World Pipelines - April 2021

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Volume 21 Number 4 - April 2021

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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 4 | APRIL 2021 03. Comment It's child's play

NDT TECHNOLOGIES 31. Around the bend

05. Pipeline news

Dominic Giguere, Zetec, USA.

New guidelines for ROV/AUVs; major contracts for Saipem, EnerMech and NDT Global; plus check the status of upcoming events (physical or virtual).

REGIONAL REPORT 10. Resilience in testing times

REPAIR AND REHABILITATION 36. Carbon composite to the rescue Luc Perrad, DENSO Group Germany.

Gordon Cope takes a look at how the Gulf of Mexico is getting back on its feet after facing a year full of trials and tribulations.

Luc Perrad, DENSO Group Germany, discusses the company’s new carbon fibre-based repair system, designed to restore and extend the service life of pipelines.

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ight and stable – for a long time, well-known technologies have made use of the properties of plastic fibres, such as rotor blades for wind turbines or solar panels in space travel. However, wing panels for aircraft or entire car bodies are also manufactured using carbon. Automotive manufacturers are aware that if you master lightweight construction using carbon fibres, you can build fast sports cars. And many tennis duels in Wimbledon would have been slower if carbon fibre reinforced plastics (CFRP) weren’t used in tennis rackets. Lighter than aluminium – harder than steel.

Gordon Cope takes a look at how the Gulf of Mexico is getting back on its feet after facing a year full of trials and tribulations.

Quick and cost-effective pipeline repairs using CFRPs

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One of the special properties of so-called carbon composite materials is that some of them have a higher strength than steel. For this reason, they also play an important role in building pipelines. As temperatures, mechanical loads and long-term chemical influences have a permanent corrosive effect on the steel on the inside and on the outside, serious defects can occur in the pipe wall. Whether this is repaired with a steel sleeve or the damaged section is completely replaced, the pipeline must first be decommissioned at great expense.

However, this is entirely different if the pipeline is repaired with the help of carbon composite materials: DEXPAND®-CF70, the new composite repair system from DENSO Group Germany, allows repairs to be made to

he Gulf of Mexico, a mainstay of US oil and gas production for over a century, was hard-hit by the emergence of the COVID-19 pandemic in March 2020. While the pain was widespread throughout last year, there are signs that the region may see better times ahead.

Onshore Thanks to the devastating decline in demand, crude prices fell sharply and drilling and completions dropped dramatically. Onshore production in the prolific Permian basin shale play (which underlies West Texas and New Mexico), fell from 4.4 million bpd in September 2019 to 4.15 million bpd in September 2020. Rig counts in the basin fell from 485 in March 2020 to 128 by October 2020.

The rapid expansion of both oil and gas pipelines in the Permian basin that occurred over the last several years has now led to a glut of transportation, with resultant deals to

PAGE Figure 1. Pipeline repair using DEXPAND®-CF70.

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CORROSION PREVENTION 16. Finding underutilised strength in an old pipeline Ajay Arakere, Senior Engineer and Marlane Rodriguez, Operations Manager – Pipeline Integrity, Corrpro Companies.

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43. Composite repair: still going strong Matt Green and Tim Mally, CSNRI, USA.

HYDROGEN PIPELINES 46. A bright future ahead for hydrogen A. S. Tazedakis, N. Voudouris, E. Dourdounis, Corinth Pipeworks, Greece, and G. Mannucci, L. F. Di Vito, and A. Fonzo, RINA Consulting – Centro Sviluppo Materiali SpA, Italy.

Image: Corinth’s plant in Thisvi, Greece, including four pipe mills, coatings/CWC and own port.

Ajay Arakere, Senior Engineer and Marlane Rodriguez, Operations Manager – Pipeline Integrity, Corrpro Companies, present a methodology for pipeline safety designed to reduce the number of unnecessary excavations and assess only those corrosion defects most critical to the integrity of a pipeline.

A. S. Tazedakis, N. Voudouris, E. Dourdounis, Corinth Pipeworks, Greece, and G. Mannucci, L. F. Di Vito, and A. Fonzo, RINA Consulting – Centro Sviluppo Materiali SpA, Italy, discuss the certification of steel pipelines for the transportation of hydrogen.

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hile pipeline incidents have declined over the past five years, there are still significant incidents that result in injury or death and property damage.1 When quantified, numerous incidents have caused over US$3 billion in property damage since 2017.2 Excavation damage and external corrosion are two of the leading causes of significant pipeline incidents.

Many of the pipelines currently in service were constructed before 1980, and there are even pipelines built during World War II. Good practices such as coatings and cathodic protection (CP) for corrosion protection have not always been standard protocol; thus, older pipelines can be expected to have corrosion and pitting damage. Since many of these pipelines are now under the jurisdiction of a regulatory agency, like the US’s Pipeline and Hazardous Materials Safety Administration (PHMSA), the assessment

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ydrogen is the most environmentally friendly carrier of energy: when consumed it solely emits water. Energy carrier means that its potential role has similarities with that of electricity. Both hydrogen and electricity can be produced by means of various energy sources and technologies. Both are versatile and can be used in many different applications. No greenhouse gases, particulates, sulfur oxides or ground level

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ozone are produced from the use of either hydrogen or electricity.1 Consequently, hydrogen is currently enjoying unprecedented political and business momentum, with the number of policies and projects around the world expanding rapidly; in July 2020, the EU Commission adopted a new dedicated strategy on hydrogen in Europe, which explores actions to support the production and use of clean hydrogen, focusing in particular on the mainstreaming of renewable hydrogen.

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22. Methods for AC mitigation Andreas Junker Olesen, PhD and Engineer at Metricorr, Denmark.

UNPIGGABLE: INSPECTION SOLUTIONS 27. The back and forth of data gathering

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OFFSHORE OPERATIONS 53. How to fund the future of subsea Neil Gordon, Subsea UK.

Bas Roosken, ROSEN Group, Europe, and Morten Solberg, KTN AS, Norway.

®

Reader enquiries [www.worldpipelines.com] Volume 21 Number 4 - April 2021

For over 30 years, 3X ENGINEERING has developed a large range of composite products for pipeline rehabilitation and has performed many successful composite repairs all over the world.

Not only does 3X manufacture and commercialise its own products, it also offers a complete integrated service, from the design of the repair to onsite installation. The company provides highly qualified engineers and technicians to perform and supervise repair operations.

Today represented by over 50 distributors all around the world, 3X is able to quickly operate onshore, offshore and subsea to reinforce pipelines suffering from various defects.

