.). The plots and tables show sums of each property, and a linear view of the stacked-up information in a cumulative distance is also available. The linear information aids in identifying the changes in the pipe properties along the pipe segment overlaying with other properties. In addition, all the data displayed on the dashboard can be correlated. By clicking on any of the plots, the software will highlight the associated information. For example, by selecting the wall thickness of 0.385 in., it can easily be seen that the coating type associated with this wall thickness is either fusion-bonded epoxy (FBE) or liquid epoxy. Likewise, all other correlated properties are highlighted (Figure 3). In addition, in the linear view, the 0.385 in. segments are also exposed. Not only do the correlated information and highlighted sections help the user to draw the conclusion that these sections may be installations and/or repair areas, but they also provide the visual locations of the selected sections along the pipeline. All the relevant information gathered at this initial stage can be overlaid with the other stages of the inspection or assessment.

ILI reporting stages Typically, the crack detection ILI is comprised of three reporting stages: preliminary site survey report, data quality report (DQR) or data quality assessment (DQA), and final reporting. Intended to attest to the tool’s functionality, the site survey report is provided within a few days after the run. The second stage (DQA/DQA) dives into the quality of the recorded data (data coverage, probability of detection, tool velocity, etc.). Historically, crack technology DQRs were delivered to operators in a written format, documenting high-level inspection details such as launcher and receiver information, data coverage, tool velocity and more. While this document did provide a concise summary,



Figure 2. Pipe book information visualised.

operators encountered issues in correlating locations of potentially degraded data and overspeed areas as well as defining how the overall data quality would impact run acceptance and integrity decisions. To gain an understanding of inspection quality, the evaluation team began providing DQA in a tabular format. The DQA delivered in Microsoft Excel format allows the data coverage and pertinent tool performance specification to be presented for each segment or joint. The benefits of the tabular report and segmented information include the

ability to identify locations where probability of detection (POD) and tool sizing tolerances may be impacted. However, some data manipulation may still be required to correlate with the pipeline details (e.g. long-seam type, wall thickness, coating type, etc.). When degraded data is observed, several aspects of the inspection can be reviewed to aid the decision-making regarding the acceptance of the survey. Some of the questions that ROSEN’s integrity experts may discuss with operators include: ) Are the locations of degraded data in areas susceptible to cracking (e.g. stress-corrosion cracking)? )) If there is sensor lift-off, what may

be causing it? )) Are there clear patterns in the

data coverage that indicate debris being dragged through the line? )) Is overspeed being caused

by changes in wall thickness/ installation areas or by failure to control the pressure during the run? ) Does decreased coverage

Figure 3. Correlated pipe properties.

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World Pipelines / APRIL 2022

coincide with repaired sections of pipe that may not be susceptible to cracking (e.g. newly installed areas coated with fusion-bonded epoxy)?


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Figure 4. Pipe properties overlaid with DQA.

)) Do all high-consequence areas (HCA) have acceptable

software. All line-specific information can be loaded into a project file, and the synchronised data can be displayed simultaneously, facilitating answers to many of the Answering these questions, as well as understanding aforementioned questions. other integrity concerns, often facilitates the An example of a DQA overlaid with a pipe book is decision-making process during the DQA acceptance stage. shown in Figure 4. The top of Figure 4 shows the pipe For that reason, data integration is extremely important. properties along the log distance of the line segment. The In the same way as the pipe books, the DQAs can second and third charts on the lower part of the image be easily integrated and visualised using appropriate represent information from the DQA (tool velocity, data coverage and tool performance specification). All plots are synchronised, and as the user zooms in on a specific area of interest, the corresponding data quality along with the POD and tool performance specification is readily available. If further inquiry of the data is needed, additional plots can be created to facilitate DQA acceptance decisions. For this specific case, the major concern was crack-like defects in the long seam. The DQA shows excellent results (99.97% of the pipeline with a POD of 90%, and for 98.8% of the run, the tool average velocity was below 8.2 ft/sec.). However, if there is a need to better understand the segment with reduced POD (e.g. a log distance of ~208 000 ft), it can be shown that the average POD for the segment is 85% – but the long seams of the affected joints are located within areas where the data coverage is above 94% Figure 5. Sensor coverage around the pipe circumference correlated to pipeline (Figure 5). coverage?

properties.

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Another common diagnostic plot is tool velocity versus wall thickness. Changes in the wall thickness may influence tool speed, and such plots may explain momentary tool stops and/or shortpeaked overspeeds. The ILI final stage (analysis of the data to produce the final report) is only initiated if the first two stages have provided acceptable results. At this final stage, the recorded Figure 6. Reported features distribution overlaid with pipe properties and DQA. signals are ‘translated’ into callouts (reported features). Post-inspection consulting may be useful for operators. metallography and the development of long-term Supplementary support ranges from burst pressure management plans. calculations and dig prioritisation to a full fitness-forSoftware can also be used to overlay ILI results with service assessment. Additional services that may be integrity assessment and pipeline details. At the final stage, beneficial for operators to obtain support with include everything is compiled in order to facilitate informed integrity feature response methodology based on the API RP 1176 decisions. With a few dashboards, reported features can also approach, identification of pipes to cut out and test, be correlated to the pipe details, data quality, failure pressure

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ratio and POD. It is even possible to display geographical locations (map view). The first two plots in Figure 7 illustrate the reported feature distribution (pipe body and long seam) for two confidence levels (high – Type A and lower – Type B) along the pipeline and corresponding failure pressure ratios (FPR). The plots are all synchronised to indicate pipeline properties at that location (including correlation to operators’ joint numbers) and whether that area has been impacted by reduced coverage or overspeed. Figure 6 shows a map view of the pipeline centreline highlighting the geographical location of two selected long-seam features. The chart also provides the tool technology’s estimated depth sizing and calculated FPRs, as well as the correlated pipe book details. The two selected features are located in the same joint in a riverbank. The user can simply select any of the reported features to assess pertinent details of the selected area. In this specific instance, the operator’s main concern was possible crack-like defects in the long seam. Being able to overlay the survey data with pipe properties at the DQA stage can help alleviate concerns about data degradation in certain areas and reduce the number of unnecessary and disruptive reruns. This is one example of how the provided pipe book

data can be used to facilitate approval of the ILI survey. In addition, the ability to provide an easy and dynamic way to manipulate all the available data (pipe books, ILI results and integrity calculations) provides the user with the necessary elements to make informed integrity decisions. Good software is so versatile that other datasets (e.g. previous ILIs, field verifications, repair areas, etc.) can be easily integrated to further enhance IMPs.

NIMA: supporting your asset integrity management decisions The combination of digitised historical data and modern hightech inspection systems means that vast quantities of data are now likely to be available for any pipeline. This data can help in managing complex threats such as stress-corrosion cracking, but only if we can create meaningful information by smart and efficient alignments, visualisations and analyses. One answer to these challenges is software that is specifically designed for this task, has the capability to handle large datasets, ensures repeatability and traceability, and can be adapted to suit particular situations. We experience these challenges working with hundreds of operators and have developed NIMA to help deliver solutions – and to help our clients make the right decisions.

Figure 7. Reported features distribution overlaid with pipe properties and DQA.

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Doug Sinitiere, Carboline, USA and Holly Tyler, Specialty Polymer Coatings Inc., USA, discuss the impact of bio and renewable fuels on pipeline infrastructure.

