World Pipelines November 2022

®

Volume 22 Number 11 - November 2022

The leading innovator supplying cutting-edge integrity solutions. Together we can ensure sustainable decision-making. Our combination of advanced inspection systems and expert consultants delivers a comprehensive understanding of asset safety, lifetime, and performance.

Comprehensive Asset Integrity Management

www.rosen-group.com

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CONTENTS WORLD PIPELINES | VOLUME 22 | NUMBER 11 | NOVEMBER 2022 03. Guest comment

PIGGING

Emily McClain, Vice President, Rystad Energy, USA.

05. Pipeline news

Nord Stream damage, Druzhba pipeline, and recent contract news.

&

37. Featuring ROSEN We ask Abco Enters, Ulrich Schneider, Chris Holliday, and Corey Richards about pipeline pigging.

08. Staying in the loop

John Hartley, Levidian, CEO, UK, discusses bringing the hydrogen transition within reach.

TUBE AND PIPE 41. Cutting edge technology

13. Exploring compression applications

Laura McShane, Decom Engineering, Northern Ireland.

Klaus Brun, Director of Research & Development, Elliott Group, USA, discusses how hydrogen can be a viable energy transport and storage medium in a decarbonised energy economy.

PIPELINE SERVICES 44. Carbon neutral ownership

21. Confronting climate change

Seth Tate, Manager of Contracts & Digital Offering, Sulzer, USA.

Takashi Goto, Vice President of Strategy, NTT Research, Japan, considers how existing pipelines can transform the global adoption of hydrogen energy.

25. Achieving accurate leak detection

Pedro Barbosa, Fotech, UK, a bp Launchpad company, reviews the various challenges hydrogen presents, and discusses how distributed acoustic sensing (DAS) provides an accurate and faster leak detection solution for smaller leaks.

These cutting-edge proactive maintenance techniques optimise pipeline pump management to maximise uptime and energy efficiency, says Seth Tate, Manager of Contracts & Digital Offering, Sulzer, USA.

CORROSION CONTROL 27. Protecting the unseen

ore than 285 000 miles (460 000 km) of pipelines are used to move liquid hydrocarbons to terminals and refineries around the world. This requires roughly 121 terawatt-hours per year which equates to 86 million t of CO2.1 While innovation is the major factor for improving energy consumption in new equipment, avoiding unexpected downtime and optimising existing asset performance presents the greatest opportunities for pipeline operators. Sulzer’s new and innovative approach connects technology to decades of experience in pump system engineering and maintenance to maximise equipment uptime, as well as efficiency.

Today, sustainability is being written into national laws, setting goals for a net-zero target in 2050. Governments are encouraging businesses to adopt more sustainable initiatives to the point that some major projects can only be won by companies that have made a commitment to the net-zero goal. In the oil and gas sector, many major operators joined the Oil and Gas Climate Initiative (OGCI), which aims to accelerate the industry’s response to climate change.

Julie Holmquist, Cortec® Corporation, and Tim Whited, MESA, USA.

COVER STORY 32. The ‘ART’ of pipeline inspection

Simplifying the reliability equations Looking in detail at the root cause of asset failure, as well as the latest innovations in technology, reveals how the energy consumption of a pipeline depends on several factors such as maintenance techniques, operator acumen, inventory management, and reliability-based actionable intelligence.

John Musgrave and Ian Moreau, MISTRAS Group, USA.

Operators are forced to focus on after-the-fact, highconsequence issues because they struggle to consistently relate equipment conditions to maintenance efforts and classleading technology.

This often leads to pushing the other operational assets harder, thus trading optimal efficiency with the need to maintain shipping rates. There is a lot to be said about the growth in big data analytics for pumps, but one thing is clear – it is not taking the place of the human resource, rather it is amplifying their value. Sulzer now has a solution that changes the narrative from reactive to proactive actions. Using artificial intelligence (AI), technical expertise, and proactive management techniques, Sulzer provides a competitive advantage with minimal capital investment.

Working as an operating partner, Sulzer offers Total Pipeline ServicesTM (TPS) to connect a range of services designed to improve the economic strength of pipeline pumping systems.

This flexible and simple-to-manage approach optimises pump performance, which directly reduces carbon emissions, supporting the company’s sustainability objectives.

Impacting CO2 emissions

In 2019, Sulzer began the journey to provide a solution to help customers stabilise OPEX budgets, continuously monitor pump health, and engage expertise for the best asset performance. The ability to optimise pump performance and predict issues before they become a concern has the potential to significantly reduce levels of CO2 associated with the industry.

Employing new forms of communication, Sulzer uses existing pump health monitoring as well as industry-leading expertise to focus on the heartbeat of the equipment. By illuminating pre-failure conditions and energy waste, each pump can benefit from optimised efficiency as well as reliability to ensure minimal energy demand and associated emissions.

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PIPELINE MACHINERY 47. Coming out on top

Todd Razor, on behalf of Vacuworx, USA.

LEAK DETECTION 52. In need of (outer) space

John Musgrave and Ian Moreau, MISTRAS Group, USA, outline the benefits of using proven, innovative automated radiographic testing (ART) technology for pipeline and piping integrity screening. valuating pipeline and piping integrity, particularly on insulated lines, can be a challenging endeavour. Despite the many traditional and advanced techniques and technologies available to integrity and inspection managers, each method typically comes with a downside in the form of high costs, extended time requirements, operational impacts, requirements to strip insulation, and more.

Inline inspection (ILI) is typically considered the gold standard for identifying corrosion, but this time, cost, and labour-intensive process comes with a major opportunity cost because it requires pipelines to shut down operations during the inspection, in addition to oftentimes rigorous maintenance requirements to prepare the line for the ILI tool run.

Advancements in automated radiographic testing (ART) technology – developed by MISTRAS Group, a One Source provider of asset protection

Figure 1. MISTRAS’ ART crawler services offer single-view and multi-view radiographic scans, with the ability to simultaneously analyse the top, bottom, and sides of piping with a two-axis robotic arm to autonomously drive over supports without the need for multiple set-ups or systems.

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WORLD PIPELINES

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Jesse Hughes, Orbital Sidekick, USA.

NOVEMBER 2022

ON THIS MONTH'S COVER

®

Volume 22 Number 11 - November 2022

Reader enquiries [www.worldpipelines.com]

www.worldpipelines.com

Member of ABC Audit Bureau of Circulations Copyright© Palladian Publications Ltd 2022. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

ISSN 1472-7390

CBP006075

MISTRAS Group’s comprehensive range of pipeline non-destructive evaluation (NDE) inspection solutions help keep pipeline networks in service and flowing safely. MISTRAS’ advanced technology, such as the company’s automated radiographic testing (ART) crawler services, help detect internal corrosion, pitting, and corrosion under insulation (CUI) in aboveground piping and pipelines, without stripping insulation or removing product from the lines. For more information, visit pipelines.mistrasgroup.com.

OFC_WP_November_2022.indd 1

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eopolitical events have led to a bullish outlook for global gas markets this year, a trend set to continue in the coming decades as demand for LNG grows. As well as developing gas field assets, this will require ongoing investment in infrastructure, including new pipelines to connect gas fields to LNG export terminals.

With the US set to play a primary role in supplying LNG to meet international demand, especially in Asia and Europe, substantial investment and construction of new pipelines Emily McClain will be needed to ensure the Haynesville, Vice President, Rystad Energy, USA Permian and Appalachia plays can drive continued production growth.

Between now and 2024, the Haynesville will be the primary driver of dry gas production growth in the US. During this period, the global gas market will remain tight, but we expect the Haynesville to continue accommodating the fundamental growth needed. There is a healthy amount of investment in infrastructure and pipeline takeaway commitments in the area, so it is unlikely we will see bottlenecks if all proposed projects move forward on schedule. Projects such as Louisiana Energy Access (LEAP) Expansion, Haynesville Global Access Pipeline (HGAP) and Louisiana Energy Gateway (LEG) will lay the foundation for long-term production and transport of the region’s dry gas resources.

Beyond 2025, with the addition of LEG and possible new pipelines, such as the proposed Gulf Run expansion that could ramp up later in 2025, the basin should continue producing at a high level for years to come. This includes supplying new LNG export capacity as most large operators have at least 15 - 20 years of remaining core inventory.

Permian Basin activity levels support robust structural growth for the basin in the next few years. However, growth will be non-linear and impacted by pipeline takeaway capacity. In addition, we expect short-term regional balances to remain tight, with potential infrastructure bottlenecks as early as 2Q23. Increased supply potential is supported by additional pipeline projects, adding more than 6 billion ft3/d of incremental capacity, rising from current nameplate capacity of 17.5 billion ft3/d up to 23.8 billion ft3/d over the next two years. The region continues to push the upper bounds of growth potential and is set to be the second-largest regional contributor. We anticipate the Whistler Permian Highway and Gulf Coast Express expansions will add 1.7 billion ft3/d in additional pipeline takeaway in 2023. Beyond this, we do not expect any additional pipeline takeaway capacity until mid-2024, when Energy Transfer’s New Permian Pipeline is expected online, and the Matterhorn Express pipeline in mid to late 2024. Together, these two projects will add 4.5 billion ft3/d in 2024. Additional pipeline takeaway capacity will help keep regional price differentials in check while ensuring the Permian is set for robust growth. However, compared with the dry gas supply forecast, regional balances will remain tight.

While Appalachia has seen its ‘unfair’ share of project delays and cancellations, it still plays a vital role in the future of US gas production with some growth expected.

The much-anticipated Mountain Valley Pipeline (MVP) currently under construction, along with planned pipeline projects Northern Access 2016 and Regional Energy Access, are expected to move forward and add just under 3 billion ft3/d, enabling the Northeast to potentially export over 38 billion ft3/d by 2025.

In summary, with several US infrastructure projects planned for the coming decade, Rystad Energy expects US gas production to rise 20% from this year’s levels by 2032, positioning the country as the world’s leading exporter over the long-term. This will be ideal from a geopolitical perspective: not only will it make the US an ongoing source of reliable supply, but global markets will significantly benefit from accessing US gas. We just need to see the pipelines and facilities completed to realise the country’s true potential.

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WORLD NEWS Druzhba oil pipeline repaired after leak The Polish operator of an oil pipeline running to Germany confirms that it has fixed the damage that caused a leak in mid October, and that the flow of crude oil from Russia has been fully restored.

The state-run operator, PERN, said that both lines of the Druzhba pipeline were operating normally, transporting oil.

The Druzhba oil pipeline linking Russia and Germany was partly shut after a leak was discovered in Poland, Pern said on 12 October. “The cause of the incident is not known for the moment. Pumping in the affected line was immediately stopped. Line 2 of the pipeline is functioning normally,” the operator said at the time.

The German government said oil deliveries were continuing to two key refineries, despite the leak. “Germany’s security of supply is currently guaranteed … Deliveries are uninterrupted,” the economy ministry said in a statement.

The leak on an underground segment of the Druzhba

pipeline was detected late on 11 October near the village of Zurawice, about 110 miles to the west of Warsaw.

A Pern spokesperson, Katarzyna Krasinska, told AFP that firefighters were pumping out the spilled oil, “which could take several hours”. The pipeline mainly supplies two refineries in Schwedt and Leuna in Germany.

The Druzhba (Friendship) pipeline network was put into service in the 1960s and covers 3400 miles, pumping oil from the Urals to Europe through two main branches via Belarus and Ukraine.

Germany said it was receiving less oil but still had adequate supplies. Warsaw said it was probably caused by an accident rather than sabotage.

Poland’s top official for energy infrastructure said there are no grounds to believe the leak was an act of sabotage.

“Here we can talk about accidental damage,” Mateusz Berger said.

Extent of damage to Nord Stream pipelines revealed Swedish newspaper Expressen has published photographs and film footage taken by an underwater drone at the site near the island of Bornholm, where the Nord Stream gas pipelines between Russia and Germany ruptured on 26 September.

Footage appears to show long tears in the seabed near the concrete-reinforced steel pipe. The pipe is not merely cracked but torn apart, in an act of suspected sabotage. At least 50 m of the gas pipeline appears to be missing, Expressen said.

Three separate investigations are currently trying to assess the full extent of the damage to the two twin pipelines, Nord

Stream 1 and 2, and collect evidence as to who was behind the sabotage.

Europe is investigating what caused three pipelines in the Nord Stream network to burst in an act of suspected sabotage near Swedish and Danish waters.

Sweden’s prosecution authority said in a press release that it had designated the area a crime scene. A spokesman for the Swedish coast guard confirmed in an email that there was now an exclusion zone of five nautical miles around the leaks.

Event round-up: IPLOCA’s 54th annual convention Gonzalo Montenegro, IPLOCA President 2021 - 2022, welcomed just over 400 IPLOCA members to the Annual Convention in Prague from 19 - 23 September, with the theme: ‘Pipelines Powering a Sustainable Future.’

This year’s speakers addressed how to anticipate and overcome the challenges presented by the increase in alternative energy sources; the restrictions and guidelines for reducing carbon footprint; and the related repercussions faced by the pipeline industry. A new technology revolutionising underground construction was presented, and one of the IPLOCA members entered the Guinness Book of Records.

Poster sessions were given by CRC Evans, Cyntech Group, Gulf Energy Information, LCS Cable Cranes GmbH, Monti-Werkzeuge GmbH, Pipeline Induction Heat, and Winn & Coales International Ltd. Ten minute business-to-business meetings were offered by member companies Bechtel Pipelines, Bonatti S.p.A., Fluor, Sicim S.p.A., TC Energy and Techfem S.p.A., and were fully booked.

IPLOCA is proud to announce that for the 7th year running, 20 scholarships of US$4500 each were awarded to children or grandchildren of employees of IPLOCA members.

During the OGMs the awards for 2020, 2021, and 2022 were given for Health & Safety (sponsored by TC Energy); the

Environment (sponsored by Shell); Corporate Social Responsibility (sponsored by Total); New Technologies (sponsored by BP); and for Excellence in Project Execution (sponsored by IPLOCA).

This year IPLOCA welcomed 14 new members.

Montenegro presented his ‘Year in Review’ and showed how the Association has slowly moved back to normality after the pandemic by holding more and more face-to-face meetings. During his presidential term, four face-to-face board meetings, two regional meetings, two Novel Construction sessions and an HSE & CSR workshop on sustainability were held. Membership figures have also slightly increased compared to last year.

Montenegro thanked the Board for their hard work this past year before passing the gavel to Kelly Osborn, the incoming President for the 2022 - 2023 term. Roberto Castelli was elected 1st Vice President, Leon Richards 2nd Vice President, and Adam Wynne Hughes as Treasurer. The results of the 2022 - 2023 Board of Directors’ nominations were ratified during the AGM. The IPLOCA team looks forward to seeing all its members next year in Vancouver, Canada from 11 - 15 September 2023.