For more information, visit www.3xeng.com

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ver the course of the last year, Volvo Construction Equipment (Volvo CE) has sold over one million machines. A new and game-changing partnership ensured that, even in the midst of a pandemic, the equipment manufacturer was able to release to market its biggest ever range of excavators, loaders, haulers and trucks, which were sold in almost every major toy store.

Did I mention we’re talking about toy trucks here? That part is rather crucial.

Volvo CE signed up with toymaker Dickie Toys to embark on its first venture into fully-immersive play sets for all ages.

It is the company’s most comprehensive collaboration to date, featuring not only machines from Volvo CE, but Volvo Trucks and Mack Trucks too. This venture follows on the heels of successful partnerships with toymakers such as LEGO® Technic and Bruder.

Tim Birks, Merchandise and Licensing Manager at Volvo CE says: “Dickie Toys was a natural choice. We share the same core values, we are aligned in our desire for good quality products and we have always been impressed with the ‘feel-good factor’ of their toys. And it’s been comforting to know that these toys have played an important role in keeping children around the world entertained and engaged during some of the hardest months of the pandemic.”

“Children are fascinated by huge construction vehicles,” says Oliver Naumann, Managing Director of Dickie Toys. It’s comforting to know that children all over the world are drawn to play with construction vehicle toys. The oil and gas pipeline industry needs to find a way to prolong this natural enthusiasm and curiosity,

so that adolescents and young adults feel equally as drawn to the sector.

Next month’s issue of World Pipelines will include an interview I recently carried out with the winners of The John Tiratsoo Award for Young Achievement, which was awarded by Young Pipeliners International, in partnership with PPIM, in February. The award recognises the achievements of pipeline professionals under the age of 35 and this year the two winners are so inspirational. Jess Tufts, Superintendent, Gray Oak Pipeline and Kaella-Marie Earle, Engineer in Training at Enbridge Gas Inc. talked about their career highlights so far, their mentors and the message they would give to other young pipeliners, or to those wondering whether the industry is right for them.

You must read the full interview in the May issue, but I can’t resist giving you a preview here. Jess said: “This industry offers an abundance of opportunities, and there’s something for everyone...

I get satisfaction out of knowing that what I do every day makes a positive impact.”

Before joining Enbridge, Kaella – who is an Anishinaabekwe from Wiikwemkoong Unceded Territory and Aroland First Nation – was an anti-pipeline and environmental activist for years. I’ll let Kaella take the floor here: “Those first few months at Enbridge changed my world. I realised oil and gas is full of many great people who share my vision of a future with low carbon emissions, championing communities, and including more people at the decision-making table.

“You won’t regret a career in pipelines.

Take it from me, the former anti-pipeline and climate change/environmental activist. You can work in pipelines and still care about the land, and have a meaningful career where you can enact as much change as you want.”

THE PIPELINE INDUSTRY NEEDS TO FIND A WAY TO PROLONG THIS NATURAL ENTHUSIASM AND CURIOSITY

The time is now for a real breakthrough in pipeline inspection.

Real-time digital imaging is the new standard in pipeline inspection. NEXRAY is the new standard in real-time digital imaging.

The NEXRAY real-time radiography system is made up of two main components—a medical-grade digital detector and an x-ray source—used to generate inspection images digitally and deliver real-time image output.

Engineered to inspect the integrity of girth welds, NEXRAY is designed for onshore, offshore, spoolbase, and tie-in use in both small-diameter and largediameter applications.

A Division of STANLEY Oil & Gas

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STANLEYInspection.com

WORLD NEWS NuStar announces pipeline capacity expansion project for Albuquerque market

EnerMech secures new five year deal with Chevron Australia

NuStar Energy, L.P. has announced a plan to develop incremental pipeline capacity that will allow for the delivery of approximately 6000 bpd of additional refined products, including gasoline, diesel and jet fuel, into the Albuquerque, New Mexico (USA) region.

NuStar will upgrade pump stations on a pipeline system it jointly owns with Phillips 66 Partners that transports refined products from Amarillo, Texas to Albuquerque. In addition to increasing capacity on the system, the project will install larger and more efficient electric pumps and a modern, efficient, diesel-driven pump, providing for higher flow while reducing emissions by eliminating two diesel-driven pump stations. The project is expected to be completed by mid-2022.

“The Albuquerque Pipeline upgrades will help ensure ample refined product supply for the market which has lost production due to a recent refinery closure in the state,” said NuStar President and CEO Brad Barron. “Working with Phillips 66 Partners, we are excited that we can provide this additional capacity for our shippers and the region while also achieving the environmental benefits this project provides.”

Barron also noted that this project announcement comes on the heels of another project in a neighbouring region that resulted in increased supply for Colorado. In August 2020, NuStar completed the reactivation of an idled pump station on its Colorado Springs Pipeline system. This effectively increased the pipeline’s transportation capacity by approximately 6000 bpd of refined products.

Global integrated solutions specialist EnerMech has been awarded a five year contract by Chevron Australia to provide a range of integrated services to its Western Australian oil and gas facilities.

This agreement will see EnerMech continue to deliver pipeline services including pipe cleaning, nitrogen purging and process plant drying, integrity leak and pressure testing, hydraulic hose integrity management and specialist hydraulic services.

Paul McCarthy, EnerMech’s Regional Director for Asia Pacific said: “Having worked together since 2016, we have built up a trusted relationship with Chevron and we are proud to be continuing our work together over the next five years and beyond.

“This award recognises our ongoing commitment to serving Chevron and will allow us to build on the foundations we have in Australia as we further enhance our technology offering.”

EnerMech employs staff across 40 locations around the world. The connection with Australia goes back to 2009 when it launched in Perth. The company has expanded across Australia to provide a full complement of EnerMech’s mechanical, electrical, instrumentation and inspection services to a wide range of industries.

The team of experts has since grown and developed, delivering integrated solutions on some of the most complex challenges across pre-commissioning, commissioning, shutdown and maintenance.

Bentley Systems enters into US$1.05 billion agreement to acquire Seequent Bentley Systems, Incorporated, the infrastructure engineering software company, has announced that it has entered into a definitive agreement with investors led by Accel-KKR to acquire Seequent – a leader in software for geological and geophysical modelling, geotechnical stability, and cloud services for geodata management, visibility, and collaboration – for US$900 million in cash, subject to adjustment, plus 3 141 361 BSY Class B shares.

The acquisition of Seequent is expected to initially add approximately 10% to each of Bentley Systems’ key financial metrics (ARR, annual revenue, and EBITDA) and is expected to be measurably accretive to Bentley’s organic growth rate.

