World Pipelines - January 2021

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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 1 | JANUARY 2021 03. Editor's comment The road ahead for the USA

CORROSION 35. AC corrosion: looking in the right direction

05. Pipeline news

Christophe Baeté, Belgium, and Gerald Haynes, USA, Elsyca.

CER recommends approval of NGTL’s Edson Mainline Expansion project; inservice announcements from Williams and Kinder Morgan; and contract news from Jan de Nul.

39. Danger, danger... high voltage Ian Loudon, Omniflex, South Africa.

41. Reinventing the familiarF

REGIONAL REPORT 12. Looking beyond the global pandemic

Andre Macedo and Mauricio Brandao, Baker Hughes, Brazil.

Gordon Cope discusses the implications of the COVID-19 pandemic for various areas of the US oil and gas industry, and what the future may hold.

FLOW CONTROL TECHNOLOGY 46. Changing times for control valves Jonathan Walker, Severn Glocon Group, UK.

Gordon Cope discusses the implications of the COVID-19 pandemic for various areas of the US oil and gas industry, and what the future may hold.

A

s is the case in most jurisdictions worldwide, the US oil and gas sector has been hit hard by the COVID-19 pandemic and resulting demand destruction. In addition, opposition to pipelines has heavily impacted the midstream sector. While 2020 was a grim year, 2021 holds out hope for better days ahead.

The emergence of the COVID-19 pandemic in March 2020 had an immediate negative impact in the US.

S

afe, reliable and repeatable flow control is the cornerstone of oil and gas productivity, and valves play a crucial role in this. Yet many factors can hinder the performance of control valves in established plant pipelines. This is especially true when it comes to severe service applications such as those with high pressure drops, extreme temperatures or flashing (where vaporisation causes flow problems).

Traditionally, severe control valves are accountable for more than 80% of valve-related unplanned shutdowns. However, this is set to change. The convergence of mechanical and digital engineering makes it quicker and easier to identify, diagnose and rectify underlying technical issues that can harm overall production and profitability.

Problem valve scenarios

Jonathan Walker, Severn Glocon Group, UK, discusses how the convergence of mechanical and digital engineering has optimised the detection of flow control issues.

PAGE 12

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So, what are the circumstances that can lead to compromised valve performance? Let’s take a look at some common situations.

Most of the time, problems are caused by the external production environment or the internal flow medium. For instance, extreme temperatures, humidity or salinity in the external environment can be detrimental to valves. Likewise, contaminants such as sand or black powder in the process medium can ravage internal components.

Sometimes problems occur because production parameters have changed over time. As oil and gas wells are depleted, the velocity and pressure of flow can be affected. The same is true when production is ramped up. If this is not accounted for in the specification of valves affected by the changes, their internal components can experience degradation.

Similarly, changes to pipework or assets up or downstream can have repercussions for flow velocity and pressure, which alters the physical demands placed on a control valve.

It may be that the original valve selection and specification is out of kilter with the application’s needs. When valves deployed in extreme conditions exhibit problems it’s often because a standard catalogue product is being pushed beyond its limits. In other words, a mass-produced product offering ‘next best fit’ has been used instead of a custom engineered solution. But those upfront cost-savings can quickly turn out to be false economy.

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PAGE KEYNOTE 17. A critical mission

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Koheila Molazemi, Technology and Innovation Director with DNV GL – Oil & Gas.

OFFSHORE WELDING 51. An automatic shift

COVER STORY 21. Two is better than one

Soroush Karimzadeh, Chief Executive Officer and Co-Founder of Novarc Technologies, Canada.

Syed T Hashmi and Awadh O. Oadah, Pipeline Projects Department, Saudi Aramco.

PIGGING 25. A multi-level assessment: Part Two Aiman Ali, Petroleum Development Oman, and Andy Russell, Chris Owens, Ian Fisher and Angus Patterson, ROSEN, UK.

Pipeline Machinery Review 55. Featuring Rex-Cut Abrasives.

PIGGING

&

31. Featuring NDT Global and In-Line Pigging Solutions.

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Volume 21 Number 1 - January 2021

ON THIS MONTH'S COVER

Reader enquiries [www.worldpipelines.com]

ISSN 1472-7390

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BISEP® Member of ABC Audit Bureau of Circulations Copyright© Palladian Publications Ltd 2021. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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COMMENT THE ROAD AHEAD FOR THE USA

SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com

MANAGING EDITOR James Little james.little@palladianpublications.com

ASSISTANT EDITOR Aimee Knight aimee.knight@palladianpublications.com

EDITORIAL ASSISTANT Sarah Smith sarah.smith@palladianpublications.com

SALES DIRECTOR Rod Hardy rod.hardy@palladianpublications.com

SALES MANAGER Chris Lethbridge chris.lethbridge@palladianpublications.com

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ADMIN MANAGER Laura White laura.white@palladianpublications.com

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Applicable only to USA & Canada: World Pipelines (ISSN No: 1472-7390, USPS No: 020-988) is published monthly by Palladian Publications Ltd, GBR and distributed in the USA by Asendia USA, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid New Brunswick, NJ and additional mailing offices.

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I

n the second half of last year I commissioned a regional report focusing on pipelines in the US and the piece appears in this issue, starting on p.12 (‘Looking beyond the global pandemic’).

When our longstanding freelance writer Gordon Cope submitted the article at the beginning of November, he included analysis based on two scenarios: one entitled ‘Trump wins’, another called ‘Biden wins’. The Biden section appears in print in this issue, but I thought our readers might be interested in reading the alternate ending.

“Trump wins.

Throughout the first term of his administration, President Trump championed the oil and gas sector, opening up federal and Arctic lands to exploration and development, and reversing Obama administration decisions such as the cancellation of the Keystone XL crude pipeline. He also authorised rollbacks in regulatory red tape and the states’ ability to use jurisdictional powers (such as the CWA) to delay or veto interstate pipeline projects.

On the eve of the election, President Trump signed the ‘Memorandum on Protecting Jobs, Economic Opportunities, and National Security for All Americans,’ mandating the Secretary of Energy to prepare a report on “the economic impacts of prohibiting, or sharply restricting, the use of hydraulic fracturing and other technologies.” The move was seen as an attempt to highlight the potential negative impacts of Democratic candidate Biden’s policies of banning fracking on federal lands.

Trump’s re-election will reinforce White House efforts to relieve the oil and gas sector of many of the expenses related to climate change responsibilities.”

Let’s unpack that in light of the election result. There will be no such championing from Biden. In general, his administration’s policies will work towards curtailing the environmental impacts of burning fossil fuels and many predict that he plans to do this by limiting domestic oil and gas production, while raising costs. Permits may be harder to come by and subsidies and tax breaks are certainly under threat.

Biden has previously pledged to cancel a key permit for the Keystone XL pipeline, but many on all sides of the political spectrum support the project and Biden has a reputation as a deal-maker.

Biden will no doubt reduce incentives for the fracking industry, but a flat-out ban is unlikely and fracking activity will migrate to private and state-owned land. As the Council on Foreign Relations puts it: “Since natural gas is up to 40% more carbon efficient than oil or coal, Biden argues that fracking is still a step forward until renewables are more widely adopted.

As Vice President and as a Presidential candidate, he supported the Obama administration’s ‘all of the above’ energy strategy, which helped spur the fracking boom.”1 A crackdown on the emissions-heavy coal industry may boost the gas sector, as Biden looks to move away from coal for electricity generation.

Finally, Biden will not be blind to the contribution that the fossil fuel industry makes to the US economy, not to mention the importance of national energy security.

Oil and gas companies have been tackling the issue of carbon dioxide emissions for years, and the big ones will hope to work with the new administration on creating realistic and responsible climate policies for the future.

BIDEN HAS PREVIOUSLY PLEDGED TO CANCEL A KEY PERMIT FOR KXL

1.

https://www.cfr.org/in-brief/whats-next-frackingunder-biden

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WORLD NEWS CER recommends approval of NGTL’s Edson Mainline Expansion project

Williams announces early in-service capacity for critical natural gas infrastructure projects

The commission of the Canada Energy Regulator (CER) recommends that the federal Cabinet approves NOVA Gas Transmission Ltd.’s (NGTL) Edson Mainline Expansion project. The project involves the construction and operation of approximately 85 km of natural gas pipeline loops in two sections, along with the associated facilities. The project is needed to increase pipeline capacity and move gas from the Peace River project area to growing markets in central and southern Alberta.

Commissioners heard from more than a dozen intervenors, including industry, federal and provincial government departments and Indigenous peoples, and found that the project is in the Canadian public interest. As part of its recommendation, the commission included conditions related to, among other things, matters with respect to Indigenous peoples, construction activities, safety measures and standards, and environmental monitoring.

The commission is of the view that, within this project area, any potential project impacts on the rights and interests of affected Indigenous peoples are not likely to be significant with the implementation of the mitigation measures and commitments made by NGTL, as well as the conditions and accommodations recommended and imposed by the commission.

Approximately 73 km (86%) of the pipeline route will parallel the existing NGTL right of way and other existing and proposed disturbances. The commission noted that NGTL considered input from landowners, occupants, land users, Indigenous peoples and environmental studies in deciding the proposed route.

If federal Cabinet approves this project, the CER will monitor and enforce compliance with all conditions using audits, inspections and other compliance and enforcement tools.

Williams has announced that it achieved early in-service capacity and, as a result, earlier-than-expected cash flow in 4Q20, for key energy infrastructure expansions designed to serve growing demand for clean energy in the US. “Now more than ever, the essential natural gas infrastructure projects Williams delivers are critical to the United States’ clean energy future, and we take pride in living up to our long-rooted reputation of doing a good job on time,” said Alan Armstrong, Williams President and Chief Executive Officer. “Thanks to the collaborative efforts our team is taking with landowners, environmental groups, the regulatory community and other stakeholders, we are completing the projects that fuel our daily lives in a timely, safe, cost-conscious and environmentally responsible manner. On top of it all this year, our employees followed strict health safety protocols and adhered to local guidance and mandates in order to complete these critical projects amid the risks of the COVID-19 pandemic.”

The following projects attained early in-service capacity in Q4: ) Transco’s Leidy South, an expansion of Williams’ existing Pennsylvania energy infrastructure, brought 125 million ft3/d of capacity on line in November with the remaining 457 million ft3/d expected to be complete in 2021. The expansion connects robust Appalachia natural gas supplies with growing demand centres along the Atlantic Seaboard and has received key state and federal permits, including a partial FERC Notice to Proceed. ) Southeastern Trail, a Transco transmission expansion project to

serve growing demand in the Mid-Atlantic and Southeastern US, commenced partial in-service of 150 million ft3/d in November and an additional 80 million ft3/d in December. The balance of the 296 million ft3/d project is expected to come on line in 1Q21. ) Bluestem Pipeline, a 120 million bpd natural gas liquids (NGL)

transportation pipeline that provides improved market access and liquidity for mixed NGLs, was completed under budget and began service in December, two months ahead of schedule.

Kinder Morgan announces commercial in-service of Permian Highway Pipeline Kinder Morgan, Inc. has announced that the Permian Highway Pipeline (PHP) began full commercial in-service on 1 January 2021.

The pipeline has been flowing volumes during the commissioning process for several weeks prior to full commercial in-service.

PHP delivers natural gas from the Waha to Katy, Texas area, with connections to the US Gulf Coast and Mexico markets.

Fully subscribed under long-term contracts, PHP provides approximately 2.1 billion ft3/d of incremental natural gas capacity, helping to reduce Permian Basin natural gas flaring.

“We are extremely pleased to have placed PHP in service.

We are very proud of our team’s ability to execute and that we were able to complete this critical infrastructure project in the

midst of a global pandemic.

“PHP will continue to provide environmental benefits and economic value to the State of Texas for many years to come,” said Kinder Morgan Natural Gas Midstream President Sital Mody.

“We believe that the Permian Basin will remain an important supply basin for decades, and our strong network of pipelines provides the ability to connect this supply to critical markets along the Gulf Coast.”

Kinder Morgan Texas Pipeline (a subsidiary of KMI), EagleClaw Midstream and Altus Midstream each hold an ownership interest of approximately 26.7%, and an affiliate of an anchor shipper has a 20% interest. Kinder Morgan Texas Pipeline is the operator of the pipeline.

JANUARY 2021 / World Pipelines

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WORLD NEWS IN BRIEF USA The US Energy Information Administration has released the US Energy Atlas, a new interface for web map applications and a comprehensive open data catalogue. It shows detailed energy infrastructure in redesigned maps with enhanced navigation and data accessibility features.

GERMANY Flowrox, a Finland-based company specialising in flow control, process automation, environmental and solid-liquid separation technologies, has strengthened its operations in Central Europe by opening a new subsidiary, Flowrox GmbH in Ratingen, Düsseldorf, Germany.

BRAZIL EIG Global Energy Partners has announced it has signed a definitive agreement with Fluxys for the sale of EIG’s approximately 27.5% stake in Transportadora Brasileira Gasoduto Bolívia-Brasil (TBG). TBG owns and operates the Brazilian section of the BolíviaBrazil pipeline, an approximately 2600 km (1600 mile) natural gas pipeline system, including the main natural gas transportation network in the south of Brazil.

