World Pipelines February 2022

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®

Volume 22 Number 2 - February 2022

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CONTENTS WORLD PIPELINES | VOLUME 22 | NUMBER 2 | FEBRUARY 2022 03. Editor's comment 05. Pipeline news

Jeff Ortego and Alan Matthews, Celeros Flow Technology, US, explain how and when to deploy reciprocating pumps to deliver better efficiency and reduce total cost of ownership.

Updates on Gazprom and PGNiG's legal battle, North American pipeline lengths, and contract news from Imenco and ConocoPhillips.

R

eciprocating pumps offer many benefits in low flow, high pressure applications commonly found in the oil and gas sector. However, the technology is not as well understood as centrifugal pumps, which can lead to mis-specification. Every process condition needs a pump. The challenge facing pump specifiers and users is to identify the technology that will best meet the

KEYNOTE ARTICLES: CYBERSECURITY 10. The case against keeping it in-house

Vicki Knott, CEO and Co-Founder of CruxOCM, Canada, considers pipeline cybersecurity in 2022 and argues that promoting your IT head to ‘CSO’ is a recipe for disaster.

PAGE

Figure 1. Reciprocating pumps bring benefits in critical flow control applications where high differential pressure is combined with relatively low flowrates.

Vicki Knott, CEO and co-founder of CruxOCM, Canada, considers pipeline cybersecurity in 2022 and argues that promoting your IT head to ‘CSO’ is a recipe for disaster.

H

ow are cybersecurity, control systems, and digital transformation related? Spoiler alert – they are the only way our industry will make it into the future and they require innovation. Times, they are a-changing. Let’s start with the ultra hot topic: cybersecurity. I will say this upfront and repeat it over and over again: please do not promote your 20+ year IT veteran employee to Chief Security Officer (CSO). Think about it from this perspective – how much have cell phones changed in the last 20 years? Do you think the same engineers that built the 1990s old school car phone built the iPhone? It’s unlikely. So, why are we expecting our engineers and IT professionals that have epic amounts of organisational-specific business acumen to also learn how to build cybersecurity capabilities that evolve at an unprecedented pace every year? Doesn’t it make more sense for them to keep the core business running and pass down critical operational knowledge to new team members? Based on what I have seen in the industry, promoting internal folks to unrealistic roles is far too common. Not only are we setting up tenured, loyal employees to

30

fail, but we are also hurting the business’s bottom line by wasting time and money implementing non-optimal solutions. As an industry, when we set employees up to fail, we unknowingly contribute to a culture of risk aversion. Risk aversion is important in our industry, but not to the point where employees cannot discern between business risk and safety risk – a line I see people in the industry blurring more and more these days as the market plunges us all into a scarcity mindset. Risk adverse employees who have been set up to fail by leadership are then asked to be innovative? Doesn’t sound like a working recipe to me. Bottomline, it’s critical to hire the experts. Hire the firms that have a team of coders who set up honey pots to lure in the hackers and learn their behaviours. They exist, we just have to look beyond the walls of our pipeline organisations. And I’ll repeat, this is not something your in-house team can learn.

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INTEGRITY AND INSPECTION 35. Understanding complex anomalies

Christopher Holliday, Andrew Wilde and Alasdair Clyne, ROSEN Group, Switzerland.

Control systems What seemed far fetched and down right questionable 30 years ago is now very much an operational norm. I had a control room operations lead look at me once

41. Propelling ILI to the next level

Stuart Clouston, Baker Hughes Process & Pipeline Services, USA.

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15. Taking industrial cybersecurity seriously

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Steve Hanna, Co-Chair of the Industrial Work Group at Trusted Computing Group (TCG), USA, describes how to protect the digital future of pipeline operations.

CORROSION CONTROL 45. 3D for the win

Jérôme-Alexandre Lavoie, CREAFORM, Canada.

PIPELINE MACHINERY FOCUS 48. Handling the big projects with ease Todd Razor, Vacuworx, USA.

MATERIALS PERFORMANCE 53. Transferrable testing Glyn Morgan, Element, UK.

REMOTE OPERATION 19. Intelligent insights

William Wright, nVent Thermal Management, USA.

25. A new layer of reliability for HCA pipelines Harry Smith, Atmos International, UK.

VALVES, PUMPS AND ACTUATORS 30. Explaining reciprocating pumps

.Jeff Ortego and Alan Matthews, Celeros Flow Technology, USA.

FEBRUARY 2022

Reader enquiries [www.worldpipelines.com]

WORLD PIPELINES

ON THIS MONTH'S COVER

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Volume 22 Number 2 - February 2022

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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.

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EDITOR’S COMMENT CONTACT INFORMATION MANAGING EDITOR James Little james.little@palladianpublications.com EDITORIAL ASSISTANT Sara Simper sara.simper@palladianpublications.com SALES DIRECTOR Rod Hardy rod.hardy@palladianpublications.com SALES MANAGER Chris Lethbridge chris.lethbridge@palladianpublications.com DEPUTY SALES MANAGER Will Pownall will.pownall@palladianpublications.co PRODUCTION Calli Fabian calli.fabian@palladianpublications.com DIGITAL EVENTS CO-ORDINATOR Louise Cameron louise.cameron@palladianpublications.com DIGITAL ADMINISTRATOR Lauren Fox lauren.fox@palladianpublications.com VIDEO CONTENT ASSISTANT Molly Bryant molly.bryant@palladianpublications.com ADMIN MANAGER Laura White laura.white@palladianpublications.com Palladian Publications Ltd, 15 South Street, Farnham, Surrey, GU9 7QU, UK Tel: +44 (0) 1252 718 999 Fax: +44 (0) 1252 718 992 Website: www.worldpipelines.com Email: enquiries@worldpipelines.com Annual subscription £60 UK including postage/£75 overseas (postage airmail). Special two year discounted rate: £96 UK including postage/£120 overseas (postage airmail). Claims for non receipt of issues must be made within three months of publication of the issue or they will not be honoured without charge. Applicable only to USA & Canada: World Pipelines (ISSN No: 1472-7390, USPS No: 020-988) is published monthly by Palladian Publications Ltd, GBR and distributed in the USA by Asendia USA, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid New Brunswick, NJ and additional mailing offices. POSTMASTER: send address changes to World Pipelines, 701C Ashland Ave, Folcroft PA 19032

O

ne of my favourite TED Talks is titled: ‘Instead of setting goals, define your fears’. Tim Feriss, earlystage tech investor, best-selling author and podcaster, argues that “the hard choices – what we most fear doing, asking, saying – these are very often exactly what we most need to do”.1 The talk, which is based on the principles of Stoicism, advocates ‘fear-setting’ in place of goal-setting. Tim recommends doing SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com a three-part exercise where a person asks, firstly, ‘What if I…?’ and then fills in the blank with something that they fear, or something they are avoiding, or that causes them anxiety. They then must make three lists under the headings: define, prevent, repair. Under these headings, the person writes a list ‘defining’ all the worst things they can imagine happening as a result of taking the action that scares them. Then they list under ‘prevent’ some things they could do to prevent each of those worst outcomes from happening. Finally, under ‘repair’ they list what they could do to repair the damage (or who could they ask for help and support) if the worst-case scenario happens. For part two of the exercise, they must ask themselves ‘what might be the benefits of an attempt or partial success?’ For part three: list the potential costs of inaction (emotionally, physically, financially, etc): in six months’ time, in a year’s time; and in three years’ time. Tim says: “ask yourself: if I avoid this action or decision, what might my life look like?” Tim says it’s lifechanging, and recommends doing the activity once a quarter. It strikes me that this would be a wonderful way to address challenges in your business. Often the thing we most strenuously avoid doing is the thing we really must do. If you’re looking at the future of your business, why not try fear-setting instead of goal-setting? Of course, the pipeline industry is well-versed in planning for the worst-case: any pipeline operator will tell you that emergency response planning, incident management, safety strategies and asset integrity activities are based on the principles of risk assessment, forecasting outcomes and the application of lessons learned. Those tasked with guaranteeing safe oil and gas pipeline transportation will already use something akin to fear-setting, even if they don’t call it that. In this month’s issue of World Pipelines, our keynote articles focus on cybersecurity and protecting the digital future of pipeline operation. Vicki Knott (Crux OCM, p. 10) offers a think piece on the future of your control room, and why it pays to take a disruptive approach to staffing your cyber department. The risk of cyber attacks is rising, and more attention is paid to hacks when they happen. Change in your control room is imperative: on p. 15, Steve Hanna (Trusted Computing Group) argues that the advanced connectivity provided by Industrial IoT (connected equipment, cloud storage, data mining, deep learning), must be complemented by increased attention to cybersecurity. If dark forces are looking to exploit our pipeline networks’ vulnerabilities, then we must define our fears and tackle them head on. 1.

https://www.ted.com/talks/tim_ferriss_why_you_should_define_your_fears_instead_of_your_goals


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WORLD NEWS North America to continue to dominate global transmission pipeline length to 2025 With its trunk/transmission pipeline network expected to reach a total length of 967 623 km by 2025, North America will continue to dominate global pipeline length with a maximum share of around 44%, according to GlobalData, a leading data and analytics company. GlobalData’s report, ‘Global Oil and Gas Pipelines Industry Outlook to 2025 – Capacity and Capital Expenditure Outlook with Details of All Operating and Planned Pipelines’, reveals that the total length of the global trunk/transmission pipeline network is expected to be 2 193 350 km by 2025 (with start years up to 2025, as of December 2021). North America would have the most pipeline length with 967 623 km, followed by the Former Soviet Union (FSU) and Asia with 418 824 km, and 243 772 km, respectively. Teja Pappoppula, Oil and Gas Analyst at GlobalData, comments: “North America is expected to witness the start of operations of 105 planned and announced pipelines by 2025, adding an approximate total length of 18 879 km.” Among upcoming pipelines, San Fernando–Cactus is the

longest upcoming pipeline with a length of 1609 km. The natural gas pipeline is expected to start operations in Mexico by 2023. The pipeline would bring much needed gas to energy-deficient states of Chiapas and Oaxaca in Mexico. Teja adds: “The FSU occupies second place with a share of 19.1% in the global transmission pipeline length by 2025. The total length of the transmission pipeline network in the FSU is 418 824 km and is also expected to witness planned and announced pipeline length additions of 13 807 km by 2025. This region’s pipeline combined with the world’s largest active pipeline the Russian Gas System, runs for a length of 175 200 km. “Asia ranks third place with an 11.1% share in the global transmission pipeline length. The total length of the pipeline network is 243 772 km. Sui Northern Gas Transmission natural gas pipeline in Pakistan is the longest pipeline in the continent with a length of 7915 km.” Growing demand for oil and gas, especially in Asia, and exports are primary drivers for the growth of the transmission pipelines globally.

Subsidiary for the German part of the pipeline established Nord Stream 2 AG has founded a German subsidiary, Gas for Europe GmbH. The new company is to become the owner and operator of the 54 km section of the Nord Stream 2 Pipeline located in the German territorial waters and the landfall facility in Lubmin, as an independent transmission operator in

accordance with the German Energy Industry Act (EnWG). In November 2021, the German Federal Network Agency (Bundesnetzagentur) had issued a statement saying that the founding of a subsidiary would be a precondition for the certification according to the German Energy Industry Act.

Arbitration between Gazprom and PGNiG concerning the contract price under the Yamal contract On 14 January 2022, Polskie Górnictwo Naftowe i Gazownictwo (PGNiG) received a notice of arbitration before the ad hoc Arbitral Tribunal in Stockholm from the counsel of PAO Gazprom and OOO Gazprom Export of arbitration. The notice includes a request for the revision of the contract price for natural gas supplied by Gazprom based on the Yamal Contract. Gazprom expects a retroactive increase of the contract price based on Gazprom’s revision requests of 8 December 2017 and 9 November 2020. ‘The request for the increase of the contract included in Gazprom’s notice is absolutely unfounded. We are well prepared to prove it before the Arbitration Tribunal’, said Pawel Majewski, CEO of PGNiG SA. PGNiG continues its efforts to revise the price terms for the delivery of natural gas under the Yamal Contract. Notably, that

the above-referenced revision requests of Gazprom were submitted in response to the requests of PGNiG demanding a decrease of the contract price of 1 November 2017 and 1 November 2020, provided that, at the time of record high gas prices in Europe, PGNiG’s request of November 2020 was modified on 28 October 2021. Gazprom’s submission of the notice for arbitration initiates the dispute settlement procedure specified in the Yamal Contract. PGNiG says it will take relevant action to enforce its rights and to protect the Company’s interests. PGNiG has twice, in 2011 and 2015, exercised its right to commence arbitration under the Yamal Contract. In consequence of the proceedings initiated in 2015, in March 2020, the Arbitral Tribunal revised the price formula under the contract, granting the request of PGNiG.

Crucial Iraq-Turkey oil pipeline reopens after explosion Turkey has reopened a key crude pipeline running from Iraq after it was knocked out by an explosion on 18 January 2022. Flows through the conduit, consisting of two lines in the blast area and which carried more than 450 000 bpd last year, have returned to normal levels, according to a senior Turkish official quoted by Bloomberg. National energy company Botas is using one of the lines and

repairing the other after it was damaged, the official said. The explosion happened after a power pylon fell on a pipeline during bad weather, causing a fire. The pipeline brings oil from northern Iraq to Europe via the Mediterranean port of Ceyhan and runs close to the Syrian border. The shutdown was the latest in a series the market has suffered in recent months.