Most significantly, the combination will deepen the potential of infrastructure digital twins to help understand and mitigate environmental risks, advancing resilience and sustainability.

The acquisition is subject to customary closing conditions and regulatory approvals, including New Zealand Overseas Investment Act consent as well as clearance under the HartScott-Rodino Antitrust Improvements Act. Upon closing, Seequent will operate as a stand-alone Bentley subsidiary,

with Seequent’s current Chief Operating Officer Graham Grant, succeeding its retiring CEO Shaun Maloney, reporting to Bentley’s Chief Product Officer Nicholas Cumins.

Seequent, founded and headquartered in Christchurch, New Zealand, has more than 430 colleagues in 16 office locations, serving geologists, hydrogeologists, geophysicists, geotechnical engineers, and civil engineers in over 100 countries, and the world’s top mining companies.

Its established presence in mineral-intensive geographies such as South America and southern Africa is expected to accelerate Bentley’s overall opportunities in these regions with significant infrastructure requirements. In turn, Bentley’s established presence in China, and its mainstay reach across civil engineering sectors, is expected to accelerate Seequent’s expansion in new markets.

Seequent’s products include Leapfrog, its leading product for 3D geological modelling and visualisation, Geosoft for 3D earth modelling and geoscience data management, and GeoStudio for geotechnical slope stability and deformation modelling.

APRIL 2021 / World Pipelines

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WORLD NEWS IN BRIEF BRAZIL Forum Energy Technologies has announced that it has entered into a partnership with Deepsea Technologies Equipamentos Industriais Ltda to represent its operations in Brazil, as part of the business’ long-term growth strategy in South America.

CANADA TC Energy Corporation and TC PipeLines, LP (TCP) have announced that they have completed the previously announced merger pursuant to an Agreement and Plan of Merger dated 14 December, 2020. The merger resulted in TC Energy acquiring all of the outstanding publicly-held common units of TCP and TCP becoming an indirect, wholly owned subsidiary of TC Energy.

UK Maersk Training UK has launched the first half of its refurbished Aberdeen safety and survival centre which has undergone a £720 000 refurbishment to ensure it meets the needs of the industry as it looks to the future and the energy transition. The investment has allowed for the training facilities to be upgraded and strengthens the centre’s safety offerings to the North Sea workforce.

Australia DNV is supporting Energy Networks Australia’s demonstration on how it will enable the blending of renewable and decarbonised gases into its networks by 2030, and de-risk conversion of the networks to 100% renewable and decarbonised gas by 2050. The plan is co-funded by Australian Pipelines and Gas Association, the peak body representing Australasia’s pipeline infrastructure.

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World Pipelines / APRIL 2021

ClassNK releases guidelines for ROV/AUV Leading classification society ClassNK has released its “Guidelines for ROV/AUV” which summarise the performance and safety requirements for remotely operated underwater vehicles (ROVs) and autonomous underwater vehicles (AUVs) as part of its activities to meet industry needs related to the establishment of safety standards for innovative technologies and third-party certification.

Up until now, ROVs and AUVs have been mainly used for oceanographic surveys and offshore oil and gas field development, but in recent years their utilisation as a means for maintaining offshore wind power generation facilities and pipelines has been steadily increasing. Although the utilisation of ROVs and AUVs is increasing worldwide, no international standardisation of such technologies has yet been implemented, and the utilisation of ROVs and AUVs has, for the most part, been limited to certain fields.

With this in mind, in order to contribute to the safe and effective use of ROVs/AUVs, ClassNK developed the guidelines which establish requirements related to the equipment and basic items that are

generally required for the operation of these vehicles, as well as precautions and safety measures, based on the knowledge obtained through demonstration experiments with experts and companies making advanced efforts.

The guidelines also explain related terms, classifications, and utilisation examples so that they can be used as introductory material on ROVs/AUVs. For implementing specific application cases of ROVs, they include the requirement for ROVs service suppliers as well as the procedures in using at ship surveys such as in-water surveys, internal hull surveys of flooded compartments, and damage verification. Appendices that contain excerpts of relevant rules and the results of demonstration experiments into the application of ROVs to ship surveys are also provided for supplementary purposes.

Recognising that the utilisation of ROVs/AUVs will be expanded in various fields, the society will gather the opinions and feedback of the industry and continue to update the guidelines in order to meet the needs for safety standards development and third-party certification.

Saipem awarded new contract by Qatargas for North Field Production Sustainability Pipelines Project Saipem has received from Qatargas a Letter of Award for a new contract worth over US$1 billion, related to the North Field Production Sustainability Pipelines Project located offshore and onshore the North-East coast of the Qatar peninsula.

The additional contract (EPCL package) entails the engineering, procurement, construction, and installation of offshore export trunklines and related onshore tie-in works and is part of the development of the North Field production plateau, which also includes the EPCI of offshore facilities (EPCO package) previously awarded to Saipem in February.

The scope of work for this award (EPCL package) includes three export trunklines starting from their respective offshore platforms to the Qatargas North and South Plants in Ras Laffan Industrial City for a total length of almost 300 km, as well as

associated onshore tie-in works and brownfield activities on existing onshore and offshore facilities. Pipelaying operations will be executed by the DE HE and Saipem Endeavour vessels.

Saipem will enhance the overall project execution, comprising both EPCO and EPCL scope of work, by combining relevant planned schedules and project management and will start activities immediately. Project completion is expected by mid-2024.

Stefano Porcari, Saipem E&C Offshore Division COO, commented: “This additional contract awarded by our key client Qatargas strengthens our consolidated relationship and represents a further proof of the trust in Saipem’s ability to deliver challenging projects and is a sign of success of our positioning strategy in Qatar. We are very proud to increase our contribution to such a strategic development for the country”.

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World Pipelines / APRIL 2021

Ancala Midstream secures gas transportation and processing contracts with Lundin Energy Norway Ancala Midstream Acquisitions (Ancala Midstream) has secured a life-of-field contract to transport and process gas from the Solveig field located in the Norwegian sector of the North Sea. The Solveig field is operated by Lundin Energy Norway AS (Lundin), one of Europe’s leading independent oil and gas exploration and production companies. First gas is expected in 3Q21 and will be processed through Ancala Midstream’s capacity in the Beryl pipeline and the Scottish Area Gas Evacuation pipeline and terminal (SAGE System) at St. Fergus in Scotland.

