World Pipelines - May 2021

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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 5 | MAY 2021 03. Comment A steel saga

LEAK DETECTION 26. Preparing for what comes next

05. Pipeline news

Raymond L. Gatlin, T.D. Williamson, USA.

Updates on Lake Albert development project, Nord Stream 2 environmental monitoring, new contracts awarded, and Gazprom's new gas pipeline.

NDT AND INTEGRITY 33. Pinpointing the right location Mehdi M. Laichoubi and Sylvain Decombe, SKIPPER NDT, France.

World Pipelines’ Senior Editor Elizabeth Corner interviews the winners of the John Tiratsoo Award for Young Achievement, awarded by Young Pipeliners International, in partnership with PPIM. Jess Tufts, Superintendant, Gray Oak Elizabeth Corner: Congratulations Jess! What are your thoughts upon winning the award? Jess Tufts: I am flattered to have been nominated by a co-worker for this award, and very grateful to receive the recognition of this industry panel for my achievements. I have a strong work ethic which has led me to succeed thus far in my career.

Canada’s oil and gas sector has been dealt a series of blows over the past year, but it’s still standing. Gordon Cope discusses the country’s major planned and ongoing energy projects.

EC: What’s been your career highlight so far? JT: That would have to be my promotion to the current role of Operations Superintendent for the Gray Oak Pipeline back in September of 2020. This is the large crude oil pipeline asset that Phillips 66 operates, and I am responsible for a team of 20 employees. EC: Do you have any mentors or role models in the pipeline industry? JT: Stephanie Wilson at Phillips 66 has been a great role model for me. She is currently the Manager for the Midstream Engineering and Projects organisation, and she was previously the Region Manager over operation of several of the Gulf Coast assets that I’ve worked on.


anada has immense oil and gas resources, both conventional and unconventional. Upheavals, such as the COVID-19 pandemic, the US election and environmental interventions have had a profound impact on the country’s energy sector. In the meantime, great strides have been made in developing new pipeline networks and major projects.



EC: What is your message to other young pipeline professionals? What makes this industry rewarding and attractive for young professionals? JT: This industry offers an abundance of opportunities, and there’s something for everyone. You are in the business of providing


Western Canada Pembina Pipeline has earmarked CAN$730 million in capital spending for 2021. Most of the funds, CAN$540 million, will be directed toward its Phase VII Peace Pipeline expansion. The original expansion in


REGIONAL REPORT 10. Weathering the storm Canada’s oil and gas sector has been dealt a series of blows over the past year, but it’s still standing. Gordon Cope discusses the country’s major planned and ongoing energy projects.

PIMS SOFTWARE 15. New life for your assets Nigel Curson, Alastair McLachlan and Aidan Charlton, Penspen Limited, UK.

21. Integrity software: a helping hand Alfred Kuhn, PMP, Switzerland, and Cornelis Bal, PIPECARE, UAE.





YOUNG PIPELINERS 38. Celebrating the future of the pipeline industry World Pipelines’ Senior Editor Elizabeth Corner interviews the winners of the John Tiratsoo Award for Young Achievement, awarded by Young Pipeliners International, in partnership with PPIM.

PROJECT STORY 43. Closing the gap Barry Monk, TAP Operations and Maintenance Country Manager, and Rocio Miguez, Principal Engineer, Energy Systems, DNV.

COVER STORY 49. Composite solutions: planning for tomorrow Chip Edwards and Tommy Precht, Allan Edwards, USA.

Raymond L. Gatlin, T.D. Williamson, USA, discusses a complex purging operation carried out on one of the longest pipelines in the US.

Pipeline Machinery Review


ometimes, you just have to get it all out of your system. And often, the best way is with a good nitrogen purge. Purging a hydrocarbon pipeline with nitrogen (N2) creates a dry and stable environment that’s safe for inline operations. It’s a standard technique for clearing the line before any number of activities, including preventive maintenance, hydrostatic testing, a change of service or a flow reversal. But designing pigs to traverse a 1018 km (633 mile) single-segment pipeline that cuts through America’s heartland? A job that large is anything but standard. Add in considerations so complex that the feasibility and risk mitigation planning alone took nearly a year, and you’ve got a purge project more challenging than most – one that would require global pipeline solutions provider T.D. Williamson (TDW) to engineer a purging pig like no other.

53. Featuring Allu and Trencor






Reader enquiries [] Volume 21 Number 5 - May 2021

ISSN 1472-7390

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teel firm Tata is suing its rival, Liberty Steel, over claims of missed payments. Tata has launched commercial court proceedings in the UK against Liberty Speciality Steels, Liberty House Group PTE and Speciality Steel UK, all parts of the GFG Alliance of companies. Sanjeev Gupta, who owns GFG, was hailed as a saviour when he agreed to buy the specialty steels operation from Tata for £100 million in 2017. The deal folded Tata’s world-class specialty steel division into GFG’s Liberty Steel and secured the future of 1700 staff at key sites in Rotherham, Bolton and Stocksbridge, in the north of England. Liberty Steel also acquired Tata’s 42 in. and 84 in. SAW pipe mills in Hartlepool, UK, which manufacture line pipe for the international oil and gas industry. But now Tata is suing over claims Gupta missed payments related to the deal. The litigation comes as Gupta fights to save his business from collapse following the failure in March of its financial partner, Greensill Capital. Greensill was the main lender for the 2017 deal and provided billions of pounds of support using controversial supply chain financing. Lawyers for Greensill – which counts former Prime Minister David Cameron among its advisers and is under scrutiny for its close ties with, and lobbying of, the government – appeared in court in early March to appoint administrators. The lender had “fallen into severe financial distress,” according to its lawyers and had no way of repaying a £101 million loan to Credit Suisse. Calls for the UK government to intervene are getting louder: Liberty employs 3000 workers in the UK and about 35 000 across the world. Liberty’s assets include strategically important steel manufacturing: a Liberty collapse would impact UK businesses and could cost suppliers £350 million. The British steel industry cannot be allowed to fail. It has long been under pressure from cheap overseas competition,

and weakness in the UK aerospace market has recently cut demand for some specialty products by 60%. When British Steel entered liquidation in 2019, an official receiver was appointed by the government to be a custodian of the business until a buyer (China’s Jingye) was found. But Business Secretary Kwasi Kwarteng has already turned down a request from GFG for a £170 million taxpayer-backed rescue of Liberty. In a bid for financial rescue, Gupta put in a request to ministers to fund the purchase of scrap metal with taxpayer money, so his company could recycle it. He urged the government to set up an investment structure using a ‘tolling’ arrangement, whereby it would purchase scrap that the company’s electric arc furnaces could convert into finished products. Gupta wrote an open letter on 24 March stating that he needed £170 million to balance operating losses and halt potential site closures. Kwarteng told MPs at a committee hearing that he had rejected the request because he did not receive guarantees that the investment would be used exclusively to support UK assets. Unite assistant general secretary Steve Turner said: “The loss of Liberty Steel and the specialist products it manufacturers for the aerospace, automotive and oil and gas sectors would have damaging consequences beyond the steel sector itself … deskilling whole communities, ripping hope of a secure, job from future generations and damaging regional economies.” Speaking at the end of March, UK Prime Minister Boris Johnson hinted at his willingness to support the sector: “I think British steel is a great national asset and the fact that we still make steel in this country is of strategic long-term importance ... It would be crazy if we were not to use this post-Brexit moment to use the flexibility we have to buy British steel.” The British steel industry will hope that Boris’s support for the industry extends to more than the promise of a few homegrown contracts.


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WORLD NEWS EIA: recent completions of natural gas pipeline projects increase US transportation capacity From November 2020 through January 2021, approximately 4.4 billion ft3/d of new natural gas pipeline capacity entered service, according to the US Energy Information Administration’s (EIA) ‘Natural Gas Pipeline Project Tracker’. Four projects have recently been completed and entered service: Saginaw Trail Pipeline: Consumer Energy’s US$610 million intrastate Saginaw Trail Pipeline entered service in late November 2020. The project replaced and expanded natural gas pipelines and infrastructure in Saginaw, Genesse, and Oakland Counties in Michigan, increasing natural gas capacity by 0.2 billion ft3/d. Buckeye Xpress Project: Columbia Gas Transmission’s (CGT) 0.3 billion ft3/d Buckeye Xpress Project began operations in December 2020. The US$709 million project involved infrastructure improvements and replaced 66 miles of existing natural gas pipeline with more reliable 36 in. pipe in Ohio and West Virginia. The project increases transportation capacity out of the Appalachia Basin into CGT’s interconnection in Leach, Kentucky, and the TCO Pool in West Virginia.

Permian Highway Pipeline: Kinder Morgan’s Permian Highway Pipeline (PHP) entered service in early January. The 430 mile pipeline brings 2.1 billion ft3/d of additional natural gas capacity from the Waha Hub, located in West Texas near production activities in the Permian Basin, to Katy, Texas, near the Gulf Coast. It has additional connections to Mexico. Agua Blanca Expansion Project: Whitewater/MPLX’s Agua Blanca Expansion Project, which entered service in late January, connects to nearly 20 natural gas processing sites in the Delaware Basin. It transports an additional 1.8 billion ft3/d of natural gas to the Waha Hub in West Texas. The project will also connect with the Whistler Pipeline, which is scheduled to be completed in 3Q21 and is expected to move 2.0 billion ft3/d of natural gas from the Permian Basin to the Texas Gulf Coast. In December, Tellurian withdrew its application to build the Permian Global Access Pipeline in Texas and Louisiana, effectively cancelling the project. The proposed 2.0 billion ft3/d project would have transported natural gas from the Permian Basin to a proposed LNG facility in Gillis, Louisiana.

GlobalData: Nigeria to account for 23% of upcoming oil and gas projects in Africa by 2025 Nigeria is expected to have 100 oil and gas projects commencing operations across the value chain between 2021 and 2025, accounting for 23% of the total project starts in Africa. Newbuild projects dominate the upcoming projects and account for around 90% of the total projects commencing operations across the value chain, according to GlobalData’s report, ‘Africa Oil and Gas Projects Outlook to 2025 –

Development Stage, Capacity, Capex and Contractor Details of All New Build and Expansion Projects’. The report reveals that of the 100 projects expected to commence operations during the outlook period, petrochemicals will have the highest count with 28 projects, followed by upstream (25), refinery (24) and midstream (23). Midstream projects will account for around 23% of all oil and gas projects in Nigeria by 2025.

Uganda and Tanzania: final agreements for the Lake Albert resources development project During a signing ceremony held on 11 April in Entebbe, Uganda, in the presence of Yoweri Museveni, President of the Republic of Uganda, Samia Suluhu Hassan, President of the United Republic of Tanzania, Patrick Pouyanné, Chairman and CEO of Total, as well as representatives of China National Offshore Oil Corporation (CNOOC), Uganda National Oil Company (UNOC) and Tanzania Petroleum Development Corporation (TPDC), the partners of the Lake Albert development project concluded the final agreements required to launch the project. The Lake Albert development encompasses Tilenga and Kingfisher upstream oil projects in Uganda and the construction of the East African Crude Oil Pipeline (EACOP) in Uganda and Tanzania. The Tilenga project, operated by Total, and the Kingfisher project, operated by CNOOC, are expected to deliver a combined production of 230 000 bpd at plateau. The upstream partners are Total (56.67%), CNOOC (28.33%) and UNOC (15%). The production will be transported from the oilfields in Uganda to the port of Tanga in Tanzania via EACOP cross-border pipeline, with Total, UNOC, TPDC and CNOOC as

shareholders. The agreements concluded mid April include the Shareholders Agreement of EACOP and the Tariff and Transportation Agreement between EACOP and the Lake Albert oil shippers. These agreements open the way for the commencement of the Lake Albert development project. The main engineering, procurement and construction contracts will be awarded shortly, and construction will start. First oil export is planned in early 2025. “The Tilenga development and EACOP pipeline project are major projects for Total and are consistent with our strategy to focus on low breakeven oil projects while lowering the average carbon intensity of the Group’s upstream portfolio. These projects will create significant in-country value for both Uganda and Tanzania” said Patrick Pouyanné, Chairman and Chief Executive Officer of Total. “Total is also taking into the highest consideration the sensitive environmental context and social stakes of these onshore projects. Our commitment is to implement these projects in an exemplary and fully transparent manner”.

MAY 2021 / World Pipelines


WORLD NEWS IN BRIEF USA BP Plc will spend approximately US$1.3 billion to build a network of pipes and other infrastructure to collect and capture natural gas produced as a byproduct from oil wells in the Permian Basin of Texas and New Mexico. The plans will eliminate routine flaring of natural gas in the oilfield by 2025.

UK Express Engineering has opened its new £3.5 million international assembly and test centre, part of its broader product strategy to supply assembled and tested actuators, connections and tooling for wellheads and subsea production systems for the oil and gas sector. The investment in the centre will contribute to the company’s continued development in key global markets.

USA Orbital Sidekick, the first US commercial company to deploy hyperspectral sensors in space, has announced a US$16 million Series A funding round led by Temasek, an investment company headquartered in Singapore, to expand its innovative product offerings, new strategic partnerships, and introduce its advanced monitoring technology to new industries.