NOVEMBER 2022 / World Pipelines

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CONTRACT NEWS EVENTS DIARY 16 November 2022

Global Hydrogen Conference 2022 VIRTUAL www.globalhydrogenreview.com/ghc22

6 - 10 February 2023

Pipeline Pigging and Integrity Management Conference and Exhibition Houston, USA www.ppimconference.com

7 - 11 February 2023

PLCA Annual Convention Hawaii, USA www.plca.org/annual-convention-events

13 - 15 February 2023

Pipeline Coating 2023 Vienna, Austria www.ami-events.com

20 - 21 February 2023

Transportation Oil and Gas Congress 2023 Istanbul, Türkiye www.togc.events

20 - 25 February 2023

DCA Annual Convention 2023 Miami, USA www.dcaweb.org/page/Convention

19 - 23 March 2023

AMPP Annual Conference + Expo Denver, USA www.ace.ampp.org

27 - 29 March 2023

European Gas Conference 2023 Vienna, Austria www.energycouncil.com/event-events/europeangas-conference

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World Pipelines / NOVEMBER 2022

bp awards Wood multi-region contract Wood, the global consulting and engineering company, has been awarded a multi-region engineering services contract by bp to support efficient and safe energy production through the provision of asset repairs, modifications, and enhancements.

The five year reimbursable contract, valued at around US$350 million, will be delivered via agile working methods to optimise cost and delivery performance, enabling operational efficiencies to be realised across bp’s offshore installations.

This agreement renews Wood’s existing contracts in the regions to support bp to produce energy safely, efficiently, and reliably, as the world contends with the dual challenges of energy security and transition.

Craig Shanaghey, Executive President of Operations at Wood, said: “This opportunity is exciting for Wood because it has allowed

Subsea7 charters Jones-Act compliant vessels Subsea7 has entered into four long-term vessel charter agreements with Otto Candies LLC and Bordelon Marine LLC, to strengthen offshore construction, inspection, maintenance and repair (IRM), ROV survey, and pipe/umbilical laying support operations, in the Gulf of Mexico.

Grant Candies, Wyatt Candies and Ross Candies are IRM, survey, and light construction vessels under charter with Otto Candies LLC. The Connor Bordelon is a multipurpose supply vessel under charter with Bordelon Marine LLC. The contracts have differing start dates and durations, with options for extensions.

Jonathan Perzan, Subsea7 Operations Manager for Global IRM – Gulf of Mexico, said: “These vessel charters demonstrate Subsea7’s commitment to this region’s inspection, repair and maintenance business, and our ability to support our clients in the Gulf of Mexico. We look forward to continuing the safe and successful operations we have been executing with Otto Candies LLC and Bordelon Marine LLC.” Steve Wisely, Subsea7 Senior Vice President for UK & Global IRM, said: “The continued demand for subsea services in the Gulf of Mexico region has led to these important charters for Subsea7. The charters will support the sustainable growth of our operations, and are well-positioned to secure a wide range of conventional energy and renewables opportunities, as well as other energy transition projects in the future.”

us to think big, knowing that with bp’s own bold ambitions, we can help meet the world’s energy needs as efficiently as possible. Being able to truly leverage the breadth of experience and capability from right across our business will allow us to provide a solution that delivers transformational results.

“We have an extensive track record with bp and, for the first time, this multi-region approach allows us to combine these contracts into one single delivery model that puts exceptional execution, innovation, and simplification at its heart.”

Brian Chalmers, responsible for Wood’s global relationship with bp and President of Strategy and Development for Operations, said: “I am delighted that we will have the opportunity to drive a step change in the performance of bp’s offshore portfolio.”

THE MIDSTREAM UPDATE •

Rockwell Automation and Cognite form strategic partnership

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Alberta Carbon Grid secures rights to evaluate carbon storage area

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px Group awarded contract

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DNV joins new European Fund

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Energy crisis reinforcing two speed energy transition in short term – report

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John Hartley, Levidian, CEO, UK, discusses bringing the hydrogen transition within reach.

any countries are banking on hydrogen to be an alternative clean energy source to fossil fuels as we transition to net-zero. Last year, the UK published its net-zero strategy, a 400-page document detailing the future of carbon emissions in the country. The strategy sets out ambitious goals, such as the UK being completely powered by clean electricity by 2035. The Department for Business, Energy and Industrial Strategy (BEIS) and Ofgem aim to introduce 40 GW of offshore wind power, and boost investment in wind, but there are fears this will not happen fast enough to meet the country’s goals.

This is where hydrogen comes in; when published, the strategy aimed to deliver 5 GW of hydrogen production by 2030, whilst halving emissions from oil and gas. It emphasised the need to “manage the transition in a way that protects jobs and investment, uses existing infrastructure, maintains security of supply, and minimises environmental impacts”. In July of this year, the strategy was updated and the UK has set the new goal of achieving 10 GW of low carbon hydrogen production capacity by 2030, double the previous target unveiled under its national Hydrogen Strategy in August 2021.

But there are challenges with making hydrogen a viable energy source – such as corrosion, flammability, transportation, and cost – which all need to be addressed to ensure we can meet this target. In 2019, the University of Southern California interviewed Paul Ronney, a USC Viterbi School of Engineering Professor of aerospace and mechanical engineering who studies combustion and propulsion, who said hydrogen faces barriers in becoming a reliable renewable energy. Ronney explained that one of the issues with hydrogen is that there’s virtually no pure hydrogen on Earth because it’s so reactive. Most hydrogen is made from methane in a process that produces carbon dioxide and other greenhouse gases, which ultimately causes further harm to the environment.

The pressure problem The storage of hydrogen also poses a challenge, as it requires highpressure tanks or in more complex settings – like fuelling vehicles, hydrogen requires fuel cells which end up being very costly as they use expensive materials such as platinum. In pipelines, which are integral to transporting hydrogen, ‘embrittlement’ can weaken metal or polyethylene pipes and increase leakage risks, particularly in high-pressure pipes, according to a 2013 study from the US Energy Department’s National Renewable Energy Laboratory (NREL).

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These concerns have been echoed by the UK’s National Grid. “Hydrogen can attack the metal structure under certain circumstances, certain pressures, certain concentrations,” the National Grid’s Anthony Green said. “That’s an area the material’s scientists are trying to tackle” as part of the UK’s hydrogen research.

Hydrogen National Grid is currently testing how to best transport hydrogen through existing gas pipelines. Its FutureGrid programme, for example, aims to show how the UK could re-purpose our gas network to safely and effectively transport hydrogen across the country.

Transporting, storing, and delivering hydrogen is also expensive. Because hydrogen contains less energy per unit volume than all other fuels, it takes more money to get it from A to B on a per gasoline gallon equivalent basis. Building a new hydrogen pipeline network therefore involves high initial capital costs as hydrogen’s properties present unique challenges to pipeline materials and compressor design.

Nuclear projects Other renewable infrastructure programmes face similar expensive challenges. With renewable energy from nuclear plants being too costly, too slow, and too dangerous.

According to the World Nuclear Industry Status Report nuclear energy costs between US$112 and US$189/MWh to produce, whilst generating solar power ranges from US$36 to US$44/MWh. Before leaving his post, Prime Minister Boris Johnson pledged £700 million for a new nuclear power plant on the Suffolk coast; the project, which is being developed

by French energy company EDF, is estimated to cost about £20 billion overall.

This massively costly project would not even begin to produce electricity until the 2030s. The 2021 World Nuclear Industry Status Report estimates that since 2009, the average construction time for reactors worldwide was just under 10 years, which in of itself is a long and complex process that releases a lot of CO2.

Graphene However, with Levidian graphene we could improve our existing infrastructure to accelerate the transition from natural gas to hydrogen. Levidian’s LOOP decarbonisation device uses plasma technology to crack methane into its component atoms – carbon and hydrogen. These carbon atoms are then locked away in the form of high-quality graphene. Graphene’s unique characteristics, when added to coatings, can help us prepare and strengthen our existing pipelines for more hydrogen.

To address some of the challenges presented by transporting and storing hydrogen, National Grid could reinforce parts of the gas pipe network by using just a small amount of graphene as a corrosion-resistant and waterrepellent internal coating – making it more able to carry increased quantities of hydrogen and less likely to crack.

This would allow existing gas pipelines to be repurposed, minimising disruption, and making the switch to hydrogen

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World Pipelines / NOVEMBER 2022

easier for consumers and businesses. LOOP can be deployed with ease to most sites that produce methane or use natural gas – from factories, to decommissioned oil and gas wells, to wastewater treatment facilities and landfill sites, Levidian can deliver pure hydrogen or a partially decarbonised hydrogen-methane blend, which could be game-changing for hard to decarbonise industries with complex process heating needs.

Levidian’s Chief Production Officer, Ian Hopkins explains “The LOOP systems we have developed are fully containerised, and use automated process equipment packages that split a continuous flow of methane into hydrogen and graphene. This could be used to feed into gas networks at distribution or transmission level, with the graphene being a useful byproduct for internal pipe coatings and a multitude of other applications. We can also deploy LOOP at the consumer end of the gas transportation network, and deliver whatever the required hydrogen mix needs to be to suit the incumbent combustion equipment.

This point of use application really helps the network because some of the volume implications of hydrogen as an energy carrier are alleviated. The network will need to transition quite slowly to suit the minimum level of consumer hydrogen readiness, but there may be customers that can act faster and do want hydrogen rich gas blends or even pure hydrogen today. These consumers can stay attached to natural gas networks and do the hydrogen recovery themselves with a LOOP system.

Utilising methane We are on a mission to enable natural gas to remain an essential part of the energy mix, while simultaneously preventing it from creating any CO2. Natural gas and other methane sources do not need to be regarded as a carbon contributing fuel if they are managed correctly.”

LOOP will not only help to bolster the transport of hydrogen in our network, but can actually help create it too.

By cracking methane, Levidian produces clean hydrogen in the process. This can then be used immediately as a loweremissions hydrogen-methane blend, or separated and utilised as pure hydrogen. Recently, Levidian has announced two ground-breaking partnerships. The first is with Zero Carbon Ventures to slash half a million t of CO2 equivalent in the UAE using LOOP to turn waste methane into hydrogen. The second is a trial with the UK’s largest listed water company, United Utilities, to see how LOOP can be used to turn biogas from wastewater sources into hydrogen.

Conclusion Levidian’s LOOP can help deliver the clean energy transition by decarbonising existing energy sources, creating clean hydrogen, and enabling our existing network to carry it.

The LOOP system may also deliver a very compact solution for vehicle refuelling without the need for high quantities of high-pressure hydrogen shipping and storage. National Grid’s initiative to trial LOOP technology is only the beginning. The transition to hydrogen as a sustainable renewable energy source is now within our reach.

5 February 6 - 10 • Houston

The industry’s only forum devoted exclusively to pipeline pigging for maintenance and inspection This event will draw engineering management and field operating personnel from both transmission and distribution companies concerned with improved operations and integrity management.

INTERNATIONAL CONFERENCE Technical papers will cover ILI data assessment, prioritisation of repairs, new tools, improving tool performance, external coating inspection with ILI tools, pig launch and receiving systems, new regulations and much more.

EXHIBITION Visit one-on-one with the world’s top providers of pigging, ILI, and integrity management services – over 170 companies will be represented.

TECHNICAL TRAINING COURSES 7 in-depth, technical pipeline training courses will be held prior to the conference and exhibition. Upskill your workforce for 2023.

Register now at www.ppimconference.com

Klaus Brun, Director of Research & Development, Elliott Group, USA, discusses how hydrogen can be a viable energy transport and storage medium in a decarbonised energy economy.

D

ecarbonising the world’s energy supply requires significant changes in the energy transport infrastructure. All energy must be transported from the place of production or extraction to its place of final industrial or domestic usage. The most cost-efficient method of transporting large quantities of energy over long distances is in the form of a gaseous or liquid fluid via pipeline and pumping or compression. The hydrogen economy is a critical part of the trend toward the decarbonisation of the energy sector. Hydrogen is a highly reactive gas that does not occur in its pure state in nature. It binds with other elements to form water, ammonia, methane, and many other hydrocarbons. It cannot be considered an energy source, but rather an energy carrier and energy storage medium. Since the most basic, highly exothermic reaction of hydrogen with oxygen yields clean water, it has significant

potential as an intermediary transport gas in a decarbonised energy value stream.

Major energy infrastructure changes are required to meet the production, transportation, storage, and usage needs of a functioning hydrogen economy. This includes the need to develop compressors that are very different from those currently used. For hydrogen to be a viable energy carrier, compressors must operate efficiently and reliably, and must be economically viable.

Hydrogen compression Compression applications in the hydrogen value stream do not depend on the type of hydrogen used, but on the pressures and flow rates at which the hydrogen is produced. Green hydrogen from renewable energy sources is mostly produced at low pressures using electrolysis, and must be compressed,

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whereas blue/grey/black hydrogen often exits the production process at elevated pressures and requires less compression to enter the pipeline transportation stream. The hydrogen’s purity can significantly affect compressor selection, since even small quantities of other gases blended with hydrogen can significantly impact the physical properties of the gas.

For economic reasons, it is unlikely that green hydrogen will significantly contribute to the hydrogen economy and the initial transport, storage, and distribution infrastructure in the near future. Usage infrastructure will likely rely on blue or grey hydrogen from fossil fuel source conversion.

This assumption defines and limits the operating conditions for hydrogen transport to pressure levels/ratios required by pipeline and storage operations, which tend to be between 1000 - 2000 psig and at a compression ratio of 1.5 - 3.0, respectively.

Industrial hydrogen compression uses different types of commercially available compressors. However, the requirement for rugged and reliable operations with large volume flows realistically limits the selection to centrifugal compressors for most pipeline transport applications.

Centrifugal compressors have been used for decades for hydrogen compression, but in vastly different applications, mainly in the downstream refinery processes.

A basic aerodynamic blade design can determine the efficiency of a compressor, and can be optimised for any type of gas. Thus, there is no reason a centrifugal compressor cannot be designed to operate efficiently for a light gas.

Hundreds of centrifugal compressors operate efficiently in hydrogen service, including in petrochemical and refinery applications. Other operational reasons why a centrifugal compressor is preferred for hydrogen compression are avoidance of process gas contamination with lube oil, reduced environmental leakage, no piping pulsation or vibrations, and overall lower maintenance costs.

Most hydrogen compression services can be provided using either centrifugal or reciprocating compressors.

Centrifugal compressors are head limited and may require many stages and cases in series for higher pressure ratios, while reciprocating compressors are flow limited and require many cylinders or compressors in parallel. The choice between centrifugal and reciprocating compressors requires consideration of pressure/flow conditions, as well as operating economics such as maintenance, reliability, and availability.