Aberdeen headquartered Ancala Midstream will also provide transportation and processing for Lundin’s extended production test on the Rolvsnes field which is expected to commence production in 3Q22 and is also located in the Norwegian Sector of the North Sea. Solveig is the first of two new fields tying

Trans Adriatic Pipeline and NDT Global to complete survey for TAP NDT Global, a leading supplier of ultrasonic inline inspection, acoustic resonance technology (ART), and advanced data analytics are proud to announce they have been awarded the contract to complete a baseline inspection survey for Trans Adriatic Pipeline (TAP) AG, headquartered in Baar, Switzerland.

This 878 km large-diameter gas pipeline system possesses many challenging characteristics, including mountainous terrain, high elevation profile, high wall thickness and a complex subsea depth profile. NDT Global’s ART Scan™ technology manages all these challenges, while seamlessly combining wall thickness, geometry, and mapping survey capabilities into a single inspection.

Willem Vos, Head of Product Management commented: “NDT Global are excited to begin this baseline inspection programme with Trans Adriatic Pipeline. This award further illustrates that gas pipeline operators recognise the advantage of high accuracy UT inspections and further solidifies the future of acoustic resonance technology in the global gas pipeline market.”

into Ancala Midstream’s capacity in the SAGE System in 2021 and will increase Ancala Midstream’s throughput in the SAGE System to 55%.

Jim Halliday, Chief Executive of Ancala Midstream, commented: “The addition of two new fields and the substantial reserves growth from the prolific Edvard Grieg area, provides further evidence of the strong prospectivity in the SAGE catchment area, as well as the confidence our customers have in the SAGE System as their offtake system of choice. We have worked closely with Lundin to develop innovative solutions to the technical challenges faced and in doing so reduced project development costs for the Solveig and Rolvsnes Owners.

“Ancala Midstream’s growth since 2017 shows that our operating and commercial strategy is delivering results. We would like to thank the other SAGE owners for their collaboration.”

THE MIDSTREAM UPDATE •

Black Bear Transmission sells Alabama gas gathering assets

•

Creaform releases Pipecheck 6.1 software for NDT

•

Phillips 66 names new President and COO

•

TMK announces 2020 IFRS results

•

Global offshore pipelines market to reach US$17.8 billion by 2027

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Gordon Cope takes a look at how the Gulf of Mexico is getting back on its feet after facing a year full of trials and tribulations.

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he Gulf of Mexico, a mainstay of US oil and gas production for over a century, was hard-hit by the emergence of the COVID-19 pandemic in March 2020. While the pain was widespread throughout last year, there are signs that the region may see better times ahead.

Onshore Thanks to the devastating decline in demand, crude prices fell sharply and drilling and completions dropped dramatically. Onshore production in the prolific Permian basin shale play (which underlies West Texas and New Mexico), fell from 4.4 million bpd in September 2019 to 4.15 million bpd in September 2020. Rig counts in the basin fell from 485 in March 2020 to 128 by October 2020.

The rapid expansion of both oil and gas pipelines in the Permian basin that occurred over the last several years has now led to a glut of transportation, with resultant deals to

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producers fighting to fill new and old lines. 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.

Projects have also been delayed. In June 2020, Phillips 66 put the 400 000 bpd Red Oak pipeline (designed to transport crude to the Texas Gulf Coast via Cushing, Oklahoma) on hold. Enterprise Products Partners deferred the start-up of its 450 000 bpd Midland to Echo 4 crude pipeline by six months, to 2Q21. Energy Transfer downscaled its planned 500 000 bpd Ted Collins pipeline from Houston Ship Channel to Nederland, Texas, to 275 000 bpd.

Enterprise and six other partners are forging ahead with the Wink-to-Webster network, a 1.5 million bpd crude and condensate system in Texas that will service ExxonMobil’s 560 000 bpd refinery in Baytown and its 362 000 bpd refinery in Beaumont. The system is expected to enter service in 2Q21. Energy Transfer is also continuing with its expansion of its 570 000 bpd Bakken-to-USGC crude network. The expansion to 750 000 bpd relies primarily on adding pump stations, which is a fraction of the cost of new-build.

Most new gas pipelines projects in the Permian are still on track. 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), are expected to be completed this year. In January 2021, Double E submitted a request to the Federal Energy Regulatory Commission (FERC) to begin construction on the Double E pipeline, a 135-mile conduit designed to move up to 1.35 billion ft3/d of natural gas from the Summit Lane Plant in the Permian basin to the Waha Hub. Double E has secured ExxonMobil as an anchor shipper (which also holds a 30% stake in the project).

The line is expected to enter service late in 2021.

US offshore Offshore Gulf projects have larger capex and longer lead times, making them more immune to price shocks than shale plays.

Nonetheless, Baker Hughes reported that the USGC offshore rig count had dropped from 22 in March 2020 to 12 by April, the lowest count in a decade.

The biggest impact on offshore production last year was from hurricanes. The 2020 season (which runs roughly from 1 May to 1 November), was one of the worst in recorded history.

The Atlantic and Gulf region experienced 30 named storms, with five hurricanes and one tropical depression disrupting crude production. In August alone, two major hurricanes, Marco and Laura, landed in Texas and Louisiana mere days apart; shut-ins related to high seas, winds and rain reduced crude oil production for that month by 27%, or 453 000 bpd, to an average of 1.2 million bpd. At Laura’s peak, nearly half of 643 offshore production platforms were shut-in, dropping the region’s daily crude production by 84%.

While oil production crept back up to over 1.7 million bpd in September, Hurricanes Delta and Zeta hit the region in October, dropping average production for the month to 1.29 million bpd. According to the EIA, it wasn’t until December 2020 that production recovered to 1.92 million bpd; in all, producers lost 42 million bbl of production due to hurricanes in 2020 alone, just under the 44 million bbl lost during the previous decade in total.

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World Pipelines / APRIL 2021

In order to keep exploration and development costs down, offshore explorers are looking for prospects that will add incremental reserves to existing plays. In late January 2021, Kosmos Energy made a significant oil discovery in the Winterfell prospect.

The well, drilled in 5300 ft of water to a depth of 23 000 ft, was testing a sub-salt Upper Miocene prospect in the Green Canyon region. The well encountered 85 ft of net oil pay in two intervals.

The find, which is located within tie-back distance, will be further delineated, adding to Kosmos’ 100 million bbls of potential reserves in the play.

“We are pleased to have started the New Year with exploration success at Winterfell validating our proven basin exploration strategy, which is focused on low cost, short cycle, low carbon development solutions,” said Andrew G. Inglis, Kosmos Energy’s Chairman and Chief Executive Officer, in a company statement.