NETHERLANDS Composite pipe technology company Strohm has announced a new strategic appointment to support its international growth ambitions. Reporting directly to CEO Oliver Kassam and based in Ijmuiden, the Netherlands, Caroline Justet has been promoted from her key account management position for Strohm to a newly created global executive role, developing the firm’s energy transition strategy.


World Pipelines / MAY 2021

Nord Stream 2: annual environmental monitoring report 2019 published The monitoring of Nord Stream 2 offshore construction activities in 2019 shows that there were no impacts other than those that had been predicted. In the Russian onshore section, there were no significant impacts on the biotic and abiotic environment of the protected area. In 2019, the monitoring focused on relevant physical-chemical (e.g. water quality and air quality), biotic (e.g. birds and marine mammals) and socio-economic (e.g. cultural heritage and ship traffic) environments. The objective was to observe potential impacts caused by the construction activities implemented offshore (in Russia, Finland, Sweden, Germany) and onshore (in Russia, Germany). Construction activities included pipelay, rock placement, cofferdam installation, post-lay trenching and dredging/backfilling. Additional monitoring activities were carried out through specialist studies to enhance scientific knowledge of for example the Baltic Sea environment. Extensive mitigation measures were implemented throughout the construction phase. Conformance to the environmental and social management system has been

monitored through an environmental and social auditing programme. The monitoring results offshore verified that: ) In German waters, the impact of construction activities performed in 2018 – i.e. dredging, pipelay and backfilling – on the seabed was in line with the assessment as demonstrated by post-construction monitoring of 2019. ) In Swedish waters, underwater noise

associated with pipelay and rock placement was comparable to or lower in level and frequency than noise from commercial cargo ships in the area. This supported the initial assessment that no harm occurred to the marine mammals. ) Monitoring of third-party shipping

traffic demonstrated that risk mitigation measures were successfully implemented during construction in all countries. No incidents were recorded. Up to 40 independent contractors have been monitoring the actual impacts on the environment and marine life.

Gazprom: Mozdok – Grozny gas pipeline launched Taking part in the opening ceremony on 7 April were Vitaly Markelov, Deputy Chairman of the Gazprom Management Committee, Ramzan Kadyrov, Head of the Chechen Republic, heads of relevant subdivisions and subsidiaries of the company, and representatives of the regional authorities. The Mozdok – Grozny gas pipeline runs in the same corridor as the Stavropol – Grozny gas pipeline. The new gas pipeline with a 720 mm diameter is 101.7 km long. Only pipes of Russian make were used in the course of construction, and crossings were set up on 13 motor roads and six bodies of water, including the Terek River. A state-of-the-art gas distribution station named Grozny with an hourly capacity of 247 000 m3 was created as part of the project. The new high-efficiency facilities of Gazprom’s gas transmission system will further strengthen the reliability of the

Chechen Republic’s energy system, including the Grozny TPP, one of its key components. The facilities will also make it possible to bring gas to more consumers. Vitaly Markelov and Muslim Khuchiev, Prime Minister of the Chechen Republic, held a joint meeting on cooperation between Gazprom and the Government of the Chechen Republic. It was noted that Gazprom has been making large-scale efforts for gas supply and gas infrastructure expansion in the region since 2008. By the start of this year, the Company built over 743 km of gas pipelines in the Chechen Republic and created the conditions for connecting 11 800 households to gas. Currently, the Company and the region are cooperating under a new five year programme for 2021 - 2025. A synchronisation plan for gas infrastructure expansion in 2021 is in effect.






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Fugro awarded Jumbo positioning contract offshore Brazil

NEW DATES: 25 - 27 May 2021

Fugro is providing positioning and construction support services for Jumbo Maritime, a leading offshore installation contractor, on the Mero 1 deepwater field development located approximately 180 km off the coast of Rio de Janeiro. Using its Starfix®Navigation Suite and augmented reality QuickVision® camera system, Fugro is supporting Jumbo in the safe and efficient installation of 35 subsea torpedo piles and 24 mooring lines down to water depths of 1980 m. This critical infrastructure will be used to anchor the Mero 1 floating production unit and associated equipment. The work is being performed onboard Jumbo’s Fairplayer heavy lift crane vessel and is estimated to last six months. In addition to pre- and post-lay surveys of the piles and mooring lines, Fugro’s Starfix and QuickVision solutions will provide real-time positioning for subsea construction and installation activities without needing any hardware mounted on the subsea

Subsea Expo Aberdeen, Scotland

NEW DATES: 13 - 16 September 2021 Gastech Exhibition & Conference 2021 Singapore

13- 17 September 2021 IPLOCA 54th Annual Convention Prague, Czech Republic

NEW DATES: 21 - 23 Septmber 2021 Global Energy Show 2021 Alberta, Canada

20 October 2021 OpTech 2021 ONLINE CONFERENCE

NEW DATES: 8 - 11 November 2021 Abu Dhabi International Petroleum Exhibition & Conference 2021 (ADIPEC) Abu Dhabi, UAE

NEW DATES: 5 - 9 December 2021 23rd World Petroleum Congress Houston, USA

7 - 9 December 2021 15th annual GPCA Forum Dubai, UAE


World Pipelines / MAY 2021

New offshore project awarded to Corinth Pipeworks Cenergy Holdings SA has announced that Corinth Pipeworks S.A., its steel pipe segment, signed an agreement to manufacture and supply steel pipes to Israel Natural Gas Lines (INGL), leader in natural gas distribution in Israel, for the offshore section of a new highpressure gas pipeline between the cities of Ashdod and Ashkelon. Chevron, having recently completed its acquisition of Noble Energy, as the operator of Leviathan and Tamar offshore gas fields, has entered into an agreement with INGL for the provision of transmission services of natural gas. The new pipeline system, in addition to the expansion of other lines, will enable Chevron and its partners to send as much as 7 billion m3 of gas annually to Egypt. Corinth Pipework’s contract for approximately 50 km of 36 in. LSAW linepipe also includes anticorrosion coating and concrete weight coating, all of which will be manufactured at Thisvi facility in Greece within 2021. The installation of the pipeline is scheduled to start in 2022. This award is another significant milestone in Corinth Pipeworks’ offshore presence in the South East Mediterranean region.

infrastructure, an approach which reduces risk, increases spatial awareness and streamlines workflows. Rogerio Carvalho, Country Manager for Fugro in Brazil, said: “Fugro’s global reach and advanced technology, combined with our resources and experience from the Netherlands and Brazil, were key to securing this contract. Having overcome many challenges in planning the operations for this project amid the constraints caused by COVID-19, we’re excited to now be supporting Jumbo on this important deepwater development.” Mero field is under a Production Sharing Agreement with the Libra Consortium, which comprises Petrobras as the operator (40 %share), Shell Brasil (20 %), Total (20 %), CNODC (10 %) and CNOOC Limited (10 %). The consortium also includes Pré-Sal Petróleo S.A. (PPSA) as manager of the Production Sharing Contract.


Investment spurs Americas growth for STATS Group

Kpler appoints Mark Cunningham as CFO

Ashtead Technology signs agreement with Zetechtics

Non-metallic Innovation Centre establishes Associate scheme

Element and Bristol University agree partnership

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Canada’s oil and gas sector has been dealt a series of blows over the past year, but it’s still standing. Gordon Cope discusses the country’s major planned and ongoing energy projects.


anada has immense oil and gas resources, both conventional and unconventional. Upheavals, such as the COVID-19 pandemic, the US election and environmental interventions have had a profound impact on the country’s energy sector. In the meantime, great strides have been made in developing new pipeline networks and major projects.

Western Canada Pembina Pipeline has earmarked CAN$730 million in capital spending for 2021. Most of the funds, CAN$540 million, will be directed toward its Phase VII Peace Pipeline expansion. The original expansion in


the Valleyview-Fox Creek Corridor northwest of Edmonton, Alberta, was slated to have a capacity of 240 000 bpd. Feedback from customer development plans necessitated the company to re-scope the capacity to 160 000 bpd. The project will see a new, 20 in. line installed by the first half of 2023, mainly to handle the growth in condensate supply in the Western Canadian Sedimentary basin. Once Phase VII is complete, the company will have 1.1 million bpd capacity in its Peace and Northern pipeline systems to deliver a slate of crude liquids and condensates to the Edmonton area. Inter Pipeline plans to spend CAN$1 billion on capital projects in 2021. Approximately CAN$800 million is for the final stages of the CAN$3.5 billion Heartland Petrochemical Complex (HPC) near Edmonton, Alberta, where the company is installing propane dehydrogenation (PDH) and polypropylene (PP) units. When the complex is commissioned in 2022, it is expected to produce 525 000 tpy of PP. In February 2021, Brookfield Infrastructure Partners made an unsolicited bid to purchase Inter Pipeline for US$5.6 billion, a 23% premium over the stock’s current price. The utilities and transport operator already owns 19.65% of Inter Pipeline, and has been seeking a deal for almost a year. The latter’s stock fell by almost half after the pandemic hit, and has rebounded slowly. Inter Pipeline’s board feels that any conditional offers based on current stock value does not reflect the intrinsic value of the company. Keyera announced that the cost of its proposed Keyera Access Pipeline System (KAPS), has risen to CAN$1.6 billion from CAN$1.3 billion due to competition from other regional pipeline construction projects. The KAPS system (a 50/50 JV with SemCAMS Midstream) is designed to deliver natural gas liquids (NGLs) from northwestern Alberta to refineries and petrochemical plants in the Edmonton area. The JV will build nine gas plants with access to approximately 2.5 billion ft3/d. Two pipelines, a 16 in. condensate pipeline and a 12 in. mixed NGL pipeline will deliver up to 130 000 bpd. The project, which was delayed by Keyera for one year, is expected to come onstream in 2023. In late 2020, the federal government gave approval for TC Energy’s (formerly TransCanada) Nova Gas Transmission expansion plans for 2021. The company will spend an estimated CAN$509 million to add 85 km of 48 in. pipeline to deliver 310 million ft3/d to utilities in southern Alberta. The expansion is part of TC Energy’s programme to invest CAN$9.9 billion to add a total of 3.5 billion ft3/d incremental new capacity by 2024.

LNG Western Canada holds immense unconventional gas reserves. The Montney and Duvernay shales of northwest Alberta and northeast British Columbia (BC) contain trillions of cubic feet of gas and immense reserves of NGLs. Output now stands at 5.6 billion ft3/d of liquids-rich gas. While most of the gas is currently processed and distributed through Alberta to markets in Eastern Canada and the US, plans are underway to tap an entirely new market. The west coast of Canada is significantly closer to Asia than Australia or the USGC, making LNG transport much more


World Pipelines / MAY 2021

economical. LNG Canada, led by Royal Dutch Shell, is building up to four-train plant with a capacity of 26 million tpy in Kitimat, BC. In order to service the project, TC Energy is building the Coastal GasLink pipeline, designed to carry up to 2.1 billion ft3/d of gas from northeast British Columbia to the LNG Canada plant. The entire project is expected to cost approximately CAN$40 billion. Eastern Canada is also half the distance to the European market than the USGC. Pieridae Energy of Calgary is in the final stages of giving the greenlight to its Goldboro LNG plant in Nova Scotia. The CAN$13 billion project would contain two trains capable of producing 10 million tpy. The company has an agreement to supply up to 5 million tpy to German utility Uniper. The first phase, a CAN$720 million work camp, is being finalised this year.

Oilsands The oilsands, a bitumen deposit in northeast Alberta, contains an estimated 165 billion bbls of reserves. Output from oilsands mines and SAGD operations reached a record 3.16 million bpd in late 2020. Suncor, CNRL, Cenovus and Imperial primarily relied on expansions of existing facilities, and expect to add approximately 140 000 bpd in 2021. The Canadian Energy Regulator estimates that production will peak at 4.3 million bpd over the next 20 years. In the meantime, a wave of mergers and acquisitions continues. In October 2020, oilsands operator Cenovus and heavy oil giant Husky Energy announced a CAN$23.6 billion all-stock merger to create the third largest oil and gas company in Canada. The combined company will have about 750 000 boe/d of production and 660 000 bpd of refining capacity, as well as 16 million bbls of crude oil storage capacity. “The integration of Cenovus’s best-in-class in-situ oilsands assets with Husky’s extensive North American upgrading, refining and transportation network and high netback offshore natural gas production, will create a low-cost competitor and support long-term value creation,” said Husky CEO Rob Peabody.

Offshore east coast Newfoundland and Labrador offshore production from fields such as Hibernia and Terra Nova stands at 275 000 bpd. International explorers continue to show interest in deep water plays off the coast of Newfoundland, where independent studies have placed potential reserves at 52 billion bbls of oil and 200 trillion ft3 of gas. Several commercial deposits have already been discovered, including Equinor’s 300 million bbl Bay du Nord discovery in the Flemish Pass. In early 2021, the federal government approved proposals from BHP Canada, Equinor and Chevron for new exploration drilling projects in the West Flemish Pass.