FEBRUARY 2022 / World Pipelines

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WORLD NEWS IN BRIEF GERMANY PRISMA European Capacity Platform GmbH has announced that project company ICGB, responsible for the implementation of the interconnector Greece-Bulgaria, is a new operator on its platform.

USA In 2021, pipeline companies completed 14 petroleum liquids pipelines projects in the US, according to the recently updated ‘Liquids Pipeline Projects Database’. This total includes seven crude oil pipeline projects and seven hydrocarbon gas liquids pipeline projects; no petroleum product pipeline projects were completed last year.

EQUATORIAL GUINEA The first fully bonded 2.5 in. ID, 2200 m thermoplastic composite pipe (TCP) flowline with an integrated weight coating has been supplied to Trident Equatorial Guinea Inc. to support operations at its Elon-C tie-back, located offshore on the west coast of the Central Africa region.

UK A pioneering energy project to gather vital evidence about the suitability of the gas network to transport hydrogen will see the clean burning fuel odourised to smell like natural gas for the first time. The project, located on a disused network of gas mains in the South Bank area of Middlesbrough, will test operational procedures under 100% hydrogen conditions on an existing network for the first time.

USA The US Energy Information Administration (EIA) forecasts that US oil production will average 12.4 million bpd during 2023, surpassing the record high for domestic crude oil production set in 2019 (pre-pandemic).

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World Pipelines / FEBRUARY 2022

DNV supports world first large-scale testing of submerged CO2 pipelines DNV, the independent energy expert and assurance provider, is working with Wintershall Noordzee and the OTH Regensburg University of Applied Sciences to explore how existing natural gas pipelines in the southern North Sea can be used for future carbon dioxide (CO2) transport. The work scope entails large-scale CO2 pipeline testing of running fracture in submerged (water) condition, which is a world first for the energy industry, and a comparison with similar testing of the pipe in open air. The aim of the tests is to quantify the potential beneficial effect of the water surrounding the pipeline on the crack arrest behaviour for a specific pipeline, and thus better define the model parameters used for different backfill types. Further, preliminary simulation results

using numerical models suggest that running fracture in pipelines transporting dense phase CO2 may be easier arrested in submerged conditions vs in air. The project initiated by Wintershall will also aim at experimentally validating this theory. Klaus Langemann, Senior Vice President of Carbon Management and Hydrogen at Wintershall said: “We are optimistic about the further investigations. Our calculations already show that existing offshore pipelines could be well suited for transporting liquid CO2. The next step will be to demonstrate the reliability of the evaluation process and prove the feasibility experimentally.” The large-scale testing of the CO2 pipelines will take place at DNV’s Testing and Research Facility at Spadeadam in the UK.

Iran leads midstream project starts in the Middle East by 2025 Iran is likely to set to start operations at 27 midstream oil and gas projects between 2021 and 2025, accounting for 22% of upcoming midstream projects in the Middle East, according to GlobalData. GlobalData’s report, ‘Middle East Midstream New-Build and Expansion Projects Outlook, 2021 - 2025’, highlights that transmission projects make up 15 (56%) of the 27 projects expected to commence operations in Iran, while six are gas processing projects (22%) and four are underground gas storage projects (15%). Sudarshini Ennelli, Oil and Gas Analyst at GlobalData, comments: “Despite ongoing international sanctions led by the US, Iran is announcing massive investment plans across the oil and gas value chain, including the midstream sector. The investments focus on building greater transport and storage to meet the growing demand for oil and gas, as well as for exports.” One key upcoming transmission project is the Iranian Gas Trunkline – IGAT XI gas pipeline, operated by the National Iranian Gas company. Ennelli continues: “With a length of 1200 km, the IGAT XI project is an onshore gas pipeline that extends from Bushehr (Iran) to Tehran (Iran), with a maximum diameter of 56 in.”. The pipeline would extend from Asalouyeh, in Bushehr province, in the south, through Ahvaz, Dehgolan, to the Bazargan, in west

Azerbaijan province. The project is currently in the construction stage and is expected to start operations in 2025.” The South Pars Phase 14 is one of the key gas processing projects, with an expected capacity of 1765 million ft3/d. Ennelli adds: “The South Pars gas field, also known as North Dome, is the world’s largest gas field and is shared by Iran and Qatar. Iran is building several gas processing plants to boost output from the giant South Pars gas field, and the South Pars Phase 14 is one more step to achieve that goal. The first train of Iran’s South Pars complex’s phase 14 refinery is almost finished and would be placed into service soon.” The four underground gas storage projects are Shorijeh II, Nasrabad, Ghezel Tapeh, and Yortsha. Ennelli notes: “One of the key projects is Shorijeh II with a working gas capacity of approximately 78 billion ft3. It is one of the largest gas storage facilities in Iran as well as in the Middle East and further helps to meet peak winter gas demand. The project is currently in the feasibility stage and is expected to start operation in 2025. Shurijeh field’s current storage capacity of 20 million m3/d will be increased to 40 million m3/d, with storage capacity increasing from 2.25 billion m3 to 4.5 billion m3”.


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CONTRACT NEWS EVENTS DIARY 21 - 22 February 2022

Transportation Oil and Gas Congress 2022 (TOGC 2022) Zurich, Switzerland https://togc.events/

6 - 10 March 2022

AMPP Annual Conference + Expo San Antonio, USA https://ace.ampp.org/home

7 - 10 March 2022

17th Pipeline Technology Conference Berlin, Germany https://www.pipeline-conference.com/

21 - 23 March 2022

European Gas Conference (EGC) Vienna, Austria https://energycouncil.com/event-events/ european-gas-conference/

10 - 12 May 2022

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

23 - 25 May 2022 StocExpo 2022

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

23 - 27 May 2022

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

22 - 23 September 2022

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

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World Pipelines / FEBRUARY 2022

Imenco signs large contract for delivery of subsea cameras Imenco and DeepOcean, both based in Haugalandet, Norway, are major national and international contributors in their markets. The contract includes delivery of 96 underwater cameras, which DeepOcean will mount on its entire fleet of remotecontrolled underwater vehicles (ROVs) over the next three years. “The cameras are developed by Imenco and can stream high quality IP video with low time delay. We have worked closely with DeepOcean for a long period of time, and are very happy to have landed this large and valuable contract”, says Area Sales Manager, Inge Ivesdal. Erik M. Hauge, Operations Director for DeepOceans’ Europe region, says “This helps to strengthen our local region, Haugalandet, and its strong position as a subsea region. Over a three year period, we will replace all our underwater cameras on the ROVs with a future-oriented quality product, which will strengthen our competitiveness”, says

ConocoPhillips announces agreement to sell Indonesia assets for US$1.355 billion The company announced it has entered into an agreement to sell the subsidiary that indirectly owns the company’s 54% interest in the Indonesia corridor block Production Sharing Contract (PSC) and a 35% shareholding interest in the TransAsia Pipeline company. The sale to MedcoEnergi for US$1.355 billion is subject to customary adjustments and is expected to close in early 2022, subject to certain conditions precedent. The Indonesia assets being sold produced approximately 50 000 boepd for the nine months endin 30 September 2021, and had year-end 2020 proved reserves of approximately 85 million boe. The effective date for the transaction will be 1 January 2021. In addition, through its Australian subsidiary, the company announced that it has notified Origin Energy that it is exercising its pre-emption right to purchase up to an additional 10% shareholding interest in Australia Pacific LNG (APLNG) from Origin Energy for up to US$1.645 billion. The transaction is expected to close in the 1Q22 and is subject to Australian government approval.

Hauge. Demand for advanced underwater cameras and other underwater electronics is particularly high in the US and the UK, in addition to Norway. In total, this part of the business has a turnover of more than US$12 million, and around 80 of Imenco’s 300+ employees are engaged in the development, production and sales of camera technology from the bases in Haugesund (Norway), Aberdeen/Wick (Scotland) and Lafayette (LA, USA). The cameras that will be delivered to DeepOcean are the SubVIS Orca HD IP Zoom camera, a high-end camera that is used as the main camera on ROVs. The camera has a built-in, Imenco-developed computer for transferring high quality and low time delay video. Numerous different parameters can be configured by the user to adapt to the operator’s other equipment and the operational conditions.

THE MIDSTREAM UPDATE •

Feasibility study completed for Soyuz Vostok gas pipeline project

Voith becomes sole owner of ELIN Motoren

Siemens Energy presents sustainability report

Pakistan to strengthen natural gas transmission pipeline network

Technical Toolboxes acquired by HKW Follow us on LinkedIn to read more about the articles linkedin.com/showcase/worldpipelines


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Vicki Knott, CEO and Co-Founder of CruxOCM, Canada, considers pipeline cybersecurity in 2022 and argues that promoting your IT head to ‘CSO’ is a recipe for disaster.

H

ow are cybersecurity, control systems, and digital transformation related? Spoiler alert – they are the only way our industry will make it into the future and they require innovation. Times, they are a-changing. Let’s start with the ultra hot topic: cybersecurity. I will say this upfront and repeat it over and over again: please do not promote your 20+ year IT veteran employee to Chief Security Officer (CSO). Think about it from this perspective – how much have cell phones changed in the last 20 years? Do you think the same engineers that built the 1990s old school car phone built the iPhone? It’s unlikely. So, why are we expecting our engineers and IT professionals that have epic amounts of organisational-specific business acumen to also learn how to build cybersecurity capabilities that evolve at an unprecedented pace every year? Doesn’t it make more sense for them to keep the core business running and pass down critical operational knowledge to new team members? Based on what I have seen in the industry, promoting internal folks to unrealistic roles is far too common. Not only are we setting up tenured, loyal employees to

fail, but we are also hurting the business’s bottom line by wasting time and money implementing non-optimal solutions. As an industry, when we set employees up to fail, we unknowingly contribute to a culture of risk aversion. Risk aversion is important in our industry, but not to the point where employees cannot discern between business risk and safety risk – a line I see people in the industry blurring more and more these days as the market plunges us all into a scarcity mindset. Risk adverse employees who have been set up to fail by leadership are then asked to be innovative? Doesn’t sound like a working recipe to me. Bottomline, it’s critical to hire the experts. Hire the firms that have a team of coders who set up honey pots to lure in the hackers and learn their behaviours. They exist, we just have to look beyond the walls of our pipeline organisations. And I’ll repeat, this is not something your in-house team can learn.

Control systems What seemed far fetched and down right questionable 30 years ago is now very much an operational norm. I had a control room operations lead look at me once

Vicki Knott.

10


11


and say, verbatim, “five years ago I would have told you to leave and kicked you on your way out the door – now, we’re in need of automation. These kids treat SCADA (Supervisory Control and Data Acquisition) like a video game. They just don’t have the same field knowledge us old guys have”. Our industry has changed dramatically in the last 30 years, and it’s evolved even faster in the last five. Centralised SCADA systems are a must for current pipeline operations. Another fun way to think about them is the operating system for your pipeline. One of the current weaknesses of these systems is the inability to push frequent updates (think your phone again). For cybersecurity reasons, on-prem SCADA systems make sense. With the rise of virtual commissioning via VPN tunnels, there is no reason that updates to the pipeline operating system (aka SCADA) cannot be pushed more frequently. One of the reasons they are not is because of the way our industry is used to purchasing SCADA systems, which has historically been through perpetual licenses. Procurement teams are so used to this model that when they see a subscription pricing model they push back, ignoring the fact that the software world has moved to SaaS (subscription) pricing because it includes updates and maintenance. Gone are the days of perpetual followed by egregious bills for custom consulting. It’s in the best interest of the pipeline company and the software provider to keep software up-to-date. For pipeline companies this ensures that the software they have paid for is constantly providing value. This keeps software providers accountable. It also enables a reliable revenue stream for software providers to fuel growth in order to build new solutions the industry needs. Software subscription pricing models for pipeline control systems are a pure win-win. Trust me, I have been on both sides. Allowing our amazing SCADA providers to transition to a subscription pricing model and allowing updates via VPN are two very low touch ways to ensure your SCADA system is resilient and ready for at least the next five years. Adding a RIPA platform to automate your control room operations is a revenue generator, sure to take care of talent scarcity issues, ensure safety through automation and maximise volumetric throughput where needed. Might as well keep moving into the future with new control room automation software capabilities.