Association for Materials Protection and Performance (AMPP) launched A new organisation, the Association for Materials Protection and Performance (AMPP), has been formed by a merger between Houston-based NACE International, The Corrosion Society; and Pittsburgh-based SSPC: The Society for Protective Coatings. AMPP’s name, logo, and other brand elements were revealed at an event on 6 January led by AMPP CEO, Bob Chalker and the organisation’s executive leadership.

“AMPP brings together the world’s leading corrosion prevention and protective coatings organisations under one umbrella,” said Chalker. “With a vision to create a safer, protected and sustainable world, the new association will focus on the future of materials protection and performance.”

With more than 40 000 members in 130 countries, AMPP consists of two governance structures— AMPP, a 501(c)(6), and AMPP Global Centre, a 501(c)(3). AMPP provides services to members in the areas of certification, accreditation, membership, advocacy and public affairs, and AMPP Global Centre focuses on standards, technical and research activities, conferences, events, education, training, publications and pre-professional programming.

“No other organisation offers the depth and breadth of materials protection and performance information, standards, education, certification, and contractor accreditation programming that AMPP

now provides,” said Tim Bieri, Chair of the AMPP Board of Directors and Vice President for Materials & Corrosion Engineering, bp America, Houston.

“Through AMPP, we will be able to raise the level of excellence of our professional community and have a greater impact on society through our expanded network of members worldwide.”

“I’m looking forward to bringing together the expertise that’s been instrumental in developing standards, training, publications, and other technical resources that support our members and advance our industry,” said Joyce Wright, AMPP Global Centre’s Chair; and Trade Manager for Strategy and Innovation, Huntington Ingalls Industries – Newport News Shipbuilding, Hampton, Virginia. “With one voice contractors, owners, craftsmen, manufacturers, corrosion experts, consultants, and industry stakeholders, will do more to protect society across the globe.”

For the near future, NACE and SSPC accreditations and certifications will remain as they are currently. “For years AMPP’s new combined membership has been aligned in one very important way, our members are dedicated to protecting infrastructure and assets from corrosion and deterioration. Guided by this common purpose we will be a stronger, more powerful voice for our industry by working together,” said Chalker.

CANADA Delays in the expansion of export pipeline capacity have contributed to wider differentials and lower prices for crude in western Canada than otherwise would have been expected, a new analysis by the IHS Markit Canadian Oil Sands Dialogue finds. IHS Markit estimates that, without pipeline export capacity constraints, western Canadian heavy crude oil would have obtained at least US$3/bbl more, on average, compared with WTI, Cushing, 2015 - 2019.

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World Pipelines / JANUARY 2021

Boskalis acquires Rever Offshore Boskalis has announced the acquisition of all the shares of Rever Offshore’s subsea services business. Rever, formally known as Bibby Offshore, offers a broad range of solutions in the area of subsea construction, inspection, repair and maintenance.

Rever has historically operated in the North Sea out of Aberdeen (UK) and holds a strong track record. Through this transaction, Boskalis will obtain two diving support vessels of which one is fully owned (Rever Polaris) and a second chartered (Rever Topaz).

The group employs an onshore staff of around 130 in addition to approximately 220 offshore workers. The 2020 annual revenue

is approximately €90 million, most of which is generated through numerous framework agreements. Based on projected cost synergies, the acquisition payback period is expected to be less than three years.

Through this acquisition, Boskalis strengthens its current position in the subsea services market in Northwest Europe, Africa and the Middle East and its capabilities to serve both the traditional oil and gas market and the rapidly expanding offshore wind market.

On the important North Sea subsea market, Boskalis is now a solid top three player opening up ample opportunities for operational efficiencies and synergies.

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WORLD NEWS EVENTS DIARY NOW ONLINE:

26 - 28 January 2021 European Gas Virtual (EGV) 2021 https://energycouncil.com/event-events/ european-gas-conference/

NOW ONLINE:

19 - 30 April 2021 CORROSION 2021 https://www.nacecorrosion.org/

RESCHEDULED:

25 - 27 May 2021 Subsea Expo Aberdeen, Scotland https://www.subseaexpo.com/

8 - 10 June 2021 Global Energy Show 2021 Alberta, Canada

SBS Energy Services sets new world record in GOM decommissioning project SBS Energy Services (SBS), a leader in snubbing, hydraulic workover, and coiled tubing applications, has successfully completed a multi-phase project to decommission approximately 29 000 ft of 10 in. by 6 in. insulated pipeline in the Gulf of Mexico in partnership with Helix Energy Solutions, setting a new offshore snubbing unit/hydraulic workover world record.

The project, which was completed successfully in 22 days, ahead of schedule, consisted of retrieving and removing a Pipeline End Termination (PLET) to surface of a DP3 drilling intervention vessel.

The second objective was to use a 340K snubbing unit to rig up and intervene inside the pipeline with an optimised drill pipe string to perform washing/flushing operations until reaching the second PLET. A cap was then installed on the first end of the pipeline and placed back in the original trench on the seafloor with the deployment rigging and drill string for permanent

abandonment in-situ. The final task was to record the final pipeline position on the seafloor.

A highlight of the operation was cleaning out the flowline rather than cutting it into sections, which has been performed previously on long flowlines such as this one. This approach significantly reduced the number of critical subsea lifts and overall timeline for the cleanout and lay down.

Performing the full cleanout in a single lift also required minimal onshore disposal of flowline components.

This deepwater pipeline cleanout utilised the Helix Q4000, an intervention and construction vessel, working in 3287 ft of water. “To our knowledge, this has never been done before, especially considering the total cleanout depth of almost 29 000 ft with over 25 000 ft of that being lateral length on the ocean floor,” said Bobby Bray, President of SBS.

https://www.globalenergyshow.com/

Noble Midstream completes integration and development plans RESCHEDULED:

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

RESCHEDULED:

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

RESCHEDULED:

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

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World Pipelines / JANUARY 2021

Noble Midstream Partners LP has announced that the partnership has successfully integrated its business into its new affiliate, Chevron Corporation. Chevron has announced its capital and exploratory budget for 2021, with activity planned on Noble Midstream dedicated acreage in both the DJ and Delaware basins.

Robin Fielder, President and CEO of the partnership stated, “Noble Midstream achieved significant accomplishments this year, reducing its cash operating costs by more than 20%, placing multiple major equity-method investment pipelines into full service, and beginning to fund our investments and distribution from cash flow from operations.

“Along with these wins and a 2021 organic capital programme focused mainly on well connections, we expect Noble Midstream to generate sizable cash flow in excess of capital expenditures in 2021 and enable the Partnership to reduce debt and protect the balance sheet.”

THE MIDSTREAM UPDATE •

Phillips 66 announces 2021 capital programme

•

Ocean Infinity selects Sonardyne for pioneering Armada fleet

•

UK announces funding for underwater engineering hub

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2021 AFT Platinum Pipe award winners announced Follow us on LinkedIn to read more about the articles linkedin.com/showcase/worldpipelines

CONTRACT NEWS Pinnacle Midstream II announces new natural gas gathering and compression system

Stakeholder Midstream acquires gas gathering and processing assets

Pinnacle Midstream II, LLC has announced that the company has entered into a 15 year gas gathering, processing and purchase agreement with DoublePoint Energy, LLC, pursuant to which DoublePoint agreed to dedicate certain of its leasehold acreage related to natural gas production to Pinnacle. The agreement anchors Pinnacle’s greenfield build of a new natural gas gathering and compression system in the Midland Basin.

The Pinnacle Dos Picos Gathering System is expected to come into service in 2Q21 and supports the extensive multiwell pad development taking place in the Midland Basin, one of the most prolific production areas in North America.

Initially the Pinnacle Dos Picos Gathering System will service Midland, Martin and Glasscock counties. Future expansions are planned as producer activity continues to increase.

The Pinnacle Dos Picos Gathering System will give producers access to the industry’s newest gathering and compression engineering technologies that are designed to accommodate the high volumes associated with multiwell pad development and centralised drilling campaigns.

“We are extremely excited to have the opportunity to team up with DoublePoint, one of the region’s premier and most active producers,” said Pinnacle Midstream II CEO J. Greg Sargent. “ DoublePoint has some of the best and proven acreage in the basin. We believe the Pinnacle Dos Picos System’s strategic location will be a game changer for DoublePoint and many other producers operating in the Midland Basin.”

The Pinnacle Dos Picos Gathering System was designed with expansion in mind. The system is engineered for top-ofclass runtime that will handle the increasing volumes of hydrocarbons the region’s extensive existing and undeveloped formations are expected to generate.

Pinnacle has ready access to the capital required to align the gathering and compression infrastructure in the basin with the demands of producers that are continuously developing multiple benches. Pinnacle is engaged in discussions with other producers regarding additional dedications and services.

Pinnacle Midstream II, LLC is backed by growth capital from management and Energy Spectrum Capital. “We are very excited about Pinnacle’s Dos Picos System,” said Energy Spectrum Partner Mike Mayon.

“The Pinnacle team’s proven ability to plan and execute on midstream infrastructure projects that anticipate their customers’ critical needs is second to none in the industry.

We are very happy to be a proud partner in Pinnacle’s ongoing successes.”

Stakeholder Midstream, LLC has announced it has acquired gas gathering and processing assets from Santa Fe Midstream, LLC. Located in Yoakum County, Texas (USA), the assets include Santa Fe’s 30-30 Gas Treating and Processing Plant, lowpressure gas gathering pipelines, downstream residue and NGL lines, and a long-term acreage dedication from an established San Andres oil and gas producer.

The Santa Fe System will complement Stakeholder’s existing Campo Viejo Processing Plant and gathering system currently serving San Andres producers on the Northwest Shelf of the Permian Basin. The acquisition brings the combined systems’ gas processing capacity to approximately 85 million ft3/d, total gathering pipeline mileage to approximately 450 miles and total acreage dedications to the combined gas systems to greater than 200 000 acres.

“We entered the San Andres play in 2016 due to the unique blend of production stability and growth potential, and that thesis has been validated by our customers’ performance,” said Stakeholder Co-CEO Robert Liddell. “Despite a challenging commodity environment in 2020, our system volumes continued to grow year over year and we expect that trend to continue. This consolidation enhances Stakeholder’s capabilities to provide even better service to our customers.”

The Santa Fe acquisition follows Stakeholder’s August 2020 purchase and integration of a crude gathering system owned collectively by Walsh Petroleum, Inc. and Burk Royalty Co., Ltd. The August acquisition brings pipeline mileage on the crude oil gathering system to approximately 150 miles and acreage dedications to the crude system to approximately 150 000 acres. The San Andres Crude Gathering System includes 60 000 bbls of storage and is connected to Phillips 66, Plains All American and the Centurion Pipeline System.

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World Pipelines / JANUARY 2021

Jan de Nul acquires multipurpose subsea cable and flex-lay vessel Jan De Nul Group signed on 4 December 2020 an agreement for the purchase of the offshore construction and cable lay vessel Connector from Ocean Yield ASA. This marks a further investment in the offshore installation capacities of the Luxembourg-based maritime contractor. The vessel will be officially transferred during 4Q20.

Philippe Hutse, Director Offshore Division at Jan De Nul Group: “The Connector has a very good reputation in the sector and is known as one of the world’s top tier subsea installation and construction vessels. She’s capable of operating in ultra-deep water up to 3000 m deep. Through the market consolidation involving this new investment, we now own and operate the largest fleet of dedicated cable lay vessels. The Connector will further strengthen the Jan De Nul fleet for the future of offshore energy production.”

Same name, better game...

PWT is now a Qapqa brand Qapqa acquired the PWT-division of ITW Welding.

This fantastic step strengthens our position in the pipeline industry and ensures we are better able to serve the customer needs. We remain to work closely with ITW Welding. As always moving forward, we continue to improve our high-end welding technology.

Qapqa B.V. / The Netherlands / P (+31) 321 386 677 / info@qapqa.com / qapqa.com

12

Gordon Cope discusses the implications of the COVID-19 pandemic for various areas of the US oil and gas industry, and what the future may hold.

A

s is the case in most jurisdictions worldwide, the US oil and gas sector has been hit hard by the COVID-19 pandemic and resulting demand destruction. In addition, opposition to pipelines has heavily impacted the midstream sector. While 2020 was a grim year, 2021 holds out hope for better days ahead.

The emergence of the COVID-19 pandemic in March 2020 had an immediate negative impact in the US.

13

Consumption of fuel and feedstock products fell by 30% as travel and work bans were imposed across the nation.

Crude production in major basins was curtailed by several million barrels per day. Refinery output fell as diesel, gasoline and jet fuel demand collapsed.

The Permian After rapid expansion of both oil and gas pipelines in the Permian basin in Texas and New Mexico, operators struggled to fill their networks. Kinder Morgan offered discounts of 50% on its Eagle Ford line. Magellan sweetened tariffs for customers on its Permian BridgeTex network, whose contracts expired in 2020. Energy Transfer enticed customers with a volume incentive programme on its Permian Express system.