Challenges Since 2008, TC Energy has been battling to build the Keystone XL pipeline. Designed to deliver 830 000 bpd of Alberta crude to the USGC, the Obama administration refused to authorise a cross-border permit. Upon his election, President Trump used an executive order to approve its construction. President Biden

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campaigned on a promise to cancel it, and one of his first actions as president was to issue an executive order cancelling the previous administration’s permit for Keystone XL. The government of Alberta, which owns a stake in the line, protested vehemently, but chances of the line being built are increasingly slim. Enbridge, which exports over 3 million bpd to the US through its crude network, is working to add incremental capacity. The Trans Mountain Expansion (TMX), a project to triple the capacity of a crude pipeline running from Alberta to the British Columbia port of Burnaby, has faced a decade of obstruction from the government of British Columbia, First Nations and environmental groups, to the point where Kinder Morgan sold the project to the federal government in 2018. The result of delays has been a massive cost escalation, from CAN$7.4 billion to CAN$12.6 billion. While protests continue, construction on the line proceeds apace in both British Columbia and Alberta. Efforts to increase Indigenous support for the pipeline, which runs through a score of reserves, continues. Several Indigenous members from Saskatchewan, Alberta and British Columbia have joined together to form Project Reconciliation to negotiate an ownership stake. “I’m hoping it can happen in this new negotiation that’s taken place and everything comes out in a positive result and it’s a win-win for the First Nations, for TMX ownership and the government,” said Robert Morin, a member of the Enoch Cree First Nation, west of Edmonton. In late 2020, British Columbia health authorities issued an order regarding the workforces at several major construction projects to limit the transmission of COVID. Two lodges housing workers for CoastalLink Pipeline experienced outbreaks in December 2020, just prior to demobilisation for the Christmas holidays. During remobilisation in January, the company was limited to 400 workers in January, 2021, slowly increasing to 1000 by mid-February. The company noted that the order will both increase costs and delay the construction schedule, but was still assessing data in order to determine the extent of the impact.

Renewables As the world gradually moves away from fossil fuels toward renewables, so too is the Canadian oil patch. Hydrogen has great advantages as a clean fuel because, when it is burned in a fuel cell to create energy for electricity, the only emission is water. Analysts project that the global hydrogen market could reach US$12 trillion by 2050, when up to 30% of fuel needs will be met by hydrogen. The key to greenhouse gas (GHG) reductions is to create hydrogen without emitting carbon. Traditionally, hydrogen is made using the steam-methane reforming process, where hightemperature steam is used to strip hydrogen from natural gas. The energy-intensive process also produces large amounts of carbon dioxide (CO2). Blue hydrogen is made the same way, but the carbon dioxide is captured and sequestered underground (CCS). Hydrogen can also be made by electrolysis (running an electric current through water to separate hydrogen from oxygen). If the electricity is sourced from solar or wind power, the output is called green hydrogen. Many nations in Europe are already developing hydrogen hubs (also called hydrogen valleys and hydrogen clusters), that rely on


World Pipelines / MAY 2021

existing production and usage of hydrogen, most notably around refinery and petrochemical plants. Government, researchers and consultants are looking at potential sites in Canada. “There is the potential for a sort of early hydrogen hub in Canada in the Alberta Industrial Heartland, and there’s been some work that’s been done there,” said Debbie Scharf, Director General, Natural Resources Canada, at a recent hydrogen forum. Blue hydrogen is an ideal candidate for production in Alberta. As home to Canada’s oil and gas sector, the province has a long history of hydrogen production, as well as CCS. Royal Dutch Shell employed Fluor Canada to build its Quest Carbon Capture & Sequestration facility at the Scotford Refinery outside of Edmonton. In addition, it designed the nearby North West Redwater Sturgeon refinery, which captures carbon for transport via the Alberta Carbon Trunk Line to enhanced oil recovery projects in Central Alberta. FortisBC, the largest energy transportation company in British Columbia, has a goal to reduce its costumer’s GHG emissions by 30% by 2030. A key facet will be introducing hydrogen into its energy mix; because hydrogen has a tendency to make metals brittle, studies are currently underway to determine what amounts are safe to both the infrastructures of pipeline companies and consumers. The growth of electric vehicle (EV) cars will require massive amounts of lithium. The metal is primarily mined or extracted from brines, both costly and environmentally-damaging processes. Lithium also exists in high concentrations in waste brines from many conventional crude operations, however. A typical mature well in Alberta can produce up to 10 bbls of water for every bbl of crude extracted; every day, the province produces millions of barrels. Normally, the waste water, which can contain over 80 mg/l of lithium, is reinjected. A Canadian company is working to commercialise that resource, however. In early 2021, E3 Metals opened a direct lithium extraction (DLE) testing facility in Calgary. Brine from a Leduc field well is injected into a vessel containing proprietary chemicals that selectively absorb lithium ion. The lithium concentrate (around 5000 mg/l) is then extracted for further processing into battery-grade chemicals. The company will gather information in order to build a larger field test facility.

Future While adversarial events such as the cancellation of Keystone XL have had short-term impacts on the Canadian energy sector, Canadian production and exports are still on an upward trajectory. Oil output in Western Canada is expected to rise from 3.9 million bpd in 2020 to 4.45 million bpd by the end of 2021. Canada now exports approximately 3.8 million bpd to the US, which is expected to rise to 4.2 - 4.4 million bpd by 2026. Pipeline expansions in progress will add almost 1 million bpd by 2025, and crude-by-rail capacity is continually growing. In conclusion, Canada’s potential as an energy producing nation will continue to grow due to perseverance, innovation and a focus on producing oil and gas in an ethical, cost efficient and environmentally-sound manner. To that end, the midstream sector will benefit as new and existing markets for oil, gas, and renewable fuels expand.

Nigel Curson, Alastair McLachlan and Aidan Charlton, Penspen Limited, UK, present a statistical derivation of the present value (PV10) of a step-out development based on remaining life.


he oil industry uses the PV10 value to evaluate hydrocarbon assets. It is a calculation of the present value of estimated future hydrocarbon revenue, less direct expenses. It is discounted to the present using an annual rate of 10%. In practice, when

Figure 1. Step out development.

applied to a post plateau and declining oil or gas reservoir connected to a host platform or processing facility by a relatively long pipeline, the PV10 value is limited by the asset’s remaining life, including pipelines and wells. Having to intervene for a repair or access to a well with declining


revenue can lead to the end of the economic life of an asset or field. However, appreciating that a producing asset comprises various critical components, this article mainly concentrates on the pipeline asset. Understanding the condition and opportunity of the pipeline as a distinct asset has the potential to realise future value. Several standards guide the fitness for service (FFS) of pipelines, including DNVGL-RP-F101,1 ASME B31G,2 and the Pipeline Defect Assessment Manual (PDAM). 3 Some standards specifically address remaining life assessment, such as ISO TS 12747,4 and NORSOK Y-002.5 These standards tend to focus on technical integrity. NORSOK Y-002 uses the term ‘integrity level’ and defines it as the absence of risk. It notes that risk in this context has various aspects, varies with failure mode, criticality, and system type. It describes it as not being a variable but having lower and upper bounds and an acceptable level. It does not explain how it is derived and indicates it can never be fully known. ISO 16708 takes a more general approach across the whole life cycle and is more tangible in its use, in that it provides target failure probabilities based on fluid category, location (proximity of people) and safety class.6 An offshore oil pipeline is classed as ‘normal safety class’, which for an ultimate limit state is assigned an acceptable failure probability of 1x10-4 or 1/10 000 per km, per year. In practical economic terms the remaining life is determined when adding more years of operation reduces net present value. In other words, the present value of direct expenses exceeds the present value of the operation. This is typically driven by the need to intervene to undertake expensive repairs or replacement. This can be driven by inspection data and/or a perception of risk. Most remaining life methodologies systematically identify credible failure mechanisms such as corrosion and fatigue. They then use historical data, such as inspection data or operating conditions, to determine

the degradation rate. The degradation can be expressed in terms of corrosion growth rate, fatigue life reduction, or possibly crack growth rate. This is combined with a FFS assessment to determine when risk in the future becomes unacceptable, and where intervention/repair or decommissioning is required. Inspection and monitoring are used to determine the rate of degradation and track progress against the prediction. More sophisticated methodologies, such as implemented within the Penspen THEIA platform take actual live data and use this to dynamically calculate the remaining life.7 This creates value for the operator, e.g. tactical value (small value pool) with a quicker route and more confidence in the optimal operational solution, and strategic value (big value pool) with deferred capex and the avoidance of failures.

Design life Pipelines are typically designed for 30 years and many are now operating considerably beyond their original design life. The safe operation of pipelines in the North Sea is controlled by a series of regulations that requires the assessment and management of risk. This is carried out by the pipeline operator implementing a rigorous pipeline integrity management system (PIMS). The design life is chosen to prevent failure during operation due to time-dependent degradation mechanisms such as corrosion and fatigue. This assumes a degradation rate in the design phase. When the pipeline reaches the end of its design life, this does not mean the pipeline should immediately be decommissioned because it is now representing an unacceptable risk. In practice, considerable investment has been made in managing the pipeline in operations, performing inspections and implementing mitigations. In practice: ) The corrosion rates and fatigue rates established during the original design process may prove to have been conservative. ) Defects could have been repaired.

Figure 2. Cumulative PV10 per month of operation.


World Pipelines / MAY 2021

Extending the pipeline’s life might have considerable business advantages due to remaining recoverable hydrocarbons, pipeline change of use or exploiting the possibility of third parties using the asset for their product. It may even make the asset attractive to potential buyers. These last aspects are now covered by UK legislation. The strategy for maximising economic recovery in the UK (MER UK) came into force in March 2016.8 This obliges all stakeholders to maximise the expected net value of economically recoverable petroleum. If a party decides not to do this, it must allow others to use its license or infrastructure, including pipelines.

Tunnel-Goat Straddle carrier suitable to move and line up pipes inside tunnels, electric or diesel version.


Liifting capacity Lifting capacit capaci up to 18 Ton, pipe diameter up to 70 inch.

Asset life extension (ALE) process The concept of life extension is to increase the asset’s life but still maintain an acceptable risk. This would normally consider changes not considered in the original design, including changes in: ) The integrity of the asset through the development of flaws from corrosion or fatigue. ) Fluid compositional or flowrates. ) Environmental loading. ) Temperatures and pressures.

Corrosion is usually the most significant degradation mechanism for pipelines. Typically for offshore pipelines,

this is on the inside of the pipeline since anodes are quite good at controlling external corrosion. However, anodes do occasionally require replacement. The uncertainty associated with corrosion rates is an important factor. ISO 12747 states that the degree of uncertainty in the calculated corrosion rate (and therefore the remnant life) should be determined by calculating upper and lower bounds.4 ALE goes beyond just estimating the remaining life of the asset, but also includes organisational requirements in terms of competencies, continuous operability of safetycritical equipment, updating inspection and monitoring requirements, legislation requirements and updating PIMS documentation.

Remaining life optimisation In general, the risk associated with operating a pipeline increases with time and accelerates as they approach the end of their life. If the predicted remaining life is not enough to satisfy the overall field economics due remaining reserves, there will be a need to consider alternatives. These can include: ) Replacing the pipeline or parts of it. ) Repairing parts of the pipeline. ) Downrate to operate at a lower

pressure. ) Use of inhibitor to reduce the

corrosion rate. ) To change the composition or flowing Figure 3. Statistical distribution of remaining life.

conditions to reduce the corrosivity of the product. ) Increasing inspection frequency to

carefully manage the risk associated with operating an asset towards the end of its life. Having the capability to model these ‘what if’ scenarios quickly will drive the optimum forward plan. The THEIA platform has this forecasting perspective and capability.

Effective maintenance strategies

Figure 4. Statistical distribution of PV10.


World Pipelines / MAY 2021

The last bullet point from above is important. Inspection and the subsequent actions for pipelines can be classified as condition-based maintenance. The actual condition of the asset is used to determine what maintenance needs to be performed. Inspection using an intelligent pig is expensive, takes time

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Table 1. Distribution for principle variables

) A cost model



Standard deviation

Resultant max value

Resultant min value

Oil price (US$/bbl)





Production decline (per annum)





Repair cost and inspection cost (million US$)





Corrosion rate (mm/y)




to procure and can be disruptive to operations. The opportunity here is to use predictive maintenance as a supplement to inspection to optimise decision making. This would include highly efficient inspection matching routines to predict corrosion growth rates and confidence levels along the pipeline, use of real-time data including pressure, flowrates and temperatures to give live updates of remaining life on a dashboard, along with other KPIs to enable mitigating actions to be taken as required. These tools are implemented within THEIA which is based on an industrial analytics platform.

Net present value (NPV) modelling It is hard to compare all the above options directly since they all have different investment and revenue profiles with time. A good way of comparing them is to calculate the NPV of each, where all the income (cash outgoings) and investments (cash outgoings) are netted and brought back to a value today (present value). The option with the highest NPV is the most attractive. Most applications of NPV are assessed on a deterministic basis where the answer is one value. This is necessarily conservative. In practice, the rate of decline, the rate of degradation and oil/gas price are not fixed values. All these values can vary considerably. This article considers a hypothetical oilfield, based on the typical North Sea step out development (Figure 1) with declining production and an ageing pipeline. It uses statical analysis to calculate the possible variation of PV10, taking account of the variation of oil price, decline in production, degradation rate, cost of inspection and cost of repair intervention. Reservoir decline is based on Arp’s decline analysis model.8 Statistical analysis is based on Monte Carlo Simulation.