Digitalisation Digital transformation has been underway for what now – a decade? Not to beat a dead horse, but hoping you didn’t promote those internal folks to head of digital transformation as well. If you did, all is not lost, assuming of course you didn’t also then hire a massive cloud provider and imagine they will solve all of your problems that you didn’t know you had, with solutions you didn’t know you needed. Oh you did do that? I’m sorry. Ok, let’s start again. Now is an excellent time to promote long-term employees to ‘Solution Lead(s)’, then ensure the company is not inadvertently promoting a scarcity mindset that’s contributing to business risk aversion (while innocently claiming that its safety risk aversion). The winning recipe? Domain expert Solution Leads with decades of industry experience having

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World Pipelines / FEBRUARY 2022

the autonomy to work with any new company/vendor they like to design the solutions the industry needs, all while unencumbering the companies they work with to enable them to scale and serve the industry as a whole. Sounds like a pipeline utopia to me. Building software products in-house has never been successful in our industry and the push for digital transformation is not going to magically make them work. For example, I know of a large pipeline company that built its own SCADA system over a decade ago. They have since replaced it with an off-the-shelf SCADA system due, in part, to their inability to support it in-house over the long-term. Imagine the total bill of that internal effort over the duration that the homegrown system was in place. Another thing this particular company has done is kicked off an in-house innovation department. I have heard that it is struggling and not producing the results that were anticipated. For readers not familiar with the literature on why big companies fail to innovate, here is an article from Forbes, to which the opening statement is: “There are thousands of books, articles, briefings, blogs and tweets about why companies fail to innovate. They offer insights about why the usual – almost always successful – suspects fail to innovate. Which is the first clue. Why do successful companies fail, where start-ups succeed?”1 The book ‘The Innovator’s Dilemma’ is quoted in this article and I believe it should be mandatory reading for all executives in the pipeline industry today.2 Spoiler alert as to why big companies fail to innovate: “Research tells us that even when competition stares right in the face of successful companies, they still fail the innovation test. Worse, when there’s no competition they don’t even show up. So, what’s the innovation secret? If anything above is accurate, there’s only one way to innovate: disrupt the company, not the business model or key business processes that make all the money. More accurately, leave the company behind, and under no circumstances threaten the revenue streams that make everyone rich, and never touch the business model that fuels personal and professional wealth”. It’s important that we share innovation and digitalisation failures with others in our industry so that we can all learn. We all hear these stories through the grapevine, but they are very rarely openly discussed in a forum like this. If anyone has any digitalisation and innovation stories they would like to share anonymously, please do send them to me on Linkedin or via email and I will incorporate them into future articles for the greater learning of the industry (completely anonymously, of course). Cybersecurity, control systems and digital transformation are all related by the need for innovation in the pipeline industry. As an industry, let’s embrace start-ups and discuss our failed in-house projects – they will ultimately provide the talent and ideas needed to push the industry forward for the better.

References 1. 2.

https://www.forbes.com/sites/steveandriole/2020/08/26/why-companiescannot-innovate--why-they-will-keep-failing--unless-they-end-runthemselves/?sh=23a6c2f75a52 CHRISTENSEN, Clayton, M., ‘The Innovator’s Dilemma: The Revolutionary Book that Will Change the Way You Do Business’, 2003.


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Steve Hanna, Co-Chair of the Industrial Work Group at Trusted Computing Group (TCG), US, describes how to protect the digital future of pipeline operations.

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cross the energy sector, Internet of Things (IoT) equipment is helping drive a digital transformation. From the equipment used in oil and gas extraction, to the monitoring tools assessing an end user’s consumption, the entire supply chain is becoming more connected. In particular, the use of industrial IoT (IIoT) is on the rise, with the market predicted to reach US$124 billion this year. This kind of connected equipment allows energy companies to provide and employ more sophisticated techniques such as data mining and deep learning – functions that the cloud can provide by performing analysis on data. While there are many practical benefits of implementing IIoT, industrial cybersecurity must be taken seriously to avoid significant consequences.

An enabler for innovation IoT technologies that are enabled by lightweight sensors, cloud intelligence and greater connectivity offer many benefits to operators. For example, they offer the ability to tune the operation of their plant or facility to meet the needs of the moment, whether that is to support increased energy production, or to help create individualised products. Operators can also carry out predictive maintenance to recognise when a particular device or system is likely to fail and address it beforehand. This is more effective than preventative measure where you simply replace a piece of equipment every three years, just in case. Recognising the signs of early failure means operators don’t have to replace equipment so often which helps to reduce costs and increase uptime. For pipeline infrastructure, many parameters can be tracked that may be early indicators of potential failure. Pressure is the most significant variable, but sensors of varying types such as magnetic, ultrasonic, and electromagnetic acoustic can be used to detect

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structural abnormalities before they become a problem. Acoustic sensors can be used to detect formation or growth of cracks, and electromagnetic sensors can be leveraged to detect corrosion or other flaws. With the help of IoT devices like remote terminal units (RTU) connected to sensors and data collectors along a length of pipeline, this data can be collected and analysed in real-time. Valves and other actuators can also be remotely controlled via IIoT connections, reducing the need for on site visits.

Real risks to real operations Thanks to these numerous benefits, there is a business imperative to adopt IoT. However, there is some risk that comes associated with that – the risk of hacks and cyberattacks. The attack on Iran’s nuclear enrichment facility known as the Stuxnet Attack was a welldocumented malicious piece of code that infected the software of at least 14 industrial sites in the country. Since then, there has been many ‘copycat’ attacks, in Germany, Ukraine and across the world. In 2017, Triton malware shut down critical infrastructure in the Middle East by attacking the safety systems of a gas pipeline. If an overpressure situation had occurred, the safety systems would not have been able to kick in, causing a tremendous risk to lives. Costs of cybersecurity attacks are also growing – whether that is ransomware, e.g. the Colonial Pipeline attack, or actual physical damage to equipment such as the attack on a German steel mill in 2014. Even indirect attacks where business systems are hacked can have an impact on earnings and the ability to keep systems up and running.

How do these attacks occur? At each layer in the architecture attackers can infiltrate, with the opportunity to target individual pieces of the supply chain, like a programmable logic controller (PLC) or RTU. If they can compromise the network, attackers can monitor and access confidential information or even change data and commands as they’re going through the network if the data and commands are not authenticated and integrity protected. If an attacker can successfully gain access to a server that has control over a large number of devices, the impact of the attack will be much greater. The main risks to operators are costs in the form of equipment repair and replacement, and remediation – but also safety. The effects of an attack could be more than monetary, depending on the environment. In the most extreme scenarios, attackers could shut down the entire operation or cause an overpressure situation by controlling pumps and valves. This could result in a leak, or even an explosion.

The role of industrial cybersecurity Industrial cybersecurity is vital for maintaining the reliability, safety, and cost of systems. Sufficient cybersecurity measures empower operators to maximise a whole host of things, such as uptime, reliability, and quality

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of operations, and as a result customer satisfaction. While cybersecurity measures are often driven by government regulations, they can also provide financial benefits by reducing costs, protecting private and confidential data, and avoiding damage to reputation as well as possible expensive lawsuits. In summary, operators can gain a competitive edge through maintaining efficient operations with minimum downtime. Industrial cybersecurity inverts the traditional triad of security values for IT security: confidentiality, integrity, and availability. In operational technology, or industrial control systems (ICS) security, availability is most important, integrity is essential, and confidentiality is less of a concern. For example, in a conventional IT system, if someone doesn’t know a password they may be locked out. That’s not an acceptable choice when the password is needed to perform a safety function and the person needs to get in and adjust the system if they are authorised to do so. Additionally, IT security equipment typically rotates every three to seven years, but in industrial equipment it is normal to have equipment installed for 20 - 30 years. While newer equipment considers the current technology and threat landscape relevant to the intended industry, older equipment can be outdated, posing a higher security risk.

How can operators protect their industrial IoT? Supply chain authentication Device parts and accessories purchased by an operator might not be authentic, which could lead to system downtime and revenue loss, malfunctioning or safety problems. With the current shortage of supplies and parts as a result of the pandemic, the risk of counterfeit parts is heightened. In the case of a device, a chip called the hardware root of trust can be used, containing a public and private key pair, and a certificate that can be used to authenticate that hardware.

User authentication Mutual authentication, best based in hardware, can be utilised to authenticate people. For example, via twofactor or multi-factor identification where a member of personnel must use their mobile phone in order to verify identity. This ensures the person gaining access, is none other than the intended user of the equipment.

Secured communication Secured communication ensures anyone with access to the network can’t necessarily see what is going on and can’t modify commands in transit. To do this, you must authenticate the two components and any people, but also encrypt, and protect the integrity of data in transit. Secure communications protocols like transport layer security (TLS) or datagram transport layer security (DTLS) provide these protections. Encryption may be skipped in some cases but mutual authentication and integrity


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protection are essential to prevent network-based attacks. These secure protocols should be supplemented by secure elements protecting the private keys on either side so that if the software on a machine does become infected, nobody can steal a copy of that machine’s private keys.

Secured software update If systems are working as expected, operators can be reluctant to update the software on their industrial control system since updates can lead to problems you didn’t anticipate. However, software becomes increasingly vulnerable over time without an update. Attackers can find vulnerabilities in software to take advantage of to infect the system. Therefore, software needs to be updated not to add new features, but to fix security flaws that have been discovered. But it is vital to authenticate the software and check its integrity before installation, since the last thing operators want to do is load malicious software.

Implementing standards Standards have been developed over the last few decades to improve industrial cybersecurity. IEC 62443 is the international standard for cybersecurity, to be used not only by customers but also vendors to make sure they are implementing best practices for industrial cybersecurity. The standard is required in Japan’s critical infrastructure programme and is likely to be required more broadly in the future. Other countries have similar national standards.

While there are more than a dozen different parts to this standard, there is training and certification for devices available to simplify this. This standard recognises there is no one size fits all approach for industrial cybersecurity and the more safety critical the system is, the stronger level of protection you need for it. There is a new technical document (bit.ly/3fwOQA3) on the landscape, offering guidance for securing industrial control systems by Trusted Computing Group (TCG). This document is shorter and simpler than IEC 62443 and covers the common security use cases: device identity, access control and securing secrets as well as more unusual use cases like physical attacks, equipment as a service and handling legacy systems.

A more secure future for industrial cybersecurity While even more rapid adoption of IIoT seems to be in the pipeline for coming years, it is time for operators to make cybersecurity a priority. This is how they will reap the benefits of connected equipment and a digitally transformed business, while minimising the risk to operations, and also the safety of personnel. By implementing specifically developed standards to protect IIoT, pipeline operations can be made smarter and more efficient, with the correct protection against attackers looking to exploit vulnerabilities in connected equipment.

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William Wright, nVent Thermal Management, US, explores how advanced pipeline monitoring software is revolutionising temperature-sensitive pipeline operations. he long pipeline sector has fuelled hundreds of technological breakthroughs – from the rise of the automobile, to sending humans into space. Despite being a key driver of innovation and the most popular form of fluid transport, the pipeline industry itself has witnessed comparatively few technological transformations throughout its history. Since the introduction of steel welded joints in the 1920s and the subsequent construction of leakproof, high-pressure, large-diameter pipelines, the underlying physical infrastructure of the industry has remained virtually unchanged.1 The explanation for this continuity is simple – the existing technology works. Equipped with such a solid foundation, pipeline engineers have been able to focus their attention on innovations beyond the pipeline itself. Such developments include reducing internal pipe corrosion by incorporating drag-reducing polymers into petrochemical products prior to transport.2 In recent years though, the rise of smart technology, coupled with increasing public and government scrutiny, suggests that the pipeline industry is due for a major technological shake-up.

Getting smart: the implications of Industry 4.0 The digital revolution has transformed the daily operations of hundreds of industries, including food production, building management and chemical processing. Smart technology, enabled by the Internet of Things (IoT), allows multiple systems to connect and share data to provide operators with an unprecedented level of real-time insight and control. A prime example of the benefits

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this technology can bring can be seen in how it has revolutionised the world of electric heat tracing (EHT). The unsung hero of markets around the world, EHT systems ensure materials of all kinds are maintained at the optimal temperature for safety, storage and transportation. In addition, these systems play an instrumental role in protecting vital infrastructures from harsh winter weather. The latest smart heat tracing controllers take this protection to the next level. With highly sophisticated remote monitoring capabilities and continuous system optimisation, the latest solutions help lower total operating costs and ensure small errors do not escalate into a total system shutdown. A host of industries have already embraced the potential of smart EHT, yet progress in this area has been slow when it comes to long pipeline infrastructure. Many lines already feature largescale heat tracing systems, but the historical high installation or retrofitting costs and the prospect of large-scale data collection and sharing have made operators hesitant to invest in Industry 4.0. However, with governments enacting ever more stringent

Poor pipeline monitoring: the Refugio oil spill On 19 May 2015, a corroded pipeline ruptured, resulting in 142 800 US gal. (541 000 l.) of crude oil leaking out into the state protected Gaviota coastline in California, USA. The pipeline’s operators located 1225 miles away in Midland, Texas, remotely detected pressure anomalies on the morning of 19 May and shut down the line as a precaution – though the damage had already been done. Local pipeline workers remained unaware of the leak until state authorities, alerted to the oil spill by reports from the public, notified them that there was oil in the water. The struggle to find the source of the leak and stop the flow of oil into the surrounding environment meant that clean-up efforts could not begin for 16 hrs following the initial spill, resulting in total clean-up costs of approximately US$96 million.5 Beaches in the surrounding area were contaminated for months following the incident and, all-told, clean-up workers counted at least 202 dead birds and 99 dead mammals collected from the affected area, though the true scale of the spill’s impact on local wildlife will never be fully known.6, 7

Counting the costs In the months following the spill, a number of civil cases were brought against the pipeline owners, including class-action lawsuits from local fisherman whose livelihoods had been impacted by the incident.8 The city of Santa Barbara also sought US$2.1 million in compensation for lost tourism income and tax revenue – resulting in a significant financial penalty for the pipeline operator.9, 10

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sanctions on oil providers following safety incidents, and public patience with repeated pipeline leaks wearing thin, the time has come for the industry to invest in a safer and more technologically advanced future. Fortunately, leading heat-tracing solution providers have begun to develop truly revolutionary pipeline monitoring systems, which offer businesses the complete line insight they need to assure safety, boost efficiency and secure their reputation for decades to come.