Many projects have also been cancelled. In June 2020, Phillips 66 put the Red Oak Pipeline on hold. The joint venture with Plains All American was designed to ship 400 000 bpd of crude oil from the Permian basin and Cushing, Oklahoma, to the Texas Gulf Coast. Phillips also deferred the Liberty Pipeline, a proposed 350 000 bpd crude line from the Rockies and North Dakota to Cushing.

Gas pipelines in the Permian are faring somewhat better, averaging around 11.5 billion ft3/d throughout mid-2020. While LNG demand is depressed, exports to Mexico are seeing an upward trend as they surpassed 6.4 billion ft3/d in mid-2020.

Rystad, a consultancy, expects Permian gas output to reach 16 billion ft3/d by 2023. Under such a scenario, they expect the 2 billion ft3/d Permian Highway Pipeline (PHP), and the 2 billion ft3/d Whistler pipeline (each designed to takeaway gas from West Texas for delivery to the Gulf Coast, South Texas and Mexico), to remain on track for completion in 2021.

Other projects, including the Pecos Trail Pipeline, Tellurian’s Global Access Pipeline, and the Permian to Katy pipeline, are on hold.

Rockies basins As a result of COVID-19 and low prices, oil and gas production in the Rockies basins (including the DenverJulesburg (DJ), Williston, Powder River, Green River Overthrust, San Juan and Piceance), has been plummeting.

Colorado’s DJ basin has seen a decrease in production from 763 000 bpd of crude and 5.58 billion ft3/d of gas in late 2019 to 605 000 bpd and 5.13 billion ft3/d by late 2020 as operators stack rigs, suspend wells and build up drilled but uncompleted (DUC) inventories. The decrease is having a significant impact on major long-haul pipelines such as Tallgrass Energy’s Rex pipeline, which stretches 1700 miles from Wyoming to Ohio. As firm, long-term contracts expire, producers are reluctant to re-up at current rates, and will be seeking tariff reductions of as much as 50%.

Problems with Dakota Access Pipeline In July 2020, the US District Court of Columbia ordered the closure of the Dakota Access Pipeline (DAPL) over potential

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World Pipelines / JANUARY 2021

environmental impact. The court said the US Army Corps of Engineers violated the National Environmental Policy Act (NEPA) when it granted an easement to operate a portion of the line beneath Lake Oahe in South Dakota when the operator, Energy Transfer, had not conducted an adequate Environmental Impact Statement (EIS), and ordered the operator to empty the 570 000 bpd line within 30 days. Energy Transfer appealed that it would take far longer than 30 days to safely empty the line, and that an adequate EIS would take well over a year to conduct. A federal appeals court granted an emergency stay of the order, setting an 18 December 2020 deadline for legal arguments and responses. If the three year old line – which transports approximately 40% of North Dakota’s crude production to market – is permanently shut-down, operators would once again have to rely on expensive crude-by-rail.

Keystone XL President Trump, a long-time supporter of the Keystone XL pipeline, issued a presidential permit in late July 2020, giving the owner of TC Energy the right to increase maximum throughput capacity from 590 000 bpd to 760 000 bpd. The Alberta government, Canada, has promised over CAN$5 billion in investment and loan guarantees to the project, eager to alleviate pipeline export blockages.

The project is battling legal challenges, however. A lower court ruling that Keystone XL cannot use the US Army Corp of Engineer’s Nationwide Permit 12 (allowing pipelines to cross rivers with minimal review if they met specific criteria) was upheld by the US Supreme Court. TC Energy must now seek an individual permit, potentially pushing back the start of US construction into 2021.

Cancelled gas lines In July 2020, Dominion Energy cancelled its US$8 billion Atlantic Coast natural gas pipeline. The 966 km pipeline was designed to deliver Marcellus gas to consumers in Virginia and North Carolina. After years of delays in the approval process, Dominion and partner Duke Energy decided to pull the plug as the project went billions of dollars over budget.

The cancellation will mean that these companies and other electric utilities will have to find more expensive alternatives to their coal-to-gas switching efforts.

Bankruptcies There was a surge in oil patch bankruptcies in the US during 2H20 as producers and oilfield services companies have sought protection from creditors. Rystad Energy predicted that 55 exploration and production companies would enter Chapter 11 protection by the end of 2020, alongside another 44 oilfield services companies, bringing the total associated debt to over US$100 billion.

Those who survive will do so in an economic environment of low oil prices, high debt loads and the paucity of investor capital. Bank lending practices are expected to tighten even further, limiting the ability of

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shale producers to continue drilling. Wood McKenzie expects average growth rate in shale production to slow by 80% from 2019 levels. “It will be like driving with the parking brake on,” the company noted.

Consolidation of shale players is well underway. Two years ago, Concho Resources was valued at US$32 billion.

In October 2020, ConocoPhillips offered US$9.7 billion in stock in order to consolidate land holdings in the Permian. Chevron also concluded the purchase of Noble Energy and WPX merged with Devon. Pioneer Natural Resources bought Parsley Energy for US$4.5 billion, combining the two Permian basin-only crude producers into a 328 000 bpd entity. All of the deals were stock-only transactions, reflecting the difficulty of raising cash.

Good news In September 2020, Enbridge finally won the right to restart its Line 5 pipeline in Michigan after gaining approval from the Pipeline and Hazardous Materials Safety Administration and receiving the green light from the Michigan Circuit Court. For the last several years, Enbridge has been working to replace sections on the 65 year old line running from Alberta to Ontario through the US. Opponents argued that the line, which runs under the Strait of Mackinac in the Great Lakes, endangered the drinking water of 40 million residents.

In June 2020, the US Environmental Protection Agency (EPA) issued a final ruling narrowing the scope of review for proposed oil and gas pipelines that states have used under the Clean Water Act (CWA). Until now, states (such as New York) have used Section 401 under the CWA to stall or deny permits for interstate pipelines under the pretext of climate change. The environmental review of interstate pipelines is under the authority of the Federal Energy Regulatory Commission (FERC), but states opposed to fossil fuels were using the CWA (which gives them authority regarding water quality), as a means of opposing pipelines within their jurisdictions.

Energy Transfer will complete a scaled-back version of its Ted Collins pipeline. The line, designed to transport 275 000 bpd from West Texas to its Houston terminal will be completed in late 2021.

Enterprise Products’ 450 000 bpd Midland-to-ECHO 4 pipeline is expected to enter service in 2H21, six months later than originally planned. The line is underpinned by long-term contracts, and, in the company’s opinion, is a more viable capital expenditure than the dozen projects in its development plans that have been either cancelled or deferred.

Rig counts have risen by 5% since lows in May 2020, but active frack crews have more than doubled over the same time, as operators allocated CAPEX to complete a portion of the 6000 DUC wells in the US inventory, which will stop shale well decline rates and potentially reverse overall production declines.

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In October 2020, DAPL received approval from Illinois to double its capacity from 570 000 bpd to 1.1 million bpd.

The pipeline now has approval from all four states it passes through – North Dakota, South Dakota, Iowa and Illinois – to proceed. “It’s critical we continue to support and expand our nation’s pipeline infrastructure like DAPL to help family budgets and keep our economy moving – especially in this time of recovery from COVID-19,” said Consumer Energy Alliance (CEA) Midwest Director, Chris Ventura.

November election The election of President Biden is expected to increase regulatory burdens and costs to the oil and gas sector.

While his campaign promise of a fracking ban on federal lands will have limited effect in the Texas portion of the Permian, much of the basin in New Mexico is under federal lands, and will heavily influence investments in that state.

President Biden has also publicly stated that he will cancel Trump’s approval of the Keystone XL pipeline. The Alberta government, which owns part of the pipeline, has stated that it would finance legal challenges to the move; key Biden supporters, such as Labor and several ROW states, could also influence implementation of this pre-election pledge.

In a note prior to the election, Goldman Sachs predicted that a Biden win would “likely to be in fact a positive catalyst” in causing oil prices to rise, as the expected tightening of regulations, taxes, methane restrictions and drilling restrictions would create “shale supply headwinds”, raising the cost by as much as US$5/bbl and thus placing upward pressure on the global price of oil.

The future In the short-term, the US oil and gas sector has been heavily affected by both supply and demand, much like the global industry. While OPEC+ has extended its production cutbacks through to 2021, the economic rebound from the COVID-19 pandemic has been slow and painful, and may reverse should a second deadly wave sweep the continent prior to the development of an effective vaccine. Until supply and demand come into equilibrium, American oil companies will face bankruptcies, and pipelines will encounter reduced tariff incomes and delays and cancellations of new projects.

Eventually, however, a semblance of normalcy will return. While renewable energy sources will continue to make strides, the US and the world will still have an immense appetite for fossil fuels for several decades to come, allowing upstream, midstream and downstream stakeholders to once again make long-term investments in one of the world’s most prospective jurisdictions.

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SCAIP is the original manufacturer of our product line designed over the years and owner of the related know-how. Any other machine that may have a similar design but is not produced by us does not have the same technical features as our products.

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With deep decarbonisation of the world’s energy system still many years away, Koheila Molazemi, Technology and Innovation Director with DNV GL – Oil & Gas, examines the predictions and possible solutions for a lower-carbon future.

In its fourth year, DNV GL’s 2020 Energy Transition Outlook paints a stark picture of a rapidly evolving energy mix. What are the key findings?

We provide an independent forecast of developments in the world energy mix over the next three decades (Figure 1). Our dedicated oil and gas report presents the demand, supply, and investment forecast for hydrocarbons, and decarbonised and green gases to 2050, and focuses on the outlook for converting the oil and gas industry into a zero-carbon provider.

We forecast a decarbonising world in which energy demand plateaus, renewables grow significantly, natural gas becomes the world’s largest energy source, and oil demand never again reaches the levels of 2019.

From our research and modelling, the overarching message is that efforts to reduce carbon emissions are still nowhere near fast enough to deliver on the COP21 Paris Agreement – which aims to keep global warming to ‘well below 2˚C’, limiting the increase to 1.5˚C. The outlook predicts that we will exhaust the 1.5˚C carbon budget under the Agreement in 2028, and exceed 2˚C in 2051.

The oil and gas industry may be successful in reducing its carbon emissions by a third (32%) by 2050, but climate change and ambitions to reduce it are outpacing action. Ultimately, an energy system that does not accept the release of carbon emissions needs to be achieved.

What impact has COVID-19, stringent travel restrictions and the volatile oil price had on the predictions for oil in particular?

There’s no doubt that 2020 was an extraordinary year, with

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conditions that we’re all learning to live with on a daily basis: individually, as a society, and economically.

Compared with our previous outlook, peak oil has occurred sooner than expected due to COVID-19-induced shock and plummeting demand in early-2020. While this crash has had a significant impact on financial markets, and potentially on the shorter-term ability of oil and gas companies to invest in new projects and in the energy transition, oil still has a significant role to play in the coming decades.

Crucially, we will not see a single energy transition to 2050, but several – each interrelated and playing out differently around the world. These include transitions from fossil fuels to renewables, from coal and oil to natural gas, and from fossil fuels to decarbonised gas (Figure 2).

In 2019, we saw the industry start to loosen its purse strings, with spending on new developments and technologies back on the agenda. Now, as we return to tighter cost control, what does this mean for future expenditure?

Figure 1. DNV GL’s Energy Transition Outlook is now in its fourth year.

Figure 2. World primary energy supply by source.

In 2020, global crude primary oil demand fell 13% to a level not seen since the early 2000s. Though it will rebound somewhat to 2023, we expect demand to decline gradually to half of its 2018 level in real terms by 2050 (from 83 million bpd in 2018 to 42 million bpd). While oil demand will decline rapidly in some regions, it will continue to grow in others, so sustained investment in oil and gas will be needed over the next three decades to maintain production at levels required to meet global demand, even in a declining market.

Amid decreasing production, conventional onshore oil will continue to provide the largest and most stable share of total oil production. As the industry faces significant pressure on cost, the cheapest, easiest-to-access oil is set to win in the long run. This has regional implications, with the Middle East and North Africa and to a lesser degree North East Eurasia, set to reap the benefits (Figure 3). This means increasing pressure on unconventional onshore and offshore oil production to 2050.

Upstream oil expenditure in 2050 will be one third of the levels in 2018. From the late-2030s, we see an uptick in capacity additions for conventional onshore oil but a steep decline in additions for offshore oil, closely followed by a drop in additions for unconventional onshore.

The future of the gas industry on the other hand, is far more positive in comparison to oil.

What transformations will we see in demand, production and capacity towards mid-century?

Figure 3. Crude oil production by region.

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Fossil fuels will account for 54% of the primary energy supply in 2050, compared to around 80% today. More than half of this supply will come from natural gas as it becomes the world’s largest energy source from the mid2020s.

When compared with the forecast for oil production during the period, we see that offshore gas production

will stay more competitive. This is partly due to continued strong demand, bringing more certainty that investments with longer horizons will make a return, partly due to the price advantage of regional supply by (offshore) pipelines over LNG imports, particularly in regions with welldeveloped gas infrastructure.

So, as the least carbon-intensive fossil fuel, gas will play a prominent role in the energy transition.