Economic model The economic model used has three components: ) A revenue model which assumes an initial production rate, a decline in production per year and the oil price. ) A cost model which uses a fixed price for the

organisation, a price per barrel of oil price for production chemicals, the cost for intelligent pigging and General Visual Inspection (GVI) based on a set frequency in numbers of years.


World Pipelines / MAY 2021

which includes the cost of a repair and associated inspection linked to the integrity of the pipeline.

The cost model calculates the revenue, costs and contributing NPV each month, taking account of degradation and required intervention to repair. The end of life is triggered when the forwardlooking NPV is low or negative, normally coinciding with a required intervention. This is illustrated in Figure 2. Running the model on a deterministic basis (no variation in inputs), gives a remaining life of 10.8 years and an NPV of US$250 million. Using Monte Carlo simulation and varying the main parameters of oil price, annual decline and corrosion rate, an NPV with a median of US$246 million and a standard deviation of US$66 million and a remaining life with a median of 10.2 years and a standard deviation of 1.9 years are produced. The distributions are shown in Figures 3 and 4, with reasonable probabilities that remaining life and PV10 could be 8.0 years and US$180 million respectively. The variations used are given in Table 1. .13

Conclusions Use of an NPV model such as implemented within THEIA to quickly compare remaining life options is considerably superior to a deterministic assessment and provides valuable insights into the possible variations. An insight from the above model is the fact that the changes in remaining life, where the reduction in revenue due to reduced production is in line with degradation, are not that significant in NPV terms. This is because the majority of NPV contribution has been in the early life. Where remaining life optimisation will have a more significant impact on NPV will be where production is still at a high level, but the oil price is low, income is low and investment decisions are deferred or where a replacement pipeline dictates the end of economic life.

References 1. 2.

DNVGL. RP-F101 Corroded Pipelines. ASME. B31G - 2012(R2017) Manual for Determining the Remaining Strength of Corroded Pipelines. 3. Penspen Limited. Pipeline Defect Assessment Manual Version 2, a Joint Industry Research Programme. 4. ISO. TS 12747:2011 Petroleum and natural gas industries – Pipeline transportation systems – Recommended practice for pipeline life extension. 5. NORSOK. Y-002 Life extension for transportation systems (Rev. 1, December 2010). 6. ISO. 16708: Petroleum and natural gas industries, Pipeline transport systems, Reliability-based limit state methods. 7. Penspen Limited. THEIA - Cloud Based Integrity Tools and Industrial Analytics. 8. Arps, J.J. Analysis of Decline Curves, SPE-945228-G, 1945. 9. Oil and Gas Authority, UK. The Maximising Economic Recovery Strategy for the UK. 10. ISO. 13623 (2000): Petroleum and Natural Gas Industries - Pipeline Transportation Systems.

Alfred Kuhn, PMP, Switzerland, and Cornelis Bal, PIPECARE, UAE, talk through a new integrity management software solution designed to assist operators transitioning into the digital pipeline era.


ery often, pipeline integrityrelated data are dispersed across organisations, large or small. This creates challenges to manage a holistic approach due to multiple data locations. Some information may still be paper based and massive amounts of digital information are also available in different departments. The worst case happens when information is stored in people’s heads only.


In such an environment, fact-based decision making will be difficult and time consuming, with one question often looming over the decision maker – do I have all the relevant information, and is it accurate and up-to-date? PIPECARE is proud to announce its latest software development, the Predicta® software suite, for efficient pipeline network integrity management with its main objective to ‘maintain the pipeline condition to operate safely, reliably and economically within its design parameters until the end of its design life.’ More often than not, it is the case that operators concentrate on and action the short list of features in pipeline inspection reports, usually to to three pages, that form an instant threat to the pipeline integrity only. The rest of the report, which forms the major part and could be up to hundreds of pages, is rarely analysed in detail. This is understandable, as the decision making for justifying the optimisation of maintenance cost can be too complex to comprehend, with many factors playing a role in the deterioration process of pipeline materials.

Figure 1. Anomalies distribution.

International standards, such as API, ASME, DNV, the Predicta software utilises the results of inline inspection and other datasets, as a base to evaluate the pipeline integrity by: ) Consolidating all available data. ) Presenting all available information in a comprehensive way. ) Recommending maintenance and repair optimisation. ) Visualising information in easy-to-understand graphs and

dashboards. ) Supporting quick decision making.

Predicta integrates data quickly and accurately, and enables access to existing databases and formats like PODS, APDM, GIS, SCADA helps to use various standards for integrity assessments and extend the pipeline network life cycle efficiently. The alignment – or rather, the lack of it – in pipeline inspection reports makes it even more difficult to assess progress development of the deterioration process. This is also caused by the limited accuracy of distance measurement of pipeline inspection intelligent tools. They measure distance by so-called odometer wheels, but these wheels are subject to proportional slippage over the entire distance or localised slippage at areas in which the inspection has accelerated. Alignment of inspection reports has always been extremely difficult and that has also resulted mostly in aligning only the most severe features for urgent repairs, as the opportunity to maintain had passed long time ago. The inspection per pipeline caused the integrity managers also to concentrate on single pipelines only, rather than on the maintenance of the entire pipeline system. Even the information on single pipelines is massive; it is not uncommon for some pipelines to have hundreds of thousands of pipe wall deteriorating features. This information is digitally reported but it is not comprehensible as it not aligned with previous reports, and figuring out the impact of each feature is as good as impossible.

Predicta modularity

Figure 2. Circumferential as distance function of relative distance to closest girth weld plot.


World Pipelines / MAY 2021

Predicta’s modular design and built-in integration capabilities supports effective and efficient pipeline network integrity management. The Predicta software suite has been designed modular with the following structure: • Predicta Basic Entry-level – Desktop module.

• Predicta Risk Assessment – Server based module. • Predicta Integrity Management – Server based

module. Predicta Basic Entry-level is the base module with main focus: • Alignment (weld, feature and anomaly). • Leak prediction (whole pipeline and for each anomaly). • Corrosion growth rate (CGR) calculation. • Segmentation. • Report generation. This module uses mostly information obtained from the inline inspection of pipelines. Various data set formats can be imported and used for alignment and further assessments. Predicta Risk Assessment is the second module incorporating: ) Visualisation of the pipeline network in 2D and 3D maps, graphical views, and tabular format. ) Advanced dashboarding facilities displaying integrity

parameters, risk-based assessments, and repairs optimisation. ) Pipeline integrity assessment based on a wide

range of assessment standards and generation of all available digital information of your pipeline, with recommendations for optimising your maintenance expenditure. Predicta Integrity is the third module integrating the following functionalities: ) The prediction of the pipeline’s asset lifetime and integrity for future optimisations. The self-learning abilities of Predicta increase the accuracy over time. ) Pipeline joint severity classification that guides to the

areas requiring attention. ) Repair recommendation for each joint based on feature

growth, risk-based assessment, end of design pipeline life and optimisation of rehabilitation works. ) Corrosion growth model compatibility for future

prediction calculations to show the deterioration of the pipeline integrity by active corrosion growth including fatigue cracking, HIC, SCC, and weld cracks. ) Based on available data, PIPECARE research of

international standards, and statistics, the leak and rupture prediction model helps to optimise expenditure and avoid product spills. The three modules build on each other and may be implemented all at once or step by step, thus giving the users flexibility in time and expenditure.


World Pipelines / MAY 2021

Predicta project phases The typical Predicta project consists of the following eight phases:

1. Data gap analysis The targets of this project phase are to understand: • The project team. • The customer’s project organisation, especially the point(s) of contact in the departments. • The needs and challenges the customer has so that the project outcome meets these requirements. • The data infrastructure and which data are available in the organisation. • Which data need to be migrated from paper into electronic format. • Identify all stakeholders. • Agree the implementation path and possible schedule.

2. Risk model definition Together with the customer the risk model will be defined, based on the specific customer situation. The results of the data gap analysis will be considered and additional data historical information and operational data, will determine which shall be implemented in the model. The risk model may either be based on available basic risk model or on the customer’s model if it already exists. After the initial meeting with the customer’s subject matter experts (SME) the model will be described in the so-called risk manual which will be reviewed, discussed and approved in a follow-up session before the implementation starts.

3. Data conversion In this phase the output of phases 1 and 2 will be used to establish the exact location(s) where data are stored and how they will be accessed by the software. Data which are available on paper only, will be digitised. Additional required data, identified in phases 1 and 2 will be provided. This phase might be supported by having a data specialist on site.

4. Predicta configuration The software is configured based on the results of the previous phases. This includes but is not limited to the Risk model, agreed upon reports, dashboards and the interface(s) to the customer’s data sources. A meeting or conference call, where the results of phases 1 - 3 are reviewed and explained, will make sure that the scope of work and the functionality is clearly understood by all involved departments. During this phase the training documentation and schedule will be prepared.

5. Testing Test procedures are performed to check the quality of the Predicta configuration. These tests cover the functionality of the software as well as the replication of the customer environment. Test procedures ensure that all customer requirements are covered and meet expectations. The testing

will be performed at a PIPECARE premises with customer participation.

a customer’s premises for a defined time period for direct support.

6. Onsite implementation

Predicta holistic approach

After the test phase is successfully completed and Predicta functionality is confirmed as specified, the software will be implemented in the customer’s IT environment. If required an ‘isolated’ IT system environment may be provided by the customer to perform tests prior to implementation in the ‘hot’ customer IT system. Another series of tests will be performed to check that Predicta is compatible with all requirements of the IT department before the software Is handed over to the customer’s experts.

The Predicta software suite provides a holistic approach to future maintenance guidance services allowing: ) Comprehensive and straightforward guidance for integrity decision-makers. ) A unique tool for considering asset life extension

management which adapts to future changes with its self-learning ability. ) Self-learning ability to adapt to future conditions.

7. Training and handover During the implementation phase customer user training may already start. Predicta product SMEs provide formal training specific to the customer’s implementation and data. Training documents and manuals are provided for future reference. The successful conclusion of the training and handover will be documented in the handover protocol.

8. After implementation support Predicta SMEs will be available to support on customer request with further training, data migration, and configuration changes. After project handover it is recommended to have monthly follow up meetings to discuss any questions which are beyond the daily routine works. On customer request a PIPECARE SME may stay on

) Reducing cost of ownership by optimising pipeline

maintenance and preventing failures.

Conclusion Predicta is an innovative pipeline integrity management software system designed to assist pipeline operators to transit into the digital pipeline era. Easy data access and import from various sources ensures that Predicta is the tool to use to support and improve integrity management decision making. Machine learning and artificial intelligence help Predicta to adapt to operational changes in the future. The advanced new features, future vision and co-operation with oil and gas industry leaders differentiates Predicta from other pipeline maintenance software.

Raymond L. Gatlin, T.D. Williamson, USA, discusses a complex purging operation carried out on one of the longest pipelines in the US.


ometimes, you just have to get it all out of your system. And often, the best way is with a good nitrogen purge. Purging a hydrocarbon pipeline with nitrogen (N2) creates a dry and stable environment that’s safe for inline operations. It’s a standard technique for clearing the line before any number of activities, including preventive maintenance, hydrostatic testing, a change of service or a flow reversal. But designing pigs to traverse a 1018 km (633 mile) single-segment pipeline that cuts through America’s heartland? A job that large is anything but standard. Add in considerations so complex that the feasibility and risk mitigation planning alone took nearly a year, and you’ve got a purge project more challenging than most – one that would require global pipeline solutions provider T.D. Williamson (TDW) to engineer a purging pig like no other.



Piggability assessment mitigates risk When the 40 in. pipeline was built more than 50 years ago, it was the largest northbound crude oil line in the United States, with an initial capacity of 256 000 bpd (today, the total is four times that). The system, which runs between the Gulf Coast and southern Illinois,

Figure 1. Excavated special flow tee with pig bypass.

originally carried Louisiana crude to the Midwest. Later, it began transporting imported oil from the Louisiana Offshore Oil Port (LOOP) north. To prepare the pipeline for preventive maintenance, the owner decided to de-inventory its entire contents. Obviously, removing 5 million barrels of oil from a pipeline is daunting. Every factor from start to finish has to be carefully evaluated; any misstep can jeopardise the project budget and timetable, not to mention the safety of crews and the communities along the right-of-way. That’s why planning and executing this purge project required a strategic partnership between the operator, the project engineering team and TDW, and took more than two years from start to finish. Among the earliest activities was identifying risks and developing mitigation strategies. For TDW, that included a piggability assessment to help them understand conditions and features inside the pipeline, and how the configuration of pump stations, in particular, would affect the ability of the purge pig to navigate the system. What they discovered influenced the blueprint for the purge pig, but it wasn’t the only design consideration. TDW also had to develop a pig that would provide a continuous seal – 0.000% bypass – between the N2 and the crude oil the entire way. If it didn’t, N2 bypass could air lock the system and stop the pig in its tracks.

Pump stations create unique challenge

Figure 2. Typical booster pump station layout.

Figure 3. SmartPlug® isolation tool coupler design.