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uch of our energy infrastructure is undergoing significant material storage and transportation changes. This includes differences in feedstocks, compositions, feedstock percentages, materials injected for transport, and in some cases, the method of delivery. While this makes sense for many investors and energy companies that create and build this infrastructure, it also means there is an impact, in some cases a significant one, for those who consider the effects this may have on corrosion, metallurgy, and the safe transport and storage of these goods. In some cases, this is nothing new – there have always been, and continues to be, changes in the types of hydrocarbons and gases that are processed, stored, transported, and ultimately taken to consumer end use. However, the changes in the feedstocks in use make us look more closely at corrosion, metallurgy, and the like. The industry, in general, has given more focus to addressing corrosion challenges before they occur. There are new and innovative technologies, which, if fully adopted, will further help support these critical assets. Several factors have prompted these changes in recent years. All infrastructure is regulated and governed by different bodies, standards, and in many cases, countries. These can vary widely by policy, activist investors, and a general sense of the operators or developers adjusting their energy profile. Take the US Congress, for example, when they enacted the Renewable Fuel Standard (RFS) in 2005. Essentially the programme mandated that oil companies blend a certain amount of renewable fuel into the transportation fuel supply annually. This increased the development and production of renewable fuels from both crop and non-crop-based feedstocks. Similarly, in Canada, the Renewable Fuels Regulations (RFR) were established in August 2010. While there were some studies commissioned and completed before the establishment of these regulations, most of the onus of adequately ensuring the integrity of this infrastructure was with those who own and, in many cases,

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operate the assets and infrastructure. And as we’ve seen, there have been learnings along the way that have helped guide material selection decisions regarding the storage and transportation of biofuels through the value chain. As these biofuels are processed and produced, they will follow the same value chain as other fuels. They will be stored, transported, and sold. This article will look at the corrosion impact we’ve seen so far and how the role of material selection is as important as it’s ever been. Perhaps one of the most significant factors in this is the acceleration of projects centering around carbon capture and storage (CCUS) and EOR. So much activity growth has occurred in the strategies of large companies related to either reducing or reusing carbon. CCUS and EOR are viable and sometimes commercially prudent ways to get there.

Role of the pipeline operator The need to be flexible and adaptable has always been, in some part, what the pipeline industry has collectively faced. For context, this collective includes all developers, operators, general contractors, applicators, manufacturers, and service providers linked to the assets they collectively build, work on, and maintain. They have had to overcome many challenges through the years, including politics causing the protest, delay, and cancellation of pipeline projects, a global pandemic, supply chain disruptions, labour shortages, financial market volatility, and many other challenges. To avoid further scrutiny, when an operator, or investor, looks at a significant investment in building assets, they must take special care and planning to ensure the safety of the public and the long life of the pipeline. This is especially true in renewables or biofuels as there is, and will continue to be, more infrastructure on line to support what some call the energy transition pivot.

Carbon scenarios and corrosion challenges

Figure 1. Pipe lays ready to be installed adjacent to a worksite. Inspection will be performed after mechanical crews are complete to ensure all damaged areas are repaired.

Figure 2. A skilled craftsman installs a protective coating prior to backfill and after surface preparation.

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World Pipelines / APRIL 2022

One of the newer investments in assets for operating companies lies in the transportation of CO2, a component of natural gas. Converting gas into CO2 is a great way to put a potent greenhouse gas and an unused reservoir of hydrocarbons to work. Until recently, CO2 had been discarded or stored near large processing plants. We can now convert the CO2 back into usable fuels and yield more than four times as much fuel as previous approaches. This is practical and highly beneficial in today’s energy environment, which has growing concern and added knowledge of the negative impacts that portions of the energy industry have on our environment. CO2 goes through three stages during transport in a pipeline. The first phase is when the product gets loaded into the pipeline from processing. The gas is at its most toxic and dangerous levels at this stage. Dehydrators and pumps remove the water and add pressure up to 1500 psi, and the operating temperature is around 60°C (140°F) at this stage. This creates a challenging scenario as the coating on the pipe may take on extra stress and movement related to the expansion of the steel. This expansion, along with the temperature elevation, causes additional corrosion issues. As the product moves into the next phase, the pressure gets raised to 2200 psi. Due to the removal of the water, the gas turns into a liquid, and the product starts moving quickly. The third stage is the most productive as the CO2 changes to the dense phase. The flow is maintained and can operate at an ambient temperature. As a result, corrosion concerns are at their lowest. That said, material selection still matters here as it is essential to have a proper coating system in this long stretch of pipe. Another area of concern for corrosion in a CO2 line is at road and water crossings and other low areas of geographical terrain where the pipeline drops in elevation and the water gets dislodged from the bottom of the pipe, causing the product to change back to the liquid


THE PIPELINER’S PROMISE IT IS MY DUTY to safeguard my family, my community and the environment by keeping product in the pipe. To know these lines inside out and to remain vigilant to threats. IT IS MY UNWAVERING COMMITMENT to the industry that drives me to understand and apply only the highest standards of pipeline operation and maintenance. IT IS MY DEDICATED PASSION for pipelines that compels me to partner with industry leaders, share best practices and collaborate on ideas for future innovations and advanced applications. IT IS MY RESOLUTE MISSION to overcome the most difficult obstacles, and learn from my victories and defeats. To push forward tirelessly until I succeed. IT IS MY ENDURING PLEDGE to always deliver on my commitments, never underestimating the critical role that pipelines play as energy lifelines in fueling everyday life and unforgettable experiences.

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phase. These areas are at a high risk of corrosion. Best practices indicate using a high build coating (typically 40 mils or higher) with high impact resistance in these areas. The pipe used in water crossings and bore sections is a much heavier wall thickness than the mainline pipe. This weight causes sheer resistance and soil stress, which can significantly impact coatings. A high build ARO epoxy coating handles the rock, soil movement, and stress in these sections. Regarding corrosion protection strategies, material selection, and metallurgy, we should note that there are also several other areas the operator considers when building and maintaining these assets. For example, corrosion inhibitors and CRA or corrosion-resistant alloys are often deployed and widely considered part of the ‘system’ of corrosion mitigation for CO2 scenarios. Usually, the amount of resources and detail around corrosion protection strategies is directly proportional to the organisation’s or the number of assets they own and operate. Those truly invested in reliability and maintenance will tell you this is part of a larger culture, not just a programme someone has to meet the minimum requirements needed. The struggle to have a robust corrosion protection strategy is even more challenging when considering the amount of turnover from one asset owner to another. Different philosophies and cultures collide, multiple types of reporting, and different contract strategies mean there is genuinely a mixed bag of conditions for assets. One crucial area related to the application of these corrosion systems is the training and development of the

craftspeople hired to install these systems. Like many industries, the craft needed to support these critical projects requires additional people to backfill those more experienced employees who have been doing this work for many years and have left the industry or retired. Competency in these areas is vital. A significant key to successfully applying these systems is the in-depth knowledge of the corrosion process, product systems and technology, any special equipment needed, the importance of documentation and the role of quality control, the operator’s specifications, and several other vital factors. Many craft companies end up spending an excessive amount of time and valuable resources working through the bidding or RFQ process and are spending less and less time working with those craftspeople to develop their skills and continue to ‘raise the bar’. This puts more and more challenge on the material providers to be very present, supportive, and in tune with the projects for which their materials are in use.

Summary Adequate expertise, time, and energy are essential in the material selection process to ensure the safe operation of assets and infrastructure. Carbon reduction, carbon neutrality, and carbon utilisation will remain under heavy scrutiny, but they will also see use in new and innovative ways. As these changes occur, we need to be aware of the impacts this will directly have on existing and new assets and collaborate with operators, contractors, material suppliers, and other service providers to ensure the integrity of this infrastructure.

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Iain Rennie, Operations Director, Asset Guardian Solutions Ltd, UK, discusses the benefits of a truly successful control system.

W

hen considering the integrity of pipelines, it is not just the physical assets, the nuts and bolts, that need to be considered, but also the virtual aspects of the pipeline. In an increasingly digital age, pipelines are controlled, monitored and protected almost exclusively by programmable control and safety systems, running on modular control system hardware and running bespoke software configurations. At Asset Guardian, we deal in managing and maintaining the integrity of the control and safety systems such as PLC, DCS, SIS, SCADA and associated databases, reporting and information systems. This includes the software backups, hardware configurations and all the associated documents and information. Everything running

on your operational technology (OT) network.