Operators have also dramatically reduced the costs of Greenfield platforms due to better supply-chain logistics, standardised hub designs, and sizing hubs for nearer-term output rather than long-term. Shell drastically altered its Vito project in the Mississippi Canyon area, shaving 70% off the costs of the original concept. When it enters production in 2021, the fourcolumn, semisubmersible floating production unit will have the capacity for 100 000 bpd of crude and 100 million ft3/d. BP’s Mad Dog 2 project, also expected to enter production in 2021, will have a capacity of 140 000 bpd. The initial cost in 2013 was estimated at more than US$20 billion, but BP and partners spent three years simplifying and standardising the design, reducing costs by over 60%, to US$9 billion.

Some offshore operators are selling Gulf assets to concentrate on other basins. Hess sold its 28% interest in the Shenzi Field in Deepwater Gulf of Mexico to operator BHP Billiton for US$505 million. “Proceeds will be used to fund our world class investment opportunity in Guyana,” Chief Executive Officer John Hess said.

Offshore lease sales The Gulf of Mexico Outer Continental Shelf (OCS), covering approximately 160 million acres, is estimated to contain approximately 48 billion bbls of undiscovered, technically recoverable oil and 141 trillion ft3 of undiscovered, technically recoverable gas.

A US Gulf of Mexico oil and gas lease round held in late November 2020 proved surprisingly robust. The Bureau of Ocean Energy Management (BOEM), raised US$120 million from 23 companies bidding on 93 blocks. One-third of those blocks were in 1600 m or more, with Repsol Equinor placing a successful bid of US$121 million on ultra-deepwater block NG15-06 in the Walker Ridge exploration region. “Despite circumstances imposed by the coronavirus, we are confident that industry remains interested in acquiring new leases to support their portfolios,” said Mike Celata, Director of BOEM’s Gulf of Mexico Region. “The Gulf of Mexico is a world-class resource area that serves a key role in our nation’s energy security.”

Challenges One of the first moves under President Biden’s administration was to order the Interior Department to enact a 60 day moratorium

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on issuing oil and gas leases on all federal lands, minerals and waters “to the extent possible” and undertake a “rigorous review” of existing leasing and permitting practices (the order will not restrict activities on land held in trust for Native American tribes).

The Bureau of Ocean Energy Management (BOEM), subsequently cancelled a March 2021 lease sale that would have offered 78.2 million acres in the Gulf of Mexico. Currently, leases on federal lands account for approximately 10% of US supplies.

If the moratorium should eventually turn into a permanent ban, such a move would have a significant negative impact on the Gulf of Mexico. The American Petroleum Institute (API) estimates that a ban would cause offshore crude production to drop 44% by 2030, and offshore gas production to fall by 68%. Imports would have to increase by 2 million bpd, resulting in US$500 billion being spent on foreign supplies.

The Biden administration also cancelled TC Energy’s Keystone XL pipeline. First proposed in 2008 as a 2000-km ‘bullet line’ to deliver 830 000 bpd of Alberta crude to the USGC, the Obama administration refused to approve a cross-border permit. Upon his election, President Trump used an executive order to reverse the decision, but Biden’s move is considered to be the nail-in-thecoffin for the US$8 billion project.

The government of Alberta, which had invested US$1.5 billion in the project, was understandably upset. “We are deeply disturbed that one of President Biden’s first actions in office has be to rescind the presidential permit for the Keystone XL pipeline border crossing,” said Alberta Premier Jason Kenney. “This is a gut punch for the Canadian and Alberta economies. Sadly, it is an insult directed at the United States’ most important ally and trading partner on day one of a new administration.”

COVID has had a significant negative impact on Gulf deepwater export terminals. Prior to the pandemic, there were a dozen proposals to build facilities that could accommodate very large crude carriers (VLCCs), capable of carrying up to 2 million bbls to market. Currently, exporters must use smaller vessels to transport crude out to VLCCs moored in deeper waters.

The 18% drop in Permian production – as well as decreased consumption in consumer markets – has halved exports from the US, which has taken the urgency out of the stampede, and there are now only three export proposals before federal maritime regulators. Phillips 66 and Trafigura are slow-walking their application for the Bluewater Texas Terminal (BWTX) project in Corpus Christi, supplying regulatory-compliance information as needed. Enterprise Product Partners and Enbridge’s Sea Port Oil Terminal (SPOT) in the Houston Ship Channel is pushing its approval process into latter 2021, and Sentinel Midstream has suspended permit reviews for the Texas GulfLink deepwater port in Freeport.

Environmentalists are also stepping up opposition. Sierra Club has submitted a petition to Maritime Administration opposing the Bluewater terminal. “There is huge community opposition around these projects,” said Sierra Club attorney Devorah Ancel.

While hurricanes mostly affected offshore production, extreme cold impacted onshore fields. A Polar vortex hit Texas and the USGC in February 2021, blanketing the state in snow, ice and severe cold. Wells froze and refineries shut due to power outages. Analysts estimated that more than 30 million bbl of production was lost, as well as 3 million bpd of refinery production for more than a week.

14

World Pipelines / APRIL 2021

The future BloombergNEF, a research service, estimates that US shale oil producers have cut their average breakeven costs from US$44/bbl in 2019 to under US$36/bbl in 2020 through improved efficiencies, optimised well and field operations, and renegotiated service contracts. With the announcement of OPEC+ production cuts in early 2021, the price of WTI crude has crept above US$60.

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 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.

Regardless of Keystone XL’s cancellation, USGC refiners are increasingly relying on Canadian heavy crude to fill their feedstock slates. Enbridge is the largest crude exporter to the US, shipping over 3 million bpd on its extensive network. The Calgary-based company is increasing capacity to the US through incremental additions. The renovation of Line 3 running through Minnesota and the expansion of Southern Access connecting to Patoka, Illinois (both expected to be completed in 2021), will add approximately 375 000 bpd capacity to the US Midwest. From there, the reversal of Marathon and Plains All America Capline Pipeline from Patoka to Louisiana will create 1.2 million bpd of new access to the Gulf Coast.

Prices are showing signs of stabilising. In January, Saudi Arabia announced an extra 1 million bpd production cut for 1Q21, spurring WTI prices to exceed US$50/bbl and Henry Hub gas prices to reach US$2.70/million Btu. So far, crude prices have remained strong, and analysts estimate that cash from operations (CFO) for US shale operators will rise from US$55.7 billion in 2020 to US$73.6 billion in 2021, paving the way for increased capital expenditures. With some Permian break-evens currently hovering around US$40/bbl, operators have re-deployed crews in the basin, and the rig-count was approaching 200 in late January 2021 (and offshore rigs increasing to 16). Operators are also allocating more capital to bring drilled but uncompleted (DUC) wells online. The Permian basin contains over half of all US DUCs. In June 2020 it had swelled to 2400 wells, but by early 2021 it had dropped to 1900, a 20% reduction.