World Pipelines / MAY 2021

Pump stations are often the most restrictive sections of a pipeline system. They’re also one of the most complicated for a pig to traverse, given all the valves, tees, fittings and other appurtenances inside them that can block or hold up passage. Still, pigs travel through tight and difficult spaces every day. The secret is knowing the dimensions of the tightest point and understanding the kinds of pipeline features that the pig might encounter. Armed with that information, TDW routinely launches the right pig for the pipeline, product and purpose. The problem this time was that the system’s 15 pump stations were similar, but not identical. This meant that the purge pig might be able to get through one station easily, only to become stuck in – or even damaged by – another. Reviewing the pipeline’s original design documentation provided some insight into how the pump stations were configured. To provide a full picture of features and critical dimensions, however, the operator had to excavate around several stations. This revealed that the pump stations had more in common than previously thought. There were only six unique layouts, not 15. To simplify matters even more, only three key features – flow tees, check valves and bypass lines – represented an elevated risk to pigging, although their proximity to one another inside the pump stations was also of concern. Pigging through the pump stations was just one of the obstacles TDW had to overcome. To meet the design

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specifications, the purge pig would have to be high sealing and maintain the seal, without bypass, the entire length of the pipeline. That meant seals and guide discs needed to be durable enough to withstand one of the longest distances a single pig would have to go in TDW history. In addition, the purge pig would have to be continuously tracked and monitored from launcher to receiver. And the entire purge run? It needed to be completed within three months.

Proven technologies frame solution

Figure 4. Proven wheel suspension design modified for purge pig.

Figure 5. Final purge pig design.

Figure 6. 3D model of purge pig in check valve.


World Pipelines / MAY 2021

From the start, it was evident that this project would require TDW to leverage proven technologies and services from across its entire value chain and multiple service centres. For example, engineers determined that to maintain seal and zero bypass through the pump stations, two large-diameter pigs would have to run in tandem. This pig train would require a coupler substantial enough to handle not just its weight but also the significant pulling and driving forces it would experience. The proven coupler design from the SmartPlug® isolation tool seemed like an appropriate solution, but TDW wanted to confirm it was the right choice. Their Engineering Analysis team verified the coupler’s suitability using finite element analysis (FEA). That also allowed engineers to pinpoint where high stress points were concentrating and mitigate those through an additional factor of safety in the design. Engineers also had to reduce the weight on the front drive sections of both pigs and ensure that the pig train remained centred in the pipe ID for the entire run. They achieved both objectives by using a proven wheel suspension design that was borrowed from the TDW 42 in. MFL+DEF inspection tool and modified for the exact weight of the purge pig. In addition, TDW knew that the pigs’ sealing cups and guide discs would have to be made from a special kind of urethane to avoid excessive wear. Fortunately, the company’s pigging product development team had been evaluating and testing a new urethane formulation for several months prior to this project – and one objective of this formulation was to provide outstanding wear resistance and durability during long runs or in abrasive environments. Incorporating this high wear-resistant urethane with TDW RealSeal® high-seal technology provided the right combination to ensure proper sealing during the purge pig train’s critical journey. Finally, engineers designed an adapter on the purge pig to accommodate the installation of tracking technology, enabling round-the-clock monitoring. After multiple design iterations, followed by multiple 3D model simulations of each component as the pig traveled through the various pump station layouts, TDW validated their purge pig design. But before they could launch it, another facet of the project had to be resolved. To ensure throughput during the purge, the pipeline would have to be cleaned first.


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Cleaning clears the way The feasibility study indicated it was possible, probably even likely, that there was residual paraffin and other particulate in the pipeline – nothing unusual, given that it had been in service for more than 50 years. The problem, though, was this: if solids accumulated in front of the purge pig, it would increase the differential pressure required to move the pig, possibly to a point above the system’s maximum operating pressure (MOP) limitations. And if that happened, the pig would stop moving and have to be retrieved through a coupon cut out of the pipeline, an expensive proposition that would

Figure 7. 40 in. VANTAGE® cleaning pig.

Figure 8. DEF+GMFL inline (ILI) inspection tool.

throw the entire project off schedule. Paraffin build-up could also prevent the purge pig from effectively sealing against the pipe wall while creating the possibility of N2 bypass. To mitigate those risks, TDW drew once again from their toolbox, choosing the 40 in. VANTAGE® cleaning pig to run ahead of the purge pig. Because the VANTAGE pig is equipped with blades, it can cut through and clear wax – unlike brushes, which can become packed with paraffin and start riding on top of the debris rather than removing it. Once the pipe was clean and paraffin-free, there was one last challenge to contend with before the purge itself could begin: ensuring it could be done while maintaining service to the operators’ customers. The only solution was to purge the pipeline in two phases. The operator purged the first 645 km (410 mile) section in two months. The remaining 373 km (232 miles) were completed a month later. The phase one schedule allowed for inspection of the purge pig at several locations and refurbishment, if necessary. To look for damage that could obstruct the purge pig and delay the project, TDW launched its DEF+GMFL ILI technology after configuring it to operate in this unique pipeline. Specifically, they utilised a tool that is typically configured for 42 in. pipelines in a 40 in. configuration, with enhancements to ensure it could travel and collect data through the entire long-distance run. During each of the two purge phases, TDW utilised pig trackers 24 hours a day to update the location of the pigs and ILI tool at established markers. Additionally, pig trackers staged at each booster pump station provided notification when the pigs entered and left. Because the pump stations had to be off when the pigs passed through, this allowed the operations centre to know precisely when the pumps could be started up again.

Purge finishes safely and on time Purging this long and complex pipeline required months of planning and preparation between TDW, the operator and the project engineers, but in the end, all that diligence paid off. All of the cleaning, purging and ILI equipment performed as required and was received in extremely good condition, passing post-run examination by a wide margin. As for the new, high wear-resistant urethane formulation TDW pressed into service, it proved more than capable of standing up to demanding requirements. At post-run inspection, the cups showed less than 2% wear. The purge pig also satisfied all criteria, avoiding costly or time-consuming surprises and enabling the project to wrap up on time. In fact, the purge pig was received within 12 hours of scheduled completion.

Note Figure 9. Field launch preparation of ILI tool.


World Pipelines / MAY 2021

A white paper describing this project was presented at PPIM 2021.

Mehdi M. Laichoubi and Sylvain Decombe, SKIPPER NDT, France, discuss the use of magnetic technology to locate and map buried steel pipelines.


uried pipelines are the most secure and efficient mean to transport vital resources for our communities. A precise mapping of such infrastructures is a critical input to Geographic Information Systems (GIS) used to ensure the safety and integrity of these networks. The safety impact of such an information is twofold: prevent any threat due to third party excavations, and monitor any ground movement


Figure 1. UAV with SKIPPER NDT’s embedded technology.

on unstable slopes (landslides) that could affect the pipeline structure. According to the 2019 Common Ground Alliance report1, which promotes effective underground infrastructure damages prevention, incidents are on the rise and reached an all-time high. In 2019 a total of 532 000 excavation-related damages to underground facilities were recorded in the US alone, representing a 4.5% increase compared to the 2018 estimate. The human, environmental and financial costs of these incidents are significant. In the US, over a 10 year period, third-party damage on gas networks caused 363 fatalities, 1392 injuries and US$800 billion in financial losses. Damages to buried pipeline due to third party intervention are a global concern. In Belgium, an excavator’s impact on a buried gas pipeline resulted in an explosion two weeks later, with a high number of casualties, 24 dead and 132 seriously injured. Addressing the challenge of third-party damages to buried infrastructures is a pressing issue for operators and regulators. Some countries have started to enforce stringent legal requirements. In France, a government decree2 mandates operators to map critical pipelines, at a precision of at least 40 cm laterally (X,Y) and vertically (Z). SKIPPER NDT has developed a buried pipeline positioning technology using magnetic mapping. This solution, which combines magnetometry and topography measurements, provides significant competitive advantages compared to existing tools in terms of: ) Data accuracy: proprietary algorithms automatically process the acquired data, minimising human error and measurement bias. ) Continuous measurement: data is acquired continuously

along the right-of-way. It ensures that no area of interest is missed thanks to a high-resolution magnetic view of the pipeline and its underground environment. This is especially useful in the case of pipeline intersections. ) Operator safety and field accessibility: the versatility of

our equipment and detection methods allows UAV-based inspections on previously inaccessible locations while ensuring the field operator safety. Moreover, the technology is contactless and does not require any modification of the pipeline’s operating conditions. The processed results of the network’s location (latitude, longitude, and altitude/depth of cover) are provided in various formats to be compliant with the client’s GIS system. The equipment and methods involved in the SKIPPER NDT georeferencing technology will now be detailed, and its efficiency illustrated through a real case study.

Equipment and methods Data acquisition tools: tailor-made, patented, highprecision equipment Figure 2. Description of the inspection protocol and data analysis process.


World Pipelines / MAY 2021

In terms of hardware, the SKIPPER NDT team has patented a ground-based mobile equipment that can be pulled by

an operator or towed by a vehicle. SKIPPER NDT has also released a UAV-based solution for its magnetic inspections. Both tools embark for the most part the same equipment: ) Five triaxial fluxgate magnetometers. ) GNSS with a centimetric precision. ) Inertial Measurement Unit (IMU). ) Ground distance sensors (Lidar, Infrared and Ultrasonic

sensors). This is UAV specific. ) Proprietary electronic card for data integration.

In order to record the most granular level of magnetic field and avoid any interferences, a tailor-made electronic system was developed in collaboration with prime research centres. It allows the combination of high resolution magnetic measurements (nanotesla-level) with centimetriclevel spatial resolution on a UAV agnostic embedded material.

Figure 3. Resulting magnetic maps of the previous inspected area. The two maps rely on the same dataset but treated with different algorithms.

SKIPPER NDT data processing: proprietary protocols and algorithms To reach optimal levels of magnetic field sensitivity, SKIPPER NDT has developed specific acquisition protocols to increase the native resolution of its magnetometers while compensating for signal interferences. Systematic sensors’ calibration and level control resulted in a tenfold resolution improvement. Regarding its algorithms, SKIPPER NDT has implemented ten methods to obtain precise planimetric and altimetric positions according to various configurations of field acquisitions. The result is a robust measurement protocol under various operational conditions and terrain types. Information gathered through visual inspection on the field and client’s data integration allows us to enrich the deliverables and correlate magnetic phenomena on the network.

Inspection protocol: general principles The inspection’s objective is to perform a magnetic map of the pipeline’s right-of-way between two points (Marker A and Marker B). Using one of our two available tools described before, the operator will map the area where the pipeline is thought to be located (orange dashed line, Figure 2). This will enable the generation of a magnetic map that will include the pipeline location as well as its surroundings. In some cases, a current injection on the pipeline is required during the inspection. It is injected at the cathodic protection cabinet or at the test point. The current does not exceed 10 amps. The suit of proprietary algorithms will then interpret the data. The variety of processing




options will ensure an optimal result regardless of terrain conditions.

Case study: comparison between traditional tools and SKIPPER NDT’s technology In collaboration with Teréga, France’s second largest gas network operator, a field trial under real conditions was conducted. Surveyors contracted by Teréga geolocated two pipelines of 6 in. and 8 in. diameter respectively, in an open ditch. The ditches were then backfilled, and SKIPPER NDT was requested to geolocate the pipelines in a blind test. SKIPPER NDT conducted two tests using two different vectors, ground-based mobile equipment as well as a UAV described in the Material and Methods section.

Inspection parameters The two distinct pipelines were inspected with our protocol and the parameters of each inspection are outlined in Table 1. Figure 4. Magnetic maps of each inspected areas with its corresponding colorbar (in nanotesla) on the left. Estimated XY position of the corresponding pipeline in blue line.

Magnetic maps and pipeline positioning Through data acquired during each inspection using our tools, a high-resolution

Acc u r at e • To u g h • r e l i a b l e THE LEADING BRAND OF HOLIDAY DETECTION EQUIPMENT SINCE 1953


(713) 681-5837

georeferenced magnetic map of the inspected area is generated. The automatic SKIPPER NDT data analysis process allows us to infer the absolute position of each inspected pipeline (Figure 4).

Table 1: Summary of the inspection parameters for each of the two inspections

SKIPPER NDT performances: comparison to the reference line

First Inspection

Second Inspection

Pipe’s Nominal Diameter (DN)

DN 200/8 in.

DN 150/6 in.

Dimensions of the inspected area

387*33 ft

482*33 ft

Duration of the inspection using

13 min.

14 min.

6 min.

7 min.

Results of each of the two detections are the Field Machine compared to the reference position taken by the Duration of the inspection using land surveyor in open ditch. the UAV Figure 5 illustrates SKIPPER NDT’s positioning performances compared to the reference line for each tool on each inspected Field machine 6 in./482 ft pipeline. Acquisition time 14 min. ) Field machine results: 5 in. accuracy for 90%, compared to the reference, for Average precision 2.4 in. both inspections. ) UAV results: 13 in. accuracy for 90%,

compared to the reference, for both inspections. The acquisition time is 6 minutes.

Additional detections: pipeline’s magnetic environment SKIPPER NDT’s does a continuous measurement along the pipeline. As a result, it can precisely map bends and elbows. Furthermore, it can detect metallic objects and structures around the pipeline. Hence, during this pilot test, SKIPPER NDT was able to identify a crossing point with another pipeline which presence was not previously reported (Figure 6).