Essential EHT: skin-effect tracing systems Thousands of businesses use EHT technology in their daily operations, but the unique demands of the pipeline industry call for a special type of heat-tracing. Skin-effect tracing systems (STS) are versatile heat management systems (HMS) designed to deliver heat to large-scale pipelines which span rugged terrain, protected environments or even densely populated areas. This technology is vital for several reasons. Firstly, while pipeline transfer is considered safer and more environmentally friendly than road or rail petrochemical transportation methods, it is not without its risks.3 A well-designed STS-HMS ensures temperature sensitive fluids remain stable and uncontaminated during transportation, particularly when dealing with especially temperature-sensitive substances, like vacuum gas oil (VGO), asphalt, phenol, waxy crude oil or liquid sulphur. Linked to this, EHT systems play a crucial role in facilitating the efficient transfer of fluids through the pipeline, by maintaining materials at the correct temperature for optimal viscosity. They are also vitally important for assuring the safety and quality of liquid products, helping mitigate issues such as volume expansion, and irreversible state changes, such as polymerisation. Finally, heat-tracing systems provide versatility and access, giving organisations the option to transport a wide variety of materials regardless of the ambient conditions, be it arctic tundra or dense forests. Given their central importance, STS are installed across virtually every long-line pipe around the globe. While these pipelines do often feature highly sophisticated cabling infrastructures, the historical technology used to monitor them can be surprisingly basic.

On the market: existing monitoring technologies The sheer scale and complexity of long-line pipelines makes achieving comprehensive oversight of an entire line challenging. Nevertheless, there are multiple tried and tested measures operators can harness to keep an eye on their pipelines. The first and most commonly used of these are traditional mechanical temperature sensors, such as thermostats and electronic temperature sensors, referred to as resistance temperature detectors (RTDs). Though they differ in terms of underlying technologies, these both fall into the category of point-sensing devices, meaning they are only capable of sensing temperatures on the discrete pipeline stretch where they are installed. As a result, multiple sensors must be installed along the pipe to provide a complete overview. Given the costs involved with placing these detectors, however, lines are invariably left with sensor gaps which can lead to cold or hot points remaining undetected by operators. Supervisory control and data acquisition (SCADA) systems provide another means for engineers to monitor conditions


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along the pipeline. These systems gather data from local remote terminal units (RTU) for display on one human interface in a central control room. Operators can monitor the hydraulic conditions of the line and send simple operational commands – like opening/ closing valves – through the SCADA system to the field. While providing greater insight and control than mechanical sensors alone, the capabilities of these systems can be limited. The effectiveness of SCADA set-up is dependent on the number and spread of the RTUs across the line, and relies heavily on line operators to manually monitor and interpret information from thousands of miles of pipeline.4 If all remote monitoring methods fail, operators can be forced to go manual. Even with a SCADA system, it can be difficult for them to identify the exact site of the leak or technical error, once it has been flagged by the monitoring equipment. Occasionally, companies must send drones or manned vehicles along the length of a pipeline to search for a fault and pinpoint the exact location where an intervention is needed. This process is time-consuming, costly, and could result in serious issues remaining unresolved for days, weeks or even longer – with potentially disastrous results.

Making the change: a new generation of monitoring systems Following the successful implementation of smart technology in other industrial markets, leading EHT equipment manufacturers are now focusing on bringing the benefits of connected systems to the pipeline sector. Fibre optic technology is a key tool that manufacturers are employing to help deliver seamless, comprehensive oversight of an entire pipeline. In contrast to traditional temperature sensors, fibre optic cable can be installed

Building the world’s longest continuously heated and insulated pipeline In 2004, a large oil reserve was discovered in the Barmer basin in the state of Rajasthan, North West India. The find had incredible potential, with projected production levels in excess of 200 000 bpd – equal to 25% of India’s domestic oil production.11 There was one important factor that pipeline operators would have to manage though; the oil deposits at the newly named Mangala oilfield were waxy in nature, meaning they would need to be maintained at 65˚C to provide flow assurance and ensure smooth, fast transfer of the fluid through the pipeline. So began the construction of a 700+ km, continuously heated and insulated pipeline, encompassing 32 skin-effect heat tracing circuits. The project was one of the first to incorporate the latest pipe heating and monitoring technologies, including advanced electric heat tracing, pre-insulated pipes and fibre optic cabling installed alongside the pipeline, which provided continuous monitoring of the pipeline asset. The overall result was a line that is not only impressive in size, but also delivers a more reliable, secure and safe blueprint for subsequent smart pipeline projects.

Figure 1. The nVent RAYCHEM Pipeline Supervisor gives operators complete oversight over their long-distance pipelines.

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along the full length of the pipeline, beneath the insulation layer. By measuring the intensity and return time of the backscatter generated by sending laser beam pulses down the fibre optic cable, these systems provide highly accurate distributed temperature sensing (DTS) and quickly pinpoint the exact location of faults. Beyond the obvious advantages of continuous temperature monitoring and faster detection of unexpected temperature and pressure changes, fibre optic pipeline monitoring also allows operators to identify third party interference and crucially, areas where the system is under increased strain. With this capability, companies can take immediate corrective action to avoid potentially catastrophic incidents, maximising the safety, efficiency and profitability of their lines. To push the capabilities of this new generation of monitoring technology further and provide flow assurance, nVent RAYCHEM developed ‘bundled technology’ packages for new-build and retrofit pipeline installations. These include EHT or STS cables, pre-insulated pipe sections, thermally isolated pipe supports and anchors, fibre optic DTS and most recently, advanced analytical software. nVent RAYCHEM Pipeline Supervisor (RPS) is the company’s newly launched temperature critical pipeline monitoring software that provides unprecedented access to pipeline performance trends, predictable analytics and rich actionable data insights to keep pipelines operating smoothly and safely. With the help of the bundled technologies model, companies have been able to pursue previously unattainable line-lengths, opening up whole new markets that had previously been inaccessible.

Down the line: the future of pipeline monitoring As the world’s energy needs and the demands of the various process industries continue to evolve, pipeline operators must think seriously about investing in a safer, smarter and more adaptable infrastructure. Brimming with as yet untapped potential, smart EHT and monitoring technologies can help businesses avoid the major incidents that are as catastrophic for corporate reputations as they are for the environment, and pave the way for the next generation of high-performance pipelines.

References 1.

2. 3. 4. 5. 6. 7. 8. 9. 10. 11.

LIU, H., “pipeline”, Encyclopedia Britannica, 11 August 2021, https://www.britannica. com/technology/pipeline-technology. Ibid, “pipeline”. Ibid, “pipeline”. Introduction to Industrial Control Networks” (PDF). IEEE Communications Surveys and Tutorials, 2012, http://www.rfidblog.org.uk/Preprint-GallowayHanckeIndustrialControlSurvey.pdf KACIK, A., Refugio oil spill cleanup costs near $100 million, Pacific Coast Business Times, 27 June, 2015, https://www.pacbiztimes.com/2015/06/27/refugio-oil-spillcleanup-costs-near-100-million/ ROCHA, V., El Capitan beach to reopen a month after Santa Barbara County oil spill, Los Angeles Times, 19 June 2015, https://www.latimes.com/local/lanow/la-me-ln-elcapitan-beach-oil-spill-20150619-story.html BRUGGER, K., Refugio Reviewed, Santa Barbara Independent, 24 December 2015, p.13 https://issuu.com/santabarbaraindependent/docs/sbi_519_12-24-15 Ibid, 3 months after oil spill, Santa Barbara region recovering. WELSH, N., Santa Barbara County Sues Plains Pipeline Over Refugio Oil Spill, Santa Barbara Independent, 11 January 2018, https://www.independent.com/2018/01/11/ santa-barbara-county-sues-plains-pipeline-over-refugio-oil-spill/ OSGOOD, B., $22 Million Restoration Plan for Refugio Oil Spill Released, The Santa Barbara Independent, 6 May 2020, https://www.independent.com/2020/05/06/22million-restoration-plan-for-refugio-oil-spill-released/ CHAKKALAKAL, F., Hamill, Marty, Beres, Jim, IEEE, Building the world’s longest heated pipeline: A technology application review, 2014.

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Harry Smith, leak detection expert at Atmos International, UK, discusses effective turnkey leak and theft detection for remote operations on liquid pipelines. eing able to monitor your pipelines with ease is a vital aspect of remote operation. Pipeline operators need to not only be able to control the starting and stopping of pumps, or the opening and closing of valves, but they also need to be able to detect when there is a leak or theft activity. For pipelines in remote or harsh environments, or in high consequence areas (HCAs), leak detection systems (LDS) are critical. However, it’s not practical, safe or costeffective to complete site inspections on a regular basis. This challenge is further compounded when you consider the recent issues faced with the COVID-19 pandemic, limiting the ability to perform site inspections further for pipeline operators with reduced headcounts. This is even more challenging for many smaller pipeline operators, as many of their employees work from home for an extended period. There’s a focus on digitisation, to run pipelines not only safely but optimally, even in HCAs. This is possible by leveraging the data that pipeline leak detection systems collect. Here we’ll discuss various turnkey LDS technologies for liquid pipelines that can help with remote operation, enabling pipeline operators to: ) Rapidly implement non-intrusive solutions.

how to put data at the fingertips of the key pipeline personnel. Hardware like Atmos Eclipse has already been installed on thousands of miles of pipeline around the world, from the UK, to Europe, Asia and Africa. Atmos Eclipse is nonintrusive and measures flow, pressure and temperature for Atmos’ leak detection software (Atmos Wave Flow and Atmos Pipe) to effectively detect and locate leaks. The pipelines where Atmos Eclipse units are installed are often long-distance and in remote areas, where regular site inspections are difficult. The data that Atmos Eclipse collects is sampled at 60 Hz (60 samples/sec), to allow for high levels of sensitivity, a quick response time and accurate leak location. It’s a cost effective and easy to install unit, that can be implemented with minimal downtime of the pipeline. The unit is good for harsh climates where remote monitoring is crucial: ) Operates in -20˚C to 60+˚C temperatures.

) View, analyse and respond to data.

) Flash memory is available in case of communications

) Is explosion proof, ATEX certified (ATEX/IECEx: Zone 1

Gas IIA, T6). ) Can be buried to a depth of 2 m (maximum).

outages (up to 4.5 hours). ) Support working from anywhere.

Monitoring pipelines remotely in HCAs Having effective leak and theft detection is crucial to protect the environment, communities and pipeline operators from the dangerous impacts of leaks or ruptures. In HCAs such as river crossings and urban environments, it is especially important to consider

) Can operate using solar and wind power (90-250 Volts

AC line or 24 Volts DC). ) Multiple communications options (TCP/IP, line of sight

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pressure sensors that are in contact with the pipeline fluid. The theft detection hardware has recently been implemented in remote locations of Congo and Indonesia, where there can be regular theft activities. The areas where Atmos Odin has been installed also have a very limited access to power and communications.

Non-intrusive and rapid installation Being able to install LDS on HCA pipelines quickly and easily is crucial. Having to carry out highly impactful engineering activities on pipelines in urban areas can cause Figure 1. A variety of scenarios where Atmos Eclipse can be installed for remote monitoring. major disruptions to communities; likewise for pipelines that are in environments that are natural habitats to an ecosystem. It is also important from a safety )) Works for liquid pipelines like crude oil, multiproduct and point of view that pipeline personnel should not work for water. long periods of time on HCA pipelines running through some very harsh environments. The Atmos Eclipse can be installed in a variety of difficult Both Atmos Eclipse and Atmos Odin offer a rapid scenarios, including within tight spaces. The integrated solar installation. Atmos Eclipse is non-intrusive and doesn’t require and wind power capability enables the pipeline leak detection any tapping points, removing the need to drill, weld or cut to work not only as part of a networked environment, but also the pipeline and reduces the risk of thieves using existing standalone in hostile and remote locations. This is a futureproof tapping points to steal product out of the pipeline. The unit approach to leak detection considering the move to renewable clamps on to the outside of the pipeline, without interfering energy sources. with the cathodic protection systems. With a weight of Atmos Eclipse is excellent for real-time leak and theft just 6.6 kg, Atmos Eclipse is easy to transport to the section detection in these areas. Recently, it was able to detect theft of pipeline where it is to be installed and requires minimal activities on a multiproduct pipeline with a length of around human resource to fit into place. 100 km and diameter of 12 in. at a location in Europe. The Atmos Odin simply attaches to the pipeline at any thieves had been running a sophisticated operation. available tapping point. There’s no need for external power Atmos Odin can also be used alongside LDS software to or communications and it is easily concealed from vandals detect leaks and thefts in remote operations. It differs from and thieves, to avoid arousing suspicion. Over a three week Atmos Eclipse in that it is an easy-to-use data acquisition period, Atmos Odin can collect data, with no need to charge unit, also designed for use in areas without power or in between. communications. Atmos Odin is self-powered through battery The installation of both solutions can be completed and attaches directly to the pipeline at any available tapping with minimal to zero downtime of the pipeline making them point. It is also effective for remote operation: effective from a financial standpoint. )) Requires no external power or communication. )) Certified for Zone 1, Ex d, ATEX, and IECEx. )) Minimal installation requirements (existing tapping points). )) Easily concealed from vandals and thieves. )) Long operating time (three weeks). )) Works for liquid pipelines like crude oil, multiproduct and

water. Working alongside Atmos Theft Net to display the data, Atmos Odin is excellent for detecting theft because it uses

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View, analyse and respond to data With the need to keep site inspections down to a minimum, access to data into the integrity of remote pipelines is a vital aspect of monitoring. Atmos Eclipse can connect to cellular, radio, and standard RS485 and TCP/IP communications, to transmit the data it collects in real-time. The data gathered from Atmos Eclipse is backed up and secured in Atmos Cloud. It can be pulled into supervisory control and data acquisition (SCADA) systems and a web GUI to present a visual view to pipeline operators, accessible anywhere by desktop. The web GUI is customisable, so you can setup a range of views. For example, displays for engineers could include a map displaying the layout of the


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pipeline, with different graphical charts for leak and theft detection. When Atmos Odin is installed, the internal GPS transmitter acquires the location with accuracy, these GPS signals are continually logged with measurements from its internal pressure sensor. The data that Atmos Odin collects is downloaded and analysed by Atmos’ team of experienced engineers in Atmos Theft Net. Offline data analysis like this is unique to Atmos and provides better theft detection sensitivity than conventional online LDS. This helps to accurately locate illegal tapping points, to within metres.