We expect global gas demand to peak in the mid2030s at 185 EJ, around 20% higher than the 154 EJ in 2018. From that point it will fall by just over 10% to 165 EJ at mid-century. Around half of the demand for natural gas will come directly from its end use – in buildings, manufacturing, transport, and non-energy use such as for petrochemicals. The other half will come from power generation which will increase by almost a fifth from 2018 to 2035 globally, largely due to increased demand in Greater China, the Indian subcontinent and South East Asia, outpacing growth in renewables. This provides the energy security and stability the world needs alongside variable renewables in the transition. By 2050, demand for natural gas for power generation will drop back down to 2018 levels, as renewables scale.

Gas production will increase 12% from 4.520 billion m3/y in 2018 to 5.070 billion m 3/y in 2035, before decreasing to 4.570 billion m3/y – a level marginally higher than in 2018. Production from all field types will increase to 2035. Unconventional onshore gas will see the greatest proportion of this, followed by conventional onshore and then offshore, though all three sources will remain competitive.

North America, the Middle East and North Africa, and North East Eurasia will dominate natural gas production,

accounting for approximately 75% of the world’s supply throughout the forecast period. For example, significant volumes of Russian gas are set to supply Europe and Asia, through existing or planned transnational pipelines including Nord Stream, Nord Stream 2, TurkStream, and the proposed Altai (Power of Siberia 2) pipeline to China, and also shipped from Yamal and Arctic LNG II fields by fleets of LNG carriers.

With climate change pressure, changing fortunes for oil and gas and the prospect of a ‘new normal’ post-COVID-19, would you say we’re at a crossroads on the journey to deep decarbonisation?

The transition to renewables and efforts to cut carbon intensity will significantly reduce emissions, but they will not deeply decarbonise the natural gas the world’s energy system will depend upon for years to come.

Solutions include electrifying oil and gas assets, reducing flaring and venting of gas during production, increased efforts to detect and stem methane leaks, and efficiency gains through digitalisation. However, oil and gas production and distribution accounts for only a quarter of the industry’s carbon emissions; the majority occurs during the combustion of oil and gas.

It is only by removing the carbon from natural gas – before or after combustion – that the oil and gas industry can deeply decarbonise, reaching hard-to-abate sectors throughout the value chain.

By 2050, we expect that the industry will broadly not be measured on carbon emissions per barrel of oil or gas it has produced, as is the default today, but by lifecycle emissions per barrel consumed. We recognise that while

Figure 4. Energy transition timeline: the oil and gas horizon.

JANUARY 2021 / World Pipelines

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hydrogen at scale.

We forecast that both will happen in order to realise the hydrogen economy, just not until the 2040s.

How far can partnership and policy shift the timeline on emissions reductions?

Figure 5. Energy-related CO2 emissions by region.

there are limited options to reduce emissions from oil consumption, other than shifting to another energy source, we forecast that hydrogen and carbon capture and storage (CCS) will be a catalyst for deep decarbonisation after 2035.

Greater investment in infrastructure and new technologies are clearly needed to turn this prediction into reality and this takes time.

Where are we at now and what needs to be done to fast track action?

We predict that just 13% of natural gas will be decarbonised in 2050, with 12% of world energy emissions captured by CCS â&#x20AC;&#x201C; mostly from natural gas. However, this transformation will not scale for another 15 years, and only really gets going in the 2040s (Figure 4).

Encouragingly, we are seeing a change in spending intentions. Fossil energy expenditure represented more than 80% of world energy expenditure in 2018, but this will decline to 44% in 2050, with non-fossil expenditure accounting for 34% and grid expenditure 22% in 2050.

The technologies needed to accelerate the energy transition are available today, but they need to scale, and sooner. On one side, the world has started down the path to much greater use of renewables and battery storage, which will enable further electrification of sectors such as transport, manufacturing and heat in the home. On the other side, technologies to decarbonise natural gas are yet to take off.

The problem is that CCS wonâ&#x20AC;&#x2122;t move down the cost learning curve unless the industry significantly increases its rollout of the technology, but we donâ&#x20AC;&#x2122;t foresee this happening until the costs have come down or a carbon price exceeds the cost of the technology. Hydrogen faces a similar issue. It relies on CCS for blue hydrogen, and on the cost of electrolysers falling to produce green

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We foresee that carbon dioxide emissions are set to remain stubbornly high until the mid2030s. Such harmful discharges from energy use will fall just 15% to 2035, then dropping 40% to 2050. This masks significant regional variations, as shown in Figure 5.

Pressure is understandably increasing on the oil and gas industry to decarbonise, from all sides: society and government, investors, and also people within the sector itself.

Public energy policies are key, not just in setting out the path for the world and the oil and gas industry to decarbonise, but also in deciding how quickly it heads down that path. In our outlook, we point to policies in Europe, China and North America that will create the impetus for scaling hydrogen and other low-carbon fuels, and propel recognition that scaling CCS will be essential to meet climate targets.

Ultimately, these policies could transform the industry into the decarboniser of hydrocarbons and supplier of CCS. We believe the mid-2030s is the point at which these policies will begin to act as a catalyst for this transformation. The quicker that government incentivises industry to adopt technology, such as through a competitive carbon price, the quicker the industry takes the technology down the cost-learning curve for it to become independently financially viable.

Forming partnerships among government, industry, and associations will be crucial in scaling innovation and new technologies. Collaboration on frameworks for making hydrogen and CCS safe, effective, and commercially viable will give us the certainty we need to manage new risks and accelerate our transformation towards a lowcarbon future.

It requires a radical shift in the role and reputation of oil and gas: from contributor to a potential climate catastrophe, to becoming a trusted and indispensable participant in the global effort to address climate change.

Syed T Hashmi and Awadh O. Oadah, Pipeline Projects Department, Saudi Aramco, discuss the benefits of using dual seal technology for a double block and bleed isolation.

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audi Aramcoâ&#x20AC;&#x2122;s Pipeline Projects Department initiated a technical proposal to utilise a hot tap installed dual seal technology for proven double block and bleed isolation of a 32 in. natural gas liquids (NGL) pipeline, successfully completing the project in January 2020.

The technology provided safe isolation which allowed the demolition of the launcher and receiver without interrupting production. A double block and bleed isolation was installed at both

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Figure 1. Dual Seal Isolation technology.

Figure 2. Dual Seal Isolation technology at isolation location.

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ends of the pipeline, while the NGL flow was maintained through existing bypass lines. The tie-in work for the new pipeline segment was successfully completed on 18 January, 2020.

The execution of a hot tap installed dual seal isolation is considered a success story, which has benefited Saudi Aramco in safely executing live pipeline-based modification while maintaining a sustainable supply of energy to the world.

This article shares the success of deploying and documenting the outcomes of introducing hot tap installed dual seal technology for the first time in Saudi Aramco capital projects, to execute safe pipeline isolation using a proven double block and bleed isolation tool.

The isolation equipment utilised provided a fail-safe and fully monitored double block and bleed isolation of the pressurised gas pipeline. The dual seal configuration provides an annulus void, which can be pressure tested to verify both seals are leak-tight before breaking pipeline containment. Additionally, both seals are leak tested at 100% of the maximum potential isolation pressure to ensure the integrity of the isolation.

This technology can be used to isolate sections of a pipeline anywhere in the system, and can be operated in pipelines from 3 - 56 in. and up to 2220 psig.

The hot tap installed dual seal isolation technology is deployed through a single split tee fitting and requires no extensive disposing of oil or flaring of gas to atmosphere during blowdown. In addition, integrated ports on the isolation tool launcher can be used to vent, purge and flush the isolated pipeline section. This feature further increases safety and reduces the hazards to personnel on site, as well as the environmental impact.

The project scope of work was to replace a section of the NGL pipeline without interrupting the flow. This replacement was originally planned to be carried out using conventional line stop technology; however, for various reasons, the project team decided to consult with specialised vendors to provide a dual seal isolation technology

Figure 3. Tie-in point KM25 and KM22.

to meet the company’s requirements of positive isolation.

The project team reviewed the technical proposal and scope of work offered by the vendor to isolate the 32 in.

NGL pipeline to remove scraper traps and tie-in the new segment. The scope of supply included preparing all required documents such as the Site Survey, Factory Acceptance Test (FAT), Methodology, Documentation, Responsibility Matrix, JSAs, Risk Assessment, HAZOP Study and Pipe Stress Calculations.

The pipeline isolation using a single line stop, conducted by Saudi Aramco Hot Tap and Stopple Division, was not feasible and the project team proceeded with the proposal to deploy a leak-tight dual seal isolation through a single hot tap penetration.

A single split tee fitting was welded onto the main line at two locations between the 24 in. bypass lines, along with the sandwich valves and hot tap machines. Two 32 in. hot taps were carried out and the pipe coupons were recovered. Once the hot tap machines were removed, the dual seal isolation tools were installed and deployed into the pipeline through the hot tap penetrations. The isolation tool seals were hydraulically activated to provide isolation of the pipeline.

After activating the seals, the pipeline pressure behind the isolation tool was vented and a Secondary Seal Test was conducted. During the Secondary Seal Test, the annulus pressure was equal to pipeline pressure and monitored for pressure leak-off to prove the integrity of the seal with full differential pressure. Once the Secondary Seal Test was proven, the Primary Seal Test took place by venting the annulus pressure to ambient and monitoring for pressure build-up, thus proving the Primary Seal integrity with full differential pressure.

The Integrity Leak Test was conducted after that to confirm a Zero Energy Zone was provided between the two fully proven seals. The isolation seals include a fail-safe feature as both seals are activated and maintained by two independent mechanisms, hydraulic activation and pressure

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differential across the seals provided by the pipeline pressure.

With the isolation certificate issued, the section between the isolation tools was then drained, flushed and purged using nitrogen, until a Lower Explosive Limit of zero was achieved. The spool piece was then cut out and a new spool was successfully welded into position.

The upstream, downstream and annulus pressure of the isolation equipment was continually monitored through the isolation. Active readings of hydraulic set pressure, pipeline pressure, and annulus pressure were continually provided by the onsite isolation technicians.

Non-destructive testing and a leak/pressure test were conducted on the newly welded joints while the isolation remained in place.

Financial benefits achieved by deploying this dual seal isolation technology included cost savings resulting from eliminating the requirement to depressurise, purge and flush the entire line. Additionally, deploying this technology for the tie-in project, instead of using conventional line stop equipment, removed the requirement for two 2 in. hot taps to act as pressure equalisation ports and two 10 in. hot taps for the deployment of inflatable balloons.

Conclusion The hot tap deployed dual seal isolation tool provided reliable, accurate, and high-integrity pipeline isolation.

In addition, it reduced manpower and job duration – saving two months of the schedule when compared to performing a shutdown – and provided an effective double block and bleed isolation.

This technology reduced the overall cost of the project by eliminating depressurising, flaring and nitrogen purging employed in the conventional hot tap and line stop methods. In addition, this technology allowed the continued production of NGL during pipeline modifications with a high integrity isolation and sufficient contingency due to dual seal configuration and fail-safe design.

In the second of a two part series, Aiman Ali, Petroleum Development Oman, and Andy Russell, Chris Owens, Ian Fisher and Angus Patterson, ROSEN, UK, discuss how different levels of information, converted from raw inspection data, can be used to refine integrity decisions.

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ltrasonic wall thickness measurement (UTWM) inline inspections provide an accurate map of a pipeline’s wall loss. They collect so much detailed data however, that significant simplification is needed to turn them into information, which can then be used to gain knowledge – this is the ‘knowledge hierarchy’ shown in Figure 1.

Part 1 of this two-article series described how the large amounts of detailed data captured by UTWM can be processed into information, including qualitative and quantitative anomaly definition, as well as the rate of change (corrosion growth rates) necessary for making future integrity predictions.

This article (Part 2) goes on to demonstrate how the different levels of information were used to gain knowledge of a pipeline’s integrity status, using progressively detailed methods. Although these required ever more input data

25

and effort, they reduced uncertainties and resulted in significant OPEX savings, while maintaining safe operation.

Assessment approaches and levels – turning information into knowledge Having reduced the complex data into anomaly size and rate-of-change information, the final step was to gain knowledge from it. The anomaly dimensions described in Part 1 were first screened using the Step 1 Modified B31G (simple area approximation) approach (Figure 2).

Acceptance was defined as the anomaly not exceeding tolerable dimensions within five years of the assessment date. Internal and external anomaly depths were grown

at their respective characteristic growth rates. Interacting internal/external features were grown at the combined rate.

Those anomalies that failed Level 1b Step 1 (105 in total) were assessed using Level 2 Step 2 where possible, though due to the applied tolerances, it was necessary for some anomalies to go straight to Level 2 Step 3. The Level 2 approaches are summarised as follows:

Level 2 Step 2 – Detailed RStreng using the simple boxes from the listing, which make up clusters This is a simple approach frequently used with MFL data, where the profile is approximated by rectangular boxes.

For UTWM, these boxes are approximations of individual corrosion sites within a cluster. Following this level of assessment, the number of code failures was reduced from 105 to 34 anomalies.