Drone 6 in./482 ft Acquisition time

6 min.

Average precision

6.1 in.

Standard deviation

1.7 in.

Standard deviation

3.8 in.

90th percentile

4.7 in.

90th percentile

12.9 in.

Field machine 8 in./387 ft

Drone 8 in./387 ft

Acquisition time

13 min.

Acquisition time

5 min.

Average precision

1.5 in.

Average precision

5.2 in.

Standard deviation

0.7 in.

Standard deviation

4 in.

90th percentile

2.5 in.

90th percentile

10.3 in.

Figure 5. Tables of distance discrepancy between SKIPPER NDT’s predicted position of the pipeline and land surveyor’s reference. Each table displays the duration of the acquisition (in minutes), the mean error along the line, the standard deviation, and the error for 90% of the given results (in inches).

Conclusion SKIPPER NDT’s localisation solutions are precise and cost-efficient for protecting pipelines from third party damage and for identifying pipeline movement on unstable slopes. The main features include access to the entire pipeline while ensuring high safety standards, precision of measurements, continuity of detection, and quick response to clients.

References 1.


Common ground alliance, 2019 report, Resource-Redirects/excavation-relateddamages-to-utilities-cost-the-usapproximately-30-billion-in-2019 French Standard: NF S70-003-3

Figure 6. On the left side, high frequency and low frequency magnetic maps showing an anomaly tagged with (1). These anomalies illustrate the presence of a pipeline crossing the inspection area horizontally. On the right side, the position of the anomaly is correlated to the true position of the crossing pipeline.

MAY 2021 / World Pipelines


World Pipelines’ Senior Editor Elizabeth Corner interviews the winners of the John Tiratsoo Award for Young Achievement, awarded by Young Pipeliners International, in partnership with PPIM. Jess Tufts, Superintendant, Gray Oak Elizabeth Corner: Congratulations Jess! What are your thoughts upon winning the award? Jess Tufts: I am flattered to have been nominated by a co-worker for this award, and very grateful to receive the recognition of this industry panel for my achievements. I have a strong work ethic which has led me to succeed thus far in my career. EC: What’s been your career highlight so far? JT: That would have to be my promotion to the current role of Operations Superintendent for the Gray Oak Pipeline back in September of 2020. This is the large crude oil pipeline asset that Phillips 66 operates, and I am responsible for a team of 20 employees. EC: Do you have any mentors or role models in the pipeline industry? JT: Stephanie Wilson at Phillips 66 has been a great role model for me. She is currently the Manager for the Midstream Engineering and Projects organisation, and she was previously the Region Manager over operation of several of the Gulf Coast assets that I’ve worked on. EC: What is your message to other young pipeline professionals? What makes this industry rewarding and attractive for young professionals? JT: This industry offers an abundance of opportunities, and there’s something for everyone. You are in the business of providing



energy, which the world desperately needs. This includes fuel to heat homes and enable vehicle and air transportation. I get satisfaction out of knowing that what I do every day makes a positive impact. EC: Can you talk about your hopes for the future? JT: Professionally, I want to continue to learn and grow to be the best leader that I can be. I enjoy managing and developing people to their full potential. In general, I hope the world goes back to normal soon. EC: What does a typical day look like in your current role? JT: I am responsible for the pipeline operations of the crude oil system that goes from west Texas all the way to the coast at Corpus Christi. So I have a lot of meetings, like everybody, but day-to-day I’m responsible for ensuring that the field operations are maintained adequately. I’ve got a team of 20: there’s a team

that sits in west Texas, and one that sits in south Texas. They do all of the equipment inspections; they’ll go and turn valves, take samples for quality management of the crude oil that ships on the system. I’m based in Houston and I’m probably in the field 25 - 50% of the time. My job has been a little bit challenging with COVID-19 – I haven’t been able to be in the field nearly as much as I would like to be. EC: How did you get into the pipeline field? JT: I am a chemical engineer, with a minor in economics, graduated from Ohio State. My first job out of school was with a manufacturing company, not in the oil industry, and then I was looking for a new opportunity and I had family that lived in Houston and worked in oil and gas, including both of my sisters, so I applied to a variety of roles and the pipeline role was the one that was the right fit for me. I joined the midstream operations team seven years ago and haven’t looked back.

Kaella-Marie Earle, Engineer in Training at Enbridge Gas Inc. Elizabeth Corner: Congratulations Kaella! What are your thoughts upon winning the award? Kaella-Marie Earle: I was surprised and honoured, but my first thought was that I hope the visibility inspires other young Indigenous people to be more involved in the oil and gas pipeline industry. Its such a great place to work, and a place that has so much room for innovation.

Jess Tufts.


World Pipelines / MAY 2021

EC: What’s been your career highlight so far? KE: I would say one of my biggest career highlights was just joining the industry a few years ago. Right before I was an engineering intern at Enbridge Gas (from May 2018 to August 2019) – I was an antipipeline and environmental activist for years. The last thing I expected was to work in oil and gas. I thought the industry was dying, and an unethical place to work because of climate change and other social issues. When I got the job offer, I was actually afraid that I was drinking the proverbial Kool-Aid, but I chose to accept the internship because I saw that the company was working on a number of carbonemission reduction projects like hydrogen blending and renewable natural gas (RNG). During my first few weeks at Enbridge Gas, I expected to be surrounded by people who didn’t care about Indigenous people and didn’t care about the environment. And boy was I proven wrong. I was surrounded by people who poured all of their energy into delivering high quality work – putting the safety of communities and the environment first. I remember making friends with a welder there who used to sit with me over engineering drawings and we would have amazing discussions about Indigenous culture right there in the weld shop. Those first few months at Enbridge changed my world. I realised oil and gas is full of

many great people who share my vision of a future with low carbon emissions, championing communities, and including more people at the decision-making table. I’m truly proud to be working in oil and gas, and working at Enbridge. It’s been an excellent career so far and I’m excited to see what the future brings.

means everyone has something critically important to offer. Its something I always want to carry with me as a future leader in oil and gas. You really have no business being any kind of leader if you’re only accessible to the C-suite, standing on a soap box in a suit and tie. To all the leaders out there: get your coveralls dirty and earn the respect of the frontline.

EC: Do you have any mentors or role models in the pipeline EC: What is your message to other young pipeline professionals? industry? What makes this industry rewarding and attractive for young KE: I have many notable mentors in my life, including Michelle professionals? George, VP of Engineering, Storage and Transmission Operations KE: Right now, we are on the cusp of energy transition. This at Enbridge Gas. She teaches me so much about leadership, requires diversity of thought because so much innovation is on building my technical abilities and how to improve my people the horizon, and the oil and gas pipeline industry knows this. It skills. I’m so grateful to spend time with her, and I really respect and look up to her. I aspire to a similar career path. I am regularly mentored by my people leaders at Enbridge Gas, most notably Paul Hammell (Direct Supervisor) and Dan Wallace (Manager of Engineering Construction). I think the most important thing I’ve learned from the both of them is what kind leadership looks like, and how to really be there for the team. I hear a lot of leaders talk about being there for their teams, but a leader who will get scrappy for you, who will hangout in a muddy trench with you, or who will bring coffee at 9 pm to a job site during unexpected circumstances are the real deal, and thats what Paul and Dan teach me about. Being an engineer in training, both of them are also particularly talented at guiding me through the problem-solving process from the perspective of an engineering professional. Paul and Dan demonstrate an unwavering dedication to not only being there for me, but also contributing to my growth. This is authentic leadership. I also want to mention an important field mentor to me, his name is Derek Johnson. He is a construction superintendent. I really appreciate his mentorship because he has many years of field and construction experience, and everytime we talk I learn a lot from him. People in-field respect and trust him, and his mentorship allows me this opportunity to develop my skills around that. I aspire to be someone who folks on the frontline can trust and rely on. Growing up with a dad that was a union-rep (and still is), electrician and then electrical engineer – Designed with you in mind, the UltraBox features a patented those values have been instilled in me from modular approach to quickly and conveniently provide custom the beginning. FRQ¿JXUHG MXQFWLRQ ER[HV )HDWXULQJ D ',1 UDLO PRXQWLQJ V\VWHP Culturally, Anishinaabeg people ZLWK VQDS LQ PRGXOHV WKH 8OWUD%R[ SURYLGHV \RX WKH DELOLW\ understand leadership as a circle as WR DGG UHPRYH RU UHSRVLWLRQ PRGXOHV HDVLO\ DW DQ\ WLPH opposed to a hierarchy. To me, this


About Young Pipeliners International Young Pipeliners International (YPI) is a forum where young pipeliner groups from all over the world collaborate to share experiences and best practices. Representatives from groups in USA, Canada, Mexico, Brazil, Europe, Australia, India, Nigeria, Malaysia, and China share the common goal of building the next generation of pipeliners. YPI helps newcomers to the industry to gain knowledge, experience, and understanding of different facets of pipelines. YPI is a vehicle to help the next generation prepare themselves for the transfer of duty of care in the pipeline industry. For more information on YPI or to learn how to join or form a regional group, email

Kaella-Marie Earle.

makes working in energy an incredibly dynamic and fast-moving place to be right now. I work with a big group of absolutely amazing young people. There’s so much room to do some good, whether its technological advances, retooling energy infrastructure, carbon emissions reduction, or outreach work involving local communities. Energy policies are changing too, as we learn more about what we need to do to address climate change. Theres so much to do. Trust me when I say you will be surprised at how progressive the industry is. We are moving forward, full speed ahead, into a brighter future – providing safe and reliable energy to people. Its such rewarding work. And its different everyday. Plus its just fun. At my first pigging job I remember an operator yelling “Let ‘er rip, potato chip!” just before the cleaning pig launched. I was grinning as I listened on the receiving end of the gas storage pipeline for the pig to get there. An amazing amount of work goes into taking care of the lines and making sure they are safe and properly maintained, including maintenance of the surrounding environment. Who knew sending a foam bullet through a pipeline to clean it was such a good time? I sure didn’t. You won’t regret a career in pipelines. Take it from me, the former anti-pipeline and climate change/environmental activist. You can work in pipelines and still care about the land, and have a meaningful career where you can enact as much change as you want. It’s been an absolutely astounding couple of years for me at Enbridge. I’m grateful everyday that I work there. EC: Can you talk about your hopes for the future? KE: I read a story once in a book by the Harvard Business Review on Leadership. The story was about the World Bank in


World Pipelines / MAY 2021

the middle of an existential crisis. Circumstances of the world at the time were pushing the organisation into irrelevance, a movement driven by people and what they cared about. The strategy of the World Bank no longer made sense. The bank knew it had to change, and it was just a few people within the organisation who understood inside of themselves that they needed to do something about it. So they did. They initiated this massive cultural renaissance at the organisation, aligning themselves with what society was looking for, recreating a compelling new direction forward. A new direction to re-energise the people working at the bank, and empower them to focus on social issues. These actions launched the World Bank into success once again. My hope, or rather, my plan for the future is to help do exactly this. I’d like to help the oil and gas pipeline industry move into the future through a cultural renaissance. Business continuity is dependent on it. When people are empowered to make the change they want to see, they do. So we must ask ourselves, what tools must leaders provide to inspire people in a new direction for the industry? It can be scary to enter into an era of so much change, because there is risk in doing things a different way – you always need to make space for failure. But this is what it will take to reduce carbon emissions inside of oil and gas. Its not going to be easy, but I fiercely believe in it. I have to. I envision a future where oil and gas workers are re-employed, working in renewables or carbon-emission reduction. The work isn’t disappearing, it’s changing. We need to keep up. I imagine a future where Indigenous inclusion is normalized, and socioeconomic gaps are closed because the industry builds up the communities around them. I imagine a future where people view stewardship-to and their relationship-with the land in a new way. I imagine an industry where the CEO of Enbridge (or TC, or Suncor, or Cenovus, etc) is an Indigenous woman. Is a black woman. Is trans. I dream of an industry that has led energy globally into the next few decades on a new frontier. And I’m prepared to do what it takes to help get us there.

Barry Monk, TAP Operations and Maintenance Country Manager, and Rocio Miguez, Principal Engineer, Energy Systems, DNV, explain how TAP’s robust Assurance Process ensured a seamless transition between project, commissioning and operations.


he Trans Adriatic Pipeline (TAP) is one of Europe’s most strategic energy projects. A part of the Southern Gas Corridor, TAP transports natural gas from the Caspian region to Europe by connecting to the Trans Anatolian Pipeline (TANAP). The 878 km TAP pipeline crosses Greece and Albania, under the Adriatic Sea, and comes ashore in southern Italy. TAP began commercial operations midNovember 2020 and first gas started flowing at the end of December 2020. Senior managers have long considered handover to operations to be a critical process, not only because of capital cost implications, but also due to the number of stakeholders involved in complex projects. The benefits of an effective handover to operations are twofold: reducing the risk of costly remedial actions and improvement of operational safety. The


latter was one of the key driving factors behind TAP’s successful Assurance Process, which complemented the handover. Effective start-up and readiness assurance processes can prevent incidents. One notable example of an accident linked to an ineffective implementation of such processes is the BP Texas City refinery incident which killed 15 and injured more than 170 others.1 TAP Operations Assurance Manager, explains: “We recognised that TAP was a new organisation and as such did not have well-established legacy systems nor an embedded culture of

Figure 1. The seven sections depicting Verification of Readiness (VoR).