Protecting your hidden assets We call them your hidden assets. Your company will have invested millions in their development, and they are critical to the continuing safety and operation of your pipeline. However, you may not have a good record of what you have, reliable backups of the software, or proper management of the configurations and versions. The hardware and software configurations running on your control and safety systems will have been developed particularly for your pipeline, and as the owner/operator, they are your assets to maintain and protect. So you have to protect the integrity of these hidden assets, like you would your

27


physical assets. You have to keep an inventory of the control hardware, a repository of software backups with full version control, and manage changes to and faults found in these systems. By maintaining this data and software, you are maintaining the integrity of your control and safety systems. This provides the obvious benefits of maintaining both safety and operational integrity. All process control systems must comply with relevant safety regulations, and central to these internationally for the process industry is IEC 61511. A critical element of this standard is configuration and change management and software version control.

Asset Guardian: a multi-faceted solution Having invested in an Asset Guardian system to protect the integrity of your control system hidden assets, you can leverage that investment to manage other important aspects like obsolescence and cybersecurity. A key factor in obsolescence management is building your bill of materials (BoM). This can be built from the same data as the hardware configuration inventory you are already managing in Asset Guardian. This data is re-used and matched to manufacturer’s lifecycle data within the Obsolescence Module in Asset Guardian to be able to identify obsolescence risks. Full obsolescence management can be attained in compliance with international standard IEC 62402.

Software obsolescence An interesting enhancement to the latest edition of IEC 62402 is to also consider the risks around software obsolescence.

Software becomes obsolete in a different way to hardware. Since software can be easily duplicated and does not wear out, some think it cannot become obsolete. But software becomes obsolete when it loses integrity. If you cannot make changes to the software, then software is obsolete. You need to be able to maintain your software, and have the ability to change it when required, to meet changing process requirements, or even changing regulations. If your software has lost integrity because you do not have proper version control, reliable backups, cannot run the programming tools, or do not have the expertise to make changes, then the software is obsolete. Managing your software in Asset Guardian, and so maintaining its integrity, can prevent that software from becoming obsolete, and minimises the associated risks.

Cybersecurity management Also, the same inventory can be used as a basis for Cyber Security Management. A key part of your overall cybersecurity defence is a robust Cyber Security Management System (CSMS), where an inventory of devices and their configurations (hardware parts and installed firmware and software versions), are matched against published vulnerabilities. This allows cyber risks to be discovered, and crucially, prioritised against actual installed devices. Then mitigations (such as patching) can be quickly deployed and risks contained, dealing with the highest risks first. Almost all successful cyberattacks are carried out on known vulnerabilities and managing these is a crucial aspect of cyber defences. Further, in a disaster recovery scenario following an attack, Asset Guardian becomes even more useful. Having a secure repository of all your control system hardware configurations and installed software versions, allows the fastest possible recovery after an OT network is cleansed. Systems can be back up and running within hours, with the sure knowledge that the integrity of the systems has been maintained, and the latest versions of all software have been fully restored. Without this repository it can take months to restore systems, trying to obtain software from vendors, and being unsure of versions, and if latest updates are included. This also helps in compliance with national and international standards on cybersecurity like IEC 62443. So it also satisfies the regulators, and makes it more straightforward to pass audits, having all the relevant information at your fingertips.

A solution well suited across industries

Figure 1. The Asset Guardian product wheel.

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World Pipelines / APRIL 2022

Asset Guardian is useful in most industries, anywhere there are control systems and OT networks. In fact, Asset Guardian is used in most industries and this allows us to take the best ideas from across industry for the benefit of all our users. Asset Guardian is really well suited to


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industries that are highly compliant and highly regulated (like oil and gas), and especially industries which may be targets for cyberattacks, like pipelines. Pipelines also have some unique characteristics which can simultaneously make them more vulnerable and harder to manage. They tend to have more distributed control systems, housed in lots of remote outstations. Many of these will be unmanned, and difficult to mobilise a team to quickly. There will be more reliance on remote control, possibly with the use of third-party vendors. There will be lots of bespoke software configurations running on lots of smaller controllers, meaning more software backups and versions to control, and more devices to manage changes on. All this adds up to more vulnerable systems, that are harder to maintain and more difficult to recover. Which makes it even more critical to have an Asset Guardian system managing all that information, and to be properly managing all the associated risks.

Customer success story For one of our customers, using Asset Guardian to manage the integrity of their control system assets gave an unexpected benefit, when the pipeline was sold to a new owner and operator. When assets are sold, the quality of information around the control systems received by the purchasing company can be very poor. If the relevant information is held in disparate spreadsheets held by technicians and engineers, and software backups on random disks in remote fire safes or even the bottom of engineers’ drawers, collecting and handing over that information can be extremely difficult. If the purchaser is not fully aware of the concept of hidden assets, when contracts are drawn up, the criticality of this information can be missed from the contract and because it is not easy to find, it can be missed altogether. The new owner is then extremely vulnerable, where even simple failures can result in extended periods of downtime while software versions are sourced and information scratched together. Changes are impossible to control, faults are ignored, and the integrity of the running systems very quickly decline. But a plant using Asset Guardian to manage the integrity of the control system assets, has all that data and software available and secure, and can quickly and easily hand it all over to the new owner. That may involve simply handing over the Asset Guardian system as if it was part of the plant. The new owner just continues with its use almost seamlessly. Or, as in the case of one of our customers, when the pipeline is only part of their portfolio, the relevant data can be easily exported from one Asset Guardian system and then imported into the Asset Guardian system of the new owner.

Case study: SOCAR Midstream Operations When SOCAR Midstream Operations (SOCAR Midstream) took over technical operatorship of the South Caucasus Pipeline (SCP), they had to transition a number of industrial control and safety systems (OT ICSS) along with it.

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They needed to guarantee the continuing integrity of the ICSS to ensure the operation of the pipeline would continue seamlessly after the transfer. In 2019, the daily average throughput of SCP was 29 million m3 /d of gas, so it was important this was not interrupted. Luckily, the previous operator was already using Asset Guardian to manage the system change management (SCM) of the ICSS. This included having full software backups of all systems, hardware configurations, system passwords, associated information, and an established and proven process for managing changes, through the programmable systems change request (PSCR) process. Asset Guardian is key to this process as the workflow of the change requests when they are initiated, approved, implemented, and closed out, are all managed within the tool. This gives full control of pending changes, and their status, ensuring changes are properly reviewed and approved before implementation, and then properly inspected and tested before close out. Additionally, the PSCRs link to the software backup repository, and allow the software to be checked out when the workflow is at the correct stage (and not before), controlling the updates to the software, but not locking it longer than is necessary to implement the change. In a large process where there are hundreds of changes being made simultaneously, this optimises the process while keeping the highest level of integrity. Multiple changes planned to the same software can even be queued, allowing the next change to check out the software as soon as the previous change has been implemented (and checked the software back in). Automatic email notifications help at all stages of the workflow to alert relevant people as soon as software is available, or when approvals have been made, or tests completed. So it was critical that this process was transitioned to the new operators, as there would be many changes at different stages and it would have been a big disruption for these to all have to be reset and migrated to a different system. Since Asset Guardian was being used, the whole process, including all the data and software backups for SCP, could be exported from the previous operator’s system, and then imported into SOCAR Midstream’s own Asset Guardian system. This was done at the point of transition between the companies, so that the technicians and engineers were using the previous system prior to transition, and then after transition logged into a different URL for the SOCAR Midstream system, and continued on exactly where they left off. All the data was transitioned in under a day, and all software backups moved within a week. This meant the transition was achieved with the minimal delay and no interruption to pipeline operations. It also ensured the integrity of the ICSS was maintained at the highest possible level, for relatively small effort compared to similar transitions in the industry, where Asset Guardian is not being used.


Nicholas Duggan, Chief Technology Officer, The Carto Group, UK, explains how GNSS improves the speed of locating buried assets.