Level 2 Step 3 – Detailed RStreng using river bottom profiles (RBPs) from the raw UT data The most complex level of assessment used the raw RWT matrix data from the UTWM tool. These data were processed by experienced analysts to remove spurious echoes, and to account, where necessary, for echo loss.

The final number of features that required investigation and repair following this level of assessment was 11.

Plausible Profile (Psqr) model Detailed RStreng considers a ‘worst case’ profile by following the deepest path (i.e. ‘river bottom’) through the corroded area. This conservative profile only considers longitudinal interaction. It does not therefore account for circumferential spacing – i.e. if the circumferential separation of two adjacent corrosion areas is beyond certain limits (an extreme example could be adjacent deepest points at 3 and 9 o’clock), they do not need to be combined because they will not interact to lower the overall failure pressure of the feature. This is a known limitation of the Detailed RStreng method.

A number of methods have been proposed which attempt to overcome this limitation and remove unnecessary conservatism.

These include a model that has recently been developed by TransCanada Pipelines Limited (TCPL), an affiliate of TC Energy Corporation. The assessment method is known as the Plausible Profiles Model (‘Psqr’ or P) and retains Detailed RStreng as its basis.2 Instead of considering a single worst case RBP however, it determines multiple plausible failure path profiles (Figure 3). These profiles are generated based on weighted proximity (interaction) and depth rules. For each of the plausible profiles, failure pressures are Figure 2. Multi-level corrosion assessment process. Note: ACR = ‘Assessed Corrosion Rate’. determined according to Detailed RStreng. The Figure 1. Knowledge hierarchy.

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failure pressure results for each plausible profile form a distribution, that is then used to determine the estimated Psqr failure pressure (defined as the 5th percentile).

For corrosion features containing pits that are widely spaced circumferentially, the method has been shown to reduce unnecessary conservatism associated with Detailed RStreng.3 If the deepest pits in the feature are found to be axially aligned (e.g. axial slotting or narrow axial channelling) however, then the ‘worst case’ river bottom profile will be the most plausible. In this case, the Psqr method will default to using a river bottom profile; i.e. the failure pressure will be the same as Detailed RStreng.

Psqr example The Psqr assessment method was not available at the time of the original fitness-for-service assessment for this pipeline. To investigate the potential benefit of the Psqr assessment method for the pipeline, two example features were considered. This included one (Anomaly ID 2) of the

11 features that were unacceptable according to Detailed RStreng (Level 2 Step 3). The results of the Level 1, Detailed RStreng and Psqr assessments, are shown in Figure 4. In the case of very complex features (e.g. axially long and/or wide features with many thousands of data points), processing time can become significant due to the number of profiles and required iterations for Detailed RStreng. If required, the matrix data can be simplified (i.e. the resolution reduced).

For both features, Psqr provides a significant increase in the predicted failure pressures (11% and 22% respectively) when compared to Detailed RStreng, which considers the ‘worst case’ axial RBP. Anomaly ID 2 was predicted to be unacceptable at the time of the ILI according to Detailed RStreng; however, the Psqr assessment demonstrates that it would have been acceptable.

It is noted that the output from the Psqr method is a failure pressure, which is based on the distribution of failure pressures from the profiles considered. This output is not ideally suited to carrying out future integrity calculations (i.e. determining the time at which features will require repair due to corrosion growth); however, an iterative approach can be used to overcome this limitation.

The levelled approach described within this article, means that the number of such calculations can be minimised.

The difference in the profiles used for the RStreng and Psqr methods is illustrated in Figure 5, for a section of one of the above examples. As shown for this example, many of the deepest points are widely spaced. The RBP for Detailed RStreng conservatively assumes that these points are interacting, whereas the Psqr method considers the plausible profiles, taking into account the actual circumferential spacing.

Comparison of assessment results – knowledge A summary of the number of predicted investigations/ repairs following the three steps of this assessment is shown in Table 1. Based on this knowledge, appropriate repair and maintenance planning can be carried out.

Figure 3. Determination of plausible profiles using the TCPL As shown in Table 1, the predicted number of Psqr Assessment Methodology (Figure 3-1 from TCPL Technical Report).1 Top: Each plausible profile is generated based on investigations/repairs reduced significantly from 105 to 11 weighted proximity (interaction) and depth rules. Bottom: The features, by following the levelled assessment approach. dashed line represents the worst case RBP. This in turn considerably reduced the cost to investigate and remediate the necessary Table 1. Summary of assessment results features, decreasing the number of required Step 1: Modified B31G Step 2: Detailed Step 3: Detailed mobilisations.

RStreng (Box RStreng (RBP Data) From consideration of the two features Data) that were additionally assessed using the Psqr Immediate 46 7 3 methodology, it is apparent that a further step Future 59 27 8 using Psqr to assess the features that failed Additional 48* Step 3 would potentially further reduce the Total 105 82 11 predicted number of investigations/repairs. * These 48 features were clusters containing internal and external features, and could not be assessed using the Level 2, Step 2 assessment due to the tolerance applied to them.

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World Pipelines / JANUARY 2021

Conclusions From the work presented in this article, it is clear that there are significant benefits

to using a levelled approach to optimise both the knowledge gained from the feature assessment process, together with the associated costs. This can reduce significantly the number of features that are predicted to require investigation/repair, while ensuring continued safe operation.

Further benefit could be achieved when using the detailed data with the recently developed Psqr assessment methodology. For the examples considered, an increase in the predicted failure pressure of up to 22% was observed when compared to Detailed RStreng – both using RBPs based on the maximum resolution of the UTWM tool. It should be noted that this potential benefit is highly dependent on the type of feature being assessed. For an axially aligned feature (e.g. axial slotting or narrow axial channelling), the failure pressure would be same as Detailed RStreng. Although there are some trade-offs in terms of processing time and future integrity assessment, it is clear that the Psqr methodology could provide significant benefit for certain feature types.

Figure 4. Assessment summary for two sample features (failure pressures).

References 1.

2.

3.

KARIYAWASAM, S., ZHANG, S. et al., “Plausible Profiles (Psqr) Model for Corrosion Assessment,” PRCI, 23 September 2019.

“DNVGL-RP-F101, Recommended Practice, Corroded Pipelines,” DNVGL, May 2017.

KIEFNER, J. et al., “Peer Review of the Plausible Profiles (Psqr) Corrosion Assessment Method, Prepared for the Corrosion Technical Committee of PRCI,” 9 August 2019.

Figure 5. Extract of UT matrix showing circumferential spacing between deepest points & Psqr plausible profiles.

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PIGGING World Pipelines asked NDT Global and In-Line Pigging Solutions some questions about pipeline pigging.

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NATHAN LESLIE, Senior Vice President - Sales and Marketing Management, NDT Global Responsible for the overall sales and marketing functions of NDT Global, Nathan focuses on delivering value to current and future customers while looking for ways to enhance and strengthen integrity management programmes.

HADDOW THUL, Business Development Manager, In-Line Pigging Solutions Haddow Thul is a young pipeline professional who is eager to provide industry leading service to pipeline owners and operators through combining field expertise and new technology. Starting his career as a Field Technician eight years ago, he has since grown to become the Business Development Manager at In-Line Pigging Solutions, Canada.

Discuss a recent technological enhancement that has benefitted your inspection instruments or inspection capabilities NATHAN LESLIE, NDT Global NDT Global is excited to unlock Acoustic Resonance Technology (ART), a cutting-edge technology to complement NDT Global’s ultrasonic technology (UT) solutions. With the addition of ART, we are extending our market reach, offering gas operators the same level of service and asset insights as we are currently delivering to liquid pipeline operators.

By adding ART to our portfolio, we have successfully intertwined exceptional people and technologies to collectively serve and advance the entire pipeline industry.

From an operator perspective, NDT Global can now be viewed as a ‘one stop shop’ for gas and liquid pipeline inspections and integrity management services.

HADDOW THUL, In-Line Pigging Solutions Over our past 18 years in service, we have gained the trust and respect of our clients through supporting them with industry leading experience and service when it comes to pipeline integrity projects.

In-Line Pigging Solutions (ILPS) has adopted a technology-eccentric strategy to pair with our industry expertise as part of our business model in the highly competitive market of pipeline integrity. Our goal for investing and bringing in technology is to execute our services in a safe, reliable, and cost-efficient manner for our clients. To fulfill this goal we have created a proprietary system solution called The Element System.

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PIGGING The Element System combines remote box tracking technology, portable pressure instrumentation and our Element Web Interface to tie all components of a project together to take our project execution, communication, and efficiency to another level.

Each element of the system can be used together as a system or individually based on customer needs.

Traditionally, tracking sheets and run information is stored on Excel spread sheets, stand alone gauges, and the pig is somewhere in the line, and information is communicated through a burdensome amount of phone calls and texts.

The Element Web Interface solves these issues, providing a live view of a tool run in which all of the associated data is in one easy to view location for project stakeholders. The Web Interface App is a user-friendly website that allows all stakeholders â&#x20AC;&#x201C; from field employees to project managers â&#x20AC;&#x201C;

In-Line Pigging Solutions: the Element system.

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to access run information. A user can view tool speeds, tool locations and various ETAs, along with pipeline pressures.

The Element Web App receives its information from live trackers, remote tracking boxes and portable pressure transmitters. Integrated software allows for consistent communication and decision making during fast paced projects. Once a project is complete, it is archived for future reference for project planning and decision making.

The Remote Tracking Boxes (RTB) are unmanned tool tracking units that provide real-time tracking updates by providing passage times and the ability to live stream geophone, ELF and magnetic data. The boxes have presented outstanding value in safety sensitive and remote locations that are difficult to access. The RTB is placed on the pipeline rightof-way and allows for trackers anywhere on the line to access the box and stream live data, as if they are physically there. For example, a tracker no longer has to enter unsafe or difficult to access areas during a tool run as the remote box will be placed and can be used to remotely listen to the pipeline. The Remote Tracking Boxes make it extremely difficult to miss a passage, and they help to understand what is happening on a pipeline to ensure a tool run is being executed as planned.

The Portable Pressure Sensors (PPS) provide precision oversight to quickly understand what is happening during a pipeline integrity project. The PPS continuously captures second by second pressure data and provides cry-out alarms when a pressure threshold is surpassed. Traditionally, field crews would have to rely on watching gauges or calls from the pipeline control centre. These devices have proven to be invaluable when performing ILIs (purges, smart tool runs, commissioning and decommissioning) hydrotests, during cut outs, and when locating stopped tools.

Although In-Line Pigging Solutions has begun to use advanced technology products to ensure a higher level of service, these tools are only as valuable as the ILPS field professionals using them. Our field professionals now have more tools and information than ever before to complete projects successfully and safely. Clients have also reaped the benefits of this system as we are beginning to see cost savings on projects of up to 30%.

Outline the scope of a recent inspection project (or upcoming one) for oil/gas pipelines NATHAN LESLIE, NDT Global Regulatory body PHSMA and industry association PRCI are joining forces to improve inline inspection (ILI) technologies, in particular the ability to detect, size, and characterise features interacting with dents. At NDT Global, we thrive on the opportunity to overcome unique and difficult operator challenges. We continuously look for new ways to push technology boundaries to ensure pipeline operators have the best understanding and insight of their pipeline conditions.

In-Line Pigging Solutions: the Element web interface.

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Our experts have been working hard to advance our technologies as we understand the current challenges and uncertainty operators face of not knowing if a dent

Hifi provides the most ǹȳ΄ǹ˗ȧɄȳ ȳʇ̶͔̓ʇȠ͔ͣɄȳ ɥʇȠɄ̥ ˧̛͔ʇȧ ̓Ʉ˗̓ʇ˗ɪ ͔Ʉȧɴ˗˧ʳ˧ɪΖ ʇ˗ ͔ɴɄ Έ˧̥ʳȳ ¤ʇɥʇԾ̓ ɴʇɪɴ ɥʇȳɄʳʇ͔Ζ ȳʇ̶͔̓ʇȠ͔ͣɄȳ ̓Ʉ˗̓ʇ˗ɪ Ԟ¤Wƍԟ ː˧˗ʇ͔˧̥̓ ǹȧ˧͔ͣ̓ʇȧՏ ͔̥̓ǹʇ˗ ǹ˗ȳ ͔Ʉː̛Ʉ̥ǹ͔̥ͣɄՏ Ʉ΄Ʉ̶Ζ ːɄ͔Ʉ̥ ˧ɥ ͔ɴɄ ̛ʇ̛Ʉʳʇ˗ɄՏ ӪӭԧӱԧӬӰӮ ʇ˗ ̥Ʉǹʳ ͔ʇːɄ ¤Wƍ ˧ɥɥɄ̥̓ Έ˧̥ʳȳ ȧʳǹ̓​̓ ʳɄǹʫ ȳɄ͔Ʉȧ͔ʇ˧˗ ǹ˗ȳ ̛̥Ʉ΄Ʉ˗͔ʇ˧˗Տ ̓Ʉȧ̶ͣʇ͔ΖՏ ɥʳ˧Έ ː˧˗ʇ͔˧̶ʇ˗ɪՏ ̓ʳ˧̛Ʉ ͔̓ǹȠʇʳʇ͔Ζ ǹ˗ȳ ː˧̥ɄՏ Έʇ͔ɴ˧͔ͣ ɥǹʳ̓Ʉ ̛˧̓ʇ͔ʇ΄Ʉ̓

ĚɄǹ̶˗ ː˧̥Ʉ ǹ͔ ɴʇɥʇɄ˗ɪՐȧ˧ː ǹ˗ȳ ʇ˗ɥ˧ԝɴʇɥʇɄ˗ɪՐȧ˧ː

PIGGING

&

NDT Global: customer inline inspection test loop run at NDT Global test yard.