Figure 2. SURAP responsibility relationships.


World Pipelines / MAY 2021

operational assurance. There was an opportunity to develop a robust assurance system, reflecting industry best practice techniques, adapted to suit TAP’s specific needs. Ultimately, this became TAP’s Start Up Readiness Assurance Process – SURAP.” Once the strategic decision had been made to implement SURAP, TAP engaged DNV to produce a procedure that combined technology with TAP’s organisational structure and methods to support the transition from project to operations, and enable operations to demonstrate readiness for start-up and early transmission operations. A dedicated operational readiness team was established to work with the project, commissioning and long-term operations teams. According to Ruurd Hoekstra, Operations Readiness Transition Manager, “Early input from the Operations team was recognised as a critical component of the design and construction process. A key aspect of that was to maximise operational experience and insight during the design and execution phase, working with the projects team to ensure pipeline and facilities’ long-term reliability.” DNV was further tasked to support the execution of the process as part of the integrated operational readiness team, and to provide independent consistency of assurance across disciplines and countries during the construction and commissioning phases of the TAP project. The SURAP had to provide an opportunity for a cross functional team to: ) Verify that all technical requirements for each specific asset or facility and interdependent assets and facilities were in place, and supported by the associated technical documentation and certification dossiers. ) Verify that all information regarding operational

readiness, including HSSE and operations

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management system, management permits, system, consents permits, and consents licences, and as well as organisational licences,structures, as well as organisational including trained structures, and competent resources including were trained in place and competent and in a state resources of readiness. were in place and in a state of readiness. ) Verify that the required business processes, e.g.

documentation & data management, logistics, supply chain, materials & spares, contracts & procurement, commercial arrangements, hydrocarbon accounting, were in place prior to the progressive start-up of the integrated gas transmission system (commercial operations).

existing operations and maintenance industry codes. TAP’s code of choice EN 1594 (Pipelines for maximum operating pressure over 16 bar. Functional requirements) referenced EN 12327 (Pressure testing, commissioning and decommissioning procedures. Functional requirements) for commissioning, but the standard did not contain specific assurance requirements, enabling TAP to determine the level of verification required. The checklists were drafted drawing from both TAP and DNV expertise, as detailed in: ) DNV International Safety Rating System ISRS. ) Centre for Chemical Process Safety (CCPS) Guide to Pre-

Start up Safety Reviews. In addition, the SURAP had to: ) Ensure seamless communication and transfer of asset-related information between the stakeholders: contractors, suppliers, and operators. ) Ensure senior managers were provided readily accessible

progress information to support any go/no-go decisionmaking process. The delivery of the SURAP objectives was based on the use a of a bespoke TAP-specific checklist to verify all required parts of the process were completed simultaneously.

Creating the SURAP database The first phase of the SURAP process was devoted to generating the database. The Assurance team looked at the

Ruurd Hoekstra explains that the database goes beyond the level of assurance he has experienced working for other operators, as the TAP organisation and assets are start-ups with no operational history. Cross-checks and reviews of the Verification of Readiness (VoRs) sheets and Pre-Start Safety Reviews (PSSR) contents were subsequently conducted by the SURAP Process Owners and by TAP key personnel and subject matter experts. The SURAP database was divided into seven VoRs, each of them referring to a specific discipline to be checked before introduction of hydrocarbons (IoH) into the system: Each sub-VoR was driven by a nominated focal point, one or more accountable persons responsible for the completion of the SURAP requirements, and assurers with a level of independence, who verified that the evidence provided met the requirements in a timely manner.

Figure 3. SURAP VoR Completion through Introduction of Hydrocarbons (IoH) to Commercial Operations (COD).


World Pipelines / MAY 2021

MetriCorr Implementation of SURAP Pipeline and facilities were divided into distinct commissionable sections. Each commissionable section was assigned assurance items, some universal, some unique to the particular section, e.g. subsea section of the pipeline. Changing the order of commissioning would have been possible in terms of executing SURAP. Recurrent meetings were set to facilitate progress reporting to the SURAP process owners and TAP senior management. The SURAP database was the tool used to track progress towards VoR completion. Focal points were tasked to provide the assurers with the information needed to satisfy the SURAP requirements and storage of evidence to ensure traceability. The assurers verified that the evidence met the database requirements and advised the SURAP team if an item could be closed in the database. The multidiscipline nature of the regular SURAP meetings during the execution phase minimised common errors which often undermine readiness assurance efforts, such as: ) Skipping or forgetting parts of the reviews needed to ensure completeness of the process. ) Omitting safety, commercial, permitting, etc. critical

aspects from the review.

Readiness reviews and go/no-go events TAP implemented Readiness reviews as part of the process involving engineering, procurement and construction (EPC) execution teams, project and operations representatives. The reviews were delivered in workshop format a month ahead of the introduction of hydrocarbons into each commissionable section, and included the generation of an action log to allow tracking of outstanding items to completion. Readiness reviews preceded and supported the go/no-go events. The SURAP VoRs supported the evaluation by the leadership team in their decision making. Readiness reviews and go/no-go events were effective at ensuring appropriate approval steps were taken before proceeding with IoH. “All members of the Leadership Team were invested in the process and encouraged their teams to engage with the SURAP during both the Introduction of Hydrocarbons and the Commercial Operations phases,” said Ricardo Ruiz, Operations Director.

Pre-start-up safety review (PSSR) The SURAP included the development of PSSR checklists to support TAP personnel completing full physical asset verification on site. This was typically conducted 48 hours ahead of the introduction of hydrocarbons in each commissionable section. The PSSR contained the requirements to be checked during the physical inspection. They were divided into themes and included sections to confirm which items were checked with positive and/or negative results. The steps followed during the SURAP documentation completion phase are summarised in the following:

Corrosion & Cathodic Protection Remote Monitoring

Remote Monitoring is the Best and Cheapest AC Mitigation Available How? The purpose of AC mitigation is to prevent AC corrosion of buried pipelines. From a corrosion perspective, it is the AC current density that is the driving parameter. Several studies have shown that this can readily be reduced by careful control of the applied CP. )DU PRUH HႇHFWLYH WKDQ $& grounding installations. The trick is to keep a balance between AC and CP, and to GRFXPHQW WKH HႇHFWLYHQHVV of this strategy. This has never been easier, than with the ICL (interference corrosion logger), Masterlink (RMU), and high sensitivity ER probes from MetriCorr. $QDO\]H &3 HႇHFWLYHQHVV E\ the most intuitive parameter; the corrosion rate! And a lot more.

Measured parameters: • Corrosion rate (μm/y) • Pipeline potential (V) On ,QVWDQW Rႇ FRXSRQ

,QVWDQW Rႇ SLSHOLQH IR-free (calculated) Native (option) • DC current density (A/m2) • AC voltage (VRMS) • AC current density (A/m2) • 6SUHDG UHVLVWDQFH ȍ P

MetriCorr – –

Independent verification body The Assurance Strategy included the provision of an internal verification body (IVB) to confirm that TAP carried out their commissioning responsibilities in line with industry best practice. The scope of the IVB included: ) Review and confirmation that the database VoRs and PSSRs met best industry practice.

session, reflecting on the execution costs and value added by the SURAP deliverables.

Pro content ) The SURAP database was well structured, robust, very

comprehensive and cross-departmental. Very efficient at maintaining focus on essential start-up and readiness deliverables throughout the process.

) On-site independent verification activities of the

following project stages to validate the documentary evidence:

Pro process ) Weekly workshops for each VoR improved the efficiency

of the process and communication between teams. • Commissioning. • Ready for operation.

) Accountable & Assurer belonging to different teams

worked well, resulting in improved quality. GL Industrial Services UK Ltd., part of the DNV group, provided “objective, independent evidence, in line with good industry practice that the parts of the TAP Transportation System necessary to provide transportation services are tested and are ready to be put into commercial service”. The IVB issued a certificate of conformity. For the verification of commissioning and readiness, the IVB prepared a methodology for the verification of readiness to operate (VOCRO) based upon the principles of current verification specifications, including: ) DNVGL-SE-0474, “Risk-based verification”. ) DNVGL-SE-0471, “Verification of onshore pipelines”. ) DNVGL-SE-0475, “Verification and certification of

submarine pipelines”. ) DNVGL-SE-0479, “Verification of process facilities”.

The IVB explained that “The methodology identified the people, process and plant aspects which were relevant to TAP’s organisational and asset readiness. Physical asset aspects covered integrity and functionality for which specific verification elements were identified on a schedule for each commissioning section. Then, for each element, an IVB review of documented evidence was conducted, followed by on-site surveillance where necessary. Close liaison was maintained between TAP and IVB throughout project execution to enable a rapid resolution of any elements of concern before they could cause delay to commissioning dates. Some 1292 elements were addressed by IVB over the course of VOCRO.”

Lessons learnt The implementation of the SURAP lasted just under 18 months. The process started when concrete plans and sufficient detail was available to the team. It concluded at the time commercial operations begun. During this period the SURAP team organised two ‘lessons learnt’ workshops. The first took place in December 2019, six months into the process, and the second in October 2020 after completion of the process. An additional optimisation workshop was completed in December 2019. The following statements were recorded during the final


World Pipelines / MAY 2021

) SURAP enabled focus and ensured all disciplines were

given the same weighting. ) The reporting tool helped to maintain focus on readiness

per discipline. ) The process is fit for purpose and can be adapted for

greenfield and brownfield projects.

Future improvement Under aspects for future improvement, the teams listed the interface with other TAP system, as well as the resources required for maintaining the process, including time and manpower. TAP Operations Assurance Manager added that “The SURAP process sat at the apex of TAP’s assurance pyramid and brought together the different strands of assurance from all areas of the organisation, enabling TAP to demonstrate readiness for start-up and reliable long-term operations.” DNV created and customised the SURAP process with TAP to provide a robust framework and detailed checklists to undertake readiness reviews of commissioning activities and commercial operations. Asle Venas, DNV Senior Principal Pipeline Specialist and Chairman of one of the SURAP Readiness Reviews, commented “I have never seen a readiness process that covers all issues in such a structured way before”.

Conclusion Meaningful assurance processes, such as SURAP, can have a significant impact on successful start-up events and sustainable long-term operations, whether first time start-up, or post facility turnarounds. Strategic, early decision making on operational assurance objectives by organisational leadership, based on organisational maturity, culture, experience and expertise, can ensure that operational start-up assurance programmes provide value to the organisation in the critical areas of safety, cost and schedule.

Reference 1.

“BP America Refinery Explosion”, in CBS Library. bp-america-refinery-explosion/. Last accessed 12 Feb 2021.

Chip Edwards and Tommy Precht, Allan Edwards, USA, discuss the launch of a new composite repair system and where the technology could be headed in the future.


or the better part of the past 30 years, composite repair technologies have been used to repair highpressure pipeline systems around the world. In the early days of their use, these repair systems were primarily used to reinforce corrosion features. However, through extensive research and testing efforts over the last 15 years involving pipeline companies, composite repair technology companies, regulatory agencies, research organisations and subject matter experts, their use has extended to the reinforcement of dents, mechanical damage, vintage girth welds, pipe bends, seam welds and, more recently, leaking defects. Studies involving environmental and operational conditions have also been conducted to address elevated temperature conditions and subsea installations.1 Joint Industry Programmes (JIPs) have been instrumental in achieving widespread adoption of composite repair systems. Organisations such as the Pipeline Research Council International, Inc. (PRCI) have played a central role in evaluating composite repair technologies, including E-glass, carbon and even Kevlar fibre systems.2, 3, 4 With standards such as ASME PCC-2 and ISO 24817, minimum design requirements for the composite repair industry have been established, bringing expected uniformity among at least ten internationally recognised composite repair companies. This article will provide a brief examination of the benefits associated with using composite repair systems. A discussion will follow on the development of a new


composite solution brought to market by Allan Edwards – the OmegaWrapTM repair system, which is available in both E-glass and carbon variants. Finally, a brief dialogue is provided to address current knowledge gaps and areas for future exploration regarding the use of composite reinforcing technologies.