Blending hydrogen with natural gas Blending hydrogen with natural gas, so the existing natural gas infrastructure can be used to transport hydrogen to industrial and domestic end users, could be a viable method to use hydrogen produced from otherwise curtailed wind and power sources. Small quantities of blended hydrogen (below 20%) would have little impact on the compression infrastructure, but as the percent fraction of hydrogen increases, so do the compressor power and head requirements, as Figure 1 shows.

The problem with this approach is that the infrastructure of most small industrial and domestic end users is not ready for any amount of hydrogen. Hydrogen is highly explosive, leaks easily, and has a very wide flammability range, making it difficult to manage from a safety perspective.

This problem is not insurmountable for large industrial facilities and users where proper hydrogen safety measures, protocols, and discipline can be implemented, but it poses significant challenges for small and non-industrial users.

Unfortunately, because of the interconnectedness of the current natural gas pipeline infrastructure, it is very difficult to control where hydrogen will flow once it is introduced into the transport system. Hydrogen would be everywhere, including in domestic distribution, in often unknown compositions and percentages. Even though hydrogen and natural gas blending sounds like an obvious solution, huge safety and infrastructure issues would need to be addressed. On the other hand, when transporting pure hydrogen, the safety risks are easier to address and mitigate vs the significant cost of a completely new pipeline infrastructure system for hydrogen.

Compression applications

Figure 1. Compression work as a function of percent hydrogen blended with natural gas. (Source: Kurz R., Allison, T., Brun, K., ‘Pipeline Compression for the Hydrogen Economy’, DOE Seminar 2021)

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World Pipelines / NOVEMBER 2022

When designing infrastructure for the hydrogen economy, several compression applications must be considered. Table 1 shows the most important ones with their expected pressure ratio range. Depending on the size of the hydrogen-producing source, the flow rate of these applications can vary widely.

Most high-volume hydrogen compression applications fall into a pressure ratio range between 2.0 - 3.0.

The compressor types usually considered for hydrogen are reciprocating, screw, centrifugal barrel, centrifugal horizontally split, and integrally geared. Since both reciprocating and screw compressors are severely flow limited, they cannot be practically used for large-scale hydrogen applications. The remaining technology options all rely on proven centrifugal compressors, but use different layouts and stage arrangements. Centrifugal barrel

compressors show the highest potential for large, industrial scale, reliable, and low-cost hydrogen compression.

Centrifugal compressors in hydrogen compression applications

Most hydrogen compressors are used in refineries for hydrotreating, hydrogen plants, and hydrocracker applications.

In these applications, feed gas, recycle, net gas, and booster compressors compress hydrogen over a wide range of pressures and flows.

Table 1. Hydrogen compression applications and expected typical pressure ratios Hydrogen compressors are also used in gasification, electrolysis, and many Pipeline recompression (1400 psi) PR 1.2 - 1.5 [96.5 bar] chemical and petrochemical plants.

Header station (electrolyzer, steam reformer, PR 2.0 - 6.0 Compressing hydrogen presents four gasifier) to pipeline pressure or liquids major technical challenges. Hydrogen is an plant extremely light gas. It can cause hydrogen Fuel supply to power plant: embrittlement in ferrous alloys. Hydrogen a) Gas turbine combustor pressure from PR 1.5 - 3.0 molecules are very small, making sealing reformer (500+psi) [34.5+bar] and containment difficult. Additionally, b) Storage tank pressure (7000 to 14000 psi) PR 10+ there are safety issues because of [843 - 965 bar] its explosiveness, low auto-ignition temperature, and wide flammability range.

Light gases are difficult to compress, and result in a low head rise per compressor centrifugal stage. Even at relatively high impeller tip speeds of 350 m/sec., typical pressure ratios per stage seldom exceed 1.1. For rotor dynamic reasons, there are finite limits to shaft length in any compressor. Centrifugal compressors can mechanically fit a limited number of stages per casing, usually 10 - 12. In addition, the impeller and shaft material must have sufficient strength, while being light enough to minimise hoop stresses at high rotational speeds. Table 2 compares the number of impellers and cases required for the application case in Table 1 for conventional compressors with tip speeds around 1200 ft/sec. vs novel, high-speed impellers operating at twice this speed.

Theoretically, impellers with tip speeds over 2000 ft/sec. are possible if non-metallic materials, magnetic or gas bearings, and special seals are used.

Shaft and impeller material can include titanium alloys, Figure 2. Directionally wound carbon fibre compressor impeller. continuously wound carbon fibre, and ceramics. For example, a continuously wound carbon fibre shaft has high torsional strength and a quarter of the density Table 2. High-speed vs low-speed compressors when compared to a steel shaft. Figure 2 shows a novel, Conventional compressor (1200 ft/sec. tip speed impellers) high-speed compressor impeller made from light, highElectrolyzer to pipeline PR=2.5 40 impellers (4 - 5 cases) strength, directionally wound carbon fibres that can Pipeline PR=1.3 8 impellers (1 - 2 cases) operate at tip speeds exceeding 2000 ft/sec. recompression The greatest challenges for high-speed hydrogen CGT fuel gas PR=2.0 30 impellers (3 - 4 cases) compression are the use of common turbomachinery compression materials, impeller designs that can handle very high High-speed compressor (2400 ft/sec. tip speed impellers) hoop stresses, seals and bearings at speeds where there Electrolyzer to PR=2.5 10 impellers (2 cases) is limited operational experience, and high-speed drivers pipeline and gears at speeds over 50 000 RPM. Unfortunately, Pipeline PR=1.3 2 impellers (1 case) most of this technology is currently being developed, recompression and is not practical for rugged industrial applications CGT fuel gas PR=2.0 8 impellers (2 cases) requiring high reliability, such as pipeline or storage compression service. Critical research gaps must be addressed before

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World Pipelines / NOVEMBER 2022

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this technology can be applied commercially. More conventional compression technologies will have to be used until then. If a significant hydrogen pressure rise is needed, current impeller technology requires long compression trains with many stages per casing.

Hydrogen embrittlement is a metallurgical interaction between ferrous metals and hydrogen gas at certain pressures and temperatures that can lead to rapid yield strength deterioration of the compressor base metal. To prevent it, API 617 limits materials in hydrogen gas service to those with a yield strength less than 120 ksi or a hardness less than 34 HRC, which limits the maximum allowable speed of a given impeller.

This issue can be addressed with high-head impellers and alternative materials with higher strength-to-density ratios, but these technologies are not yet mature. In addition, special surface coatings are available to minimise exposure and direct penetration of hydrogen into the metal as shown in Figure 3.

As a safety precaution, current design practices limit the design yield strength of the exposed alloys to below 827 MPa, further limiting the operating speed of the compressor and its pressure rise per stage.

Finally, because hydrogen molecules are small, case end and interstage sealing is challenging. Most hydrogen compressors use tandem, dynamic dry gas seals and multiple static O-rings to minimise leakage flows. Nonetheless, hydrogen detection and scavenging is often required to minimise the risk of hydrogen exposure to the atmosphere and the associated explosive hazards.

Practical hydrogen centrifugal compression solutions

Figure 3. Elliott specialty Pos-E-Coat® hydrogen compressor coating.

Elliott’s Flex-Op® compressor arrangement, shown in Figure 4, improves the head, flow, reliability, and operational flexibility of hydrogen compressors. The arrangement consists of four compressors on a single gearbox, which allows individual compressors to run in series or parallel (or both), with multiple extractions and side streams.

Hydrogen compression requires a large number of compression stages to achieve a reasonable head. With up to four casings, more than 40 impeller stages can fit into a linear footprint that traditionally only fits 10. This shrinks the linear footprint of the compressor section from about 40 ft to roughly 10 ft. Since each rotor is connected to its own pinion via a flexible shaft coupled to the central gear, the rotor speeds can be individually optimised for the highest aerodynamic efficiency. A barrel casing coupled with a single, multi-pinion gearbox allows powering of the entire assembly by an electric motor with a variable frequency drive, a variable speed drive motor, a steam turbine, or a single/two-shaft gas turbine. Figure 5 shows two of these arrangements.

Engagement/disengagement of individual compressors is possible for additional operational flexibility if using clutch or torque converter couplings at the compressor shaft ends.

The casing arrangement allows it to operate in parallel for high

Figure 4. Flex-Op compressor arrangement with four individual centrifugal compressors mounted to a single, multi-pinion gearbox.

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World Pipelines / NOVEMBER 2022

Figure 5. Flex-Op compressor arrangement with an electric motor drive and a variable frequency drive or an electric motor variable speed drive.

throughput, or in series with intercooling between bodies for the highest-pressure ratios. Finally, the arrangement provides easy access to all four compressors for maintenance and repair using a single mezzanine or platform and crane.

Conclusion Hydrogen can be a viable energy transport and storage medium in a decarbonised energy economy. Green and blue hydrogen are the most promising of the different forms of industrially produced hydrogen, but require compression for pipeline transport or storage. The hydrogen economy requires compressors that are different from those currently used in industrial applications.

For applications such as pipeline, storage, and feed compression, hydrogen compressors that can reach compression ratios between 2.0 - 3.0 are required. Several complex challenges need addressing when designing compressors for these applications, including light gas head rise, static and dynamic sealing, explosive safety, and material compatibility. Significant technological development is underway to design high-speed centrifugal compressors optimised for hydrogen compression, but this technology is not yet near maturity. Alternatively, a more conventional solution, such as Elliott’s Flex-Op compressor arrangement, can handle the required compression duties with currently available and proven compressor and gear technologies.

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Takashi Goto, Vice President of Strategy, NTT Research, Japan, considers how existing pipelines can transform the global adoption of hydrogen energy. n February, Pew Research published an alarming finding: federal action addressing climate change fell to the 14th highest-rated (out of 18) policy priorities among polled US adults. Only 42% of respondents felt dealing with climate change “should be a top priority for the president and Congress to address this year.”

But the threats posed by climate change continue to grow, and now is not the time to de-emphasise our climate priorities in favour of issues some might deem more pressing. Rather, now is the time to invest resources in the most creative and innovative technologies that will help us mitigate this existential threat.

One of those innovations rests entirely on advancing the capabilities of our future global pipeline infrastructure.

Conversations around renewable or cleaner energy sources often centre on a handful of solutions – wind, solar, water and tidal, geothermal or nuclear power. Yet, another vital alternative is too commonly overlooked despite its place at the very beginning of our periodic table: hydrogen.

Hydrogen is too often absent from conversations about the global transition to cleaner energy sources; fortunately, we’re beginning to see that change. In September, a coalition of 20 countries agreed to increase their output of low-emission hydrogen 90-fold by 2030.

In 2021, research published by Qatar University scientists in Frontiers in Sustainability noted that “Low carbon hydrogen can be an excellent source of clean energy, which can combat global climate change and poor air quality.” Additionally, the research stated that a hydrogen-based economy could decarbonise sectors “including transportation, shipping, global energy markets and industrial sectors.”

If properly adopted, hydrogen can be expected to meet the world’s ever-growing demand for electricity and heat. It is particularly difficult to reduce carbon consumption when heating buildings running on conventional energy sources, so it is believed that substituting hydrogen as an alternative energy source will greatly contribute to reduced carbon usage. In the future, hydrogen may even become renewable as it can be produced by

Figure 1. Example of existing pipeline infrastructure that could be used for the transportation of hydrogen.

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reforming from fossil fuels, using byproducts from chemical plants or through the electrolysis of water.

Yet, hydrogen energy is by no means a panacea. Energy experts rightly highlight the drawbacks and obstacles to the wide-scale implementation of hydrogen as a clean energy source, especially regarding its transmission. Under the typical model of building hydrogen-transmission-specific pipelines, energy companies must contend with high land acquisition and construction costs, long building times and the potentiality of creating new environmental dangers through leaks or spills.

The research published in Frontiers in Sustainability fairly states, “...there are still some barriers to the realisation of a hydrogenbased economy, which includes large-scale hydrogen production cost, infrastructure investments, bulk storage, transport and distribution, safety consideration, and matching supply-demand uncertainties.”

Hydrogen gas: the potential The question then becomes, how do we safely implement the global adoption of this high-potential cleaner energy source while overcoming very real barriers to its transportation and economic viability?

The solution lies in rethinking the transportation methodology completely, moving beyond the impulse to tear up existing pipeline infrastructure or blindly build entirely new pipelines, but exploring instead how to transport hydrogen gas through the realisation of a new transportation model, placing a hydrogen-capable transportation pipeline into existing piping infrastructure.

That model is the long-term vision of a new study implemented

by NTT Anode Energy Corporation (in collaboration with the National Institute of Advanced Industrial Science and Technology and Toyota Tsusho Co., Ltd.) in August 2022. NTT Anode Energy is a Japan-based company focused on leveraging the information communications and DC-power-supply technologies of the NTT Group to develop smarter energy solutions for business applications.

Under this double-piping model, a hydrogen pipeline made of stainless steel will be placed into existing pipes, also known as ‘sheath pipes’, made of either polyethylene or steel.

This study, the next step in the proof-of-concept process for transportation of hydrogen through existing communication pipelines, communication tunnels, and water and sewage systems, begins with the manufacturing of a mock piping system on which

Figure 2. Overview of the hydrogen transportation business model.

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various trials can be conducted. During these trials, hydrogen transportation will initially be tested along a distance of 250 m at an approximate volumetric flowrate of 2300 m3/hr, enough hydrogen supply to power 33 large commercial facilities (like hotels).

These trials are the world’s first attempt to achieve mediumpressure transport of hydrogen gas at room temperature due to the technical feasibility related to safety using a double-pipe system. Ultimately, it aims to measure four key transportation factors with the goal of formulating technical industry standards for future use. Those factors include: )) Onsite investigation standards for hydrogen leakage detection. )) Verification of detection of signs indicating operational

abnormalities. )) Establishment of a control sequence to ensure ecological

safety. )) The performance evaluation of several hydrogen sensors

under real-world conditions.

Fuel for the future Hydrogen is considered generally safe and can be found throughout our everyday lives, including in various types of drinking waters. It also has a wide variety of uses across industries, including semiconductor cleaning, as rocket fuel, as fuel for maglev trains and airplanes, and more recently as a heat and electricity source for automobiles, hotels, and hospitals.

In the future, the ultimate aim is the transportation and effective implementation of green hydrogen, which must be clearly delineated in any conversation about the potentiality of hydrogen as a clean energy source. An expert commentary published by the National Resources Defense Council, for example, notes that hydrogen “is currently produced via a dirty process that relies on fossil gas as feedstock and emits a significant amount of carbon pollution. However, the process can be cleaned up to produce a ‘green’ version using renewable energy and water.”

The NRDC post then states that “Green hydrogen … can help us achieve a 100% renewable energy electricity sector by allowing us to store power for longer periods of time.”