NDT Global: inline inspection tool preparation at NDT Global warehouse.

has an interacting feature, such as a crack or corrosion. By successfully detecting these injurious features operators can optimise their integrity management plans, prioritising critical remediation efforts and operate their pipeline assets safely.

northern Alberta location carrying hot oil. This scope included purging, cleaning, drying, tool tracking, waste disposal and third party management. Due to the remote location and customer budget, we utilised the Element System to be more effective in completing the scope of work. Using the Element System, the project saw considerable savings. We were able to use the PPS to understand pressures in various positions on the line. We used RTBs to track the various tools that were in the line. All this information was tied back to the Element Web Interface, which aided decision making and communication between field and office staff.

Challenges like this are where NDT Global has always differentiated itself. We have some real advantages that we believe will help the industry.

HADDOW THUL, In-Line Pigging Solutions We recently completed a full turnkey service for decommissioning an 11 km NPS12 pipeline in a remote

How is your company weathering the COVID-19 storm? How are you adapting to current norms?

NATHAN LESLIE, NDT Global We have a phenomenal crisis team in place across the NDT Global business who continue to meet regularly and lead our organisation on a cautious path ensuring our employeesâ&#x20AC;&#x2122; and clientsâ&#x20AC;&#x2122; ongoing safety. Where practical, we have moved to remote working while maintaining the same level of service our clients have come to expect from NDT Global. What was initially a one-day working from home trial is now approaching a nine-month reality.

From a customer perspective, business continuity plans are in place across all NDT Global facilities and functions, ensuring we meet the needs of our customers. In the event we must close a facility, we are prepared to re-distribute the work immediately to ensure there are minimal disruptions to project executions. Our teams have worked hard to ensure business as usual during this uncertain time as we are in regular contact with our customers so we can understand individual restrictions and requirements related to COVID-19.

We understand the importance of ensuring our customers can continue to operate their critical assets while protecting the environment and people by managing safe pipelines with functional integrity programmes.

We have kept at a forefront the potential psychological and physical impact COVID-19 has on our employees.

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This is particularly important as the spread of the virus continues indefinitely. We continue to maintain high levels of engagement and communication with our employees. We recently ran a mental health and wellness week, to encourage and promote healthy habits and routines which benefit mental, as well as physical health.

HADDOW THUL, In-Line Pigging Solutions Our team has done a phenomenal job navigating the COVID-19 storm. Project Managers, accounting, operations, scheduling, warehouse and support staff came together working remotely to ensure there were no hiccups to operations or the success of field-based projects. Just before the pandemic hit and forced everyone to work remotely, we had fortunately adopted a new internal communication platform. This communication platform made it seem as if we were still operating in the office together.

Our field staff (which comprises approximately 70% of our workforce) went above and beyond to protect co-workers and themselves. Tailgates meetings were held remotely, everyone respected local rules, wore proper PPE, and they communicated with project managers when they felt they were in a potentially compromising situation.

Christophe BaetĂŠ, Belgium, and Gerald Haynes, USA, Elsyca, explains how remote monitoring and computational modelling can help operators transition into the digitalisation of pipeline corrosion control.

A

ccording to the NACE SP21414 and ISO18086 standards, AC corrosion risks on pipelines requires knowledge of both the AC and CP current density at a coating defect or coupon. The induced voltage is mainly a result of the pipeline coating properties, connections to grounded structures (anode beds, other pipelines, AC grounding systems, etc.) and the powerline characteristics (AC load, phase arrangement, tower configuration, etc.). An

accurate interference and mitigation design engineering study should include all these variables.

Simply installing AC groundings at the highest measured AC voltage locations on the pipe, does not necessarily address the risks at all the small surface areas of (e.g. 1 cm2) on the pipeline, as these small coating defects are difficult to detect during surveys, and therefore these risks can be overlooked.

Variations in power line load may vary significantly during a given period, due to diurnal, monthly

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or for seasonal (winter or summer) fluctuations. These variations are captured by remote monitoring devices, but their installation locations should be carefully chosen.

Pipeline case

Figure 1. Pipeline routing (blue) in collocation with high voltage AC power lines (red) with ER probes and with EMF/LEF locations.

A 27 mile-long 8 in. pipeline, in co-location with seven high-voltage AC powerlines, is used in this case study.

The pipeline collocates for 2 miles with a paralleling 345 kV powerline in the west and another 1 mile stretch is collocated with a 69 kV power line in the east. The remaining powerlines are mainly crossing the pipeline at different locations.

Computational modeling was performed using the Elsyca V-PIMS software to validate: ) The effectiveness of the AC mitigation system. ) The operational conditions of the CP system. ) The overall AC corrosion risk.

Figure 2. Corresponding V-PIMS computational model.

Figure 3. Pipe-to-soil ON potentials before and after repair of insulation joint (IJ).

Figure 4. AC potential fluctuations (measured and simulated) as function of power line load.

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World Pipelines / JANUARY 2021

The pipeline was installed in 2010. In 2016 several AC corrosion anomalies were detected during an ILI MFL inspection run. An AC mitigation system was then installed in 2017 to mitigate the induced AC voltages and AC current in the pipeline. The AC corrosion risk is monitored by eleven electrical resistance (ER) probes connected to the pipeline and eight electromagnetic field/longitudinal electrical field devices (EMF/LEF) installed adjacent to the power lines. The former device measures the corrosion rate and electrical pipeline parameters (AC voltage, AC current density, DC current density and pipe-to-soil potential) via a probe, whilst the latter device indirectly measures the power line load and phasing. The devices were installed as depicted in Figure 1.

Model calibration Field data and pipeline properties are used to calibrate the computational model such that the computed simulation results are aligned with real-world data. Recordings from the LEF/EMF devices permitted the accurate calibration of the power line load and phasing conditions.

The pipeline coating resistance/impedance of 23 kOhm.m2 for the FBE coating was computed by iterating on the pipe-to-soil ON potentials (Figure 2) and AC voltage on the pipeline (Figure 3). For the pipe potentials two different CP scenarios were considered, as the insulation joint (IJ) located halfway along the pipeline route was compromised for a period of time. The AC voltage readings over time were taken in the western parallelism where ER-probe data and EMF/LEF data was available.

The ILI anomaly size of corrosion features exceeding 10% metal loss were included to refine the coating resistance at specific spots. There was a good correlation between the measured and simulated data. Soil resistivity measurements were taken at 10 selected locations. The soil resistivity at the pipeline depth varies between 3.5 Ί-m and 253 Ί-m with the logarithmic mean value of 13 Ί-m.

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Pinpointing hot-spots The profile of the AC induced voltage along the line

Figure 5. Simulated (full line) versus measured (markers) induced AC voltage under average and maximum power line load.

with the mitigation in place was simulated and compared with survey and monitoring data at various times. Under maximum recorded powerline load the induced voltage reaches 4 V just before the insulation joint installed halfway along the pipeline route, and 13 V at the most eastern part at the receiver valve. Note that there are no ER probes installed at highest peaks in the AC voltage. The AC current density resulting from the AC voltage and local soil resistivity reaches values above 100 A/m2 in locations where monitoring devices are absent. In Figure 6 it is clearly seen that the AC grounding is required downstream of the parallelism in the west.

The simulated AC and DC current density along the pipeline are plotted in the AC corrosion risk diagram according to ISO18086 standard for those locations where ER-probes were installed, and metal loss features were detected, and maximum AC corrosion activity is determined from the computational simulations. Figure 7 demonstrates that the computational model predicts AC corrosion risks at the most vulnerable locations along the pipeline.

Mitigation

Figure 6. Simulated AC current density profile along the pipeline route under average and maximum power line load.

Acknowledging the risks and identifying the most vulnerable locations allows further improvements with the AC mitigation system. In the first instance the sensitivity of the existing mitigation design was investigated through computational modeling. Figure 8 shows that the AC grounding MIT05 system is potentially responsible for an increase in the AC current density (by a factor of five) when it is not functional.

Permanent monitoring of drainage current through the grounding systems or monitoring the pipeline potentials was recommended. Finally, three additional AC grounding systems have been designed to mitigate the risks and ensure continued pipeline integrity. At maximum power line loads the computed maximum current density does not exceed the 100 A/m2.

Conclusions Figure 7. AC corrosion risk at locations of interest under average (left) and maximum AC powerline load (full markers are under elevated CP).

Figure 8. Effect of malfunctioning AC grounding on the AC current density (west part).

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World Pipelines / JANUARY 2021

New pipelines can become easy victims of AC corrosion with increased risks when they are not properly assessed and mitigated. The risk assessment must be based upon reliable data gathered, but also gathered in the correct locations. The AC mitigation system should be design where hot-spot areas actually occur on the pipeline.

As demonstrated in this case study, specific peaks in the AC current density can occur at unexpected locations and at remote distance from the parallelism between the pipeline and power line. Computational modeling can accurately calculate these risks and predict the potential for AC corrosion attack for the entire pipeline route, on the proviso that that the models are correctly and suitably calibrated. This ultimately results in an overall cost reduction, since a considerable amount of inspection digs, pipeline repairs and monitoring devices can be avoided.

L Ian Loudon, Omniflex, South Africa, discusses the best practice for using cathodic protection systems in hazardous environments, such as those found in South Africaâ&#x20AC;&#x2122;s Sunrise Energy project.

ocated on the picturesque west coast of South Africa, Saldanha Bay, Sunrise Energy is Africaâ&#x20AC;&#x2122;s largest open-access Liquified Petroleum Gas (LPG) import terminal. It is a publicâ&#x20AC;&#x201C;private partnership between Mining, Oil & Gas Services (MOGS) and the Industrial Development Corporation (IDC). By enabling the import of LPG in large quantities, the facility advances the oil and gas sector in the province by boosting regional energy security and downstream competition. Like with any other piece of critical infrastructure, the LPG storage containers and related structures must be protected from the ever-growing risk of corrosion, particularly in coastal environments.

Corrosion is a natural, electrochemical process where metals are gradually degraded over time as part of two simultaneous chemical reactions. One of the most common examples of this is rust, where iron is electrochemically converted by water and oxygen into hydrated iron oxides. This involves two reactions, an anodic oxidation that corrodes the metal structure and a cathodic reduction, occurring at the same time. Cathodic protection (CP) systems are used to control the corrosion by ensuring that the structure to be protected remains the cathode in any electrochemical reaction. This can be done using one of two methods.

The first method is using galvanic protection, where the metal structure is connected to another metal alloy that has a more negative electrode potential than it.

This ensures that the structure is the cathode of the electrochemical cell, and the metal alloy becomes a sacrificial anode that is corroded in its place.

The second method is impressed current cathodic protection (ICCP), where a current is externally introduced into the structure to ensure that it remains cathodic with respect to its environment. For larger structures, like industrial pipelines, galvanic

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sometimes impossible, to physically check on the CP systems to make sure they are operating correctly. So, what can be done instead to make sure the system is running safely and effectively?

Safety first

Figure 1. Omniflex PowerView CP exterior.

Crucially, because of the risk of explosions occurring, all CP systems operating in hazardous areas must be intrinsically safe. This provides reassurance that the electrical equipment can operate safely in these settings by limiting the amounts of electrical and thermal energy available as a potential ignition source. This is achieved by only allowing low voltages and currents to enter the hazardous area and by preventing any significant energy storage from occurring.

In potentially hazardous environments like those involved in the Sunrise Energy project, where there are large quantities of volatile LPG, the importance of having intrinsically safe CP systems cannot be overstated. In this scenario, a single spark from a power leak could create an ignition source for a massive explosion that could endanger lives. In South Africa, the SANS 60079 standards define the requirements for electrical equipment in explosive atmospheres. All CP systems in the hazardous area must conform to this as a minimum requirement.

Remote monitoring CP systems

Figure 2. Omniflex PowerView CP interior.

protection cannot deliver the necessary current to protect the asset, so ICCP is used instead. In this method, anodes are connected to a direct current (DC) power source, which may, in turn, be connected to a transformer-rectifier (TR) alternating current (AC) power supply.

On large scale LPG projects, it is vital that CP systems are used to protect structures against the on-going threat of corrosion.