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very year thousands of new gas pipelines are installed, and field engineers must record data on the pipeline components including the pipe segments, connections, asset type, pressure tolerance and personnel. Details down to individual welds are captured and entered into a geographic information system (GIS) database to support utility operations and asset management. In many cases, the data must be recorded before a pipeline is buried. Utilities use the data to identify pipes in the field with potential problems. Global navigation satellite system (GNSS) technology has become the go-to for collecting this data quickly, easily, and accurately. Keeping a database of buried assets is a crucial element for renewing, maintaining, and locating pipelines. Collecting the data requires speed and the ability to capture locations in difficult conditions. The data supports utility operations and asset management and can be shared with other utilities and public agencies when necessary. Utilities can utilise the collected data to find pipe in the field quickly to identify potential problems efficiently. Out of necessity, one of North America’s most established civil and municipal engineering firms, Suburban Consulting Engineers, Inc., (SCE), has built an enhanced GIS system that uses GIS technologies to support the collection of detailed asset information required by gas utilities and

Figure 1. Keeping a database of buried assets is a crucial element of maintaining pipelines. GNSS built on VRS technology has helped streamline the process.

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regulatory agencies. To capture the locations, attributes and associated geotagged images, SCE uses Trimble R2 GNSS receivers with TDC600 handheld data collectors running ESRI Collector software. In some areas, SCE accesses correction data via a real-time GNSS network built on Trimble VRS technology. SCE has over 30 years of expertise working with gas utility companies. They developed the high-efficiency techniques to collect live ‘as-builts’ of their client’s pipelines so they could meet requirement for traceability. The work has culminated in a method that meets strict Pipeline and Hazardous Materials Safety Administration (PHMSA) requirements. As part of its

process, SCE uses the ESRI GIS platform to provide a consistent geospatial framework to record the detailed information. SCE creates a custom library of forms for each gas utility client for data collection that enables field engineers to use standard workflows while capturing asset information. With the GNSS receiver providing positional accuracy down to centimetre-level, SCE Technicians are confident in the location of data. By using the large capacity data storage in the TDC600, they can maintain extensive GIS databases and store information and images. For each project, the collected data is transitioned to an ESRI geodatabase where quality assurance (QA) is performed to test for connectivity between pipeline sections and consistent attribution. The resulting data is fully traceable, verifiable and provides a complete record for the life of the assets in accordance with the PHMSA regulations. As a result, SCE clients no longer need as many of their own GIS technicians to model or translate data. Each client is able to see a full digital twin of their pipeline, updated digitally weekly and customised to be consistent with their own existing schema and formats. One of SCE’s clients is Southern Company Gas, a Fortune 500 energy services company headquartered in Atlanta, Georgia. Jacob McGlincy, GIS Supervisor with the company, appreciates the benefits of using the GNSS solution with GIS. As he was wrapping up final inspections and commissioning activities at the end of a new pipeline project, McGlincy was asked to find all the pipe segments installed on a transmission pipeline project that were manufactured on a specific day, had a specific type of coating, and had a field bend. “It took just five minutes to query our data and identify seven pipe segments from more than 1100 that had been installed – together with their exact locations in the field.” McGlincy said. The seven segments were verified, and the pipeline was successfully commissioned on time. “Without the real-time access to the detailed data, this research could have taken days or weeks with many unsuccessful exploratory digs to find and verify these segments,” he said. Using GNSS, SCE has reduced man-hours by being quick Figure 2. Using GNSS with GIS, technicians can easily record and and efficient in the data collection process during pipeline store data about pipelines for future reference. construction, with just one day needed to load the Enhanced GIS data into their clients’ GIS. Before this change, the data could not have been captured with the same degree of completeness or precision. According to SCE’s Georgia Office Manager, Marc Sheridan, there is more to come. “This isn’t the end result,” Sheridan said. “We started this data collection system seven years ago and we’re still advancing it. What started as simple pipeline feature collection is now growing and moving to material collection. Inspection reports are going digital and we’re working on inspections and close-out packages to provide complete pipeline documentation.” Together these changes that include the increased use of GNSS will enhance the efficiency and accuracy of GIS data collection when mapping the location of gas pipelines for asset management, pipeline assessment, pipeline Figure 3. SCE uses a ESRI GIS platform that reduces man-hours by being quick and services and maintaining pipeline integrity. efficient in data collection during pipeline construction.

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Inline isolation keeps product in the pipe during complex valve replacement at major offshore gas fields, says Rolf Gunnar Lie, Regional Business Development Manager, T.D. Williamson, Asia Pacific.

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atural gas operators often face a trade-off of sorts while ensuring pipeline integrity. They have to create a safe work zone for maintenance or repair, but that can mean depressurising the pipeline and removing its contents – a process that comes with steep costs, both economic and environmental. Pipeline depressurisation requires flaring huge volumes of gas. When bleeding down a gas export pipeline, for example, it is not unusual for several hundred million ft3 of gas to be flared off. Not only does that represent significant inventory loss, in a world where CO2 equivalents emissions are being targeted and oil and gas companies are trying to meet environmental, societal and governance (ESG) standards, voluntary flaring is becoming less and less acceptable – even outlawed in some areas. At the same time, bleeding down the system is an often-lengthy process that can equate to costly lost production, sometimes running in the millions of US dollars. It’s not unusual for it to take days to depressurise and purge a section of the pipeline with N2 before carrying out the repair and then to refill it before normal production can resume. Fortunately, there are safe and efficient alternatives to depressurisation. Operators can use either hot tapping and plugging (HT&P) or

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inline isolation to eliminate flaring and product loss, minimise downtime and avoid, or at least reduce, service interruptions – resulting in substantial savings. Those issues were top of mind when a pipeline operator in Malaysia needed to simultaneously isolate three critical gas export pipelines before replacing five leaking valves whose passing rates exceeded allowable limits. The pipelines are part of Malaysia’s largest offshore integrated oil and gas facility, which acts as a gas hub supplying approximately 600 million ft3/d. Choosing trusted isolation technology that could tackle this complex project and satisfy the operator’s business objectives and timetable was a priority. “Because the gas export lines transport the entire gas field’s production, the operator needed to both limit how long they were offline and keep product contained,” T.D. Williamson (TDW) Global Field Services Manager Thomas Idland said. The SmartPlug® isolation system helped accomplish those goals. The isolation also represented an important milestone in the region. Although high-pressure isolation technology had been deployed on main gas export pipelines in Malaysia several times before, this was the first time three isolations were executed at the same time on the same platform during a single shutdown campaign. In fact, Idland said, isolating the pipeline using SmartPlug technology was one of the project’s major drivers. “The SmartPlug system offered a quick and reliable alternative to otherwise unsafe and time-consuming options,” Idland added. “Without SmartPlug technology, operation with defective pipeline isolation valves and corroded components would have continued.

Figure 1. The three pipelines that were isolated.

The best isolation for the demands of the job There are two primary methods of isolating gas and liquids pipelines: intrusive isolation – also known as HT&P – and non-intrusive inline isolation, also known as SmartPlug. HT&P involves welding of a fittings and cutting into a live pipeline and inserting a plug or STOPPLE® device downstream of the work zone to isolate it from pressurised product. By contrast, non-intrusive inline isolations are made by a piggable tool such as SmartPlug. Existing pig traps and quick opening closures (QOC) are used as the point of entry into the pipeline and point of exit. The SmartPlug tool is pigged under pressure to the set location and can be pigged back to the platform after the isolation has been completed. In this case, two of the three pipelines to be isolated – one of them 24 in. and the other 32 in. – were connected to separate platforms while the third line, also 32 in., went to the onshore gas receiving terminal. However, all three of them shared a common header at a topside, meaning they had to be isolated simultaneously. During these works the pipelines and the platform are in shutdown mode meaning that production is temporarily stopped but the pipelines remain pressurised except from sections where repairs take place. Because these isolations would be performed at the platform risers close to seawater level, inline isolation was preferred over HT&P, as the location would make hot tapping very challenging. Project requirements determine whether the SmartPlug tool will be propelled to the isolation point using pipeline product or a set of pumps or compressors and another medium, such as threated water or N2. Because the tool is bi-directional, it can be pigged to the receiving end or back to the launcher after the maintenance or repair operation is complete. Because the two pipelines coming from the offshore platforms were in shutdown mode – meaning there was no flow in the line, but it remained pressurised except in the section between the pig trap and isolation point – the three SmartPlug tools were launched from each of the pig traps. They were pigged with treated seawater from external pumps a total distance of approximately 30 m (98 ft) then set in a vertical topside section in the riser just below the shutdown valve. The tools were tracked along the pigging route by the SmartTrack™ system using extra low frequency (ELF) signals.