Paradoxically, the Biden administration’s moves may, in the end, bode well for domestic producers. Goldman Sachs analysts note that the president’s proposed US$1.9 trillion stimulus would boost US demand by 200 000 bpd while at the same time restricting supply through drilling bans. The result will be to prop up crude prices for the next several years.

Eventually, a semblance of normalcy will return to the energy sector as vaccines help the pandemic recede and raise fuel consumption. While renewable energy sources will continue to make strides, an immense appetite for fossil fuels will persist 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.

Ajay Arakere, Senior Engineer and Marlane Rodriguez, Operations Manager – Pipeline Integrity, Corrpro Companies, present a methodology for pipeline safety designed to reduce the number of unnecessary excavations and assess only those corrosion defects most critical to the integrity of a pipeline.

W

hile pipeline incidents have declined over the past five years, there are still significant incidents that result in injury or death and property damage.1 When quantified, numerous incidents have caused over US$3 billion in property damage since 2017.2 Excavation damage and external corrosion are two of the leading causes of significant pipeline incidents.

Many of the pipelines currently in service were constructed before 1980, and there are even pipelines built during World War II. Good practices such as coatings and cathodic protection (CP) for corrosion protection have not always been standard protocol; thus, older pipelines can be expected to have corrosion and pitting damage. Since many of these pipelines are now under the jurisdiction of a regulatory agency, like the US’s Pipeline and Hazardous Materials Safety Administration (PHMSA), the assessment

16

17

of a pipeline’s heath with regards to integrity and corrosion is a common practice today. Assessment typically includes the excavation, inspection, and remediation of all identified corrosion defects that are greater than 50% wall loss, as well as modelling to determine a time frame for other identified corrosion anomalies to reach a critical size.

During the design of a pipeline, a wall thickness is determined that includes mill tolerances, defect tolerances, and tolerances for time-dependent threats, such as external corrosion, that could compromise a pipeline’s integrity. Out of all the tolerances considered during the design phase, external corrosion would be the most uncertain time-dependent feature that would require maximum tolerance. However, after a pipeline has been in service for decades, and regular abovegrade electrical surveys and constant monitoring have been performed, we could almost certainly know the pipeline’s corrosion characteristics.

Design philosophies have changed over the years. Older, more conservative design methods have been replaced by modern design principles that, without a reduction in safety, allow for higher operating stresses. For example, in the 1950s, the wall thickness of pressure equipment was designed so that the pipe or pressure vessels’ maximum hoop stress but would not exceed the allowable stresses. Now, modern design methods are based on well-established fracture mechanics principles which permit the use of higher permissible stresses. Therefore, older pipelines have large safety factors and tolerances which result in the underutilisation of wall thickness material. To ensure efficient utilisation of all thickness material, a methodology was developed to calculate a new nominal wall thickness which could potentially save pipeline operators from excavating significant amount of pipe unnecessarily.

Figure 1. Methodology approach.

18

World Pipelines / APRIL 2021

Theoretical case study The hypothetical case looked at pipeline construction from several decades ago that did not have an external coating or CP. When pipeline integrity became more widely monitored and federally regulated in the US, the hypothetical pipeline was dug up and inspected for corrosion, then an external coating was applied to the pipeline. Due to regulatory requirements and advancements in technology, this hypothetical pipeline also has inline inspection (ILI) data to use in assessing the pipeline’s condition.

Due to the years without external coating or CP, the assumption is that general corrosion exists along the pipeline along with areas of severe deep pitting. Based on the conservative wall thickness design, many of these corrosion defects would be at 50% of the nominal wall thickness and considered detrimental to the pipeline’s safety. Therefore, it would require immediate excavation and remediation. We assumed that internal pressure is the only loading acting on the pipeline and external corrosion is the predominant threat.

Hypothesis The authors believe that the aforementioned case (or similar events) is a story that many pipeline operators could tell about one or more pipelines in their portfolio. Despite vintage pipelines having experienced severe corrosion, we believe there is still sufficient remaining strength in the pipeline for safe operating conditions (MAOP). Thus, we were motivated to develop a methodology to identify and target only the most critical corrosion defects accurately. Our goal was to apply commonly used standards in the industry to identify the corrosion defects that have the most significant risk to the pipeline’s integrity, and reduce the total quantity of unnecessary pipeline excavations and repairs.

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Figure 2. External corrosion defect.

Optimised nominal wall thickness We can accomplish our goal by determining an ‘optimised’ nominal wall thickness, using information known about the pipeline and its external corrosion threat. We will apply that knowledge to commonly used American Petroleum Institute (API) and American Society of Mechanical Engineers (ASME) standards. The following two approaches were considered: bottom-up and top-down.

Bottom-up This approach uses ASME B31.4, which is the design code for the mechanical design of liquid systems. We determined for the minimum wall thickness required on the internal design pressure (or MAOP), the pipe’s outside diameter and an allowable stress of 72% of the specified minimum yield strength (SYMS). This bottom-up approach sets the bottom line for your optimised wall thickness.

Top-down The top-down approach is similar to an API 579 Level I assessment and utilises wall thickness averaging. This method is used extensively in the refining and petrochemical sectors to analyse small segments of pressure components. Then, we use the data available for the pipeline to determine the average remaining wall thickness. This approach was validated using the co-efficient of variation (CoV). Our theoretical test sets found the CoV to be less than 10%, suggesting the method is an acceptable one.

In both approaches, allowances for corrosion and repairs should be taken into consideration when utilising them to determine an optimum wall thickness. This method will allow for a conservative and safe approach.

As seen in Figure 1, using engineering judgment and conservative assumptions about future corrosion growth, as well as allowances for possible repairs and optimised the established thickness. In the test case, the %SMYS for the optimised wall thickness was slightly higher than the current operating stress.

However, there was still enough remaining wall thickness to withstand the internal pressure and some secondary bending stresses. It was assumed that internal pressure is the only primary load acting on the cross-section of the pipeline.

corrosion defect depth and length are determined.