Normally, after being installed, CP systems are left to operate unmonitored, especially when they are used on structures that are underground or submerged in water, which is often the case for industrial pipelines. The same applies to the Sunrise Energy project, where large containers of volatile LPG fitted with CP systems are buried underground. In these situations, it is extremely difficult,

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World Pipelines / JANUARY 2021

Next, because it is difficult to physically monitor the CP systems in use, remote monitoring can be used to check performance and system integrity. To help provide this, Sunrise Energy engaged Omniflex, a specialist in remote monitoring and control of CP systems. Omniflexâ&#x20AC;&#x2122;s systems provide benefits such as automatic testing and results logging, long-term cloud-based data storage, regular status reports by email and alarm condition alerts by SMS and email.

Remote monitoring of CP systems in this way offers several key benefits for customers. Firstly, as regulations continue to evolve, data accessibility and transparency are more important than ever, and cloud-based remote monitoring platforms provide businesses with a single, easy-to-access repository for all live and historical data.

Secondly, by automatically monitoring and recording data relating to asset performance and system status, all abnormal events, like power outages or system failures, can be reported directly to all relevant personnel without delay. This enables site managers and engineers to act immediately, which leads to significant reductions in maintenance costs as well as avoiding any unnecessary downtime.

Thirdly, the ongoing maintenance costs are lower for enterprises that use remote monitoring technologies to monitor their CP systems. This is because they do not need to physically inspect difficult-to-access systems, like underground LPG containers, or pay for engineers to conduct routine on-site inspections. Furthermore, the duration of any necessary on-site inspections is lessened because preliminary testing can be done remotely before the visit. This reduces the overall cost and minimises any disruption caused by the inspections.

In summary, remote monitoring of CP systems provides site managers with peace of mind that their systems are operating efficiently and effectively around the clock, and alerts for when they are not.

Andre Macedo and Mauricio Brandao, Baker Hughes, Brazil, explore the mitigation measures developed in response to the risk of stress corrosion cracking in flexible pipelines.

I

n 2017, the Brazil National Petroleum Agency (ANP) issued a failure mode alert: stress corrosion cracking (SCC-CO2) triggered by the presence of CO2 in high pressure pre-salt conditions had been identified as the cause of broken tensile armour wires on a certain flexible pipe installation. Relatively common in other applications where carbon steel is subject to high CO2 concentrations, this failure mode was unknown in flexible pipe – and it presented a major challenge for operators in Brazil’s extensive pre-salt fields.

Flexible pipes have played an important role in Brazil’s history of oil production. No other oil province in the world has applied flexible pipes so intensively as the Campos Basin, for example, where approximately 2223 km of risers and flowlines have been installed to connect giant fields including Marlim, Albacora and Roncador, in water depths that range from 1500 - 2000 m. It is no exaggeration to say that flexible piping has been crucial to the development of Campos and other basins as viable production sites.

Flexible advantages Of course, flexible piping is not exclusive to Brazil. Its widespread deployment is down to the many advantages it offers to so many operators. With concentric and unbonded layers, each of which contributes to the mechanical strength and chemical resistance needed to withstand deepwater conditions, flexible pipes were designed to ensure collapse resistance, internal pressure capacity, bending stiffness and axial-load capacity – among numerous other advantages to deepwater operations.

In addition, this unique design gave operators several logistical advantages. Flexible pipes can be transported on smaller, nimbler and more cost-effective vessels. Manufacture does not require quality-sensitive offshore processes such as welding or field-joint coatings – both of which have, historically, raised concerns about operational integrity.

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As the name suggests, they also give operators the luxury of flexibility and enable them to make subtle but important changes at later stages of a project, without incurring severe cost penalties.

Once in production, flexible piping gave operators the option of moving subsea lines and re-positioning pipes in response to production needs, or postponing the exact location of productionwell placement decision. As operators started production and built knowledge of reservoir behaviour, that flexibility allowed them to optimise both output and field life.

That ability to be easily recovered, inspected, repaired, re-laid and connected at new sites was key: flexibles proved themselves to be the best way of reducing time to first oil by enabling feasible

production in short timeframes, even before reservoir de-limitation and subsea layout consolidation. They reduced the risks of drilling campaigns and delivered associated advantages in terms of time and cost.

The ANP’s announcement about SCC-CO2 in 2017 therefore had implications for the entire industry.

Addressing SCC-CO2 One short-term option was for operators to reduce their perceived risks by moving away from flexible pipe solutions and adopting rigid pipes instead. But by doing so, all the flexibility that had allowed Brazil to develop offshore fields efficiently would be lost.

Operational complexity, such as the water depth, bore size, temperatures, pressures and contaminants found in the Santos Basin, requires constant review and development of the technology – in this case, the optimisation of subsea hardware, as well as installation and operational procedures.

For this reason, Baker Hughes directed its considerable research and development efforts to the exploration of alternative mitigation measures for its clients in Brazil. In the aftermath of the problem identified in 2017, and while not experienced on its own manufactured pipes, Baker Hughes began work on an extensive programme to improve the resilience of the installed fleet and to deliver the next generation of SCC-CO2-resistant pipes.

Understanding the problem Figure 1. Flexible pipes have played an important role in Brazil’s history of oil production.

As the ANP report noted, SCC-CO2 is a condition that can induce cracking and even failure in a pipe’s steel wires. However, three conditions need to be present simultaneously for such cracking to take place: environment (water and concentrated CO2); high tensile stress exceeding a critical level; and very high-strength materials that are consequently crack-susceptible. If one of these three elements are designed out, cracking cannot happen. Since environmental conditions and high levels of tensile stress were unavoidable, the improvement had to come from the materials used in pipe manufacture.

Also, critical to developing an improved pipe solution is the knowledge that the SCC-CO2 phenomenon is defined by two stages – nucleation and propagation – and that managing them requires different, but complementary approaches.

In the case of propagation of an existing crack, fracture mechanics can be used to define the remaining life of the asset and mitigation work needed. However, a completely different approach is needed when considering the susceptibility of a pipe to crack nucleation.

In this case, multiple small-scale tests using armour wires taken from commercial products can be run for six months to simulate severe environmental conditions. When Baker Hughes ran these kinds of tests, wires were exposed to various combinations of contaminants while loaded at stresses close to the yield point.

Collaboration and composites

Figure 2. Composite pipe.

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World Pipelines / JANUARY 2021

The lab results showed that it is feasible to design and manufacture a flexible pipe to operate in a SCC-CO2 envelope without incurring any damage. In fact, the tests showed that, in pipes proposed, designed and developed by Baker Hughes, the initiation of cracking would only occur if the loading on the wires and associated stress was raised to double that experienced in the field.

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Sensors and models

Figure 3. The new material offers superior gas permeation performance, but without the traditional metallic layer that is most susceptible to CO2 damage.

Recognising that pipes in service were also a concern for operators, new ways of carrying out dissections to define initial cracks (the starting point for fracture mechanics) and calculating the service life of installed fleets was also needed. This required some means of testing to identify whether a given pipe was flooded or not.

Naturally, this is a key challenge for integrity management teams: the pipes are not designed to have this kind of verification performed once they have been installed and bringing a riser or flowline to the surface for verification is incredibly disruptive.

However, it is an area where sensor technology can deliver exceptional results. Baker Hughes’ proprietary sensor technology is now embedded into current risers for pre-salt and work continues developing methods for retrofitting sensors to installed pipe.

Such a system can detect any ingress of water from the topside into the riser annulus along its full length. It provides continuous monitoring, rather than one-off inspections, without extra vessels or ROVs. It can also cover up to five separate pipes and monitor all riser sections from the FPSO up to a 3600 m range. A database of Baker Hughes’ SCC-CO2 programme outcomes also enables quick identification of products that are not susceptible to this damage mode.

Continuing development

Figure 4. SCC-CO2 is a condition that can induce cracking and even failure in a pipe’s steel wires.

With the results of extensive testing and lab-work as a foundation, Baker Hughes began to develop solutions for its customers. One of the most important steps was to build alliances and partnerships with key material suppliers, test houses, installers and external experts such as the National Composite Centre (NCC) in the UK. This has brought experiences, insights and lessons from other industries to the manufacturing of flexible pipe, adding robustness to the qualification and validation programmes.

The outcomes of this work are a new hybrid composite material for pipe manufacturing. The new material offers superior gas permeation performance, but without the traditional metallic layer that is most susceptible to CO2 damage. Not only does the composite pipe reduce the concentration of CO2 at the tensile armors, and is not susceptible to SCC-CO2, it is also lighter than standard flexible piping. This reduces installation costs even further and allows operators to deploy risers in a free-hanging catenary, removing buoyancies, accelerating installation time and improving safety.

Recent pipe designs have also included reinforced outer layers to protect against perforation or damage during installation, while all end-fitting ports and seals can be tested against external pressure to prove their capacity in deep water. A machined area that allows ultrasonic testing inspection for detecting flooding and a visor rated to 2500 m water depth are added to end fittings.

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World Pipelines / JANUARY 2021

A team of engineers is now developing comprehensive sets of modeling tools that will be further calibrated by the test results, as well as undertaking a wide range of manufacturing trials in an automatic fibre-tape placement module. This work will enable the behaviour of any pipe structures to be predicted without repeating full qualification testing.

These kinds of testing campaigns will continue in order to confirm that all variables – and any combination of variables – that may influence or trigger the SCC-CO2 damage mechanism – are fully explored, mapped and documented to ensure the industry can develop the mitigation strategies for their particular circumstances.

However, the work in Brazil is part of an even bigger picture.

The world’s oil and gas sector faces unprecedented challenges to meet social and political demands for greater environmental responsibility and emission reduction in the face of extraordinary price pressures and capital constraints. There is, as a result, no shortage of speculation about what the new normal will look like: from autonomous operations to extremely efficient, carbon neutral developments.

What is perhaps less widely discussed is the idea that ‘normal’ of any kind will be an increasingly rare phenomenon within the oil and gas sector – or indeed within any industrial sector. Constant innovation, continual development, permanent evolution and a relentless re-assessment of what works and what can be done better, will be the defining features of successful operators and their service companies. Whether it is the use of advanced sensors, data and analytics, or the modification of manufacturing materials, almost every aspect of the business is open to re-evaluation.

The reality is composite flexibles combined with advanced sensors and conventional pipe design and manufacturing offer a viable way to continue to use flexible pipes in pre-salt without concern for SCC-CO2.

Jonathan Walker, Severn Glocon Group, UK, discusses how the convergence of mechanical and digital engineering has optimised the detection of flow control issues.

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S

afe, reliable and repeatable flow control is the cornerstone of oil and gas productivity, and valves play a crucial role in this. Yet many factors can hinder the performance of control valves in established plant pipelines. This is especially true when it comes to severe service applications such as those with high pressure drops, extreme temperatures or flashing (where vaporisation causes flow problems).

Traditionally, severe control valves are accountable for more than 80% of valve-related unplanned shutdowns. However, this is set to change. The convergence of mechanical and digital engineering makes it quicker and easier to identify, diagnose and rectify underlying technical issues that can harm overall production and profitability.

Problem valve scenarios So, what are the circumstances that can lead to compromised valve performance? Let’s take a look at some common situations.

Most of the time, problems are caused by the external production environment or the internal flow medium. For instance, extreme temperatures, humidity or salinity in the external environment can be detrimental to valves. Likewise, contaminants such as sand or black powder in the process medium can ravage internal components.

Sometimes problems occur because production parameters have changed over time. As oil and gas wells are depleted, the velocity and pressure of flow can be affected. The same is true when production is ramped up. If this is not accounted for in the specification of valves affected by the changes, their internal components can experience degradation.

Similarly, changes to pipework or assets up or downstream can have repercussions for flow velocity and pressure, which alters the physical demands placed on a control valve.

It may be that the original valve selection and specification is out of kilter with the application’s needs. When valves deployed in extreme conditions exhibit problems it is often because a standard catalogue product is being pushed beyond its limits. In other words, a mass-produced product offering ‘next best fit’ has been used instead of a custom engineered solution. But those upfront cost-savings can quickly turn out to be false economy.

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All the factors mentioned so far relate to extreme, volatile or altered production environments that push valvesâ&#x20AC;&#x2122; technical boundaries. But even well-specified, highlyengineered valves experience wear and tear over time which can lead to production issues.

The bottom line is that valve populations need ongoing monitoring, management and maintenance to ensure problems are identified and rectified at the earliest opportunity.

The valve maintenance spectrum Valve maintenance can be as simple as replacing consumable parts such as gaskets, packing sets and seals. At other times, more complex technical intervention is required.

When a valve is presenting problems, it may be that the valve trim (the internal components which contact process media) needs attention.

Trim damage can be caused by a variety of issues such as cavitation or flashing, which result from pressure let down or inherent physical properties of flowing media. In some cases, it is possible to design valve trims to withstand or eradicate these phenomena. However, modifications to surrounding pipework or evolving process conditions can introduce new vulnerabilities.

Depending on the circumstances, repair and maintenance of these valves might involve a straightforward exchange

of hard parts such as the valve plug, seat or cage. In more extreme situations, the valve may need to be taken to a specialist workshop where it can be retrofitted with a newly specified trim designed to withstand specific operating conditions.

Remote inspection and monitoring As the complexity of control valve management escalates, and commercial margins come under greater pressure, more sophisticated maintenance strategies are becoming the norm.