A true double block isolation

Figure 2. Dual module SmartPlug® isolation system.

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Field-proven in more than 330 offshore and onshore projects, SmartPlug meets the accepted criteria for a true double block and monitor (DBM) isolation as defined by DNV-RP-F113.1 Broadly speaking, a barrier is deemed to be ‘double’ when each plugging module can retain the full line pressure individually, is tested and its integrity is monitored. In the typical SmartPlug configuration, two plug modules work independently, each to isolate the full pipeline pressure alone, meaning the tool has 100% contingency. SmartPlug technology is supported by the formal failure mode, effect, and critical analysis (FMECA) study; this means redundancies


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Leaving nothing to chance Safety is always a top priority when doing pipeline isolations. Personnel injuries or loss of life or assets are totally unacceptable. As part of their comprehensive performance and safety protocols, the operator conducted in-house technical and safety review sessions in parallel with site visits and engineering studies conducted by TDW. An in-depth risk study with hazard identification (HAZID), hazard and operability analysis (HAZOP) methodology and multiple safety workshops helped assure Figure 3. Dual module double block and monitor (DBM) SmartPlug tool. the risk management of the project. Among other operational aspects, TDW engineers left nothing to chance when it came to ensuring the piggability of the SmartPlug tool. Idland said that engineers performed a piggability study to ensure that each SmartPlug tool could be safely pigged to the set location and retrieved back to the pig trap. “This is standard practice and a requirement set by the Type Approval issued by DNV for the SmartPlug tool,” he explained. Engineers also took aim at one of the key concerns about inline isolation: the potential for excessive pipeline hoop stress, or hoop stress approaching the elastic limit of the pipeline at the location of the plug module. A pipe stress analysis was also performed. It checked the hoop and von Mises stresses in the sealing and gripping area of the set location on each plug module against permissible utilisation, as defined by the DNV-RP-F113.1 Isolations taking place on sites usually require compliance with safety class ‘high’ specifications as outlined in.1 Spreading the stress over both of the isolation tool’s plug Figure 4. Loading the SmartPlug tool (left) and the SmartPlug tool at modules helps ensure that the hoop stress does not approach set location (right). the elastic limit of the pipe – and further enhances safety during the operation. For thin-walled pipelines, for example, in the tool reduce the likelihood of potential plug failures during onshore, if hoop stress levels could reach a critical level, external an isolation to an acceptable level of probability as defined by reinforcement clamps can be used to support and strengthen the DNV-OS-F101.2 pipeline locally at each plug location. Activated remotely, the SmartPlug tool uses internal hydraulics to engage the gripping elements (slips) and the A robust alternative sealing element (packer) on the pipe wall. Once the gripping and Isolating the pipeline using SmartPlug technology was one of the sealing elements are fully in place and engaged, the downstream major drivers for this shutdown campaign. The SmartPlug system pressure is reduced to create differential pressure across the offered a quick and reliable alternative to otherwise unsafe, plugging module. This is repeated for each plug module in costly and time-consuming options. sequence. The SmartPlug system is designed to be self-locked Using SmartPlug technology, the integrity of the gas in the set position so that it is fail-safe as long as there is delta export pipeline was safely restored while the operator avoided pressure across the plugging tool. depressurisation and gained enormous benefits, including in terms After setting each isolation tool against the 75 - 90 bar of sustainability, which is one of their key commitments. (1087 - 1305 psi) gas pressure in each pipeline, technicians Not only did the isolation shave a week off the monitored the annulus pressure between the two plug modules project’s turnaround time, but it also kept approximately for four hours to verify that both plug modules were sealing 380 - 400 million ft3 of inventory from being flared. And properly. TDW issued isolation certificates and the valve considering that flaring a single m³ of natural gas produces replacement work was underway. approximately 2.75 kg of CO2 equivalents, SmartPlug isolation After the new valves were installed, the launcher and the kept the equivalent of 21 000 t of CO2 from being released into receiving end of the pipeline were pressurised with treated the atmosphere. That’s roughly equal to the annual emissions seawater as part of the unsetting procedure. However, before produced by 4600 passenger cars. unsetting the three SmartPlug tools, a pressure test was conducted to 82 bar (1189 psi) for one hour to verify that all flange References 1. DNV-RP-F113: Recommended Practice, Pipeline Subsea, Edition October 2017. joints were leak-proof. The SmartPlug tools were then unset and 2. DNV-OS-F101: Offshore Standard, Submarine Pipeline System, Edition November pigged back to the receiver using gas pressure from the pipeline. 2016.

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Harvey Hancock, Gripple Limited, UK, argues that an increased understanding of attachment methods is vital to improving the efficiency, safety and performance of cables.

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lectrical Heat Tracing (EHT) cables were initially developed in the 1930s as a proposed alternative to steam heating which had been adopted since the early 1900s. Although EHT cable wasn’t initially suitable for use with heavy machinery, due to its tendency to crack under high temperatures, technological advances have meant that we are now able to install EHT cable in even the most extreme environments. Thousands of kilometres of EHT cable are installed globally each year with the requirement for installations set to continue to rise as investment continues. This is especially true when considering that the scale of pipelines has increased massively over the last 25 years with both average diameters and lengths rising – thus increasing the overall capacity

Figure 1. Gripple Heat Tracing Kits consist of a GHTK Tensioner, GHTK Clips and pre-cut lengths of wire rope.

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on offer (an increase of 82% since 1996). This, in turn, will inevitably increase the requirement for EHT cable installations. Whilst millions of dollars have been invested in improving the performance of EHT cables, somewhat neglected has been the importance of innovation whilst developing methods of attaching cables to pipelines. Traditional methods of attachment include the use of ‘off-the-shelf’ parts such as banding or tie wire, which are installed at 300 mm intervals to ensure that the cable remains in close proximity to the pipe in an attempt to maximise the efficiency of heat transfer. The industry’s admirable passion for maximising the performance of the overall system has, until now, been centred upon improving the technology of the cable itself. This is despite the fact that the chosen attachment method can play a pivotal role in ensuring that any common failure modes are avoided, thus allowing costly time-consuming delays to be minimised and cable lifespans to be maximised.