Support working from anywhere

Figure 2. Atmos Eclipse in operation using solar and wind power in a remote location.

The impact of COVID-19 outlined the importance of the ability to work from anywhere as part of remote operations. Some of the smaller pipeline operators were particularly affected, advising control room staff to work from home during the height of the pandemic. Access to the data into the integrity of the pipeline is crucial for remote operations, whether off field, working from home or in the control room. The web GUI supplied for Atmos solutions like the Atmos Eclipse can be accessed anywhere on a desktop. With the ability to connect to a virtual private network (VPN), it is secure and addresses cybersecurity concerns often associated with working from locations outside the control room. Pipeline leak detection software that work with Atmos Eclipse such as Atmos Wave Flow also supports control room staff with intelligent learning. This means the LDS can compensate for variations, correcting any metre errors present in the system. Uncertainty in the system has a direct correlation with response time. The intelligent learning helps greatly reduce false alarms, building trust in the system for pipeline operators and therefore improving their response to alarms. Atmos Wave Flow can also report a variety of alarms through different communication channels, SMS and email for instance, an ideal way of reporting for when working both on and off field.

A new layer of reliability for HCA pipelines with turnkey solutions

Figure 3. Atmos Odin installed on a pipeline.

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Ultimately, forming an effective LDS strategy that works as part of your remote operation is crucial for detecting leaks and thefts. Pipelines are always being built in places that are HCA, either because they are urbanised or challenging environments that can be hazardous for site inspections. Pipeline leak and theft detection instrumentation such as Atmos Eclipse and Atmos Odin add a new layer of reliability to your LDS without a huge financial burden. They are robust systems that are easy to install, work even under harsh climates or in areas where there is little or no power. Site inspections can therefore be kept to a minimum and data is easily accessible. Atmos Eclipse, for example, pulls through real-time data to a web GUI that’s accessible from anywhere by desktop. Going forwards, the advancements in solutions like this are going to continue to play a vital role in effective and safe remote pipeline operation.


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Figure 1. Reciprocating pumps bring benefits in critical flow control applications where high differential pressure is combined with relatively low flowrates.

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Jeff Ortego and Alan Matthews, Celeros Flow Technology, US, explain how and when to deploy reciprocating pumps to deliver better efficiency and reduce total cost of ownership.

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eciprocating pumps offer many benefits in low flow, high pressure applications commonly found in the oil and gas sector. However, the technology is not as well understood as centrifugal pumps, which can lead to mis-specification. Every process condition needs a pump. The challenge facing pump specifiers and users is to identify the technology that will best meet the

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application criteria. Commonly, such criteria will comprise efficiency, reliability and environmental impacts – including energy consumption – and regulatory requirements. The pump also has to comply with time and budget constraints. These are not limited to capital costs and installation time; the total cost of ownership and the frequency and length of essential maintenance outages are also an important consideration. In the majority of standard duty applications, centrifugal pump technology is deployed. This technology is widely understood, proven in the field and generally reliable. However, it is not always easily scalable, and can sometimes become prohibitively expensive. Centrifugal pumps also experience poorer performance above certain viscosities and experience high erosion rates in services with entrained solids, which is where a reciprocating pump can provide a better alternative. Reciprocal pumps are particularly suited to critical flow control applications where high differential pressure is combined with relatively low flowrates. Examples include systems for wash water, butane injection, glycol services, amine services, high pressure chemical injection, and hot oil catalyst transport. In these circumstances, reciprocating pump technology can provide a better and more efficient solution, with benefits including: )) Lower erosion rates than centrifugal technology due to lower speeds. )) Simplicity of deployment. )) High efficiency (90% reciprocating vs 50% centrifugal). )) Near-zero emissions, when correctly applied and

maintained. However, lack of familiarity with the mechanism and the need to take an entire system approach to the flow control design can prove a barrier to deployment. In this article, we will explore the technical differences between the two pump technologies and explain the simple steps that can be taken to optimise reciprocating pump performance.

Figure 2. A reciprocating pump is essentially a device that moves a plunger or plungers in and out of the liquid.

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Operating principles There are fundamental differences in the way centrifugal and reciprocating pumps operate. It is important to understand the basic principles in order to appreciate the benefits and disbenefits of each technology. Centrifugal (kinetic) pumps work by the conversion of rotational kinetic energy, typically from an electric motor or a turbine, to create a static fluid pressure. Flow velocity is increased in the impeller and this energy is subsequently converted to static pressure due to change in the flow area in the volute section. Reciprocating pumps use the positive displacement method. Here, liquid is displaced, delivered, or discharged at a fixed rate per revolution of the pump. This displacement rate is dependent upon the plunger diameters, the stroke length, and the number of plungers used. A reciprocating pump is therefore a device that moves a plunger or plungers, creating a moving boundary in the pumping. Check valves ensure the direction of flow is maintained from suction to discharge during the operations of the pump changer. The reciprocating motion generated by use of the crank and the slider mechanism in the pump causes the liquid to be moved and energised from suction to discharge. One of the benefits of reciprocating pumps is that precise capacity can be achieved with a fixed volume of fluid because the flowrate (or flowrate generation) is linearly proportional to the speed. As a result, variable capacity is achieved by changing pump speed, while the pressure on the discharge side of the system is set by the system itself. This means we can generate near constant flow regardless of pressure to match process performance. An important distinction here is that a centrifugal pump has varying flow and varying head, resulting in a curvilinear response instead of a rectilinear response.

Following best practice As we intimated in the introduction, when it comes to correct pump specification, it’s not just about the pump. Although a vital piece of equipment, the pump needs to be considered as part of the wider system in order to achieve optimal results. API 674 gives best practice guidelines for the correct specification of positive displacement pumps, including crankshaft-driven power pumps and direct-acting pumps driven by steam or other gases. These guidelines require reliable operation in a wide variety of services and conditions. There are speed limits imposed based on the stroke length of the machine: these speed limits are in place to reduce the potential for piping vibration in the wider system; left unchecked those vibrations can produce water hammer, piping failures, etc. The pulsations produced by reciprocating pumps are typically also controlled by use of adequately specified pulsation equipment which reduces the magnitude (amplitude) of pulsations. Capital costs can be greatly reduced through use of adequate pulsation equipment and pump sizing optimisation. Changing flowrates can be accomplished by changing plunger diameters to increase or decrease displaced volume at a given speed. The speed can also be varied however, providing a



wide operating range for a given pump. Maintenance typically consists of checks for packing leakage, but leakages can be greatly minimised, reduced, or completely controlled to mitigate release of the pumped fluid(s) to the environment. Design specifications and installing the ‘right’ pump can make all the difference between a successful and reliable installation and a costly installation with poor performance. Here’s where we need to understand some acronyms. MAWP is the maximum allowable working pressure of the fluid allowed within the pump. NPSH is net positive suction head, which is a quantity that can be available in the system (NPSHA) and also a quantity that can be required by the pump for reliable operation (NPSHR). NPSH is typically used in the specification and calculation of centrifugal pumps. When dealing with positive displacement pumps, however, we are actually interested in net positive inlet pressure (NPIPA and NPIPR). These criteria are more adequate descriptions of what is available and what is required in terms of how the pump physically operates – particularly with regard to the operation of the suction valves.

Design solutions Concerns around reciprocating pump technology include premature fatigue failure, noise and vibration (e.g. water hammer) in connected pipework. These phenomena can be caused by excessive speed on a reciprocating pump, which produces higher and higher frequencies within the piping surrounding it. Although difficult to control post-installation, it is readily achievable to design out the potential for such issues. In addition to adhering to the speed ratings laid down in API 674, pulsation reduction equipment can be installed to control pulsations. Typically, these solutions are referred to as discharge dampeners and suction stabilisers. The discharge dampener is responsible for reducing the potential for fatigue failures and mechanical vibrations from the discharge side of the system. With reciprocating pumps, there is commonly a low suction pressure entering the pump and a very high discharge pressure, typically of several thousand PSI. This high working pressure means there is a whole lot of energy available to produce damage if things go wrong. The discharge dampener greatly reduces the amount of pulsation in the piping. On the suction side of the system the installation of a suction stabiliser is recommended to reduce the amount of acceleration head experienced by the pump in the system. This has the effect of helping to provide the best suction performance of the pump by reducing the amount of acceleration head loss, relative to what the static head is in the system. It also helps reduce phenomena like water hammer and the generation of vapour pockets.

Resolving post installation issues Of course, ideal conditions are difficult to achieve in real industrial applications, but in our experience the root cause of an issue is generally not the reciprocating pump technology itself. For example, on one application that Celeros Flow Technology (Celeros FT) was called in to investigate, a reciprocating pump was causing unacceptable downtime issues for a downstream oil and gas operation. Frequent valve spring failures were resulting in a pump shut down every two to three weeks, leading to frequent maintenance interventions and the associated costs.

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The reciprocating pumps in question had been installed originally to replace smaller wash water pumps with no modification to the piping. At the time of sale, the customer had been made aware that the piping system was undersized and that reliability would be compromised. The pumps had a long history of breaking suction and discharge valves, until a modified valve design was proposed and installed. The remaining reliability issues focused around packing and valve springs. Celeros FT conducted a site investigation to determine the cause of the frequent valve spring failures. Springs were analysed for the type of failure, repeatability of failure, and conclusions drawn regarding the cause. Analysis revealed that a fatigue failure was occurring in an area of the spring where the pitch was changed to close and grind the ends during manufacture. Surface defects in this area were produced during this pitch change, resulting in stress risers that led to a premature fatigue failure which was not displayed in other installations of the same pump model. Solving the issue was reasonably straightforward. The existing valve spring design, material and manufacturing process was unchanged – with the exception that the completed valve springs were shot peened. This additional process mitigated the stress concentration at the surface of the spring wire produced during manufacture. Upgraded valve springs were installed at the site and the failures stopped occurring. Tracing the cause of valve spring failure back to the point of system interaction with the pump resulted in a manufacturing improvement that restored the reliability of the reciprocating pumps. Frequent downtime is a thing of the past and maintenance costs have been greatly reduced. In this manner, Celeros FT was able to tailor component design within the pump to mitigate the issues caused by poor system design and inadequate pulsation control.

Conclusion Reciprocating pumps have much to offer in terms of improved performance, efficiency and energy consumption, particularly in low flow, high pressure differential applications where centrifugal pump technology is uneconomic due to scale or ineffective due to the process liquid viscosity. However, proper sizing of a reciprocating pump can greatly affect the operating parameters of the machine. Several sealing arrangements can be configured based on process fluid, lubrication requirements and environmental leakage concerns. Power frame and fluid cylinder ratings are independent values from each other, but neither should be exceeded during operation. Also, pulsation equipment and the piping system around the reciprocating pump can have a large effect on long term reliability of the system. There is a wealth of information and guidance available to help specifiers feel confident in deploying this technology effectively, ranging from API 674 to support from individual equipment manufacturers. Celeros FT has recently revised its reciprocating pumps portfolio to align it with current market conditions, reducing design complexity and making it simpler to match the pump to the application.


Christopher Holliday, Andrew Wilde and Alasdair Clyne, ROSEN Group, Switzerland, outline the assessment of coincident anomalies in pipelines.

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here are many threats to in-service pipelines, and pipeline operators have robust integrity management plans and programmes to counter such threats – indeed, many regulators demand such plans and programmes. Although not an exhaustive list, most anomalies that affect pipeline integrity can be identified as falling into one of three categories: ) Three-dimensional, volumetric metal loss, such as corrosion, pitting and gouging.

) Geometric, or deformations, such as dents, wrinkles,

bending strain etc. ) Crack-like, for example lack of fusion, hydrogen cracks,

fatigue and stress corrosion cracking (SCC). Published methodologies are available for the assessment of each of the above anomaly types; for example, remaining strength (RSTRENG) within ASME B31.G for corrosion anomalies, API RP 1183 for dents, and

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) How do I know if different

anomaly types are actually interacting? ) What is the likely effect

on failure pressure if, say, a dent interacts with a gouge? ) How do I assess coincident

anomalies?

Inline inspection (ILI) Figure 1. Examples of different ILI tools.

Figure 2. A typical dent-gouge combination.