In this study, safety measures will be investigated under the assumption of unsteady conditions, including rupture accidents

and natural disasters during pipeline operation. However, it remains important to note that a hydrogen leak will not cause an explosion of its own accord. Spontaneous combustion will occur only if there is an ignition source of 500˚C or higher nearby. Additionally, hydrogen has a lighter specific gravity than city gas and LP gas, and diffuses in the air four times faster than air, oxygen, and nitrogen.

Beyond identifying the safety measures and standards needed for the everyday operation of such hydrogen transportation models, the study will also verify the profitability of such products, providing a cost analysis of the transportation, energy input and overall economic efficiency as compared to alternative means of hydrogen transportation.

Based on the knowledge and data gained through this project, NTT Anode Energy and its collaborators will promote and establish technical studies on safety measures for practical use. In the future, the project will support the supply of hydrogen to urban areas like public and commercial facilities, data centres and communications buildings, as well as for powering fuel-cell vehicles.

Safety considerations While the potential of hydrogen gas is nothing short of transformative, progress in science and technology occurs incrementally; so, too, will the global transition to cleaner, more sustainable and renewable energy sources like hydrogen. However, progress must occur with ecological and operational safety top of mind, while realistically considering the economic principles intrinsic to real-world implementation.

As the NRDC expert commentary concludes, “When handled responsibly, green hydrogen is less dangerous than other flammable fuels that we rely on today. Moving forward, industry and government institutions must build on existing robust safety protocols and continue to make safety a key priority for investment and refinement to ensure that hydrogen becomes part of a clean and thriving economy.”

Conclusion The stakes are clear: climate change is causing, and will continue to cause, devastation for our environment, our ecology, and our society. And efforts to cut carbon emissions simply are not happening fast enough. As research shows, carbon emissions reduction needs to increase tenfold to meet goals established in the Paris Agreement.

This new study of hydrogen transportation is the next step in the realisation of a hydrogen-based revolution, proving that innovation is built on the advancements of the past: the pipelines of today will one day be transporting the clean energy of tomorrow, as we look toward a more sustainable future for all.

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Pedro Barbosa, Fotech, UK, a bp Launchpad company, reviews the various challenges hydrogen presents, and discusses how distributed acoustic sensing (DAS) provides an accurate and faster leak detection solution for smaller leaks.

he oil and gas industry is currently undergoing a major shift as companies look to reduce emissions and achieve net-zero by 2050, or earlier. As well as turning attention towards sustainable energy sources such as wind and solar as part of this energy transition, oil and gas companies are investigating clean hydrogen – produced using renewables, nuclear or fossil fuels with carbon capture – as an alternative fuel source.

Indeed, it is anticipated that demand for clean hydrogen will grow fivefold by 2050, avoiding up to 80 Gt CO2 emissions.1,2 There are many hydrogen projects being initiated worldwide, however, there are approximately only 1600 miles of hydrogen pipeline infrastructure that currently exists in the USA compared to 305 000 miles of natural gas pipelines, and 190 000 miles of liquid fuel pipelines.3 According to the Hydrogen Council, there have been more than 520 large-scale projects and 90+ GW of electrolyser production capacity announced globally.4 As part of these projects, companies are building new pipelines while transmission system operators (TSOs) are looking at repurposing existing natural gas pipelines.

As the popularity of hydrogen increases, it becomes vital that the pipeline network is robust with systems in place to transport the gas safely.

Transporting hydrogen gas is no easy feat, and operators face new challenges not seen with the transport of oil and natural gas.

The challenges of transporting hydrogen Hydrogen is highly flammable Hydrogen presents a higher risk of explosion compared to other fuels because it has a very high energy content per mass. For example, the energy content is approximately

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three times higher than petrol, which means it has a lower ignition energy, so it can ignite more easily.5

High risk of leaks The size of a hydrogen molecule is smaller than any other gas. As such, it diffuses more easily in materials than other common gases at equivalent pressures. This makes it prone to leaking easily through cracks or poor joints in storage and transportation systems.6 Hydrogen is generally non-corrosive and does not react with the materials used for pipelines. However, at certain temperatures and pressures it can diffuse into a metal lattice causing ‘hydrogen embrittlement’.7 In particular, hydrogen has the potential to embrittle the steel and welds used to fabricate the pipelines, which can damage their integrity.

Environmental issues The environmental benefits gained by introducing hydrogen as a mainstream fuel would quickly be offset if there were any leaks. According to the UK government’s policy paper ‘Atmospheric implications of increased hydrogen use’, hydrogen leakage will affect atmospheric composition, ultimately negatively affecting air quality, and has an indirect warming effect on the climate.8

Reducing the risk of leaks For hydrogen to be adopted as a major energy source, it’s clear that eliminating the risk of leaks should be a priority. To ensure pipeline safety and integrity, they need to be designed and maintained to the highest standards. This includes robust ventilation coupled with leak detection systems that can identify the very smallest of leaks. That’s where advanced monitoring technologies such as DAS have a role to play.

Typically, monitoring techniques, such as computational pipeline monitoring systems, have been used to monitor for leaks in existing oil and gas pipelines. However, since they infer the presence of a leak by computational modelling, they tend to have long detectability times and low sensitivity to small leaks. DAS, on the other hand, can alleviate these issues.

A closer look at DAS DAS technology, such Fotech’s LivePIPE II solution, turns a fibre optic cable running alongside a pipeline network into thousands of vibration sensors by using photonics. It then detects any disturbances along the length of the pipeline.

The technology sends thousands of pulses of light along the fibre optic cable every second and monitors the fine pattern of light reflected back. When acoustic or vibrational energy – such as that created by a leak or by integrity threats including third-party interferences or geo-hazards – creates a strain on the optical fibre, it changes the reflected light pattern. By using advanced algorithms and processing techniques, DAS analyses these changes to identify and to categorise any disturbance.

Each type of disturbance has its own signature and the technology can tell an operator, in real-time, what happened, exactly where it happened, and when.

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DAS delivers advanced monitoring DAS is ideal for monitoring hydrogen in pipelines for a number of reasons:

Continuous real-time monitoring DAS provides live monitoring around the clock, 24/7, and on pipelines spanning thousands of kilometres. That means operators are immediately alerted when an incident has occurred, even in the most remote locations, so they can take remedial action to prevent major incidents.

High accuracy DAS accurately locates disturbances to within 10 m, as well as identifying multiple events and their locations simultaneously. It enables operators to go straight to the site of incident, dig once, and thus minimises repair costs.

Additionally, advanced AI and machine learning included in the newest DAS technologies filter out background noise and non-threat activity, and calibrate responses for high-risk and low-risk zones. This reduces false alarms and ensures operators receive the exact information needed to make informed decisions.

Quick detection of small leaks DAS can detect gas leaks from tiny orifices as small as 1 mm, and alert operators within seconds. The technology is able to detect vibrations caused by gas being forced through small pinholes and cracks that would otherwise remain undetected.

Hydrogen as the fuel of the future Hydrogen is hotly anticipated as a more sustainable fuel source and interest in this gas is rapidly growing. Future predictions suggest that by 2035, hydrogen, electric power and synfuels will represent more than 30% of the global energy mix, and by 2050 it will be as much as 50%.9 However, hydrogen’s inherent properties mean it is especially hazardous to transport and therefore careful consideration needs to be taken when designing pipelines.

Robust strategies and technologies for minimising leaks, such as DAS, need to be implemented if hydrogen is to be accepted as a valuable alternative fuel.

References 1.

2.

3.

4.

5.

6.

7.

8.

9.

www.mckinsey.com/industries/oil-and-gas/our-insights/global-energyperspective-2022 hydrogencouncil.com/en/ceo-coalition-to-cop26-leaders-hydrogen-tocontribute-over-20-of-global-carbon-abatement-by-2050-strong-publicprivate-collaboration-required-to-make-it-a-reality www.energy.gov/eere/fuelcells/hydrogen-pipelines hydrogencouncil.com/en/ceo-coalition-to-cop26-leaders-hydrogen-tocontribute-over-20-of-global-carbon-abatement-by-2050-strong-publicprivate-collaboration-required-to-make-it-a-reality www.eia.gov/energyexplained/hydrogen www.hyresponse.eu/files/Lectures/Safety_of_hydrogen_storage_notes. pdf www.hyresponse.eu/files/Lectures/Safety_of_hydrogen_storage_notes. pdf www.gov.uk/government/publications/atmospheric-implications-ofincreased-hydrogen-use www.mckinsey.com/industries/oil-and-gas/our-insights/global-energyperspective-2022

Julie Holmquist, Cortec® Corporation, and Tim Whited, MESA, USA, explore mitigating corrosion on cased pipeline crossings.

n estimated 1.18 million km (730 000 miles) of pipelines transport oil and gas around the world – enough to circle the globe over 29 times.1 Of these, at least 485 288 km (301 544 miles) of pipelines transmit gas in the US alone, not including gas distribution and gathering lines.2 Inevitably, these pipelines intersect many highways, roads, and train tracks, passing unseen many feet below. Often, these pipelines are encased in a larger pipe to protect against the extra load and the possibility of exterior damage, while also theoretically making it easier to repair and replace pipeline sections without disturbing traffic. Unfortunately, this unseen environment is also ripe for corrosion that could go unnoticed for many years. Because of this, MESA, a nationwide corrosion control services company headquartered in Tulsa, Oklahoma, has been on a journey for the last decade to fill these casings with a new form of corrosion protection developed in conjunction with Cortec Corporation. The efforts began in response to specific needs of a major pipeline operator, and have resulted in the creation and patenting of CorroLogic® VpCI® Filler technology. This specialty technology, based on a time-tested corrosion inhibiting chemistry, is an important corrosion mitigation strategy for pipeline owners to be aware of due to its particular aptitude for dealing with the unseen environment of cased pipeline crossings.

The cased pipeline crossing landscape The landscape for protecting cased pipeline crossings is vast. For example, Tim Whited, CorroLogic VpCI Specialist

27

and NACE CP Specialist at MESA, who was an integral driver in the development of CorroLogic VpCI Filler, estimates that there are tens of thousands of cased pipeline crossings in the US alone, and that MESA has applied the CorroLogic VpCI Filler technology inside a few hundred casings. This means tens, if not hundreds,

Figure 1. Vapour phase corrosion inhibitors (represented by yellow dots) have the ability to migrate through air and water to form a protective molecular layer on the metal surface. This is ideal for protection of unfilled spaces in cased crossings, as well as protection under disbonded coatings. (Source: Cortec)

of thousands of cased crossings are future candidates for further protection.

While installing casings at pipeline crossings was once in vogue, it is increasingly going out of style with technologies such as horizontal directional drilling (HDD) and other sound alternatives to cased pipeline crossings becoming more dominant.3 However, the fact remains that hundreds of thousands of pre-existing cased crossings are only getting older and will likely face more challenges as they age. Corrosion on the external surface of the carrier pipe inside cased crossings may be enhanced due to debris trapped inside the annulus during installation, and by moisture entering the annulus through failed seals and holes in the casing walls. Further, coating holidays on the carrier pipe may be a corrosion risk in the presence of an electrolyte (e.g. water) inside the casing annulus.4 Metallic shorts between the carrier pipe and the casing can occur and are areas of concern for corrosion on the carrier pipe surface.

The good news is that Southwest Research Institute (SRI) findings suggested a high level of safety at cased crossings in 2007. However, although corrosion related catastrophes at these crossings appear to be few and far between, their study shows that when a corrosion failure does occur, it can be drastic and even life threatening.

One of the most extreme cases reported by SRI occurred in 1985. A natural gas pipeline running under Kentucky State Highway 90 ruptured, the gas ignited and burned a large area, five people were killed in a house, and three were burned running from a mobile home. The cause was attributed to “unsuspected and undetected atmospheric corrosion”, according to the National Transportation Safety Board report. Factors such as cyclic water condensation and

Figure 2. Cased pipeline crossing illustration showing internal carrier pipe, insulating spacers, casing, end seals, and vent/filler pipes.

(Source: Cortec. CAD drawing courtesy of Tommy Lee)

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World Pipelines / NOVEMBER 2022

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coating damage due to high heat from a nearby compressor station were also indicated. Another case from 1980 was less serious but involved a casing short in a kerosene pipeline.

Figure 3. The centre pipe is the ventilation duct to the pipeline casing buried underground at this pipeline crossing. A similar vent on the ‘low side’ (ventilation to the bottom of the pipe) is where CorroLogic VpCI Gel application is ideal. The left pole is where the electrical potential can be measured to determine CP condition. (Source: Cortec, courtesy of Eric Uutala)

The short was believed to have been present for a decade.

Groundwater had leaked in and caused corrosion thinning on the bottom of the carrier pipeline inside the casing. The study found that five out of 11 reportable pipeline incidents in the Office of Pipeline Safety (OPS) database from 7 August 1984, to 8 November 2006, were tied to corrosion.

SRI also concluded based on data that shorted casings tended to have a higher corrosion rate.5 Although serious incidents are few and far between, they underscore the importance of preventing and not just mitigating corrosion. Fortunately, catching the problem before it gets too serious is more likely in this day and age since the Pipeline and Hazardous Materials Safety Administration of the US DOT (PHMSA) now requires inspection of “hazardous liquid pipelines” every five years and “natural gas transmission pipelines” every seven years.6 Whited explains that this can be done through inline inspection (ILI) tools that use GPS to identify corrosion anomalies on the carrier pipe surfaces inside cased crossings.7 When corrosion anomalies are detected, it is often a sufficient reason to add extra corrosion protection.

SRI reported in 2007 that about 10% of the crossings whose data they analysed had a corrosion anomaly of 20% wall thickness or more. They noted that, according to the modified ‘ANSI/ASME B31G-1991 (R2004) Manual for Determining the Remaining Strength of Corroded Pipelines’ standard, repair is not necessarily needed for pipes with anomalies of less than 20% wall thickness. However, mitigation of active corrosion is required.8 While the preceding data provides a good outlook for pipeline safety, it is also a call to action for pipeline integrity management going forward. The important thing is to identify corrosion and apply a mitigation technique before it is too late. When the SRI study was prepared, mitigation options were limited primarily to wax fillers. The prospect of greater effectiveness and convenience has since improved with the development of CorroLogic Gel Filler.