The problems with tradition Whilst traditional methods of attachment could appear to have withstood the test of time, they are certainly not without problems. There are several issues which arise if careful consideration into a suitable attachment method isn’t undertaken. The potential issues, which are outlined below, only magnify the importance of selecting the right attachment materials for any EHT cable installation. One of the main issues for any product which is to be installed in a potentially hazardous environment, and a consideration which should always be at the forefront of all thinking, is the potential for health and safety issues. Traditional attachment methods are notorious for their tendency to cause cuts to the hands and wrists due to their sharp-edged nature, despite the care which is taken to provide suitable PPE. They also often present problems such as repetitive strain injury (RSI) due to the nature of their installation. In fact, accidents are so frequent in oil and gas environments that some facilities have now begun referring to the number of ‘hours’ since last incident rather than the previously used number of ‘days’ since last incident. As well as the obvious and potentially devastating human costs, the financial costs of health and safety issues cannot be underestimated. The oil and gas market has the highest overall spending per employee on prevention measures of any sector throughout the whole of Canada. In Alberta alone, CAN$10 425 was spent between 2016 and 2020 to cover claims of being ‘caught in an object’ whilst CAN$11 370 was spent in the same time period to cover claims of ‘falling to a lower level’ (Alberta Workers’ Compensation Board (WCB)). Whilst many of the health and safety procedures which are enforced are justifiable, any future actions which can be implemented to reduce encounters with potential health and safety risks should be considered. Improving the simplicity of installation

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methods through the adoption of tool-free systems, and reducing the amount of time spent in potentially hazardous environments by substantially improving installation times, are both achievable if innovative EHT cable attachment methods are considered. The chosen attachment method also plays an important role in ensuring that the time spent onsite is minimised. As the ‘fixing points’ at which the EHT cable should be secured to the pipe are so frequent, only small lengths of cable can be attached per installer, per hour. This leads to high labour costs, particularly when considering the wider costs of travel and accommodation in the remote locations where EHT cable installations take place. Some of the most common failure methods which are associated with EHT cables, such as failure from incorrect trace ratio or cables losing contact with the pipe, are fully reliant on the performance of the chosen attachment method. Cable failures lead to the conduction of ‘meggers’ (maintenance checks) which can prove highly timeconsuming and unproductive. Discovering physically damaged cables during the ‘megger’ can often lead to the need to remove and replace a full section of cable which would otherwise still be useful. This can prove to be expensive, particularly when considering mineral insulated cables which often cover vast lengths in one circuit and therefore cannot be cut to replace damaged sections. Whether we are considering an installation from a health and safety perspective, or judging a project by its cable’s performance, ensuring that any EHT cable is protected is paramount to a project’s success. As ‘off-the-shelf’ products, any traditional methods of attachment aren’t specifically developed to be used in conjunction with the application, which presents issues which could otherwise be foreseen. For example, the application of current attachment methods involves applying full tension to the ‘fixing point’ which restricts the natural thermal expansion of the cable/pipe. This leads to the ‘fixing point’ digging into the EHT cable and creating a ‘snag’ which often results in a cable failure. The environmental impact of the chosen attachment method must also be considered. The nature of traditional installation methods means that installation materials will often quickly become redundant, as often one ‘fixing point’ (or ‘wrap-around’) is required per individual cable pass. This process is not only extremely time-consuming from an installation viewpoint – through the use of an unnecessary amount of materials – but time, effort and money is also spent on logistics to transport the materials to site. The risks of these potential issues can be avoided by choosing an innovative attachment method which has been specifically designed for use in conjunction with EHT cable.

Considering the future, today A lack of consideration into the performance of attachment methods for an installation could lead to


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Understandably, there are concerns and considerations which need to be made before an alternative attachment method can be specified for an installation. The feeling that the traditional methods of attachment are ‘tried and tested’ are justified but this doesn’t necessarily make them the most efficient and reliable processes possible. Innovation and the adoption of new technologies is paramount to the future success of the EHT market and this shouldn’t only be restricted to the cable itself.

Conclusion

Figure 2. Gripple Heat Tracing Kit.

a lack of efficiency, reductions in productivity due to time-consuming maintenance checks or even more serious consequences such as cable failures. Each of these issues risks the potential loss of millions of dollars and could be easily avoided by the use of a specifically engineered, fully-tested attachment system which is designed especially for use with EHT cables. Gripple has used its vast experience and knowledge of cable management systems, gained whilst working in the construction and solar industries, to develop an innovative method of attaching EHT cables which operates with the intention of minimising health and safety concerns, reducing installation times and improving reliability. The system has been developed alongside key players within the industry including large-scale EHT cable manufacturers, contractors, installers and engineers, as well as the author of key specification for heat tracing to ensure that the product complies with regulations.

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Whether installing an EHT cable on a longline pipeline – which is designed to take a product from one location to another – or conducting an installation on a self-contained pipe processing skid, the chosen attachment method can make a big difference on the efficiency, safety and performance of the cable. The EHT market is rapidly evolving, meaning new technologies are being adopted and implemented in an attempt to drive safety and reliability. The vast majority of past investments in innovative technologies have been made specifically to develop the performance of EHT cables, with minimal consideration for any improvements in performance which could be offered by an increased understanding of attachment methods. To summarise, it is worth outlining the positive impact which can be had on all project stakeholders if attachment methods are promoted from an after-thought to a serious consideration. Minimised installation times can be made possible for contractors meaning more competitive bidding rates, improvements in reliability can be made possible for engineers meaning less downtime or maintenance checks and a reduction in health and safety risks can be made possible for safety officers meaning minimised risk of accidents onsite. Two key materials are required for the installation of an EHT cable: the EHT cable itself and the selected attachment method. After recent successes in the development of future technologies for EHT cables, it’s time for the market to step away from the past when considering the future of attachment methods.


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coatings

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Some questions from World Pipelines about pipeline coatings.

STEVE CRAWLEY, Group Technical Director and ANDREW STUART, Sales & Marketing Director, Winn & Coales (Denso) Ltd, a member of Winn & Coales International Ltd Steve Crawley is the Group Technical Director of Winn & Coales International Ltd and Managing Director of Premier Coatings Ltd, as well as a Director of Winn & Coales (Denso) Ltd. He joined the Winn & Coales International Group 29 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 32 years ago in 1990 and has broad and extensive experience in technical sales of field joint and mainline coatings. Andrew is an active member of the pipeline industry and was appointed to the IPLOCA Board of Directors in 2021.

Why do pipeline owners/ operators choose your coatings method, and what benefits does it bring? As with most industries there have been trends towards greater mechanisation and automation in coating application to eliminate human errors, improve quality and efficiency. But as a technology neutral company, we recognise that different coating methods each have their advantages and disadvantages. Moreover, the pipeline is paramount. Winn & Coales Denso have been supplying systems for pipeline corrosion prevention for over 90 years. Whether it is a new installation or refurbishment situation, buried or exposed, wet or dry, hot or cold conditions, it is the pipeline and its environment that inform coating selection and that which in turn informs selection of the coating application method. There is no coating method that surpasses all the others, and we offer systems that use all kinds.

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coatings

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Discuss the importance of coating application methods for your product. Coating application methods should be carefully considered when specifying pipeline coating requirements. In some countries, the pipeline coating sector is well organised with recognised programmes of qualification for pipeline coating, for example, as stipulated for field joints by the Canadian Standards Association. Such standards demand product specific applicator qualification. They also clearly define the responsibilities for providing coating procedures and performing coating application. These rest with the coatings manufacturer and the coatings applicator respectively. In other regions around the world requirements may be more relaxed. Nevertheless, irrespective of local requirements, best practise should be followed, and equivalent measures adopted to ensure successful application. It is important to consider the context of specific projects particularly in relation to selecting the best method of coating application. For example, for liquid applied coatings, variable ratio spraying equipment may give excellent results but for other situations fixed ratio kits will be preferred. The circumstances of use should inform the selection. Factors to consider are project scale, site accessibility, equipment mobilisation, operator skill, material transport and storage.

How do you approach quality control? Honest and open communication is the key to ensuring that all personnel within the company, across all departments in the organisation, can contribute to improvements in quality. But quality control is just one tool that contributes to achieving desired outcomes. Any company that relies only on quality control to achieve desired outcomes is an endangered species and likely to go extinct. Quality must be built into all aspects of the organisation. You can’t depend on quality control inspection to achieve a quality product. Proper management of processes is the best guarantee of success, and product quality is the consequence of proper process management. Many vendors like to make claims about the quality of the product. Next time you hear that claim from a vendor why not ask them what personal involvement they have had with improving processes within their organisation. You might receive a reassuring answer, but if you don’t – it might be time to change your vendor.