API 579 or BS 7910 for assessing cracks. Extensive research, full-scale testing and numerical modelling have validated such methodologies, which are widely accepted and are referenced in many codes and regulations, including CSA Z662:19 and the PHMSA regulations. An engineering assessment can be conducted using approved and industry-accepted methodologies, allowing the pipeline operator to make, among other things, a repair/ no repair decision, provided that an integrity engineer has access to: )) The stresses to which an anomaly is subjected, including those due to internal pressure, residual stress, thermal stress and (where appropriate) external loading. )) The through-the-wall depth and axial/circumferential

lengths of anomalies. )) Material properties, such as diameter, wall thickness,

strength and toughness. However, when different anomaly types coincide, or interact, possibly under the influence of external loading as well as internal pressure, assessments can become more complex:

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World Pipelines / FEBRUARY 2022

Prudent pipeline operators have for many years used ILI systems as part of their integrity management programmes. Typical ILI tools are shown in Figure 1 and, as the picture makes apparent, there are different types of tools available to detect and measure the dimensions of anomalies associated with the threats referred to in the introduction. It is worth noting that many of the tools in Figure 1 can be run in combination, thereby saving operators time and money by optimising the number of ILI runs. For example, probably the most common type of inspection is an axial magnetic flux leakage (MFL-A) tool to detect and size general metal loss anomalies, together with a highresolution caliper (to detect and size deformations) and an inertial measurement unit (IMU) for the accurate location of anomalies and identification of possible areas of bending strain. Interactive threats can occur from within either the individual categories or across different categories. Examples of interactive threats within individual categories could be corrosion in close proximity (clusters) or coincident internal/ external corrosion. An example of an interactive threat across categories is a dent with metal loss and/or cracking.

Finding interactive threats from within a category Finding interactive threats from within an individual category is relatively simple and may utilise a single ILI system (typically equipped with an IMU unit). For example, metal loss anomalies can be clustered according to standard interaction criteria (e.g. 6t by 6t), interlinking cracks can be grouped into crack colonies, and deformations in close proximity to one another can be flagged. Coincidental internal and external metal loss is typically sized accurately in terms of total depth but may be (mis)classified as internal metal loss, depending on the technology used. Utilising an ultrasonic wall measurement tool can assist with sizing both internal and external components of coincident metal loss, but the correct classification of this feature type can be very challenging.

Finding interactive threats from different categories This section looks at some examples of how combined ILI data evaluation and integrity assessment of different


datasets has assisted operators in making informed decisions regarding the possible need for in-field intervention when faced with coincident threats from different anomaly types.

Dents and gouges Probably the most common form of interacting feature is a dent with metal loss. These are typically found by the alignment of data from an MFL-A/caliper combo tool. MFL tools are very sensitive to deformations, and dents can therefore be detected (but not sized) via the ID/ OD sensors. Standards such as CSA Z662:19 typically treat a dent associated with a gouge as a defect, and so remedial action is required; however, coincident dents with corrosion may be permitted, depending on their respective dimensions. Consequently, to make a repair decision for a dent/ metal loss combination, sizing is required for both anomaly types, but detection and classification are the key requirements to make a repair decision for dent/ gouge combinations. Gouges and corrosion may give rise to similar inspection-system signal characteristics, but skilled data evaluators supported by integrity engineers can classify anomalies using factors such as signal orientation, location of metal loss in a dent, satellite imagery, coating survey results and information from verification digs. The restraint condition of a dent can also provide useful information with regards to the likely origin of the dent and therefore whether gouging is likely. Unrestrained dents are more likely to have been caused during the operational life of the pipeline, e.g. due to third-party damage, and are therefore more likely to contain gouging. The major concern with a dent/gouge combination is that during formation, cracks may occur at the base of the gouge, thereby creating a deeper

defect than may be immediately apparent from metal loss ILI and resulting in a concomitant reduction in failure pressure. A Canadian operator had a pipeline that had been in service for over 30 years and approached ROSEN with the challenge of increasing their normal operating pressure for a temporary period. In collaboration with the operator, a defect of interest was identified that had previously been reported as a dent with metal loss. Following a more detailed review of the ILI signal data, it was concluded that the metal loss was highly likely to be a gouge in a dent. An example of a dent/gouge combination is shown


in Figure 2. A subsequent analysis to API 579 Part 12 demonstrated that although the predicted failure pressure was higher than historical operating pressures, it was lower than the planned temporary increase in pressure. Given timeline sensitivities for the required pressure increase, rather than perform a more complex (FEA) analysis, the operator decided to excavate the feature. The deformation was confirmed in-field to be a dent-gouge with dimensions that merited repair. Repair was completed urgently, thereby allowing the operator to successfully increase the line pressure with no reported loss of containment.

Cracks within dents Figure 3. MFL-C data showing pronounced dent indication due to sensor lift-off and linear indication within dent.

Figure 4. Elevation and strain plots for area of interest.

One of the most challenging coincident threats is the identification of cracking in dents. The major challenge is that dents cause sensor lift-off, thereby affecting the data quality of crack detection tools such as electro-magnetic acoustic transducer (EMAT) technology. However, EMAT tools are usually run in combination with a circumferential MFL tool to assist in distinguishing genuine crack-like defects such as fatigue or SCC from, for example, steepsided corrosion. Figure 3 shows MFL-C signal data associated with linear indications within a dent. While the deformation also causes lift-off of the MFL sensors, these systems are a little more tolerant than UT or EMAT, and a crack with sufficient opening (>0.1 mm) may be detected, although sizing is not feasible and the probability of detection cannot be specified. Collaboration between the MFL-C evaluator and the integrity engineer maximises the likelihood that key locations will be carefully reviewed, and potentially critical, but hard to identify, anomalies will be found. The feature in question was reported as an “immediate investigation feature” and, on excavation, the pipeline operator found a leaking crack-like defect within a dent.

Geohazard and deformation

Figure 5. Sidebooms supporting pipe in the Coldwater area.

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World Pipelines / FEBRUARY 2022

In early 2020, a pipeline operator requested a bending strain assessment of 50 ‘at risk’ locations identified by a geohazard provider. Since an additional (but not analysed) IMU dataset was available from a previous inspection, it was agreed with the operator to analyse the entire length of the pipeline for both indications of bending strain and pipeline movement. Figure 4 shows the elevation and strain plots from the two inspections, together with a ‘difference’


plot shown in green, for the region of the pipeline with the highest level of bending strain (0.79%). The 2020 data (blue line) is generally coincident with the 2014 data (red line), but the upper part of the figure shows an increase in vertical elevation of 0.3 m (green line) coincident with the location of maximum strain. The strain plots in the lower part of the figure are again typically coincident except in the area of peak strain, where an increase in strain of 0.56% was recorded between inspections. Caliper data were scrutinised at the strain location, and there was clear evidence of a developing ovality. This combination of a change in bending strain and a developing deformation provides strong evidence of movement due to geohazard loading, such as a landslide. Based on the above results, the pipeline operator mobilised ‘in-field’, confirmed the presence of the uplift in profile and the deformation, and carried out appropriate remedial action. A particularly noteworthy point is that this location was not on the geohazard provider’s original ‘at risk’ list, which demonstrates the value of assessing the entire length of the pipeline rather than ‘targeted’ locations.

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Geohazard and circumferential girth weld anomalies On 14 November 2021, a main arterial pipeline crossing British Columbia in Western Canada executed a precautionary shutdown due to forecasted storms and torrential rainfall throughout much of the province. Major highways were completely washed away, together with the ground surrounding the pipeline in some areas, leaving the pipeline exposed. As a result, numerous freespans were created, which were initially supported on wooden trestles or via sidebooms once field crews could access the site (Figure 5). Some of the pipeline girth welds contained anomalies reported by historical UT crack ILI tools, and these anomalies were subject to additional stresses due to pipeline movement resulting from the washout. As part of the process to safely restart the pipeline, it was therefore necessary to compare positional surveys performed in-field with historical IMU data to review the magnitude and direction of the additional stresses. An assessment was then performed to develop acceptance criteria (allowable freespan length and anomaly dimensions), which considered coincident internal pressure and external loading. Calculations were performed utilising the EPRG Tier 2 and BS 7910 methodologies to determine the dimensions of anomalies that could safely remain in the pipeline without further mitigation. In-field NDT was carried out on accessible girth welds to confirm anomaly sizing for comparison with tolerable dimensions, as a result of which a number of repairs were completed prior to restart. Frequent discussions of the assessment results were held with both the pipeline operator and the Canadian Energy Regulator (CER) to assist with the restart decision. Although this part of the project was relatively minor compared to the immense scope of civil and rehabilitation work, it is understood that the results of the assessments allowed the operator to accelerate the restart of the pipeline. The pipeline was successfully restarted on 5 December, thereby securing fuel supplies for British Columbia.

Summary This article has summarised some of the different coincident anomaly types pipeline operators may encounter. The article has shown how ILI systems, together with careful analysis by data evaluators and integrity engineers working hand in hand, can assist operators in understanding the nature of complex, coincident anomalies, thereby allowing informed decisions regarding in-field verification and likely repair requirements, resulting in possible cost savings.

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Innovative hardware and next-generation digital capabilities combine for the benefit of crucial infrastructure class, writes Stuart Clouston, Global Product Line Manager Pipeline Inspection, Baker Hughes Process & Pipeline Services, US.

ipeline integrity, safety and regulatory compliance are the watchwords for a global pipeline market seeking to maximise efficiencies and showcase safety at a time of increasing energy demand Inspection and management technologies have therefore never been more important, whether dictated by regulatory regimes, market imperatives or operational requirements – or some combination of those elements. Innovative pipeline inspection smart pig technology, together with digital capabilities, artificial intelligence (AI), data analysis and engineering expertise are, perhaps like never before, being used to detect defects, map maintenance and highlight future problems. This is why companies including Baker Hughes Process & Pipeline Services (PPS) put so much faith in inline inspection solutions: a complete picture of the overall condition of an asset, over time, is the best way to provide confidence in its integrity lifecycle.

A difficult landscape Pipelines are a crucial, integrated and expanding segment of the world’s industrial and energy infrastructure. The global market for management and inspection of the network is already estimated to be worth multiple billions of dollars and is widely expected to more than double by 2030. Baker Hughes alone had, by the end of 2021, inspected more than 2.5 million km of pipeline, including 600 000 km under the

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banner of geometry and mapping, 1.65 million km for corrosion and metal loss, and over 240 000 km for crack detection. Regulatory adherence dictates much of the work involved in the sector, with ageing networks – and the issues that accompany time served – also responsible for increased frequency and complexity of some inspections. Whether faced with heavily corroded assets, difficult to access pipelines, pinhole corrosion, cracks, or even pilfering and illegal tapping, Baker Hughes believes that the right inline inspection tool can help to attain safer operations, improved integrity and higher profitability.

Data and service There is more to inspection than simply gathering data or producing a report – a partner with powerful engineering capabilities and experience, alongside a strong service footprint, can help operators manage the lifecycle of an asset from start-up through day-to-day operation and into controlled decommissioning. Companies like Baker Hughes offer the ability to bundle technology, solutions, and expertise into a full-service package that produces a smarter way of working. And while that starts with identification of corrosion, metal loss, cracks etc., it also extends to management of solutions and meeting the kinds of difficult challenges often posed by complex and crucial infrastructure. Baker’s inspection tools, for example, can inspect single km or hundreds of km, in pipes from 6 - 56 in. diameter across, and in both liquid and gas. The information collected is then downloaded, analysed and used to produce a report on the condition of a line. The value of any inspection is multiplied by the integrity engineering services supplied on top of that raw data: here are your most crucial issues, here is what needs to be fixed today, here is something to watch, here is where problems have developed compared with the last inspection – it goes beyond information and into the realm of intelligence.

Evolving technology Technological advances across the inline inspection market are often incremental but that does not make innovation any less important. Last year, Baker Hughes expanded the availability of the AXISSTM system, which measures axial strain. The proactive, costeffective inline detection system searches for small changes in axial strain conditions which can be crucial to the life and safety of any pipeline, supporting geohazard management programmes and identifying threat locations. The advance helps operators to mitigate lifetime or manufacturing issues before they develop and threaten failure, while avoiding interventions such as strain gauges or cut-outs, and bending strain data from an inertial measurement unit will provide a more complete picture of overall condition. Surveys – based on an electromagnetic sensor technology and benchmarked against either a representative pipeline sample or predicted using proprietary analytical calibration – can be included as part of scheduled corrosion inspections, further enhancing operational efficiencies and cost-effectiveness. The result is a better understanding of strain history from construction through operational life, the ability to validate strain

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World Pipelines / FEBRUARY 2022

levels following relief activities, and a more comprehensive view than can be supplied by standard IMU bending surveys. It is also possible, using AXISS, to produce a total longitudinal strain integrity engineering report.

Deeper insight The capabilities of inline inspections are further enhanced and expanded through the application of digital analysis, software solutions and expert engineering services. In one example, an operator was faced with an inspection that highlighted more than 24 000 corrosion features in a section of a high-pressure gas pipeline with over 20 yrs in service, and exceeding 100 km. A prioritised repair plan was required, but that might normally take two weeks to a month, depending on factors including run length, inspection specifications, additional inputs, and scope. However, a solution developed by Baker Hughes provided an Integrity Report in just 24 hours thanks to power and benefits of our PipeImage software environment. The results are reviewed for accuracy by an integrity engineer, and data can be gathered by a third-party or by Baker Hughes, but speed is guaranteed. The comprehensive, but concise, report includes key statistics, and the full in-line inspection findings with immediate and future integrity implications. Deeper insights in this example including a high concentration of external metal loss near field joints – suggesting a possible problem with the field wrap. Also highlighted was a slightly higher proportion of metal loss in the last quarter of the pipeline, with a higher frequency at the top of the pipe, hinting at problematic soils or some other environmental influence. Overall benefits included the organisation of corrosion according to criticality, underpinning a more strategic response to the data that provided significant cost and safety benefits.