Developing a new solution for cased pipeline crossings

Figure 4. CorroLogic VpCI Gel is pumped through the filler pipe into the lower portion of the casing until it can be detected coming out the other side. Inevitably, it often picks up some of the debris contaminating the inside of the casing, which is why the right sample is darker than the left one. (Source: Cortec, courtesy of Eric Uutala)

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The landscape for cased pipeline crossing protection changed in 2010, when a major pipeline operator with 2000 cased crossings approached Cortec Corporation about finding a solution to corrosion anomalies found in some of their cased pipeline crossings – both unfilled and wax filled. Tape coating disbondment was also a concern, as were the ingress of water and air, and the presence of debris. The pipeline operator developed a list of criteria and brought it to Cortec for a solution. Some of the characteristics included the need for a corrosion inhibitor that could migrate under disbonded coatings and protect areas not completely filled with the product (i.e. air pockets or head space). The corrosion inhibitor needed to work in multiple phases – in the vapour phase, and in liquids or solids. It also needed to turn into a gel once inside the casing, and so discourage further water from entering the casing. Another important factor was the ability to conduct CP to the carrier pipe.9

Cortec’s CorroLogic VpCI Filler technology was developed in response to these needs and was patented several years later. The gel filler is comprised of two parts that are mixed onsite. The product is intended to gel at the last moment so it forms a soft, viscous substance within the casing annular space. Vapour phase Corrosion Inhibitors diffused throughout the gel form a protective molecular layer on all metal surfaces in direct contact with the gel. They also have the ability to migrate in vapour form to areas that are difficult to reach – hence the potential for them to find their way under disbonded coatings and adsorb onto the metal at coating holidays. In 2014, the basic technology was described and included in the NACE Standard SP0200-2014 for steel-cased pipeline practices.10 The technology also falls within PHMSA requirements for acceptable alternatives to addressing shorted carrier pipes when it is not practical to clear the short using isolation.11

Protecting one casing at a time With an estimated 200 000 or more cased pipeline crossings in the US, not to mention those around the world, use of CorroLogic Gel Filler is essentially only getting started.

Many pipeline operators around the globe stand to benefit from this method of corrosion mitigation that protects unseen, difficult-to-reach spaces. Reasons for adopting the technology are varied. Some pipeline owners are responding to an existing problem. They have found external corrosion anomalies in their carrier pipeline during ILI and are looking to treat it. Others are responding to regulations in critical areas. Some are even more proactive. Whited explained that many operators will fill both regulated and unregulated cased crossings. “There’s a movement amongst many operators to just address all of their casings [...]”, he said. “It’s part of their integrity management practice […] Pipelines inside of casings can have corrosion growth that occurs in that environment sometimes, and it’s difficult to get at those and fix them, so many operators like the idea of just filling the casings and expecting to be done with them at that point.”12 Applying CorroLogic Gel Filler is one of the most comprehensive ways to do so. Even though it is impossible to see what is happening inside the casing (e.g., debris blockage, insulator collapse, etc.), CorroLogic VpCI Filler helps provide well-rounded protection through its multiphase protective action, allowing it to infiltrate under disbonded coatings and into air pockets while the gel aspect discourages ingress of water and debris, and the corrosion inhibitors help neutralise the corrosive effect of any water that does get in. Another benefit of the CorroLogic Gel Filler is that it provides a medium allowing CP current distribution to the carrier pipe.

Conclusion Prevention and mitigation of carrier pipe external corrosion anomalies within the unseen and difficult to access environment inside cased pipeline crossings is a big challenge. To get the most comprehensive protection without having to dig anything up, remove pipes, or

Figure 5. Sign on cased pipeline crossing vent indicates when the casing was protected by MESA. (Source: Cortec, courtesy of Eric Uutala)

obstruct traffic, CorroLogic Gel Filler is an excellent option, both for corrosion response before the rust gets too bad, and for preventative action to make sure all cased pipeline crossings are tucked in a blanket of corrosion inhibiting gel that compensates for some of the deficiencies and intricacies inside the annular space. When dealing with the unseen, CorroLogic Gel Filler makes corrosion protection less of a mystery to achieve.

References 1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

HUSSEIN, M. ‘Mapping the world’s oil and gas pipelines.” Aljazeera. 16 Dec 2021 <www.aljazeera.com/news/2021/12/16/mapping-world-oil-gaspipelines-interactive>. Accessed 12 Aug 2022.

PHMSA. ‘Pipeline Mileage and Facilities.’ 2010+ Pipeline Miles and Facilities data download. U.S. DOT, Pipeline and Hazardous Materials Safety Administration. Last updated 28 Jan 2020 <www.phmsa.dot.gov/data-andstatistics/pipeline/pipeline-mileage-and-facilities>. Accessed 12 Aug 2022.

CorrPro Companies, Inc. ‘Final Report On Improvements to the External Corrosion Direct Assessment (ECDA) Process (WP # 360): Cased Pipes (Project #241) for Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Department of Transportation.’ Contract No. DTPH5608-T-000012. June 2010 <rosap.ntl.bts.gov/view/dot/34532/dot_34532_DS1. pd>. Accessed 12 Aug 2022.

WHITED, T. ‘Corrosion Inhibitor Solutions for Proactive Control of Corrosion Inside Cased Pipeline Crossings.’ Cortec Supplement to Materials Performance, June 2012 <www.cortecvci.com/Publications/Papers/MP/2012MP-Corrosion-Inhibitor-Solutions.pdf>. Accessed 15 Aug 2022, pp. 3-6.

Southwest Research Institute. ‘Statistical Analysis of External Corrosion Anomaly Data of Cased Pipe Segments.’ Prepared for The INGAA Foundation, Inc. Dec. 2007 <www.ingaa.org/File.aspx?id=6274>. Accessed 12 Aug 2022.

PHMSA. ‘Guidance for Inspection Reassessment Intervals.’

October 2016 <primis.phmsa.dot.gov/Comm/publications/ PHMSAGuidanceforInspectionReassessmentIntervalsLessthan7years%20 -%20Final.pdf>. Accessed 12 Aug 2022.

WHITED, T., Personal communication. 8 Aug 2022.

Southwest Research Institute, pp. i-ii.

KRISSA, L.J., DEWITT, J. and WHITED, T., ‘Development and Application of a New Solution for Mitigation of Carrier Pipe Corrosion inside Cased Pipeline Crossings,” Conference Proceedings of CORROSION 2014, Paper No. 4167.

NACE International: San Antonio, TX, 2014, p. 3.

‘Standard Practice Steel-Cased Pipeline Practices.’ NACE SP0200-2014, Item No. 21091. NACE International: Houston, TX, 2014.

GALE, J.A. Written clarification of Title 49 Code of Federal Regulations §192.467. US DOT PHMSA, 11 Mar 2019.

WHITED, T., Personal communication. 8 and 24 Aug 2022.

NOVEMBER 2022 / World Pipelines

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John Musgrave and Ian Moreau, MISTRAS Group, USA, outline the benefits of using proven, innovative automated radiographic testing (ART) technology for pipeline and piping integrity screening. valuating pipeline and piping integrity, particularly on insulated lines, can be a challenging endeavour. Despite the many traditional and advanced techniques and technologies available to integrity and inspection managers, each method typically comes with a downside in the form of high costs, extended time requirements, operational impacts, requirements to strip insulation, and more.

Inline inspection (ILI) is typically considered the gold standard for identifying corrosion, but this time, cost, and labour-intensive process comes with a major opportunity cost because it requires pipelines to shut down operations during the inspection, in addition to oftentimes rigorous maintenance requirements to prepare the line for the ILI tool run.

Advancements in automated radiographic testing (ART) technology – developed by MISTRAS Group, a One Source provider of asset protection

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Figure 1. MISTRAS’ ART crawler services offer single-view and multi-view radiographic scans, with the ability to simultaneously analyse the top, bottom, and sides of piping with a two-axis robotic arm to autonomously drive over supports without the need for multiple set-ups or systems.

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solutions – are creating a viable alternative to ILI that enables high-quality, rapid inspections with no need to strip insulation or take lines out of service.

This article looks at the variety of inspection options available to evaluate pipeline and piping integrity, and highlights ART’s accuracy, speed, and detection capabilities that make it a viable, effective alternative in lieu of ILI.

Common issues with ILI ILI tools require a handful of specific conditions to make a pipeline viable for pigging. Debris, rust, and other buildup can accumulate on the insides of a line, potentially blocking tools from moving through the line altogether or causing damage to the highly-expensive pigging technology, so lines must be properly cleaned and maintained prior to executing an ILI. During the tool run itself, production typically must be shut down to enable the tool to flow at its ideal speed to collect accurate, high-quality data. In addition, the construction features of a line can also prohibit the use of ILI tools. ILI tools require launchers and receivers to allow the tool to be inserted and removed from the line, and the size of the pig limits the bend radii that it can travel around.

Lines without launching and receiving facilities, or those with sharp, small-radii bends can sometimes be modified, but this can come at a prohibitive cost that makes ILI an impractical option.

Alternatives to ILI Outside of ILI, there are a handful of accepted alternatives that come with their own sets of pros and cons, with some serving as more viable options than others for reasons related to costs, operational impacts, and more.

Insulation and/or coating removal A common, tried-and-tested method for determining CUI involves stripping insulation and/or removing coating and conducting visual, 3D laser mapping, and ultrasonic testing (UT). While this helps to ensure a high rate of accuracy and defect identification, it comes at great expense in terms of resources and opportunity costs. Additionally, in areas of above ground insulated pipelines, such activities can pose process safety issues with lines freezing when large sections of insulation are removed.

Since there is not a fool proof visual method to determine where CUI may be present, to get to 100% assurance this process must be executed throughout the full length of the line, which could mean stripping a cost-prohibitive amount of pipeline, even when the majority inevitably turns out to be corrosion-free. This lengthy process typically involves multiple contractors, often requiring different crews to assist with removing and reinstalling insulation and/or coating, conducting NDT inspections, and executing the necessary maintenance and repairs to remedy the discovered damages. If the piping network is at height, there are also the costs, time, and resources dedicated to constructing and deconstructing scaffolding. Lastly, removing and reinstalling insulation introduces the possibility of future moisture egress points,

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potentially creating the same problem that this method is designed to detect.

Manual radiographic techniques Another alternative is conducting manual radiographic testing (RT) – a reliable and proven technique able to identify flaws such as corrosion and cracking with high accuracy. However, while it’s effective for limited spot inspections at highlytargeted locations, traditional RT is too cumbersome a process for large-scale screening.

Compared to other NDT screening methods, manual RT requires relatively expensive equipment and a far slower inspection process. In addition, two-sided access to the test object is required, making it difficult to test some lines properly. Traditional RT also entails potential safety risks via radiation exposure, and thus should be used as sparingly as possible.

Overall, though RT is a proven technique that’s been used in the oil and gas industry for decades, advances in modern technology have moved beyond its analogue foundations toward higher-quality and more cost and time-effective automated solutions.

ART screening A more recent alternative to ILI is ART. Compared with other common inspection techniques, ART enables lines to stay in service during inspections, with the ability to gather highquality, DICONDE-compliant data with product still flowing through the lines, and with no need to strip insulation or remove coating. Various iterations of ART technology from MISTRAS Group can screen for CUI at four locations of the pipe (top, bottom, and sides), scan 360˚ for internal and external metal loss, and identify internal metal loss in the bottom quadrant of the pipe. All digital image scans are recorded and saved to provide a permanent record of the inspection data, and to facilitate future inspection comparisons or correlation with past ILI runs.

Benefits of ART compared to ILI A direct comparison of ART to ILI in a few key areas showcases ART’s efficacy as a corrosion screening tool.

Detectability and accuracy Regardless of the logistical benefits that ART offers as compared to ILI, they would be rendered moot if ART could not perform the actual inspection as effectively. However, ART proves to be a viable alternative in this area. Advanced ART systems can detect defects as small as 1 mm in dia. for internal corrosion. ART is on par with magnetic flux leakage (MFL) tool accuracy at +/- 10% for pit depth, and within +/- 1% for defect length and width accuracy.

ART is an effective screening tool in lieu of ILI for any aboveground piping when inspecting for corrosion under insulation, CO2 corrosion, and microbiologically-influenced corrosion (MIC). Particularly for CUI, ART should be considered the preferred method, as it is more sensitive to light external corrosion and can detect wet insulation even before corrosion forms.

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Production impact Among the most critical benefits that ART offers compared to ILI is that ART can be utilised with product still flowing through piping and pipelines, enabling operations to continue as usual while inspections are being conducted. Whereas ILI oftentimes requires extensive internal cleaning before executing an ILI run, ART can be executed without dedicating time and cost resources to pre-inspection preparation. De-pressurising a line to prepare it for ILI also introduces process safety hazards, which should be avoided wherever possible. While the costs to an owner-operator to perform the actual ILI and ART inspections are relatively similar, the requirements to run an ILI tool to halt production, spend resources on preparatory measures, and potentially increase process safety risks make ART a far more cost-effective option.

Rapid deployment ILI runs are often planned months in advance because they are labour-intensive, have significant impacts on the other operating crews in the area, and require the ILI run to be the primary focus on large swaths of piping. Conversely, ART inspections can be mobilised in essentially the time it takes the service technicians to arrive onsite, making it an ideal option to confirm suspected leaks before they create more significant problems. In addition, because there is little-to-no asset preparation required and a minimal impact on simultaneous operations (SIMOPS), ART enables rapid field implementation from request to onsite execution.

Targeted approach Because of the high speed at which ART collects and processes data (often exceeding 1000 m/d in an upstream environment), an ART-focused scheme can screen 100% of a pipe in the time

it typically takes to inspect 5 - 10% using manual methods.

For this reason, ART is particularly impactful as a large-scale screening tool, helping integrity managers identify which pipe sections require further investigation. To fully inspect a line may far exceed the inspection and maintenance budget, and to select a sampling of the line may result in missed detection opportunities and eventual loss of containment. ART enables integrity and inspection personnel to pinpoint the areas of a line that require remediation while leaving insulation on noncorroded pipe sections intact.

Field-proven results supporting ART’s efficacy Below, a series of brief field studies demonstrate the efficacy of ART as a screening tool for piping and pipeline internal and external corrosion: )) An ART inspection was conducted with a focus on identifying external corrosion under insulation on a 34 km stretch of piping with a diameter ranging from 4 - 10 in.

The inspection targeted the bottom region of the piping.

In total, 103 m of CUI and 2.8 km of moisture saturation were detected. The ART screening determined that 31 km of the piping was free from CUI and moisture saturation. )) An ART inspection was conducted on 3615 m of 18 in.

diameter emulsion piping. Corrosion calls included 37 at ≤20%, 12 at 21 - 30%, and 2 at 40%. )) An ART inspection was conducted with a focus on

internal corrosion on an offline pipe to assess returning the pipe to service. 159 m of 8 in. diameter piping were scanned. 142 m of corrosion locations and two pipe ruptures were found for a corrosion find rate of 89%.

The operator terminated the remaining inspections due to the find rate and put the line in the replacement schedule. )) An ART inspection was conducted

on 954 m of 20 in. diameter 3 phase piping. Corrosion calls included 120 at ≤20%, and 8 at 21 - 30%.