Describe a recent coatings solution for a pipeline project. Oil India Limited (OIL) is one of the largest public sector hydrocarbon exploration and production companies in India. OIL is presently operating 1860 km of cross-country oil pipeline which runs from Duliajan, Assam to Barauni, Bihar. Due to natural degradation of the existing coal tar coating on the pipeline system, there has been increased demand on the CP system. The addition of more pipeline in the same ROW has further increased the load on the CP system. The Denso Petrolatum Tape System was supplied for the refurbishment of the pipeline and block valves, some of which were in harsh wet, marshy conditions. The chosen coating recommended for this pipeline takes us back to the previous question, that the pipeline conditions and its environment inform the coating selection and application method of a project. In this case the Denso Petrolatum Tape System was selected due to its surface tolerance, water displacing properties, bond to metal surfaces (despite the wet, marshy conditions) and ease of application. Other types of coating would have been impractical to apply and would represent an inferior choice. The challenging condition precluded the use of liquid epoxies, heat shrink sleeves, butyl tapes, and viscoelastic all of these having application requirements that would have been impractical to achieve in the field. This successful refurbishment The OIL India pipeline protected with the Denso™ Petrolatum demonstrates the importance of being technology neutral Tape System can be seen lying underwater in severe and having an extensive range of products available so that conditions. the coating selected is optimal for the project.

44


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Figure 1. Completing a 4702 m horizontal directional drill required a 24/7 effort and the pilot hole intersect method.

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Though horizontal directional drilling (HDD) is considered the most effective pipeline installation method, Raelison Novaes, Michels Corporation, USA, suggests there are still significant risks to address.

C

reated in 1956 by construction of the Garrison Dam on the Missouri River, Lake Sakakawea is part of a flood control and hydroelectric power generation project in North Dakota. With a length of 285 km, an average width of 3 - 5 km and a maximum width of 23 km, Lake Sakakawea limits the ability to transport natural gas takeaway from the Bakken Formation in northwest North Dakota to pipeline interconnects to the southeast. As a result, the existing infrastructure was not sufficient to meet transportation needs for the natural gas produced during the crude oil extraction process. Faced with costly and inefficient options of building hundreds of kilometers of pipeline around Lake Sakakawea or transporting liquid natural gas around the lake in tanker trucks, much of the

natural gas was safely burned as a flare to prevent release of hydrocarbons directly into the atmosphere. Already transporting half of the natural gas produced in the Bakken region, WBI Energy, Inc. (WBI), a subsidiary of MDU Resources Group, Inc., contracted Michels Corporation in 2021 to build the transmission pipeline and trenchless segments of its North Bakken expansion project. Michels is an energy and infrastructure construction company based in Brownsville, WI and serves customers throughout the world. According to WBI, the North Bakken expansion project was designed to provide up to 250 000 dekatherms per day (Dth/d) of firm transportation service from receipt points in the Williston Basin of northwest North Dakota and near WBI’s existing Tioga

47


Figure 2. HDD rigs and water tanks were set up on both sides of the Missouri River to facilitate efficient construction.

Compressor Station to a new interconnect with Northern Border Pipeline Company (Northern Border) in McKenzie County. The mainline pipeline work included construction of approximately 100 km of new NPS 24 (24 in. OD) natural gas pipeline, 50 km of 12 in. OD natural gas pipeline, and 0.96 km of 8 in. (8 in. OD) natural gas pipeline through rolling hills, badlands and prairie. A critical element of the project was completion of a formidable trenchless crossing the likes of which had not previously been attempted at the 24 in. diameter in the world: 4702 m – or about the same distance as a 5 km run. HDD was chosen as the most viable, yet still very challenging, method for the installation. The HDD portion of the North Bakken expansion project was 687 m longer than an HDD Michels completed in the same vicinity just two years earlier. In 2019, that 4038 m installation of a 20 in. OD steel pipe also pushed the limits of HDD technology and was considered one of the longest-ever completed in North America at that diameter. Michels put its team to work studying the project and developing multiple plans to achieve the highest possibility for success with the most minimal chances for injuries or environmental issues. Among major considerations were the following factors.

Distance

Figure 3. Drilling under Lake Sakakawea provided a necessary way to transport natural gas rather than flaring it.

To overcome the long distance, pilot hole intersect was chosen as the ideal method to connect both sides of the lake. The pilot hole intersect method places one drill rig on each side of the project and set each rig off to drill a pilot hole along an engineered bore hole path toward a predetermined intersection point approximately in the middle. Splitting the distance to be drilled between two rigs highly increases the chances of success by significantly reducing torque, improving steerability and, most of all, dramatically reducing the timeline by dividing the pilot hole schedule between two simultaneous operations. Two of Michels’ largest in-house designed and fabricated rigs, each with 500 t of pullback and thrust force, were assigned to the task. The 3760 m of pure water between both sides of project made it difficult to utilise magnetic-based tools. Instead, Michels selected a gyroscopic system to guide drilling of the pilot hole to the intersection point.

Geological conditions

Figure 4. Pipe was pulled into place in two strings, one of 130 m and one of 4573 m.

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World Pipelines / APRIL 2022

In additional to the long distance, the complex geological composition of the location with intercalated layers of clay, sand, silt, coal, and shale presented the need to prevent pressure losses and


inadvertent returns. A more competent formation was encountered at approximately 73 m below the water level corresponding to nearly 100 m of vertical distance to the entry point. A very intense pre-bore engineering and hydrofracturing analyses was followed by constant monitoring of the downhole pressure and returns. Michels took an additional preventive step on installing 220 m of casing on both sides to stabilise the unconsolidated top layers and serve as constrains to distribute push forces along the drill string to the drill bit instead of to the formation.

Environmental protection To secure the lake and the surrounding areas from any unexpected drilling fluid spills, a comprehensive plan was developed for drilling fluid management. The drilling fluid programme was managed by a team of specialists who were onsite 24/7 during drilling operations to monitor and maintain constant control of drilling fluids and drilling parameters whenever needed. After the intersect was completed and the two rigs were connected by the long drill string, the Michels crew used an in-house designed and fabricated 36 in. hole opener to enlarge almost 5 km in one single pass. The immense volume of water needed to keep up with the increased flowrate from the pilot hole to the reaming stage required specifically designed water tanks to be built onsite to ensure operations would continue uninterruptedly and the hole was always free of cuttings. At the same time, Michels Pipeline, Inc. was preparing the 24 in. product pipe to be pulled into place. Finding adequate space to lay down 5 km of pipe was a challenging task. A large amount of space was required because it was crucial to avoid mid-welds during pullback installation. Stopping during long pullbacks can increase forces, which can undermine the odds for success. With that in mind, two segments were welded separately, a 130 m section was the first segment to be pulled in, a 4573 m section as a second and last. Finally, after nearly a month, reaming was completed, and the crew was ready to swab and make sure the hole was ready to receive the long string of 24 in. pipe and seal the project. Once more, it was time for Michels Pipeline, Inc. to come

back, this time to move the product pipe to its final position for pullback. To get to that point, an incredible level of coordination was required to keep the crew safe while working with heavy lifting equipment to position the 24 in. pipe in the break-over curve. Prior to initiating pullback, Michels trenchless team had prepared a pipe thruster at the site to be used to assist breaking the inertia at the start of the pullback, or in the event the forces become too high, and the rig needed to be assisted. However, the pipe thruster was not needed. After two days, the pullback was successfully completed and Michels had, once again, proven the lengths can be pushed further than previously been done, contributing to the future of the trenchless industry.


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Mark Wood, Technical Sales Manager, ROVOP, explores how to optimise the use of ROVs for deepwater pipelay operations.