Seeing eye to eye In another example of leveraged inspection results, a subsea pipeline operator in the Middle East was faced with two sets of inline inspection data based on different technologies – resulting in a question of how best to identify appropriate remediation based on the range of information provided. Corrosion was identified first through ultrasound and then magnetic inline inspection, but recommendations in a fitness-forpurpose assessment differed in terms of both extent and location of remedial requirements. For instance, the results from the 2012 exercise showed a significant number of pitting areas, while the 2010 scan showed a number of areas of continuous long corrosion. Combining the results into a meaningful inspection report required a point-by-point comparison of corrosion defects with validation using new infield AUT data. The matching was carried out over relatively short scan distances (metres) and resulted in hundreds of accurate plots. Data was, ultimately, visually aligned and scaled to ensure location accuracy. The operator was, as a result, able to investigate and compare individual site depths embedded within complex corrosion features. Collaboration was key to the result, which provided a high level of confidence in the integrity and remediation strategy to the customer. Baker Hughes believes it is an excellent example


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Rising to the challenge The demands of the global pipeline network require a dedicated, dogged approach to inspections designed to highlight the problems of today, the anticipated issues of tomorrow, and the earliest indications of any threat to operations in the longer term. The right inspection tool hardware of course is key: whether, in the case of Baker Hughes, that means the AXISS system, whether it is the UltraScanTM, the VectraTM Gemini, the MagneScanTM or TranScanTM. Equally essential is what happens

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to the information collected, the solutions identified using the expertise and experience developed over 50 years in the industry. Leveraging the power of next-generation digital technologies is part and parcel of that analysis, alongside the unrivalled insight offered by the application of AI by engineers who know how best to harness its capabilities. Pipelines are a rich source of highly unique data requiring interpretation which lends itself well to the application and advantages of machine learning and other advanced signal analytics techniques. Our Baker Hughes analysts play an essential role to ensure data is correctly interpreted and that critical integrity decisions can be made with the confidence needed. Analysts use sophisticated software with embedded algorithms trained on a vast database of real-world pipeline defects to produce a report from this data, that helps the operators manage their pipelines. A report is actually an optimum combination of human analysis experience with the speed and capabilities of computational algorithms to detect and interpret sometimes millions of possible areas of interest found by the inspection tool. At Baker Hughes we were early adopters of the use of AI techniques in pipeline inspection data analysis, having actively used machine learning and other methods to supplement human analysis since the mid 1990s. This is an area of continued and increasing focus and as cloud computing rapidly evolves, it offers new possibilities that will continue to translate into more effective and efficient means to detect and precisely measure the integrity of pipelines. Society expects pipelines to be safe and cost-efficient; operators are seeking compliance with regulatory regimes, proven long-term integrity and higher profitability. Inline inspection technologies are central to addressing both sets of demands. Because from the moment a pipeline is commissioned, the clock is ticking. Corrosion can take root no matter what the protection system, whatever the type of product being carried, and no matter what the environment through which a pipeline runs. That is what makes accurate, comprehensive identification of defects, sizing and classification so essential. It is why companies including Baker Hughes combine data and service into a seamless market offering, powered by digital and AI technologies. Threats identified, objectives achieved, job done.

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Figure 1. Advantages of 3D scanners: Fast, precise data acquisition and ease of use (©Andritz Hydro).

Jérôme-Alexandre Lavoie, Product Manager, CREAFORM, Canada, outlines the power of 3D scanning for corrosion and mechanical damage assessment.

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recent study shed light on the most important factor when it comes to managing asset integrity in refineries, power plants, and pipelines in the field.1 Some 58% of the people surveyed identified accuracy and repeatability as the most important factors when managing asset integrity and choosing an inspection technology. Since 3D scanning is well established in the automotive and aerospace industries, it is not surprising that the vast majority of pipeline operators surveyed (97%) were willing to adopt the technology for corrosion and mechanical damage assessment. Nevertheless, they also mentioned wanting more information about the technology as well as more knowledge about its performance. This article highlights the possibilities offered by 3D scanning, such as better information-based decision-making for repairs, major financial savings, and improved public safety. It also presents information to help NDT professionals choose the right 3D scanner for the right application. In short, it answers the following questions: ) How does 3D scanning differentiate itself from traditional NDT techniques? ) What are the different types of 3D scanners and their

advantages according to specific applications? ) What do users who have opted for 3D scanning say about

the performance of the technology when assessing pipeline corrosion and mechanical damages?

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Challenges in pipeline inspection A complete pipeline integrity assessment requires the use of different tools and technologies to characterise the material integrity and provide a trusted diagnostic. Traditional NDT techniques for corrosion and mechanical damage assessment include magnetic flux leakage, ultrasonic, and manual measurement tools, such as the pit gauge. Nonetheless, these methods are increasingly challenged by 3D scanning.

Technician and environment dependency Manual techniques have the inconvenience of making the inspection highly dependent on the environment and the technician’s skills. Measurements are taken in difficult environments where conditions and positions are far from being optimal and ergonomic; technicians often lie on the ground, in the mud, under the pipe, or suspended from a rope, in the air or on scaffolding. These difficult conditions may affect the technicians’ ability to find the deepest points and measure them accurately. Moreover, their attention may diminish as the inspection lasts, producing inaccurate measurements and variable results, which could impact the quality of the report and the decision-making.

Duration of the inspection process When calculating burst pressure with manual techniques, the finer the grid, the more accurate the measurements. This means that a 2x smaller grid represents 4x more measurements (squared function). Multiple data points take time to measure, and when these data points need to be remeasured, the technician has to go back in the ditch and risk remaking measurement errors.

Analysis report and diagnosis Manufacturers of manual tools do not offer a software platform that goes as far as calculating the burst pressure based on the complete standard. With their solution, it is possible to export the depth measurement results table. Still, integrity assessment engineers must calculate the burst pressure and make crucial decisions, such as replacing a pipe segment, by looking at an Excel table filled with numbers.

to replace a pipe segment, both maintenance costs and a service interruption are involved. Therefore, integrity managers need accurate inspections and repeatable measurements in which they can count on to make the right maintenance decisions. 3D scanning brings the needed accuracy and repeatability, as well as speed, user independence, and 3D visualisation. Thus, integrity engineering teams can make the right decision that ensures public safety and maximises their chance of remaining on schedule and within budget in order to provide pipeline owners with better profitability.

Speed 3D scanning accelerates both the acquisition of data and evaluation of damages, providing a faster integrity assessment. 3D scanners have the capability to capture and evaluate all damaged sections at once. Compared to manual measurement tools, the acquisition is faster and more accurate and the acquired data is processed more quickly, helping integrity managers make better-informed decisions faster.

User independence Scanning data is repeatable, and results are the same regardless of the technician’s skills and expertise. Measurement is not only independent of the user but also of environmental instabilities, which are present in pipeline inspections in the field, in refineries, and in power plants. Moreover, user independence helps to increase the confidence level of integrity engineering teams, accelerating and improving the decision-making process. It also helps field technicians by removing the pressure they face to find damages. Technology assists them in their work and eliminates potential human errors.

3D visualisation

Solution to ensure public safety and increase profitability

Confidence in the decision-making process increases even more with 3D visualisation, which provides integrity engineers with a complete 3D picture of the pipe’s critical areas – with colour and texture. By zooming in or out and rotating it, they can assess damages as if they were in the field themselves. Compared to Excel tables, a full 3D view of the pipe’s internal and external surfaces contributes to more effective decision-making, which has a positive impact on public safety as well as on profitability.

Asset owners seek to maximise the useful life of pipelines without compromising public safety. When a decision is made

3D scanner comparison Two major 3D scanning technologies are available on the market: laser-based technology and white-light technology. Both scanner types offer similar performance in terms of speed, user independence, and 3D visualisation. However, when comparing them, versatility stands out as an important differentiator.

Blue laser technology

Figure 2. Typical working environment when measuring pipelines.

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3D scanners equipped with blue laser lines, such as the Creaform HandySCAN 3D | Black Series, are the most recent innovation in the 3D scanning world. They deliver accurate and repeatable results across all work conditions, whether under direct sunlight or in harsh environments, for various damage assessments, including corrosion, dents, and wrinkles. Not only can integrity engineers fully trust their reliable data, but they can also


Figure 3. White light scanner Go!SCAN 3D and HandySCAN 3D from Creaform.

rely on its speed to take measurements, deliver results, and complete inspections quickly and efficiently. In short, with their higher versatility, blue laser 3D scanners are a go-to solution to accurately detect all types of mechanical damages on pipelines, vessels, tanks, valves, reducers, etc.

Structured light technology 3D scanners equipped with white-light technology, such as the Creaform Go!SCAN 3D, offer a complete 3D picture (with geometry, texture, and colour) to NDT technicians who perform damage assessments. Thanks to its impressive speed, quicker setup time and field deployment, this shortens the time spent in the ditch. Because the technology is sensitive to sunlight, it requires shade to work outside properly; however, it is perfectly suitable for working inside tanks, vessels, and power plants.

Integrity assessment software In addition to benefiting from 3D scanners’ performance, integrity engineers must be able to rely on an innovative NDT software, such as Creaform Pipecheck, for their onsite inspection, detection, and characterisation of pipe defects. The combination of both hardware and software produce more accurate and repeatable results, which are traceable for future pipeline integrity analysis.

NDT companies’ trust in 3D scanning NDT companies have a lot to say about the benefits of using 3D scanning for corrosion and mechanical damage assessment, as shown in the following testimonials:

TEAM: Benefits of 3D scanning regarding safety and data quality “At TEAM, it is our goal to provide our customers with the safest and highest quality solution to any of the leak sealing needs that they might have. Innovation is one of our core values, and

we stand by this by looking into new technologies that we can consistently bring to the field to provide our safest solution.” Adrienne Garcia, Engineering Manager, Western hemisphere.

National Grid: Demonstration of speed and user independence “Each technician should get the exact same results, which means we can be 100% certain that we’re choosing the deepest points. We also get more data available on the damage of pipelines, which helps to make decisions on whether the pipeline needs repair, or it can return to service.” James Gilliver, Senior Engineer, Materials and Welding.

Key takeaways By opting for 3D scanning, integrity managers can expect to increase the speed of data acquisition and analysis while getting a complete 3D visualisation of user-independent results. Thus, faster access to better data increases the confidence level in the results, leading to better information-based decision-making, major financial savings, and, above all, improved public safety. When choosing a 3D scanner for damage assessment, which includes corrosion, dents, and wrinkles, integrity engineers should consider how versatile it needs to be and determine if it will be used 1) under direct sunlight, or 2) inside tanks, vessels, and power plants. A blue-laser 3D scanner is the ultimate choice for both applications, while a structured-light 3D scanner brings important benefits in the second application. Bundled with innovative integrity assessment software, this trusted solution enables asset owners to stick to planned budgets and timelines while ensuring pipeline integrity and public safety.

References 1.

The study was conducted in May and June 2021 on the website creaform3D.com and included site users, both customers and non-customers. Details available upon request.

FEBRUARY 2022 / World Pipelines

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Todd Razor, Vacuworx, US, tells the story of how Dun Transportation uses vacuum lifting technology to increase mobility on major infrastructure projects.

Figure 1. Vacuworx lifters aid in offloading, loading and stockpiling the 24 m (80 ft) QRLs.

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new material handling case out of the Permian Basin, USA, reflects how pipe logistics and transportation companies such as Dun Transportation & Stringing, Inc. are doubling down on vacuum lifting technology to increase mobility on major infrastructure projects. The pipe handling trades in recent decades have been coming around to ‘new’ equipment and improved methods that require fewer manual inputs than traditional rigging systems, bolstering opportunities to create safer and more efficient worksites. In some cases, pipe handlers have turned more readily to vacuum lifting amid regulatory concerns and general duties associated with keeping worksites free from potential hazards that could cause death or serious physical harm during activities such as the loading and offloading processes. Project owners, pipeline installers and equipment manufacturers each have an interest in ensuring the ways in which oil and gas pipe is handled are all extremely safe, very efficient, and in line with appropriate procedures and regulations. They are also tasked with mitigating the possibility for abrasion marks or impact damage to the delicate epoxy coatings commonly used in the manufacture of steel gas pipe. In recent years, there have been reports of certain requests for proposals with even more specific calls – as they pertain to methods of handling pipe that are preferred, or are no longer acceptable, as a result of concerns surrounding safety or physical damage to the materials being lifted. While vacuum lifting is far from a new method of material handling for Dun Transportation, the company has been reflecting on how that technology was put into play near the start of the Permian Highway Pipeline (PHP), as well as the potential positive outcomes associated with infrastructures that could help with building a cleaner energy future.