Final thoughts

Figure 2. ART inspections services help detect internal corrosion, pitting, and corrosion under insulation (CUI) in upstream, midstream, and downstream aboveground piping and pipelines, even with product flowing through the lines.

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The robust detection and speed capabilities, and increased safety of ART make it preferable to other NDT technologies for conducting integrity surveys on insulated and non-insulated aboveground pipelines. Compared to methods such as ILI and insulation/ coating stripping, ART in most cases performs at least as accurately and with far fewer resources required for noninspection related tasks. Particularly useful as a large-scale screening tool to target piping/pipeline integrity and inspection programmes, ART is a viable, accurate, and cost-effective technology to help maximise asset uptime and integrity.

PIGGING World Pipelines asks four ROSEN experts about pipeline pigging.

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ABCO ENTERS, Sales Manager, Netherlands After studying at the University of Technology in Delft, Netherlands (Physics) Abco Enters has been in technical sales since 1990 for service companies in Non Destructive Testing, both for technologies and solutions. Contributing to prevent pollution to the (sea) environment from storage tanks, pipelines, wells and other physical assets. He has held varying roles over the years in different organisations in R&D, operations, sales, business development, general management and board of director level. Since 2021, he has been a Sales Manager for ROSEN Europe BV in the Challenging Pipeline Division.

ULRICH SCHNEIDER, Business Development Manager, Germany After studying at the University of Hannover, Germany, Ulrich Schneider has spent over 40 years in operation and inspection of oil, gas and pipelines. At ROSEN, his focus is on business development and marketing for the dedicated Challenging Pipeline Division, specifically tethered inspection solutions. He has presented many papers at conferences worldwide in the last 30 years.

CHRIS HOLLIDAY, Integrity Engineering Lead, Canada Chris Holliday holds the position of Technical Lead for Integrity Services at ROSEN Canada. Chris is a registered Professional Engineer in both Alberta and Saskatchewan. He moved to Calgary from the UK, where he is a Chartered Engineer with the Institute of Mechanical Engineers. Chris graduated with 1st class honors in Mechanical Engineering from Northumbria University followed by a Post Graduate Certificate in Pipeline Engineering from Newcastle University. Chris has spent the start of his career working for ROSEN as a pipeline integrity engineer in Newcastle, conducting engineering assessments, corrosion growth, dent strain & fatigue and crack assessments. During that time, Chris has presented a number of technical papers with an emphasis on the assessment of pipeline deformations reported by ILI and pipeline structural analysis in landslide areas. Chris is a sessional instructor at the University of Calgary on the Pipeline Engineer Graduate Certificate Program and he volunteers on the Young Pipeliners Association of Canada Central Executive Committee.

COREY RICHARDS, Business Development Manager, Canada Corey Richards holds the role of Business Line Manager for ROSEN’s Field Project and Services and Challenging Pipeline Diagnostics Divisions for the Canadian region. Since 2014, his area of focus has been creating solutions for unpiggable pipelines in the Canadian, Oceania and Asia Pacific regions. He is located in Calgary after having spent five years in Lingen, Germany where he was based at ROSEN’s Technology and Research Centre. In his 13+ years with ROSEN, Corey has expanded his knowledge through various roles including: time in field operations and technical sales, before transitioning into his current position.

NEIL GALLON, Principal Materials and Welding Engineer, UK Neil Gallon is a Principal Materials and Welding Engineer working for the ROSEN Integrity Services division in Newcastle upon Tyne, UK. He holds a Masters degree from the University of Cambridge and is a Chartered Engineer, a professional member of the Institute of Materials, Minerals and Mining and an International/European Welding Engineer. He has over 20 years of experience in manufacturing and consultancy, including working for companies such as Tata Steel and GE. His current interests include the impact of gaseous hydrogen on materials and welds.

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PIGGING

&

Discuss a recently carried out pipeline pigging/inspection project.

ABCO ENTERS, Sales Manager ULRICH SCHNEIDER, Business

navigate a total accumulated bend angle of 1188° (17 bends) while successfully inspecting the pipeline for wall thickness and Development Manager cracks. ROSEN chose a tethered self-propelled bidirectional As we all know, not every pipeline is meant to be ‘pigged’; ultrasonic tool able to perform geometry, wall thickness and pipelines are frequently classified as ‘unpiggable’ due to their crack inspections in a single run. The tool was to be launched operating conditions, geometry, accessibility or a combination and received from a trap installed on the platform. After of these. For ‘unpiggable’ pipelines, ROSEN has often created extensive testing and development, the necessary equipment tailored solutions to allow for inline inspection, as was the (including a winch with a 1.2 km tether, with a breaking load case for the inspection of a 10 in. offshore oil riser recently of 2000 kg and a normal pulling force of 1000 kg) was brought inspected by ROSEN Norway. For this project, the inspection to the site. Two electrical crawlers were run in a tandem unit – launched and received from a single point – had to configuration to ensure the tool could negotiate difficult installations, such as slippery valves, Ts, etc.

An ultrasonic sensor carrier with 160 UT probes was used alongside two odometers measuring the distance travelled and the tool velocity.

The second tool was a purpose-made scanner equipped with TOFD probes.

Straight-beam pulse echo (PE) probes were installed to position the scanner correctly against girth welds to be assessed. When deploying TOFD sensors at corroded features in parent material, the tethered ultrasonic measurement tool position is used to determine the correct positioning of the TOFD tool. After presenting a site report, the equipment and the team were demobilised, and the detailed analysis was started from home. The data evaluation team now had four data sets for wall thickness (two forward and two return runs) and two data sets from the TOFD crack analysis. The full length and circumference of the targeted pipe section was successfully inspected, and the Figure 1. Extensive testing is required for any custom ILI solution. ROSEN conducted collected data was of very good quality, testing for this solution at the Bergen Norway location. meeting the required specifications.

How do you predict, or assess, pipeline failure? How do your tools help manage risk?

CHRIS HOLLIDAY, Integrity Engineering Lead A variety of methods as well as technologies are available to predict, or assess, pipeline failure. Prior to inline inspection, risk assessments of entire pipeline networks are possible; these can be used to segment individual pipelines into low, medium or high risk. Various factors are considered when making this categorisation, including the variety of threat and the inspection history. Although this is a higher-level assessment, it can often lead to smarter decision-making for future integrity management efforts.

Oftentimes that next step includes data collection.

ROSEN’s inline inspection (ILI) tools are equipped with a variety of sensor technologies, each able to gather highresolution data regarding the condition of the pipeline. Of

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course, once an ILI has been completed, the valuable data gained is translated into a variety of assessments, which cover risk management services, risk-based inspection planning, process safety management, safety and reliability services, and additional asset integrity services.

A more recent approach to predicting pipeline failure includes ROSEN’s Integrity Analytics Initiative. This method uses a large repository of historical ILI results (feature listings) along with corresponding pipeline information called the Integrity Data Warehouse (IDW). As of now, the IDW holds information about more than 12 000 pipelines worldwide, and it is growing rapidly.

This data – paired with relevant geo-enriched, socioeconomic or operational metadata – provides a clear foundation for scalable AI solutions. The approach becomes particularly relevant for uninspected pipelines. By learning from the condition of similar

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Figure 2. Geohazards can change the shape of a pipeline and may create local features, such as dents, buckles, ovalities and bending, all with potentially detrimental effects on the pipeline’s integrity.

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pipelines that have been inspected in the past, we can begin to understand the different variables that predict pipeline threats and develop models to predict the condition of uninspected pipelines. We can observe trends in inspected pipelines and apply what we have learned to uninspected pipelines. ROSEN has been advancing this initiative, and partnering with operators, to explore many applications of the IDW, such as corrosion prediction, external interference hit rate, crack prediction, condition metrics benchmarking and ranking, and corrosion growth rate prediction for uninspected pipelines. Future areas of interest include offshore asset condition, pipeline movement, bending strain and enhanced ILI anomaly classification.

Which types of pigging services are in increasing demand?

COREY RICHARDS, Business Development Manager Depending on the market, many operators are now in second or third-round inspection intervals, meaning they have established integrity programmes to address their most critical threats. They therefore are able to focus on more than the standard assessments and address more exotic features, such as selective seam weld corrosion, coincident anomalies (such

as dents with gouge/metal loss), material properties and girth weld assessments.

Additionally – and, driven by the PHMSA gas rule, particularly in the US – material verification assessments are becoming more prevalent. Pigging services around geohazards are in increasing demand due to awareness of associated failures.

Our expertise when it comes to slope stability issues and the assessment of related data is getting more and more accurate, allowing for better risk mitigation strategies.

Can you talk about pigging other types of pipelines, such as hydrogen or mixed-product lines?

NEIL GALLON, Principal Materials and Welding Engineer Pipelines transporting hydrogen are still pipelines, so all the threats operators face with natural gas lines are still relevant.

However, there are certain characteristics of hydrogen that may increase the risk of some threats more than others. In general terms, hydrogen has little effect on increasing the risk of metal loss, a large effect on cracking, a very large effect on fatigue, and an unknown effect on dents and gauges. In terms of cracking and fatigue, three factors to watch for are 1) a decrease in

material toughness; 2) a decrease in ductility; and, therefore, the inevitable 3) increase in the fatigue crack growth rate.

ROSEN has successfully inspected in hydrogen and has a comprehensive approach to both the integrity management and the inspection of hydrogen and blended pipelines.

Additionally, ROSEN has developed a phased framework for safely converting existing infrastructure to hydrogen pipelines.

The framework is based on a structured approach, which makes the process digestible and creates a step-by-step guide. Figure 3 shows what these phases include.

Figure 3. A phased approach allows for a feasible hydrogen conversion strategy.

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EDGE TECHNOLOGY Laura McShane, Decom Engineering, Northern Ireland, explains how the subsea cutting specialist completed a challenging decommissioning workscope offshore West Africa. he Chinguetti and Banda fields lie in water depths which vary between 280 m and 830 m, about 90 km from the Mauritanian capital, Nouakchott. When the field was considered no longer economically viable, the decision was made to undertake abandonment and decommissioning of the 15 designated wells, consisting of three major phases.

Phase 1 and Phase 2A, disconnected the FPSO mooring lines and recovered the risers, allowing for removal of the FPSO from the field, as well as plugging and abandoning the 15 wells. Norwegian subsea and offshore wind contractor, Havfram, was contracted to perform Phase 2B of the decommissioning work, which involved the removal and disposal, or rock dumping, of all remaining infield assets. Havfram commissioned subsea cutting specialist, Decom Engineering, to perform cutting operations on 15 termination heads (TH), six umbilicals, hydraulic flying leads, chains, and fibre ropes.

The THs are designed to terminate the flowlines to the subsea manifold. They provide an interface to the ROVCON tie-in connection tool which is a collet connector that provides the mechanical connection to the inboard hub. The production THs are insulated to prevent cool down of production flow during a production shut down. They are insulated in the annulus between carrier pipe and flowline with polibrid.

There are three off drill centre (DC) manifolds with TH connections. All DC Manifolds have similar configurations, except for DC-3 which has a pigging loop that would remain connected during manifold retrieval efforts. Cuts on DC-1 and DC-2 manifolds (six cuts each) needed to be as close as possible to the hub. For DC-3 manifold (three cuts), the cuts needed to be close to the flange side (i.e. at the connection to the flexible pipe to the termination head and away from the manifold and inboard hub) so that the weight of the TH protrusion would help

balance the weight of the pigging loop module, which remained connected to the manifold during retrieval.

Decom Engineering were contracted by Havfram to supply equipment for both the subsea cutting of the previously mentioned products and the on-deck cutting of umbilicals. The C1-24 chop saw provided by Decom had a number of modifications custom-designed for the specific cuts to be made during the project. To achieve the cuts desired on the three manifolds, the clamping method was modified to allow the saw to be clamped onto the manifold securely during the cut, and remain securely clamped to the manifold once the cut had been executed. It was essential that once the cut was performed the saw would remain clamped in position to prevent possible damage to the ROV or the tool.

ROVCON cutting As previously mentioned, there were three manifolds to recover, the first of which was DC-3, requiring three off ROVCON cuts. A 2 t uplift buoyancy module was rigged to the saw, which would allow the saw to be clamped onto the ROVCON and disconnected from the crane.

The average cut time for a ROVCON was 35 mins. Once the cut was complete the blade was fully retracted. The upper clamp could then be opened – releasing the cut ROVCON whilst remaining securely clamped to the manifold. When the clamp was sufficiently open, the ROVCON dropped from the clamp arm onto the seabed. The slack was now taken up on the crane, the lower clamp was opened, and the saw released itself from the ROVCON. Once the first ROVCON with a 10 in. internal flowline had been cut, the saw was repositioned on a centre ROVCON with a 6 in. internal flowline and the process repeated. If this was the second cut, the saw was unstabbed and recovered to deck

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for a blade change. Once the three or six cuts were completed, the manifold could be recovered. The cut section revealed that the outer wall had a larger wall thickness than what was expected (35 - 40 mm).

A total of nine cuts were performed by the C1-24 chop saw to retrieve the chain from the northeast, south and northwest clusters.

Initially, the saw was rigged without the buoyancy, however, after the first cut attempt it was decided to include the buoyancy module to help with the heave and reduce potential pinching.

The first cut was performed using a used HMX blade, which had already cut two ROVCONs. Cut time for the chain was on average 25 - 30 min. The nine cuts were then successfully made with no further issues – three TCT blades were used with three cuts per blade.

The first four umbilicals were recovered to deck without a need for the chop saw subsea. These umbilicals were then sheared into 25 m lengths on deck using deck shears supplied by Hiretech. The lengths of umbilicals 1 - 4 were spooled onto the special handling drums during retrieval, they were then spooled out through the

jaws for the shear cutter and into the carousel. Each cut took around 30 seconds.

Due to unforeseen circumstances, Umbilical 5 (UMB5) had to be cut into 30 m lengths subsea. This section of umbilical was a little over 2 km, meaning 68 cuts would be needed. After performing the first cut with the chop saw, it was immediately apparent that this would be a much quicker and consistent method (around 2 min. per cut) than the ROV super grinder (around 30 min. per cut). No need for a dredging process was an additional bonus.

The saw was slung directly to the ROV hook for this operation.

The saw was brought down to depth, stabbed in, and function tested as with previous cutting operations. The saw was then positioned on top of UMB5 with collaboration between the crane driver and the ROV pilots. Once the clamps fully closed, the cut was started and took 2 min. The saw was feeding at maximum speed with blade pressures of under 80 bar. The clamps were then opened, the UMB dropped away from both sides, and a 30 m vessel move called. The cycle time from starting one cut to starting the next cut was around 10 min. One new TCT blade made the first 57 cuts before it was too dull to continue effectively. A new blade was fitted to make the remaining 11 cuts.