Motivation Having worked within the pipeline repair industry his entire adult life, Chip Edwards, fourth-generation president of Allan Edwards, recognised an opportunity to enter the composite repair technology space. He enlisted the help of Tommy Precht, an industry veteran with 25 years of experience in pipeline repair applications. This led to the birth of the OmegaWrap

composite repair system. Chip and Tommy’s long and unique history with pipeline companies provided them with a strong understanding of the critical role that customer service plays in offering a complete repair package. With the help of ADV Integrity, Inc. (ADV) and its president, Dr. Chris Alexander, PE, development was planned and executed for both an E-glass-epoxy and carbon-epoxy version of the OmegaWrap composite repair system. The following six months involved a rigorous schedule of selecting, testing and evaluating different combinations of fabrics and resins before settling on the optimised configuration that is now available. Full-scale testing at the ADV test lab was conducted to validate the OmegaWrap composite repair technology. Though steel repair sleeves are the ‘tried and true’ method for repairing pipelines, composite repair technologies offer several unique advantages. First, composite materials that are installed ‘wet’ can be used to reinforce a variety of pipe geometries and configurations, including wrinkle bends, elbows and branch connections.6, 7 The capability of conforming to pipe ovalities also cannot be discounted. Secondly, the flexibility to select different fibre types, fibre orientations and resins produces a wide range of technologies that can be used to reinforce everything from corrosion, which primarily requires ‘hoop’ (circumferential) reinforcement, to wrinkle bends and girth welds that require axial reinforcement. Lastly, with continued advances in fibre types and resins, there are numerous opportunities for expanded growth in the composite repair space. These advantages, coupled with the ability to expand repair options beyond conventional steel sleeves, made the development of the OmegaWrap composite repair system both an attractive and necessary investment.

Development of a composite repair system As mentioned previously, the ASME PCC-2 and ISO 24817 standards have contributed significantly to the introduction of new and innovative composite repair technologies. Prior to the introduction of these standards, there were only a few companies offering composite repair technologies. Since the acceptance and utilisation of these new repair standards, however, the ‘barrier to entry’ has been lowered, allowing new companies and technologies to be introduced to the marketplace. Figure 1. Tensile testing of a coupon extracted from a composite panel. The OmegaWrap composite repair system was developed using a very strategic approach. This involved not only identifying and testing different material combinations, but also designing and conducting a testing programme to better understand the performance capabilities of the OmegaWrap system. The most fundamental test in designing and qualifying a composite repair system involves fabricating panels and conducting tensile testing to determine the tensile strength, strain-to-failure and elastic modulus. Shown in Figure 1 is a photograph of a panel where the tensile coupons were extracted via water jetting, as well as a photograph showing one of the tensile samples being Figure 2. Photographs showing installation of the OmegaWrap EG system. loaded in a tensile testing machine.


World Pipelines / MAY 2021

Depicted in Figure 2 is a series of photographs detailing the installation of the OmegaWrap EG (E-glass) system. Noted in these photographs is a pipe surface contour tool, printed with ADV’s 3D printer, that was used to ensure that an optimised contour of the load transfer material was achieved (as observed in the middle photo). In addition to meeting the minimum requirements specified in ASME PCC-2, the OmegaWrap EG and C (carbon) system variants were subjected to testing to evaluate their performance in reinforcing dents, severe corrosion and cracks subjected to extreme cyclic pressure conditions. Burst testing was also conducted on test samples reinforced with the OmegaWrap carbon-epoxy technology, containing 15% and 50% EDM notch features that were pre-cycled to ensure cracking was present. The following bullets provide details of testing conducted on the 50% deep crack sample that was estimated to fail at 1039 psig using the PRCI MAT-8 fracture mechanics software. The sample failed at 1942 psig (157% SMYS) and failed outside the repair, as shown in Figure 3. ) 12.75 in. x 0.188 in., Grade X42 pipe. ) Crack dimensions: 3 in. long by 50% deep (0.094 in.). ) Fracture toughness of pipe: Kmat = 231 ksi √in. ) Carbon epoxy system with a thickness of 0.33 in. (7 layers).

Figure 3. Post-test photo showing reinforcement of 50% crack feature.

The OmegaWrap EG System: where are we now? The new OmegaWrap E-glass system has officially launched as of April 2021. Thanks to the relentless dedication of Allan Edwards and ADV Integrity, the OmegaWrap EG composite repair system is one of the strongest e-glass offerings available on the

Figure 4. Wrapping the pipe with the OmegaWrap EG (E-glass) composite repair system.

to expand in the coming years. With the innovative approach employed by oil and gas service companies, the composite repair industry will continue to advance existing repair systems and develop new technologies that meet challenging repair scenarios posed by pipeline operators. To ensure that tomorrow’s technologies are designed to meet these challenges, it is important to identify today’s knowledge gaps. One area that will require continued development concerns the inspection of composite repair technologies. The role of inspection not only involves the technologies but requires that an assessment criterion be constructed against which feature measurements may be consistently measured. The ability to identify features such as interlaminar delamination and pipe-to-composite disbondment are only meaningful when they are compared to values identified as either ‘acceptable’ or ‘unacceptable’. Another area that requires continued development involves validation associated with pipeline operation, namely elevated temperature conditions and aggressive pressure cycling. Fortunately, previous testing programmes have demonstrated that certain composite repair technologies exist that can meet these demands. However, additional work is required to achieve widespread acceptance and adoption. The future use of composite repair technologies is promising, and their numerous uses will undoubtedly continue to expand dramatically. The key to ensuring long-term progress involves the forward-thinking mindset of companies and their willingness to invest time, capital and resources into developing new and improved technologies, coupled with validation through numerical modeling and full-scale testing. The ultimate goal is to ensure that the performance capabilities of a composite repair technology meet and exceed the rigorous demands of pipeline integrity programmes around the world – continually refining today’s technology to meet tomorrow’s needs.

References 1.

Figure 5. Saturating the E-glass fabric with the epoxy resin component prior to wrapping the repair zone.



market. With a tensile strength of 91 000 psi and a strain-tofailure exceeding 2%, it is ideally suited for applications including the reinforcement of corrosion, dents, wrinkle bends and girth welds subject to geohazard bending loads. The OmegaWrap C (carbon) system is currently in its final stages of testing. As a stiffer fabric, the OmegaWrap C system will be an optimal choice for enhanced performance under dynamic loads. Comprehensive local and on-site trainings will be offered by Allan Edwards for both the OmegaWrap EG & C systems.

The future of composite reinforcing technologies Because of the extensive assessment and world-wide use of composite materials, there is no doubt their use will continue


World Pipelines / MAY 2021





ALEXANDER, C., SHEETS, C., HARRELL, P., RETTEW, R., BARANOV, D., “Experimental Study of Elevated Temperature Composite Repair Materials to Guide Integrity Decisions”, Proceedings of IPC 2016 (Paper No. IPC201664211), 11th International Pipeline Conference, 26 - 30 September, 2016, Calgary, Alberta, Canada. ALEXANDER, C., and KANIA, R., “State-of-the-Art Assessment of Today’s Composite Repair Technologies”, Proceedings of IPC 2018 (Paper No. IPC201878016), 12th International Pipeline Conference, 24 - 28 September, 2018, Calgary, Alberta, Canada. ALEXANDER, C., RIZK, T., WANG, H., CLAYTON, R., SCRIVNER, R., “Reinforcement of Planar Defects in Low-Frequency ERW Long Seams Using Composite Reinforcing Materials”, Proceedings of IPC 2016 (Paper No. IPC201664082), 11th International Pipeline Conference, 26 - 30 September, 2016 Calgary, Alberta, Canada. ALEXANDER, C., “Advanced Techniques for Establishing Long-Term Performance of Composite Repair Systems”, Proceedings of IPC 2014 (Paper No. IPC2014-33405), 10th International Pipeline Conference, 29 September - 3 October, 2014, Calgary, Alberta, Canada. ALEXANDER, C., PRECHT, T., and EDWARDS, C., “Steel Sleeves: A New Look at a Widely-Used Repair Method”, Pipeline Pigging & Integrity Management Conference, Houston, Texas, 18 - 22 February, 2019. ALEXANDER, C., and KULKARNI, S., “Evaluating the Effects of Wrinkle Bends on Pipeline Integrity,” Proceedings of IPC2008 (Paper No. IPC2008-64039), 7th International Pipeline Conference, 29 September - 3 October, 2008, Calgary, Alberta, Canada. ALEXANDER, C., VYVIAL, B., IYER, A., KANIA, R., ZHOU, J., “Reinforcing Large Diameter Elbows Using Composite Materials Subjected to Extreme Bending and Internal Pressure Loading”, Proceedings of IPC 2016 (Paper No. IPC201664311), 11th International Pipeline Conference, 26 - 30 September, 2016, Calgary, Alberta, Canada.

PIPELINE MACHINERY review World Pipelines’ quarterly pipeline machinery focus.

Allu, Finland


he ALLU Transformer TS Drum Assembly is an effective tool for pipeline padding and backfilling applications. By allowing material to be screened onsite and then backfilled directly into a trench, it eliminates the need for dedicated stationary screening or purchase of fine soil, saving time and money. ALLU D-Series attachments work with wheel loaders, excavators, skid steers or back hoes to screen, crush, pulverise, aerate, blend, mix, separate, feed and load ALLU Transformer working on pipelaying. materials all in one stage – increasing the profitability and efficiency of pipeline construction operations. The core of the ALLU TS Drum Assembly technology A case study with one pipeline contractor recently is the configuration of the screening blades that spin realised 80% savings per cubic yard using an ALLU between the screening combs. The end product size is D-Series attachment with TS drum assembly – the ALLU defined by the space between the combs, and different DH 3-12 TS16 – on a standard excavator. In looking at fragment sizes can be achieved simply by repositioning several options, this contractor realised that traditional the combs. Because the screening combs carry most of screening had a low productivity rate and large particle the material weight, the drums and bearings experience soil and stones could easily fall into the trench, whilst less impact and load. The design of the assembly purchasing fine soil is also a high cost. ensures the machine works well in wet and dry materials The pipeline contractor opted for crushing and without any clogging. screening with ALLU DH3-12 TS16, which demonstrated


Allu, Finland

a lower cost than the other options and an 80% saving per cubic yard. Also giving them total flexibility as its available with two different blade types: standard blades for screening applications and axe blades when a crushing or shredding effect is required. The TS assembly is available in seven different models for 17.6 - 49.6 t (16 - 45 metric t) excavators and 7.7 - 33 t (7 - 30 metric t) wheel loaders. ALLU designs, manufactures and sells products for adding value to customers in numerous ALLU Transformer recycling onsite work material to backfill pipeline. applications for processing, separating, sorting, mixing and crushing materials. Typical applications include e.g. soil and waste material recycling, operations of the customers. The history of ALLU goes back for processing contaminated soil, transforming waste to usable over 30 years and today over 95% of the business is done with material. international customers globally. Driven by customer needs, the company has innovated the The serving network of ALLU consists today of own methods and equipment for transforming the processes and subsidiaries and a dealer network in more than 30 countries.

Trencor, USA


ith difficult ground conditions, changing climates, and varying crew experience, no two jobsites are the same. This is especially true for pipeline projects that are built to transport crucial daily resources like water, gas and oil. It is important that every stage of the project is done safely and efficiently. This means even before the pipe is in the ground crews must dig a clean trench to set the stage for the rest of the project. To accomplish this, every pipeline installation jobsite needs a trencher


Trencor T16 Trencher.

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Allan Edwards AMPP BAUMA CDI CRC-Evans

OFC, OBC 31 2 51 4



Dairyland Electrical Industries




Electrochemical Devices, Inc.


Energy Global


Girard Industries






LNG Industry




Pigs Unlimited International LLC




Pipeline Inspection Company


Qapqa B.V.


Ritchie Bros. ROSEN Group SCAIP S.p.A. Winn & Coales International Ltd World Pipelines

9 IFC Bound insert 7 45, 55

that is reliable regardless of the many other changing factors. That is why Trencor’s large-scale trenchers have been used on jobsites around the world since 1945. Their rock-solid structure is built to withstand the ever-changing conditions in the field to get the job done. The Trencor T16 was built to rock the trencher world. The rugged and proven machine can combat the challenges of today’s large diameter pipeline installation projects and tough ground conditions. Designed with ideal weight, power and size, the T16 maximises productivity for a wide range of trenching applications, including water, sewer, oil and gas. With no two jobsites created the same, the T16 can help tackle hard rock and changing ground conditions with ease. “At Trencor we are proud that the T16 is utilised around the world to install pipelines that transport the resources we depend on daily,” said Steve Seabolt, Trencor product manager. “To help pipeline construction contractors complete these important projects efficiently, we build our equipment with the operators in mind. The features and technology on the T16 enable heavy equipment professionals to prioritise safety and optimise operations on any water, gas or oil jobsite.” The T16 is equipped with telematics for remote monitoring and support, allowing operators to more easily manage their fleet and provide timely maintenance. The mechanical drive feature reduces tooth wear to prolong the chain life and minimise downtime needed to replace the chain. It is also equipped with a crumb shoe to ensure a clean trench for easy installation of water, gas, and oil products. Each of these features allows for optimal operator efficiency by increasing productivity and minimising downtime. The specifications of these large track trenchers provide unmatched performance. The T16 is powered by a CAT C27 950 hp engine and 3206 lb-ft of torque, giving operators the power to withstand the toughest soil and hard rock conditions. It is equipped with a mechanical digging chain drive and digging chain choices with widths up to 60 in. (1.52 m), which provides a variety of options for every jobsite. Whether a T16 trencher is being used for a water installation project in Indonesia or a natural gas project in Ohio, it is inevitable that the equipment operators will need access to quick and reliable service. This is why Trencor, sold and serviced through one of the more than 175 Ditch Witch dealerships worldwide, can provide world-class parts, service and support to all underground construction professionals at each and every stage of the machine’s lifecycle.

Pipeline Buoyancy Control & Support // Integrity & Repair

Patent Pending

EST. 1947