This movement has been further accelerated by the COVID-19 pandemic. The low oil price is one factor driving this trend, but the need for social distancing and restrictions on travel are also playing a part.

Remote monitoring is one aspect of this. Fitting legacy valves with smart positioners enables their performance to be tracked continuously against predetermined benchmarks without any need for manual intervention. Positioners maintain and control the valve setpoints, so they can provide crucial insights surrounding factors such as hysteresis, stroke time and repeatability. Introducing digital connectivity takes this to the next level, providing greater visibility and facilitating rapid response or preventative maintenance strategies.

For valves that are displaying problems, new advances in remote inspection technology are revolutionising the way they are handled. Field service engineers equipped with connected hands-free tablets can collaborate in real-time with workshop-based colleagues or service providers that offer specialist expertise. This streamlines and accelerates the remediation process before issues escalate.

Technical experts might gain frontline access to valves in Kazakhstan in the morning and a North Sea platform in the afternoon, without leaving their desk. They can see and hear valves and their surrounding equipment, gaining valuable insights to inform their decision making.

In-depth inspection of problem valves Despite the advances in remote inspection, there are times when performance problems simply cannot be identified or resolved in the field. In these situations, the valve needs to be taken offline and disassembled in a workshop where specialist valve engineers undertake a detailed inspection to diagnose the root cause and prescribe the most effective solution.

This can be a complex matter. Engineers often have to draw on data concerning the valve in question, their own wider experience and historic data about valve failures in similar circumstances. The process is like a detective investigation â&#x20AC;&#x201C; no stone is left unturned in the quest to identify the origin of the problem. Sometimes the performance issue has developed over several years, so engineers have to unpick many layers of possible causes before they can devise an effective solution.

A North Sea example Figure 1. Severe cavitation damage to a multi-stage trim.

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World Pipelines / JANUARY 2021

One such situation that Severn Glocon has encountered concerned OEM firewater pressure control valves on an

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pressure zone immediately downstream. So, as the flow medium continued through the downpipe, it would create pressure fluctuations, resulting in a ‘pull’ on the column of liquid great enough to cause it to break, then remake, causing ongoing vibration.

The solution entailed two core elements: the inclusion of a downstream diffuser tube and relocation of the valves themselves.

The installation of a diffuser tube revises the flow path, minimising the potential for downstream pressure variations.

An added advantage is that this increases the backpressure to the valve, reducing the potential for cavitation.

Repositioning the valves brings further benefits. It ensures the valves’ outlets are always full of liquid and that downstream directional changes of flow are more steady and controlled. Knowing that there was to be a requirement for higher flow volume in the future, Severn Glocon also recommended opting for a valve with a larger bore to support the required Cv and control the fluid velocity within the body envelope.

When the recommendations were implemented, the issues with vibration were resolved.

The future of flow control

Figure 2. Erosion damage to a tungsten carbide and metallic multi-cage trim.

ageing North Sea platform. The operator was experiencing high levels of vibration and pipe failure, so the company set out to reveal the root cause with an investigation focused on the control valves as well as the associated piping and its geometry.

The flow conditions presented at each valve’s inlet were accounted for, as well as downstream piping to the caisson.

Damage to the valves was certainly consistent with severe vibration. It was noted in three areas: the interface between the seat ring and the body, in the bore of the cage assembly unit and in the sealing area of the plug stem diameter. It appeared that the original manufacturer had anticipated and accounted for cavitation (when bubbles form in the process medium, then suddenly collapse as pressure recovers downstream). However, the cavitation of the process was not at a magnitude that would cause the high levels of vibration and pipe failure being experienced.

Severn Glocon had come across a similar phenomenon before, in relation to the overboard dump lines of a North Sea installation. Based on data related to this application, it was suspected that downstream piping was responsible for the valve performance issues. The company hypothesised that as fluid entered the overboard part of the pipework in question, it was being reflected backwards, thereby interacting with the ongoing flow stream and creating turbulence.

Following on from this, it was understood that the flow path taken by the liquid was likely to generate a low-

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World Pipelines / JANUARY 2021

It is exciting to see how digital technologies are making it quicker and easier to resolve performance issues caused by problem valves. Data plays a significant role here, enabling engineers to draw on a wider frame of reference when diagnosing problems and devising technical solutions.

Advances in remote monitoring and inspection are also bringing new efficiencies to valve management and maintenance, and progress can be expected to accelerate in the coming months and years.

In the not too distant future, preventative maintenance of control valves will reach new levels of sophistication.

Advances in sensor technology will aid this, identifying discreet anomalies in the sound and vibration of valves at an early stage, potentially before performance is compromised.

As more data becomes available, and tools to leverage insights from that data improve, valve management and maintenance will become increasingly refined.

Each development in this space unlocks new ways for digital and mechanical engineering to work synergistically and cohesively to drive tangible benefits for operators.

Perhaps the most transformational development is the rise of additive manufacturing techniques such as 3D printing. Severn Glocon is already exploring the use of this technology for the creation of spare and replacement valve components. It is only a matter of time before this is used to further enhance the collaboration between field service technicians and workshop-based valve engineering specialists. Digital designs for valve repairs or retrofits will be sent to 3D printing facilities for the rapid production of industry-approved components in the locality of the enduser. When this happens, turnarounds that previously took months will be slashed to a matter of hours – that really will revolutionise the industry.

Soroush Karimzadeh, Chief Executive Officer and Co-Founder of Novarc Technologies, Canada, discusses the move from manual labour to robotic technology in the oil and gas industry.

P

ipeline construction and maintenance is a challenging, high-risk work environment.

Pipeline and offshore welders are at risk from injuries due to UV light, radiant and excessive heat, carcinogenic fumes and arc flash. Combine these risks with a work environment that includes heavy equipment, suspended loads, rough terrain and extreme weather conditions, and there is obvious cause for concern.

Whether building or maintaining pipelines, working on rigs, or conducting welding operations offshore in fabrication facilities, welders are constantly exposed to these hazards. This may be the reason why the oil and gas industry is increasingly looking to automate the welding process by incorporating robotic technology.

As well as safety concerns, the welding industry is faced with a shortage of skilled welders, as many are retiring and not enough young labourers are entering the profession. In addition, there is the competitive nature of fabrication shops serving

51

the manufacturing industry. Many have seen the benefit of investing in flexible automation in order to increase their competitiveness and their bid rate on projects.

Automation

Figure 1. The Spool Welding Robot uses the power of robotics and artificial intelligence to transition offshore welding shops to automation.

Novarc’s collaborative robot technology – the Spool Welding Robot (SWR) – uses the power of robotics and artificial intelligence (AI) to transition offshore welding shops to automation.

Novarc is working with fabricators serving a number of industries globally, that need an affordable path to automation. The company’s collaborative robot provides pipe fabrication shops involved in the offshore welding industry with a smart solution to promote safety, reduce costs, increase productivity and enhance weld quality.

However, the SWR does not abandon the human operator. Instead, it works alongside the welder, allowing those with less skill and experience to do the job that previously only senior welders could perform.

The results are welds with greater precision, accuracy, speed, and a never before achieved balance of quality and productivity.

Significant gains

Figure 2. Novarc’s Spool Welding Robot (SWR) is a collaborative welding machine designed specifically for pipe, small pressure vessel, and other types of roll welding.

Figure 3. Automation solutions such as Novarc’s SWR play a key role in delivering welding projects faster and at a lower cost, within a small footprint.

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World Pipelines / JANUARY 2021

One of North America’s largest construction and engineering organisations recently purchased two of Novarc’s SWRs to work collaboratively with welders at their fabrication facility, constructing large and complex offshore platforms. According to one of the executives, it was an easy sell.

“We put our CEO on the robot, and he was able to weld a 6 in. pipe in 10 minutes. I didn’t have to do much more selling than that, except for showing the return on investment.” The client saw a return on investment in eight months, compared to three years, their maximum for realising a return on their initial investment.

“You kind of get a triple effect when you look into the return of investment situation in that I’m using lower labour, building it faster, and my overall cost is cheaper. Essentially, I can produce more units in the same footprint.”

Moving from manual welding to a collaborative process with Novarc’s SWR consistently resulted in a productivity gain of 15 - 20%, and the operators did not have to be overly experienced to deliver the same quality welds.

“The cost of labour to perform our welds decreased significantly. We could use a young welder, a fifth-class fitter, to make our welds. So there’s an added gain in needing fewer people to perform higher quality welds.”

With Novarc’s SWR, the client can produce more units on the same footprint. On average, the facility welds about 500 spools a week, in a 100 x 100 ft building. A typical pipe shop is about three times that size and has the same production rates.

Looking forward The dwindling supply of qualified labour in the welding industry is a significant issue for pipe fabricators in both

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North America and Europe, which is accelerating the need to automate. More automation can free up skilled welders from doing repetitive work, enabling them to do the more difficult welds. “The cost of labour is rising and labour is getting scarcer, so more companies are moving towards automation, because it’s the only way to survive. If they don’t invest in technology automation, then they probably won’t be around in another 10 years.”

Novarc will soon launch an AI vision system that uses algorithms to process vast amounts of data in a much more efficient way than any human can do. These algorithms will be used to fully automate the pipe welding process. The vision system, called NovEye™, minimises human interaction with the robot, and the human errors and associated costs are expected to decrease significantly.

Novarc has been working on these deep neural algorithms for the past several years. Now, with the videos and the data, the SWR also has the horsepower to run

them. These AI algorithms will help the SWR learn and adjust on its own, much as a human welder or operator of the basic SWR would. With NovEye™, the welder sets up the machine, moves the arm to the joint, hits start, and walks away while the SWR uses the AI-powered vision system to adjust welding parameters on its own.

Many leading players in pipe fabrication are looking to adopt robotic technologies that can incorporate AI systems, in order to prepare for the future.

The immediate benefits of robots incorporating AI and superior software are clear.

“The robot software allows Novarc to live link into the data to remotely access and see the same issue you’re seeing. This means you don’t have to verbally explain over the phone. They visually see the maps and the coding behind it as the SWR is operating to see the glitches, if there are any, and also help diagnose the kinks from remote access. This allows for very fast problem solving, and not having to miss something in translation or incorrectly explain the issue.”

As previously mentioned, safety is a huge concern in the oil and gas, and pipeline construction industry, and it is understood that work is awarded to fabrication shops that have a clean record and adhere to strict safety standards. “When you start putting more automation into the welding process, it practically eliminates human error. That’s a big driver into lowering costs, providing a safer place to work and a more consistent, better quality end product.

And the SWR allows you to stay within code and is very precise, and very fast.”

Novarc plans to outreach to existing SWR clients to update the weld process monitoring, so the vision system will be able to track the welding process and provide feedback in real-time to the welder. This will provide a record of the weld quality, which can then be used to determine if the joint is acceptable or if improvement is needed.

On a global level, the challenges and increasingly competitive nature of the pipeline construction industry has accelerated the shift to increased automation. The incentives for the increased use of robotics in this sector include: reducing manufacturing labour costs, improving quality and consistency, increasing flexibility in manufacturing, and decreasing costly space allocation.

All of these reasons illustrate why flexible automation allows these companies to become even more competitive, and increase their productivity and quality of their welds.

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hether the job is repairing existing or deburring new pipe, having a wheel that conforms to threads while removing excess material is vital for a secure seal. Corrosion, threadlock and burrs can destabilise the integrity of a joint by creating gaps resulting in leaks or other pipe failures. In order to effectively accomplish this operation, many oil and gas pipe experts turn to cotton fibre.

Smooth Touch is recommended for threadlock removal.

Wheel selection: critical to success Type 1 wheels are commonly manufactured from nonwoven nylon. This construction often does not allow the wheel to be dressed to match the pipe threads.

Cotton Fibre, which is denser than nylon, is easily dressable to suit the shape of any thread. Cotton fibre is also forgiving, allowing the operator to remove rust, corrosion, threadlock and burrs without altering the part geometry.

When a Rex-Cut Abrasives wheel is properly shaped to match the pipe thread it is grinding, the overall

cleaning process is 25 - 30% faster than with a nonwoven nylon wheel. In addition, a single Rex-Cut wheel typically lasts as long as 3 - 4 non-woven nylon wheels.

Shaping a type 1 wheel To prevent thread deformation, the wheel must be shaped to match the thread pattern. To shape a wheel, we recommend placing a diamond file in a vice, then pressing the edge of the wheel to it at an angle. Run the wheel until the proper shape is formed. Repeat this process on the other side of the wheel. This shape will

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Rex-Cut Type 1 GFX and HFX wheels are ideally suited for rust and corrosion removal from pipe threads. While JTX and MTX are designed for grinding thread roots and repairing cracks. For threadlock removal, Smooth Touch wheels with a medium bond are recommended. The RexCut line of pipe thread wheels are available in 2 and 3 in. wheels with the diameter sizes of 1/16 in., 1/8 in., 1/4 in. and 3/8 in. Grit sizes that are most common are: A36, A54, and A80.

Conclusion Cleaning and inspecting pipe in the oil drilling industry is a necessary process. Using the correct wheels can help make this procedure more efficient, saving inspection companies time and pipe loss.

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