Additional work

Figure 1. DC-3 manifold recovered to deck.

Due to the success and efficiency of the cutting operations on the ROVCONs, the client then requested that an additional water injection (WI) ROVCONs to be cut. Extra blades had been brought on the project in case of this event, so Decom was prepared with 10 blades to make the nine WI ROVCON cuts.

The WI ROVCONs were almost identical to the 10 in. flowline ROVCONs on manifolds DC1, 2 and 3. The only differences being that there was no polibrid insulation in the annulus between carrier pipe and flowline. The angle of the ROVCON to the seabed was greater at around 25 - 30°. Again, cut times of around 30 - 40 min. were achieved using the TCT blade, with the blade being changed each cut at the request of the client. This left one blade left over for the project.

ROVCON lessons learned

Figure 2. DC-2 manifold recovery, Chinguetti field – chop saw clamped on ROVCON.

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World Pipelines / NOVEMBER 2022

The saw clamps were more than capable of supporting the 5 t load of the cut ROVCON, despite previous concerns of potential movement of the cut piece towards the end of the cut. This meant that the crane did not have to be rigged to the flowline, and saved a large amount of time during cutting operations.

The pressure feedback shown at the Remote Control Unit and the valve pack would not have provided the required accuracy to perform any cut – the pressure gauges on the saw are essential for ROV operations.

The HMX blade was capable of cutting at least a 10 in. Flowline ROVCON and a 6 in.

Flowline ROVCON. The TCT blade only ever attempted one 10 in.

ROVCON, however, it is believed, based on the motor pressures observed towards the end of the cuts, that this blade would have been capable of at least another cut.

Mooring chain cutting The chain cutting operation was quick and efficient on the whole, however, could have been aided by the following: a dull blade will still struggle to cut even the softer products – such as chain. A new blade should always be fitted for the first cut of new products so that variables that affect the performance of the cut can be kept to a minimum.

It is difficult to land the saw exactly where is most desirable on the chain, and it is especially difficult to grab the chain in the vertical orientation. A V-block and jaws combination that allows the best clamp possible in the horizontal position is preferable. The 500 mm jaws on the upper and lower clamps are not suitable for clamping the chain.

Umbilical cutting The UMB5 cutting operation was completed in a fraction of the time allotted for it. There are still a number of lessons to be learned: the type of seabed has a big impact on visibility and ease of picking up the UMB. With the seabed being so soft, it enabled the saw to be lowered completely onto the UMB so that there was no chance of dropping the UMB when picking up.

The TCT blade made very quick work of the umbilical, with a cut time of around 2 min. However, this cannot be held indicative of all umbilical’s to be cut in the future. A careful inspection of the type of armour in the umbilical has to be made. UMB5 had large 6 mm solid strands of carbon steel which the blade did not snag on until the blade was dull. The same results could not be expected from a fine stranded stainless steel helical armoured UMB. Havfram’s Project Technical Manager, Christopher Hawtone, said on completion of the project: “Havfram recently completed the second phase of a decommissioning project in a remote location using Decom Engineering’s C1-24 chop saw to perform subsea cutting of various assets, including 84 mm stud-less mooring chain, umbilicals up to 145 mm OD, and 20 in. OD Super Duplex flowline terminations.

“From the very start of Havfram’s interactions with Decom Engineering, the team were very professional and solutionoriented, ensuring that the challenging and unique cutting scope was approached with a collaborative problem-solving attitude.

“Decom Engineering delivered quality documentation and equipment on very short lead times, and provided both Havfram and our end client with confidence in the cutting system through full scale testing, both in a test basin and hyperbaric chamber. The technicians provided by Decom Engineering possessed extensive knowledge of the tooling and were well skilled, proactive, and excellent team players.

“During offshore execution, the Decom Engineering tooling was robust and performed efficiently, successfully executing over 100 cuts, a substantial growth in the intended number of cuts, in less than the scheduled time. Overall, Decom Engineering played a vital role in the success of the project, and we look forward to opportunities that allow us to work together again in the future.”

Figure 3. Decom Engineering’s C1-24 chop saw on deck.

Figure 4. On-deck function testing of C1-24 chop saw.

NOVEMBER 2022 / World Pipelines

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These cutting-edge proactive maintenance techniques optimise pipeline pump management to maximise uptime and energy efficiency, says Seth Tate, Manager of Contracts & Digital Offering, Sulzer, USA. ore than 285 000 miles (460 000 km) of pipelines are used to move liquid hydrocarbons to terminals and refineries around the world. This requires roughly 121 terawatt-hours per year which equates to 86 million t of CO2.1 While innovation is the major factor for improving energy consumption in new equipment, avoiding unexpected downtime and optimising existing asset performance presents the greatest opportunities for pipeline operators. Sulzer’s new and innovative approach connects technology to decades of experience in pump system engineering and maintenance to maximise equipment uptime, as well as efficiency.

Today, sustainability is being written into national laws, setting goals for a net-zero target in 2050. Governments are encouraging businesses to adopt more sustainable initiatives to the point that some major projects can only be won by companies that have made a commitment to the net-zero goal. In the oil and gas sector, many major operators joined the Oil and Gas Climate Initiative (OGCI), which aims to accelerate the industry’s response to climate change.

Simplifying the reliability equations Looking in detail at the root cause of asset failure, as well as the latest innovations in technology, reveals how the energy consumption of a pipeline depends on several factors such as maintenance techniques, operator acumen, inventory management, and reliability-based actionable intelligence.

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Operators are forced to focus on after-the-fact, highconsequence issues because they struggle to consistently relate equipment conditions to maintenance efforts and classleading technology.

This often leads to pushing the other operational assets harder, thus trading optimal efficiency with the need to maintain shipping rates. There is a lot to be said about the growth in big data analytics for pumps, but one thing is clear – it is not taking the place of the human resource, rather it is amplifying their value. Sulzer now has a solution that changes the narrative from reactive to proactive actions. Using artificial intelligence (AI), technical expertise, and proactive management techniques, Sulzer provides a competitive advantage with minimal capital investment.

Working as an operating partner, Sulzer offers Total Pipeline ServicesTM (TPS) to connect a range of services designed to improve the economic strength of pipeline pumping systems.

This flexible and simple-to-manage approach optimises pump performance, which directly reduces carbon emissions, supporting the company’s sustainability objectives.

Impacting CO2 emissions

In 2019, Sulzer began the journey to provide a solution to help customers stabilise OPEX budgets, continuously monitor pump health, and engage expertise for the best asset performance. The ability to optimise pump performance and predict issues before they become a concern has the potential to significantly reduce levels of CO2 associated with the industry.

Employing new forms of communication, Sulzer uses existing pump health monitoring as well as industry-leading expertise to focus on the heartbeat of the equipment. By illuminating pre-failure conditions and energy waste, each pump can benefit from optimised efficiency as well as reliability to ensure minimal energy demand and associated emissions.

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Improved pump reliability means planned maintenance on other equipment can be completed efficiently without being called to unexpected issues on the pumps. This results in fewer long-distance road trips for maintenance personnel, which on average equate to 108 kg of CO2 per call-out.2 Decreasing pump downtime results in fewer road trips from maintenance personnel, but also fewer long-distance freight hauls to service shops, and less time running other pump assets at low efficiency to take up the slack of the unavailable pump. In all, that could easily be 3 t per event, just in transportation.3

Environmental goals

Figure 1. Employing new forms of communication, Sulzer uses existing pump health monitoring as well as industry-leading expertise to focus on the heartbeat of the equipment.

Performance guarantees With the TPS solution, Sulzer offers a continuous warranty and performance assurance on assets that are vital to the pipeline’s operation, which is a first for any OEM or maintenance provider.

This provides maintenance budget security for the operator backed by a high-quality repair service.

Pipeline pumps are designed to transfer large volumes over great distances, which requires considerable effort. The scale of the motors in these installations means that seemingly small improvements in efficiency can have significant effects on both costs and environmental impact.

In fact, technology that can improve efficiency by 1% can remove 667 t of CO2/yr on the average pipeline. This contribution can be significant to the overall company goals.4 Every pipeline asset has its own unique set of characteristics that affect energy consumption; predicting potential failures is the most effective solution in terms of uptime and cost. That is why Sulzer also monitors operating, maintenance and engineering knowledge gaps, providing the necessary focused training to the valued employees. Sulzer’s expertise in advanced pump analysis, combined with its shop overhaul and field experience, offers the best solution in the forward push to carbon neutral ownership.

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Todd Razor, on behalf of Vacuworx, USA, discusses pipe handling systems that meet global engineering and safety standards. nergy pipelines are becoming more diverse, and so are the machines relied on by humans to help lift and handle large diameter pipe lengths fabricated for the construction of new pipelines and natural gas transmission and distribution networks.

Certain hard costs, including those related to the materials and labour required to see major pipeline builds through to their successful completion, are widely anticipated and largely unavoidable. Managing certain complexities, however, on the logistical end of transporting, staging, stringing, and installing sizable quantities of large OD pipe can have an impact on overall project economics and outcomes.

The build out of major pipeline systems, such as the Baltic Pipe project in Europe,

demand multipronged periods of collaboration – reflecting the great level of care and attention to detail required to keep thousands of 12 m (approximately 40 ft) double random joints safe, secure, and damage-free during the transportation, storage, staging and installation processes.

Operators considering a turn away from hooks, slings, and cables – or the use of mechanical aids that may result in metal-onmetal contact and could harm the integrity of coated steel pipe – are commonly on the lookout for safer, faster, and more contemporary solutions. When properly attuned and supported, vacuum lifting units have stood out as formidable manual labour-saving attachments in terms of versatility and stamina in the global oil and gas pipe handling fields.

Figure 1. An RC Series unit coupled with a large capacity CAT hydraulic excavator.

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Off the shelf Bi-directional, the purpose-built Baltic Pipe project, allows for the flow of Norwegian shelf natural gas to Denmark and Poland.

Developed by Denmark’s Energinet and Poland’s GAZ-SYSTEM, it represents a new step toward greater energy security for Poland; seeking greater energy independence and the capability to satisfy growing consumption and diverse energy demands.

The Baltic Pipe project is multi-segmented and includes the approximately 110 km (68 m), 800 mm (approximately 31 in.) OD North Sea offshore pipeline – connecting Norway’s gas system with Danish interests and landing on the west coast of Denmark near Blåbjerg – as well as the key 900 mm (approximately 35 in.)

OD offshore Baltic Sea pipeline, estimated at 275 km (170 m) in length, providing bi-directional natural gas shipping capabilities between Denmark and Poland. Installed on the Baltic seabed, it crosses the marine areas of three countries: Denmark, Poland, and Sweden.

The overall project is additionally considered a major piece of gas infrastructure for the Baltic States, and creates a new supply corridor for the Central and Eastern European energy arena. The two-way gas flow is a boom for shippers, according to Energinet, as it allows for gas to flow bi-directionally and unswervingly from Poland to the Danish and Swedish markets, enhancing the potential for market flexibility.

Critical pieces Pipelines are a critical piece of oil and gas industry collateral.

They are viewed as highly important to energy security and energy independence, as well as global decarbonisation activities and long-game sustainability initiatives, such as the

sequestration of carbon, movement of low-carbon hydrogen, and transportation of cleaner-than-coal-burning natural gas.

Staying on top of material-handling complexities during major pipeline infrastructure projects is an extreme challenge.

It is noteworthy to consider some of these complexities and delve into how handlers of large OD pipe may be working to overcome lifting and manoeuvring challenges in the field. What are some alternatives for a safer process that also mitigates potential for damage to pipe joints during complex handling and installation processes?

Pipeline installers deal with an array of activities ranging from stringing and trenching to welding, the application of field coatings, bending, lowering, and backfilling. All these and more must be considered while demonstrating the same level of care for both worker safety, and protecting the coated-steel pipe lengths from damage. Joints may need to be re-handled on multiple different sites and occasions throughout the course of their journey from steel mill to the ROW. High standards have been set by regulatory authorities in Europe, the US, and other parts of the globe for the construction of energy pipelines, with strict attention paid to the integrity of individual pipe joints prior to lowering them in the ground. The tendency of fabricated pipe shippers is to try and minimise contact with the pipe, and the need to re-handle, as much as possible. The more limited repeated contact with the pipe becomes, the greater the potential is to reduce risk and mitigate exposure – automatically keeping more workers away from hazardous situations in which they may not need to be, and reducing the risk of damaging the pipe.

Figure 2. The Baltic Pipe project has included the construction of approxiamtely 900 km (559 miles) of a gas pipeline. (Courtesy of balticpipe.eu)

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World Pipelines / NOVEMBER 2022

Robustness and versatility are companion traits shared all onshore components of the Baltic Pipe in Poland, stated by companies such as MAX STREICHER GmbH & Co., a widethat the increased total gas compression of that country’s ranging organisation active in pipeline construction on the transmission system improves operational security and European continent and intercontinentally, and their Baltic network flexibility.

Pipe employers. Staying productive and bolstering the safety The landfall of the offshore pipeline can be found in factor while mitigating potential for damage is of key interest the Rewal commune on the Baltic coast. Contracts for the to all stakeholders eager for reports of smooth and efficient Goleniów and Gustorzyn compressor stations were awarded operations. to MAX STREICHER S. p. A. Improvements in Denmark and under the Little Belt have been completed, part of an expanded Danish transmission Handling innovations system. Planned expansions for Baltic Pipe infrastructure there Vacuum lifting technology has been used for many years by included construction of a new pipeline from the beach near pipe handlers worldwide including all over Europe, Australia, Blåbjerg to Nybro, a receiving terminal at Nybro, a new pipeline North America. Comprising a vacuum pump and right-sized from Egtved to the Little Belt, a new pipeline across the Little Belt, a new pipeline over Fyn from the Little Belt to Nyborg, and a new pipeline from Kongsmark to the Baltic Sea offshore landfall at the southeastern part of Zealand.

In Denmark, involvement with building out the onshore pipeline, ranging in outer diameter up to 1016 mm (approximately 40 in.), was awarded to AARSLEFF-STREICHER-BUNTE JV I/S, a collaboration among MAX STREICHER GmbH & Co; Aarsleff, a Danish contracting company; and the pipeline FEATURING CAMOUFLAGE TECHNOLOGY construction division of JOHANN BUNTE Bauunternehmung.

A new compressor station in Zealand was also constructed near the Baltic Sea offshore pipeline in Denmark to increase pressure, ensuring natural gas can be transported to Poland. This compressor station also helps ensure reverse-flow capabilities – the transport of gas from Poland into the Danish system.