An external corrosion defect can sometimes grow to unacceptable depths and potentially cause failure due to active corrosion. Therefore, to evaluate a pipeline’s condition in the future, it is prudent to estimate the time it will take for the defect to grow to an unacceptable depth and fail. This is done by modelling the growth of the fault using a predicted corrosion rate. The accurate prediction of the corrosion growth rate is critical, and therefore, should be somewhat conservative. Corrosion growth rates can be determined in many ways depending on the available data for a specific pipeline. Some methods can include: ) Comparing multiple ILI tool runs over multiple years. ) Performing actual thickness measurements in a laboratory or

on the pipeline when it’s excavated. ) Utilising Uhlig’s data for freely corroding steels and

cathodically protected steels based on soil drainage and soil resistivity. ) Estimating corrosion growth rate is, therefore, an important

parameter and accurate prediction is critical.

Defects acceptance criteria Defect assessment curves were constructed using the modified B31G equation based on the newly established optimised wall thickness. A minimum safety factor of 1.25 is recommended in ASME B31.G, but we utilised a very conservative safety factor that corresponded to 100%SMYS. We used this safety factor and the MAOP to develop an ‘acceptance criteria’ curve for defects, meaning any defects that fell below the curve would be considered unacceptable for the pipeline’s safe operation. A second ‘acceptance criteria’ for defects was also based on the anomalies that were greater than 50% of the new optimised wall thickness.

Using our hypothetical data set and the optimised wall thickness, we found a 70% reduction in unacceptable anomalies compared to the nominal wall thickness.

Conclusions Statistical and risk-based methods are often explored to determine the optimum way to assess pipeline safety. The approach presented above achieves the same objective but is based on ASME and API codes’ proven design principles.

With the leading threats to a pipeline being excavation damage and corrosion, it is believed that this approach would increase pipeline safety by reducing the number of unnecessary excavations and assessing only those corrosion defects most critical to the integrity of the pipeline.

Corrosion defect analysis Once a new ‘optimised nominal wall thickness’ is determined, it can be applied to defects already identified in the pipeline.

Figure 2, an external corrosion defect, shows what happens when the optimised nominal wall thickness is used; a new

20

World Pipelines / APRIL 2021

References 1.

2.

2021 Report for America’s Infrastructure: https://infrastructurereportcard.org/ cat-item/energy/ USDOT Pipeline and Hazardous Materials Safety Administration: Pipeline and Hazardous Materials Safety Administration (dot.gov).

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Andreas Junker Olesen, PhD and Engineer at Metricorr, Denmark, outlines various methods to stop AC corrosion, based on present knowledge about the mechanisms involved.

22

H

ow do you stop AC corrosion? Undoubtedly, this is a question that countless pipeline operators have asked themselves when experiencing an induced AC voltage on their pipelines from high voltage transmission lines. The answer is not easily found in an ordinary Google-search, primarily because the available literature points in many directions and is strongly influenced by commercial interests. This article will attempt to outline various methods to stop AC corrosion, based on the present knowledge about the involved mechanisms. The author wrote his PhD

23

on “AC Corrosion of Cathodically Protected Pipelines” and has authored several peer-reviewed papers and conference proceedings on the topic.1

What is causing AC corrosion?

As the name implies, AC corrosion is caused by an alternating current passing through the metal-electrolyte (pipe-soil) interface. While the actual corrosion mechanism is still debated, we have a pretty good understanding of the influencing factors.

An alternating current can pass in different ways, as outlined below: ) Through charging and discharging of the electrochemical double layer i.e. as current passing through a capacitor, which is unlikely to contribute to any corrosion. ) Through electrochemical reactions carrying a charge, such

as oxidation and reduction reactions, which may cause corrosion.

24

-JDC (A/m2)

JAC (A/m2)

AC voltage (V)

CP Potential (VCSE)

Thickness (μm)

Corrosion rate (μm/y)

The fraction of the current that potentially carries charge electrochemically is determined by many factors. One of Induced AC Small Defect Excessive CP these is the AC frequency. The fraction of the AC current discharge that contributes to corrosion is small for higher frequencies. At 50 - 60 Hz, which is the common AC signal Pre-requisites in the transmission grid, the fraction is perhaps only a few percent, but this may still be sufficient to cause significant Increased AC Increased DC corrosion. Smaller coating defects will cause the current to be Current (CP) Current concentrated locally, thus increasing the AC corrosion risk.

Whether the electrochemical reactions actually lead to Ohm’s Law Alkalinity corrosion, or not, is highly dependent on the metal’s surface oxides, solution chemistry, pH, hydrogen evolution and Reduced Spread Resistance electrochemical potential, all of which are strongly affected by cathodic protection (CP). Therefore, a fundamental part Figure 1. Autocatalytic nature of AC corrosion on cathodically of understanding what AC corrosion is, is understanding the 2 protected pipelines (Figure from NACE SP21424-2018). role of CP. AC corrosion is often observed when there is inadequate CP 510 1200 or excessive CP, in combination with Thickness (ER) an alternating voltage. This implies 500 1000 Corrosion rate (48 hrs) that there is an intermediate CP range 490 800 where corrosion does not occur. This 480 600 has been found empirically to be Corrosion rate reducing C around -1.0 VSCE, but dependent on 470 400 Corrosion stopped electrolyte properties. In this range D 460 200 there may still be an alternating current passing through the metal450 0 -1 01/06 15/06 29/06 13/07 27/07 electrolyte interface, but the surface Turn down CP B 20 -1.1 Low AC interference properties are such that this does A -1.2 not lead to active corrosion. This is 15 -1.3 possible via redox reactions within 10 some passive films, for example.

-1.4 The most relevant industry -1.5 5 Uac standards on the topic are NACE -1.6 Eon SP21424-2018 or ISO 18086:2019, 0 -1.7 50001/06 15/06 29/06 13/07 27/07 that correctly outline both AC and 14 Jac DC current densities as important -Jdc 400 12 parameters in the evaluation of AC 10 300 corrosion risk.2,3 Figure 1 illustrates the 8 “autocatalytic nature of AC corrosion 6 200 of cathodically protected pipelines” 4 100 as described in NACE SP21424 and it 2 states that three pre-requisites are 0 0 needed for AC corrosion to occur: 01/06 08/06 15/06 22/06 29/06 06/07 13/07 20/07 27/07 Date induced AC; a small coating defect; and excessive CP. Acknowledging that Figure 2. Remote monitoring data from ER probe on AC interfered pipeline. A) Natural period corrosion is caused by AC current, of low AC interference leads to lowering of corrosion rate. B) Operator changes the pipeline this describes the self-perpetuating on-potential from -1.6 V to -1.2 V(CSE). C) As a result of the change in on-potential, the AC corrosion rate reduces. D) AC corrosion has been stopped by a change of CP settings. mechanism in which CP enhances the

World Pipelines / APRIL 2021

MetriCorr alternating current density and thereby the driving force for corrosion.