R

emotely operated vehicles (ROVs) are an indispensable tool used across all stages of a pipeline’s lifecycle to ensure safety, integrity, stability and protection. From the initial survey and commissioning to regular inspection, repair and maintenance (IRM), and finally, decommissioning, ROV services are always in demand. In the North Sea alone, Shell has more than 200 pipelines and umbilicals, totalling 3000 km in length.1 To satisfy growing energy demand, more and more offshore pipeline systems must traverse remote and extreme terrain and environments, or cross territories that differ in their regulatory

regimes and requirements. Such CAPEX and OPEX demands, as well as building momentum to support renewable endeavours, means the ROV must keep pace to identify and solve an array of challenges quickly, efficiently and safely. ROVOP has provided high performance ROV services to the oil and gas and subsea sectors since it was founded in 2011 and is expanding its offering in the renewables arena (Figure 1). Ten years on, the independent specialist is on a strong growth trajectory having secured contracts valued at £25 million in the last six months for a diverse spread of work across offshore energy sectors in Europe, Middle East, Asia Pacific and

51


the Americas. The growth comes on the back of several recent contract wins, including the firm’s first contract with Sapura Energy to provide trenching and survey support off Mexico. The new contracts also involve dive support, IRM, decommissioning, cable lay and construction surveys for new clients, Prysmian Group and Mermaid Subsea Services Thailand, among others (Figure 2). The contract wins, along with a financial restructure in 2020, have placed the Aberdeen-headquartered business in

Figure 1. ROVOP celebrated its first decade of operation in 2021.

Figure 2. ROVOP is investing in its people, services and fleet due to increasing demand.

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World Pipelines / APRIL 2022

robust financial health with positive cash flow and available working capital to invest in its people, services and its fleet to meet future demand. Since opening its new 22 000 ft2 facility in Houston in 2015, the company has seen y/y growth with revenue rising to US$10 million and predicts grow to US$16 million within the next three years.

ROV touchdown monitoring support In recent years, one of the key focus areas of the offshore pipeline industry is creating cost efficiencies across each stage of a pipeline’s lifecycle. This, combined with increased growth in the amount of subsea infrastructure now in situ on the seafloor, as well as societal pressure for more sustainable operations, has seen a rising need for innovative approaches to support installation operations. These solutions need to be cost-efficient, maintain data quality, and be able to provide a platform that supports future technologies (Figure 3). Underwater vehicles therefore, have had to undergo a rapid transformation from high risk, untethered manned submersibles in the 1960s to smart, fast and autonomous vehicles with a broader digital reach and capabilities which has completely changed the provision of touchdown monitoring (TDM) support to the lay vessel during the lay process. This involves the ROV positioning itself at the point where the pipeline touches the seabed and then maintaining that touchdown position as the lay vessel progresses. This is particularly important to ensure the lay vessel accurately knows the lay down point relative to the vessel position, and can manage the pipeline tension accordingly. This procedure is also critical to confirm the pipeline’s integrity as it is laid on the seabed clear of obstructions. By the very nature of this task, with the pipeline disturbing the seabed, visibility is normally very poor, and skilled ROV pilots are vital for success. Additional sensors, including real-time imaging sonars and multi-beam echo sounders can assist with positioning the ROV when a visual reference is not possible. Other ROV aids, including station keeping, can also assist in reliably positioning the vehicle during this challenging process. There are some inherent challenges and risks to the ROV during the TDM operations. For shallow water pipelay operations (depths ≤50 MSW) where the ROV is deployed directly from the lay vessel, the ROV and its tether (the cable that delivers power and bi-directional communications to/ from the ROV) may be in very close proximity to the vessel stern thrusters. Any collision with the stern thrusters will lead to catastrophic damage to the ROV and potential thruster damage. This risk is mitigated by a combination of factors, one of which includes constant monitoring of the subsea currents strength and direction to ensure the ROV and its tether are always in a ‘blow off’ scenario from the vessel thrusters. On vessels where there are dual ROVs installed, one on each side, changing the operational ROV may support this mitigation. During periods of potential risk from the ROV tether fouling in a blow on situation, and if no other mitigation is possible, the ROV can stand off from the TDP and monitor the


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Figure 3. In 2020, ROVOP delivered its first remote platformbased inspection, repair and maintenance work scope, effectively reducing the number of personnel required offshore.

proximity of the TDP. ROV Inertial Navigation System (INS) can also improve ROV positioning accuracy during lengthy excursions from the vessel. For deepwater pipelay operations, where the ROV is deployed directly from the lay vessel, the stern thruster proximity risk is mitigated as the tether management system (TMS) will be positioned at depth before the ROV commences operations. On these projects, the distance between the ROV launch area and the touchdown point will be significant, often much more than 1000 m. Historically, projects of this nature would always have a support vessel to assist with TDM. However, the latest generation of ROV systems can be supplied with a TMS that can support greater capacity of tethers of more than 1500 m in length. Obviously, with such a long length of tether deployed, management of the tether to avoid seabed obstructions and entrapment under the pipeline during the lay process is crucial. Regardless, whether the TDM support ROV is installed on the lay vessel or another support vessel, ensuring lay vessel up-time is critical. Reliability of the ROV is very important to ensure uninterrupted TDM support, particularly in deepwater projects where turnaround time for return to deck to instigate repairs can be substantial. Over the past three years, ROVOP has been involved in several jacket and pipelay construction projects in shallow and deep waters globally involving its fleet of ROVs, which include: )) The Schilling HD 150hp Work Class ROV (WROV) systems (Figure 4). These WROVs and associated launch and recovery systems (LARS) can deploy a full range of hydraulic tooling and ROV sensors. The integrated modular design philosophy enables rapid maintenance in the field. )) The Triton XLX 150hp Work Class ROV systems (Figure 5).

These WROVs are heavy-duty, multi-purpose, and particularly tailored for construction and survey tasks, boasting 1100 kgf of thrust. Figure 4. The integrated modular design philosophy of the Schilling HD enables rapid maintenance in the field.

pipe and TDP using a sonar. The addition of a current meter will allow pilots to monitor the currents and take evasive action when required. Another mitigation is to fly the ROV through a ‘golden gate’. This is a mechanical structure, suspended in the water column, that the ROV will fly through on its way to the touchdown point. The golden gate will be suspended by the vessel crane or davit, outboard from the vessel at a suitable safe distance, generally by 20 - 30 m, adjacent to the stern thruster. Under certain circumstances in shallow water, the reliability of the vessel’s ultra-short baseline (USBL) system for ROV positioning can be adversely affected, either due to the beam angle or due to the vessel thrusters creating turbulence. This can normally be eliminated with the addition of an auxiliary USBL transducer mounted on an ‘over the side pole’, or by using an unmanned surface vessel with USBL transducer in the

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With several new contracts now in the pipeline, ROVOP has embarked on an active recruitment campaign. For instance, it is aiming to increase the 30 strong Houston-based headcount by at least 50%, to support future and existing clients, including its ongoing work for a major Tier 1 contractor on projects around the world.

Diversification for decarbonisation ROVOP has also renewed existing contracts in the offshore wind sector after investing in its fleet with the addition of two Schilling HD work-class ROVs. Both will be deployed on a Scottish wind farm for EDT Offshore. Over the past decade, the company has built a significant spread of contracts performing seabed surveys, UXO identification, boulder clearance, construction and cable installation support and IRM. The following ROVs with associated LARS are currently undertaking various cable lay support projects for the European wind farm market in shallow and turbid inshore waters, where they constantly operate at lengthy excursions to aid cable pull-ins at wind farm structures:



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Figure 5. The Triton XLX is a heavy-duty, multi-purpose ROV system, particularly tailored for construction and survey tasks.

)) The Schilling UHD Generation III is a 250 hp vehicle which

can handle all ultra-heavy-duty requirements and retains all the features of the Schilling HD ROV system including 60 min. repair philosophy and automated functions and tooling. When fitted with the FMC Technologies Isol-8 pump, it is also capable of meeting the American Petroleum Institute (API) 53 standards for secondary BOP intervention. )) The SAAB Seaeye Panther XT Plus is a light work class ROV,

capable of working in up to 2 knot currents and depth rated to 1500 m. They can carry a survey spread, limited tooling, and are fitted with dual manipulators as standard. This ROV type is particularly useful on smaller vessels which do not have adequate deckspace for a full size WROV.

bound insert 17 9 25 OBC 7 42

A golden gate system, as is often used for touchdown monitoring in pipeline construction, has been used in several instances on cable lay projects in the wind sector.

References 1.

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