Polish gas system upgrades as part of the Baltic Pipe campaign included the new construction of the GoleniówLwówek natural gas pipeline, built in two Building on Dairyland’s proven history of industry-leading product lines, stages, at 191 km (approximately 119 m) the PCRX® represents the next technological leap forward in decoupling in length and 1016 mm (approximately technology. Using a sophisticated design, the PCRX’s new camouflage 40 in.) in diameter, and a 41 km technology renders it virtually invisible to interrupted survey testing (approximately 25 m) pipeline connecting making it easier than ever to protect and maintain your CP system. the Baltic Pipe project with Poland’s national transmission system. The newly developed Gustorzyn gas compressor station serves as an interconnection between the gas transport systems of the Republic of Poland and the Republic of Lithuania (GIPL). Two existing Polish Scan to watch a short video. gas compressor stations in Odolanów For more product information, and Goleniów were modernised and visit Dairyland.com /PCRX extended.

GAZ-SYSTEM, which selected contractors for the construction of

THE MOST SOPHISTICATED IN THE WORLD

Figure 3. A CAT 352 and Vacuworx lifter near Kolding, Jutland in Denmark.

Figure 4. The system at work handling Baltic Pipe lengths at a storage yard.

Figure 5. Lifting capacity on the RC Series ranges upward of 25 t (50 000 lb).

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World Pipelines / NOVEMBER 2022

vacuum pad and assembly, among other components, Vacuworx pipe handling systems are controlled via wireless remote operation and commonly tasked to work in conjunction with large-capacity excavators in the field.

They can perform tasks ranging from loading to offloading trucks, barges, and railcars to stacking pipe in laydown yards, and more, such as helping fit up pipe to be welded or stringing joints alongside the ROW. RC Series lifters developed by Vacuworx have lifting capacities ranging from 10 t (20 000 lb) to 25 t (50 000 lb) and more, demonstrating the ability to handle pipe approximately 102 mm (4 in.) in diameter and up with no maximum size limit. A hydraulic rotator provides for 360° movement of the lifting apparatus, enabling fast and precise placement of pipe. This generally makes things easier for operators to perform lifting and handling tasks from an improved position, enhancing views of the lift zone while keeping a safe distance – less proximity to the material being lifted.

MAX STREICHER GmbH & Co. and its counterparts value the use of high-quality construction materials, and the joint and constant optimisation of best practices to create efficient workflows, including the provision of all information and resources needed in a timely manner.

The company’s role as part of the Baltic Pipe project build out was taking responsibility for welding, lowering, and connecting, as well as bending pipe to align with the ROW’s topography – to follow the Denmark onshore pipeline’s unique route and ground contours.

Mechanical damage defect types identified by the US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) include metal loss, metal deformation, cracking, and denting. Studies of mechanical damage also resulted in the development of guidance for inclusion in the American Society of Mechanical Engineers (ASME) codes covering the significance of avoiding damage or dents for gas transmission pipelines.

Dents, commonly caused by contact with construction equipment, are costly given inspections may be required to determine if they fall within acceptable tolerance limits.

The pipe may have to be put up for repair, too, if a certain type of damage is deemed to have a possible detrimental impact on safety or the operational performance of a pipeline.

Though they may be potentially insignificant from a structural point-of-view, according to guidance offered in an International Pipeline Conference (IPC) proceedings paper on the effects of dents and gouges in pipelines, dents can present difficulties, and must be examined closely. A dent should never be underestimated, due to its potential to cause local stress and strain concentration, and a local reduction in the pipe diameter, reducing the static and cyclic strength of a pipe.

Dent depth is highly significant in terms of how such damage may affect the burst strength and fatigue strength.

Plain dents do not significantly reduce the burst strength of the pipe, the IPC paper stated, but the fatigue life of

pipe containing a plain dent is less than the fatigue life of plain circular pipe. The burst and fatigue strength of a dented weld, or of a dent containing a defect such as a gouge, can be significantly lower than that of an equivalent plain dent. A smooth dent containing a gouge (or other part-wall metal loss defect) is a very severe form of mechanical damage.

Dents can also be associated with damage to pipe coatings – possibly leading to the initiation of corrosion or environmental cracking.

Handling manoeuvres related to specialised tasks such as pipe bending may require even more unique attention.

The activity is generally accomplished using a pipe bending machine, with features that govern the amount of the bend in the pipe section in such a way that it avoids causing damage to the pipe or delicate bonded coatings.

Offset costs Costs related to materials, labour, ROW, and ancillary expenditures make up the total price tag of a pipeline construction project, with labour costs generally dominating the lion’s share of total expenditures. Material costs reportedly overshadow the total costs in the construction of compressor stations.

Overall costs can be exacerbated if the appropriate care to protect the integrity of products is unable to be maintained sufficiently and consistently throughout the entire course of a pipe handling job – and into operational status of a newly developed pipeline.

Technological advancements in pipeline materials and monitoring systems are making pipelines safer, helping reduce the probability of environmental impacts before, during and after an installation. The focus is on maintaining pipeline integrity, environmental consciousness, and the avoidance of severe consequences that could follow an incident or accident.

In the field, during boots-on-the-ground deployments, the absence of the right equipment or methods of pipe handling can be detrimental, from a safety standpoint and a pipeline integrity standpoint.

Mitigating the potential for events that could expose workers to possible hazards, require excessive labour units, or damage pipe during the transit and installation processes, can equate to less downtime, lower costs, and higher-value tasking of skilled employees.

From a material-handling perspective, pipe movers and logistics companies are gravitating toward technologies and machines that they can envision helping overcome handling challenges and fostering more attractive business outcomes.

For the Baltic Pipe job, STREICHER GmbH & Co. acquired an RC Series lifter and 1016 mm (approximately 40 in.) pad assembly directly from equipment dealer and Vacuworx distributor Maats Pipeline, based in the Netherlands. The lifter, coupled with a high-capacity CAT 352 hydraulic excavator, was deployed on their portion of the Baltic Pipe project in Denmark for several weeks.

“The lifting device from Vacuworx was used on the bending machine,” said Jens Mogwitz, Mechanical Engineering, MAX STREICHER GmbH & Co. “The pipes used here were 32 in., 36 in. and 40 in. (approximately 812 mm, 914 mm and 1016 mm).

They were 12 m (approximately 40 ft) in length, with thicknesses between 19 mm and 30 mm (approximately 0.75 in. and 1.18 in.), and weights of up to 12 t (24 000 lb). We used the RC lifting device to unstack the pipes and took them to the pipelayer.

This is just one way to use this lifting device.”

“Maats plays a major role in our department maintenance and mechanical engineering,” Mogwitz continued. “It’s a good address for spare parts, rental machines, and pipeline equipment.”

Vacuum lifters are respected on the European front for their durability and time-saving capabilities. The diversity of such machines is demonstrated in part by their ability to couple with different host carriers like excavators, skid steers and loaders – with custom vacuum pad assemblies available for adaptation of the machines during an array of different pipe lifting and manoeuvring scenarios.

RC Series lifters are powered by powerful and selfcontained diesel engines while ‘H’ model units operate via the hydraulics of carrier equipment. The manufacturer’s propriety vacuum pad seal material is engineered to cause zero damage to pipe coatings. All Vacuworx units are designed, engineered, and tested to meet or exceed many global engineering and safety standards, including the European CE Machinery Directive, CE Low Voltage Directive and CE Electromagnetic Interference Directive, and EN13155 standards that apply to vacuum lifters, among others.

“We operate worldwide and have already implemented many projects in our neighbouring countries as well as in Africa and Australia,” Mogwitz said. “As well as the order here in Denmark, the Baltic Pipe, which we did in cooperation with the company Aarsleff and the company Bunte. In Tunisia (Navara Pipeline), as another example, we used (an RC Series lifter) to unload the pipes from the truck and (string) lay them out.

The device is really safe, and easy to use, and also saves two workers.”

Big commission The European Commission (EC) released approximately €215 million to help finance the Baltic Pipe project allowing, for the first time, for natural gas flows to Denmark and Poland from Norway. It also facilitates Poland’s ability to supply the Danish market and neighbouring Baltic states.

The capital expenditure for the Danish part of the Baltic Pipe project had been estimated at €1.1 billion, according to Energinet. Danish gas consumers, the company states, can expect the project to yield €270 million in savings on tariffs.

Poland’s energy policy aims to use natural gas as a transition fuel in pursuing its long-term goal of a zero-emission energy system, the International Energy Agency has stated.

Consumption of natural gas in that country is set to increase to 30 billion m3 by 2030, as the share of coal is reduced in electricity generation and building heating.

The overall Baltic Pipe project’s original operation date had been set for October 2022, with full operational status and delivery of full capacity of 10 billion m3 expected in early 2023. The tie-in to the Norwegian natural gas supply source was made via existing North Sea infrastructure – Europipe II – currently connecting Norway and Germany.

NOVEMBER 2022 / World Pipelines

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Pipeline managers need timely and actionable reports that allow them to get in front of potential problems, says Jesse Hughes, Orbital Sidekick, USA.

ompliance with PHMSA parts 192 or 195 for transmission pipelines generally begins with routine visual observation from small aircraft at about 2000 ft (700 m) above ground level (AGL). Through this approach, certain macro threats to the assets can be spotted and reported quickly. Unfortunately, the results are subjective at best, and tend to be inconsistent while real threats and even active leaks remain undetected. Despite real dollars being spent to achieve this compliance objective, operators recognise that the resulting reports (and reporting) leave much to be desired. As a result, new and novel technical monitoring solutions are proliferating. We see this with inline product densitometers and in-situ leak detection probes on our pipelines, as well as lane-drift and tyre pressure alerts on our automobiles. We are witnessing the dawn of a new space age where commercial access to space has become a reality. Given this, have the days of routine visual aerial patrol become numbered?

Sophisticated satellite-based data collection technologies, such as hyperspectral imagery, synthetic aperture radar (SAR), or laser imaging, detection and ranging (LIDAR), have all proven expensive to employ, which has severely limited their application in routine industrial application. The sensors themselves were expensive and the resulting data they generated all required unique infrastructure to process, even before considering the cost of deployment and operation. However, several industry changes have recently fallen into place that have radically upended the possibilities. Foremost among them is

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the cost to place an object in orbit, which has plummeted.

Additionally, technology miniaturisation allows equipment that can operate in space to be produced much more cheaply.

Leading so much of today’s literal new space race, SpaceX has demonstrated the feasibility of cheap satellite constellations delivering ever-more tailored solutions.

Commercial competitors are entering the field rapidly, and hardware costs continue falling thanks to new production techniques and a proliferation of companies entering an underserved market. Computing costs also continue to plummet, enabling software to manage skyrocketing demands for rapid data processing.

Oil and gas midstream operators have been among the first to derive essential capabilities from early detection technologies. The horizon has broadened and powerful new satellite capabilities are finally enabling them to forgo human eyes on a plane in favour of advanced, objective, persistent, and global insights from orbit.

Collection tools just got affordable Pipeline operators keep continual, watchful eyes on their assets. The tyranny of distance and geography adds significant cost and manpower to the critical task of monitoring. At the same time, safety and maintenance benefits derive from pipeline burial, being out-ofsight inherently adds ambiguity and opaqueness to the monitoring task. But there is no silver bullet as no detection system can provide all the answers, everywhere, all the time.

Competing resource trade-offs ultimately conduct the mix of solutions that operators choose for themselves, which results in a patchwork of solutions seeking to accelerate detection and identify risk. Custom satellite solutions are now included in the solutions basket, and to complement and replace some of the old ones.

Figure 1. Orbital Sidekick’s Aurora Satellite.

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World Pipelines / NOVEMBER 2022

Data requirements balloon Every photo taken with your smartphone essentially generates three images: one in red, one in blue, and one in yellow. Each of these colours represents a different frequency of radiation that the human eye is able to detect. Each resulting, integrated image is then the photo you see, share, and post. There are processing and data throughput requirements for each of these three base images. Multispectral adds a few (or sometimes a few dozen) ‘colour’ bands to the image, each containing specific information beyond unassisted human sight.

Beyond multispectral is hyperspectral imagery, which gathers as many as 500 adjacent light bands. These can extend into ranges that are indistinguishable with the human eye. The resultant data is described as a ‘cube’ and is magnitudes larger than for standard digital photography.

All of this is to say that the data volume generated by hyperspectral can easily overwhelm legacy infrastructure.

Therefore, the gap between hyperspectral technology architectures and data demand has narrowed to the point of viability. With improved availability of communications and analytical tools, market entrants are racing to provide multispectral and hyperspectral images from orbiting satellites, leveraging the improved architecture.

Process and analyse: the data burden increases The transmission architecture for data was built for data streams, not data cubes. The same was true for the computational platforms and applications built to process and analyse data. Typically, computing continues to increase in power, decrease in cost, and decrease in physical size. In many ways, processing and analysing data remains the greatest challenge in the overall cycle.

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We humans have not had enough time with complex data to make its ingestion commonplace. This limits the available expertise for processing and analysing big data.

At this stage in development, human expertise plays one of the most important roles, and the dearth of human experts is a significant limiting factor. Here, too, the industry is a bit fragmented. Some companies specialise in only the processing and analysing of other’s data (e.g.

Satalytics), while others simply collect the data and sell it forward. A few companies maintain these functions internally (e.g. GHGSat, Orbital Sidekick). The common thread across this stage of the intelligence cycle is that companies recognise that their customers do not have the infrastructure or specialised expertise required to analyse the specialised data, but they still need results fast.

Pipeline managers in particular need timely and actionable reports that allow them to get in front of potential problems. Additionally, those reports must be digestible in a format and platform that is familiar.

Disseminate through all available tools, platforms, dashboards, and applications Every person at every level of the company consumes intelligence. Email is ubiquitous, but it is always efficient and it certainly isn’t collaborative. The need to consume intelligence differently has given rise to platforms and dashboards, and control consoles are tailored for different functions within an organisation. This space is nowhere near the point of consolidation, which is why having a dissemination platform continues to be a requirement for intelligence companies. None of them will be as convenient as a clipboard thrown on the dashboard, but there are a few minimum requirements that have emerged from the midstream: privacy, accuracy, simplicity, and history. Pipeline managers demand that their information only be accessible to those they designate. The analysis must be simple, clear, and accurate so it can be printed and taken into the field for physical validation. And the platform must also convey historic information: What was here before? How does it look now? Is the issue resolved?

These are the fundamental needs for pipeline operations to include field hands and managers, as well as executives.

It’s a lot of personas to consider, but there are a multitude of companies feverishly working to solve those challenges.

Where to go from here?

Pipeline managers and operators are among the most aggressive in adopting new technologies, and the market is responding. Every stage of midstream operations intelligence gathering, which includes analysis and dissemination, companies have offerings to advance capabilities, from piecemeal to holistic solutions. These solutions are doing their best to get in front of you and will gladly answer your questions. This is an exciting time in the industry and an even better time to find a partner in space.

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