Logistics end The PHP, with connections to the US Gulf Coast and Mexico markets, went into full commercial in-service operation in January 2021. The 1066 mm (42 in.) diameter pipeline – delivering natural gas to the Katy, Texas area from Waha – has been fully subscribed under various contracts. The PHP spans 684 km (425 miles), constructed with the intention of delivering responsibly sourced natural gas to critical areas. The project, providing approximately 2.1 billion ft3/d of incremental natural gas capacity, has been acknowledged among conduits that are helping reduce Permian Basin natural gas flaring. Dun Transportation is no stranger to lifting, transporting and staging heavy-duty lengths of coated and non-coated pipes with dozens of energy companies, pipe manufacturers and pipeline contracting companies listed among its customer base. Over the course of a 111 year history, the

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Vacuworx lifting systems are made up of primary components that include a vacuum pump – driven by a self-contained engine or hydraulically powered by the carrier equipment. A vacuum reservoir and valve provide vacuum in the event of a power failure. Vacuum pad assemblies on RC Series lifters can be changed out on the fly to accommodate pipes starting at 102 mm (4 in.) in diameter and up with no limitations on maximum size. The systems, designed to be compatible with a variety of host machines, are commonly used in conjunction with high-capacity excavators in the pipe-handling fields. Figure 2. Pipe arrives at one of four rail spurs procured by Dun for the PHP. When activated, the system pulls a vacuum between the pad and pipe joint, creating a positive seal. Once the necessary suction is created, the pad seal holds until an family-owned, Sherman, Texas-based outfit has seen a lot of operator activates the release. Audible alerts warn of any pipe and a lot of progress in the midstream segment of the oil critical loss in vacuum pressure. and gas industry, and has so far counted more than 160 000 km Dun Transportation prefers running its vacuum lifting (100 000 miles) of such line handled. equipment with high-capacity, track-type excavators, such The co-ordination, delivery and storage of more than as a Caterpillar 349 or a Caterpillar 374. The lifting units are 30 000 pipe joints, all 24 m (80 ft) QRLs with varying wall equipped with remote operation and can be rotated 360˚, thicknesses, is a significant undertaking requiring extreme providing for precise placement of materials and allowing care to protect both people and property. For its part, Dun pipe to be stacked without the use of timbers for cribbing or Transportation procured four rail spurs, where delivery of PHP spacers. The pad material causes no abrasion, mitigating some stockpiles were accepted from pipe maker Welspun – out potential for physical damage while limiting human contact of its large OD manufacturing facility in Little Rock, Arkansas with the pipe. – and five laydown yards to store and otherwise stage the On its PHP route, Dun Transportation handled coated circular steel prior to the construction phase. approximately 30 340 pipe joints, weighing between 10 t Mike Nunnenkamp, Vice President and COO of Dun (20 000 lb) to 15 t (30 000 lb) each. “There are quite a lot of Transportation, covered off on some variables that were logistics with different wall thicknesses going to different considered in relation to keeping people safe and product from areas and everything may not be right where you are,” being marred or damaged as the pipe lengths were conveyed Nunnenkamp said. “Being able to easily move [the machines] in proximity to the pipeline’s proposed route. around makes that more palatable. “The biggest difference with cranes is that they require Mobility factor quite a bit of time to disassemble, to demobilise,” he stated. In 1999, Dun Transportation made a decision to turn away “Now we just pull a pin and go. On a project like this, we from cranes and hoisting mechanisms and opted toward have two crews at all times and normally have a third crew vacuum lifting equipment, specifically Vacuworx lifting going. We had about nine or 10 [Vacuworx] lifters out on this systems, as its primary method of lifting and handling oil particular job. It’s more economical. It makes movement from and gas pipe. Nunnenkamp shared his take on vacuum lifting point A to point B a lot easier.” during the lifting and handling processes, as opposed to the use of cranes and spreader bars, and what Dun Transportation has come to view as a long-term alternative to more labourClose encounters intensive techniques typically involving hooks, cables and Nunnenkamp, considering Dun Transportation’s earliest slings. encounters with Vacuworx, recalls how seeing a vacuum He made clear that the path of least resistance is generally lifting system up close, and using it for the first time, helped preferred in the pipe logistics lines-of-work, due in many solidify a relationship that’s held on steady for over 20 years. respects to the sheer quantity and dimensions of pipe lengths “We had always used cranes,” he said. “We were one of the to be handled, and the scope of any given project. first ones to test the [Vacuworx] units. We thought, ‘There “The pipeline originated in West Texas and finalised toward was no way this thing can pull pipe up in the air.’ the Gulf Coast,” Nunnenkamp said. “Throughout the handling “Vacuworx brought a machine down for us to test and try,” and logistics process, which includes offloading rail cars, loading Nunnenkamp recalled. “We thought it was outstanding that this onto trucks and stockpiling into laydown areas, with [vacuum little unit could hold [the pipe]. It was truly convincing, using it lifting], there are immediately two guys not required to hook and seeing it. From a safety aspect, there is no crane, no guys on on each end of the pipe.” each end hooking the pipe. It has always been safe and reliable.”

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implementing methane reduction strategies to avoid emissions that would have otherwise occurred during operations as part of its natural gas pipelines segment. In 2016, the company set a goal of achieving an intensity target of 0.31% of methane emissions per unit of throughput by 2025. That stated target has been surpassed annually for Kinder Morgan’s natural gas transmission and storage assets since 2017, and in 2020 it achieved a methane emission intensity rate of 0.04% for those operations. Nunnenkamp concluded his comments by framing together thoughts on the progression of technologies used to handle Figure 3. Dun handled more than 30 000 pipe joints weighing up to 15 t (30 000 lb) each. pipe and construct pipelines with a forwardthinking viewpoint regarding the roles such infrastructures are playing from both an environmental and business perspective. “I think natural gas is very critical as we transition to a cleaner energy future,” he said. “Natural gas will be a key transition piece that is critical to our country, not just economically or for energy independence, but for the cleaner energy future we all desire. “We need more supply out there and infrastructures like this are critical. Our country has always been a world leader in pioneering new ways to meet our country’s needs. I don’t envision why using energy pipelines, as part of our cleaner energy future, would be any different. We can and are Figure 4. The PHP was Kinder Morgan’s second major project out doing it more efficiently, making sure they are installed in as of the Permian arena. environmentally sensitive ways possible.” He continued: “It’s about being very efficient, the most economical, having an outstanding safety record. The people we The relationship between Vacuworx and Dun Transportation hire, who come to work for us, are an extension of our family. runs deep – and the latter still possesses the former’s first actual We treat them as such and care about their safety and livelihood production model of an RC Series lifter, stamped with the serial just as much as ours. These are some of the things that make us number ‘001’. Today, Dun Transportation owns more than 50 RC unique; good to work with. Our response time has to be quick Series units with lifting capacities on its units running up to the to accommodate customers in that regard.” 25 t (55 000 lb) range. The US Energy Information Administration reported in Nunnenkamp was quick to link safety and future December 2021 that, with two new Louisiana LNG export sustainability into his comments related to Dun Transportation, capacity additions expected to go operational by the end now onto its fourth generation of pipe handlers, and the of 2022, US LNG export capacity at that time will become industries served. “This was some of the heaviest pipe we have the largest in the world. Kinder Morgan Louisiana Pipeline’s ever had to handle,” he said. “That project lasted more than one approximately US$145 million Acadiana expansion project, set to year from start to finish, getting everything on the ground, with provide 945 000 Dth/d of capacity to serve Train 6 at Cheniere no lost-time injuries. Energy Partners’ Sabine Pass natural gas liquefaction terminal in “On the other side of that,” he continued, “the Vacuworx Cameron Parish, had been slated to be placed in commercial system in general can be used both at offloading sites and service as early as 1Q22. out on right-of-way. It doesn’t require a different machine, a The PHP was Kinder Morgan’s second major project out different pipelayer. It is flexible in its use and can be put in more of the Permian arena following completion of the Gulf Coast places during [various phases] of a project.” Express (GCX), an approximately 500 mile pipeline system. Also fully subscribed as part of long-term, binding agreements, Critical infrastructure the GCX transports about 2 billion ft3/d of natural gas to the Kinder Morgan Texas Pipeline (KMTP), EagleClaw Midstream and Altus Midstream each hold an approximate 26.7% ownership Agua Dulce, Texas area from the Permian Basin. Kinder Morgan interest in the US$2 billion PHP with an affiliate of an anchor Texas Pipeline LLC (KMTP) owns a 34% interest in the GCX and shipper holding a 20% interest. The project was built and is operates the pipeline. Equity holders include Altus Midstream, operated by KMTP. DCP Midstream and an affiliate of Targa Resources. Cutting greenhouse emissions is a major play for a company The Permian Basin is the second-biggest natural gas such as Kinder Morgan, which has remained committed to producing region in the US.

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Glyn Morgan, Technical Manager at Element, UK, discusses the expansion into hydrogen permeation testing on non-metallic materials.

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ollowing COP26 and declarations on mitigating against the climate emergency, the demand for clean energy has never been greater. The need to realise the potential of cleaner, smarter energy sources like hydrogen is now more urgent than ever. If countries are going to meet their net zero emissions targets, it is widely

acknowledged that hydrogen is going to be required to play an essential role. According to the Hydrogen Council, there are currently over 30 countries with hydrogen roadmaps, and 228 largescale hydrogen projects announced across the value chain, with 85% located in Europe, Asia, and Australia. If all projects

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Due to the small molecular size of hydrogen, it is able to permeate through polymeric, or non-metallic, materials much faster than methane or other gases traditionally associated with fossil fuels. This includes composites comprising a high proportion of glass or carbon fibres such as those used in pipelines. This means it is vital to identify which materials behave best, how well they resist hydrogen and how long they can be expected to remain serviceable. Hydrogen permeation testing can provide manufacturers with important knowledge, such as how much hydrogen is going to pass through the material, if decompression cycles are going to compromise structural integrity, or if the material will be able to stay in service for an agreed period of time. Testing has long been a critical part of the oil and gas industry’s safety processes, measuring permeability characteristics of deep well components such as seals, pressure barriers and liners. As the hydrogen economy expands, more and more industries beyond oil and gas are also looking to hydrogen. This means testing will be commonplace in other industries such as aerospace and transportation for items such as fuel system components, hydrogen storage tanks and even in domestic use for purposes such as heating and cooking.

gas permeation test can measure how quickly hydrogen passes through materials in comparison, for example, to methane, and at pressures up to 150 bar and temperatures from sub-zero to 200°C. Testing companies such as Element conduct tests with hydrogen on elastomers and thermoplastics at pressures to 150 bar with plans to increase this capability to 600 bar, with the ability to compare permeation rates to previously tested gases. Figure 1 shows hydrogen versus methane permeation through a thermoplastic at 40°C and 40 bar with hydrogen permeating approximately 40 times faster than methane. Secondly, as part of the permeation process, gas becomes dissolved in the material. When the applied pressure is removed, this gas tries to escape from the material and can cause damage in the process, referred to as rapid gas decompression (RGD) damage. Some gases cause significant problems to non-metallic materials including composites. The potential for hydrogen to cause damage needs to be investigated due to the risk of it affecting component integrity, as shown in the GRE pipe wall in Figure 2. This testing can be undertaken at pressures up to 150 bar and 150°C. The third aspect focuses on ageing, examining how non-metallic materials behave long term when exposed to hydrogen. This is addressed by measuring changes in mechanical performance over time when the material is saturated with hydrogen. In composites, it is the interface between the fibres and the resin matrix where degradation mechanisms might become evident. This testing can be undertaken at 150 bar and 150°C for many months, to replicate or accelerate in-service conditions. A long term ageing test can also be combined with a decompression test to see if ageing degradation results in reduction in decompression resistance.

What is the testing?

What testing standards are required?

Hydrogen permeation testing involves analysing three key aspects of a material’s performance. Firstly, a high pressure

Testing is most commonly performed to several industryrecognised standards, including: ) Permeation ASTM D1434, ISO 27821.

come to fruition, total investments will reach more than US$300 billion in spending over the next decade. However, the successful deployment of hydrogen will be critically dependent on the appropriate infrastructure, equipment and materials (including elastomers, thermoplastics, and composites), and the assurance and testing required to ensure their safety and longevity. It is also dependent on building expertise and understanding which will allow the industry to grow at the rate required.

The hydrogen challenge

) RGD ISO 23936. ) Ageing ISO 23936. ) NORSOK M-710. ) Plus many NACE and API relevant

standards.

Figure 1. Hydrogen vs methane permeation through a thermoplastic.

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World Pipelines / FEBRUARY 2022

In some cases customised permeation test programmes are also needed, which might be used for components such as O-rings and sealing elements. Where needed several polymer testing methods might also be included in a single test programme.



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Key considerations when preparing to undertake hydrogen permeation testing When preparing to test, it is important that the manufacturer is clear about what they want from the process, whether it’s identifying the permeation rate or understanding and modifying the material or component to reduce permeation. The sample also needs due consideration to ensure the success of the programme. Questions at the outset might include the length of term the component or material will be in use if decompression is likely to be an issue during operation. Another might also be whether the component will be in an enclosed environment where accumulation of permeated H2 could potentially become hazardous, or if a long pipeline permeating m3 of H2 will be economically viable. A hydrogen expert would work closely with the manufacturer in preparing to test, helping to ensure the right questions have been asked to create a smooth test process. Within Element, where we have 30 years’ experience of testing materials in high pressure gas environments, we are finding that our expertise from the oil and gas industry is transferable to the hydrogen market. As a member of the Henry Royce Institute committee, the UK’s National Institute for Advanced Materials Research and Innovation, Element has been involved in writing the ISO 23936 series of Standards, as the industry evolves and grows. It is hard to find proven expertise in capability in the sector because so many test houses are learning as they go. What we have found at Element is that expertise around permeation and decompression damage mechanisms, including high pressure environments, transfers well into the growing world of hydrogen. It is through adapting and using existing skills and expertise that we can support the fast growth needed in the sector.


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For over 20 years, Vacuworx has set the standard for vacuum lifting in the field. In addition to offering the best vacuum lifting systems on the market, Vacuworx also delivers unparalleled service and technical support, backed by experience no one else can copy.

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