Corrosion & Cathodic Protection Remote Monitoring

How to stop AC corrosion Back to the relevant question: how to prevent pipeline corrosion caused by AC interference? There is more than one way to do this, all being indirectly mentioned in Figure 1 as the three pre-requisites.

Option 1 – Remove induced AC This is the obvious solution, given that it is the driving force for corrosion, but it is an expensive solution with conventional mitigation designs, and it is practically impossible to completely remove induced AC. Even a few volts of AC might still be enough to cause AC corrosion.

Option 2 – Remove small defects Imagine a perfect world with no coating defects at all. It would effectively stop all forms of corrosion – but it does not exist. Poorly coated pipelines with larger defects and a low coating impedance are well ‘grounded’ and less likely to suffer AC corrosion, but this raises other concerns with respect to CP.

Option 3 – Remove excessive CP This implies aiming for the previously mentioned intermediate CP range where corrosion does not occur, despite an induced AC voltage. This solution is readily available to most pipeline operators with rectifier-controlled CP. It may necessitate a higher level of monitoring to verify the effectiveness of this strategy.

Each of these three actions potentially eliminates AC corrosion on their own but will also be effective in combination. Option 2 is not practically possible. In fact, implementation of modern high impedance pipeline coatings makes it even more plausible to have fewer and smaller coating defects where AC current discharge may concentrate.

For this reason, new pipeline coatings are often blamed for being partially responsible for the increase in AC corrosion incidents. But this is unfair, since better coatings are beneficial for more accurate CP control and effective implementation of option 3.

Options 1 and 3 are left to the pipeline operator as the only viable solutions to a potential AC corrosion problem. Which of the two options is the better alternative is always up to the operator to determine, since there may be a number of circumstances to consider, apart from AC interference. Typically, safety and economy become the governing factors. AC mitigation may be necessary from a safety perspective (touchvoltage <15 V in the US) while adjusting a rectifier and setting up remote monitoring is the cheaper alternative to prevent AC corrosion, compared to conventional AC mitigation installations.

Remote Monitoring is the Best and Cheapest AC Mitigation Available How? The purpose of AC mitigation is to prevent AC corrosion of buried pipelines. From a corrosion perspective, it is the AC current density that is the driving parameter. Several studies have shown that this can readily be reduced by careful control of the applied CP. )DU PRUH HႇHFWLYH WKDQ $& grounding installations.

The trick is to keep a balance between AC and CP, and to GRFXPHQW WKH HႇHFWLYHQHVV of this strategy. This has never been easier, than with the ICL (interference corrosion logger), Masterlink (RMU), and high sensitivity ER probes from MetriCorr. $QDO\]H &3 HႇHFWLYHQHVV E\ the most intuitive parameter; the corrosion rate! And a lot more.

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

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

Example of CP control Figure 2 shows monitoring data from an ER probe installed on a high-pressure gas pipeline in a utility corridor with three different 60 Hz powerlines (46, 138 and 345 kV).4 This was one of

MetriCorr – www.metricorr.com – info@metricorr.com

five monitoring positions on the line that showed the worst AC corrosion. During the first two and a half weeks of monitoring, it was established that AC corrosion was indeed a reasonable concern, with measured corrosion rates as high as 1200 μm/y (48 mpy). During this period, it was also established that: ) Continuous monitoring of the AC level is necessary, due to large daily and weekly fluctuations. A spot reading of the AC level ‘at the wrong time’ will not provide insight into the general interference level. ) Lowering of the AC level, naturally occurring at (A),

effectively lowers the AC corrosion risk, indicating that AC mitigation would be an effective strategy.

) Despite the AC voltage being below 15 V, this is more

than enough to generate critical corrosion – at this CP potential.

The operator was advised to reduce the rectifier output, which was done at (B). The recommendation was between -1 to -1.1 VCSE, but the level was not changeable to beyond -1.2 VCSE due to a nearby permanently installed zinc anode.

Nevertheless, the effect on the corrosion rate was immediate, as the corrosion rate fell during the following days, despite constantly high AC levels (C). After approximately one month, corrosion had been brought to a complete stop (D), achieved by a simple change of the rectifier output level. Towards the end of the shown period, both AC and DC current densities are lowering despite unchanged pipeline potential and AC interference level. This is caused by an increase in the soil resistivity and proves that ‘the autocatalytic nature of AC corrosion’ (Figure 1) has effectively been stopped.

The continued safe operation of the pipeline is verified by the absence of corrosion on this and the other four ER probes installed on the interfered pipeline section. Conventional AC mitigation, which is potentially a milliondollar investment, was not necessary.

Conclusion

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AC interference and AC corrosion risk can be handled in different ways. The autocatalytic nature of AC corrosion (Figure 1) is the key to stopping corrosion, i.e. by addressing the three pre-requisites: induced AC; small coating defects; and excessive CP. If all of these are present, AC corrosion is a considerable risk factor. By far the easiest one to change is the CP level.

References 1.

2.

3.

4.

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JUNKER OLESEN, A.; “AC Corrosion of Cathodically Protected Pipelines”; Technical University of Denmark; Lyngby; 2019.

NACE SP21424-2018; “Alternating Current Corrosion on Cathodically Protected Pipelines: Risk Assessment, Mitigation, and Monitoring”; NACE International; 2018.

ISO18086:2019; “Corrosion of metals and alloys – Determination of AC corrosion – Protection criteria”; ISO; 2019.

JUNKER, A.; NIELSEN, L. V.; HEINRICH, C.; MØLLER, P.; “Laboratory and Field Investigation of the Effect of the Chemical Environment on AC Corrosion”; NACE CORROSION; Paper 10844; 2018.

Bas Roosken, ROSEN Group, Europe, and Morten Solberg, KTN AS, Norway, detail an inspection carried out to discover the integrity status of an unpiggable pipeline, off the coast of West Africa.

I

t is a constant back and forth: from sea to land and back to sea. Large oil producers have extensive terminals for offshore production, where product moves from platforms to onshore crude oil storage terminals through pipelines. Arriving onshore, the product is treated and imperfections separated out, to then be temporarily stored in tanks. Once product fills the tanks, the crude oil is transported back onto the ocean to massive ships called Very Large Crude Carriers (VLCCs), where the product’s long distribution journey really begins. Every step of the way, the integrity of the infrastructure the product passes through is of utmost importance.

Choosing and preparing a reliable approach For an offshore operator in West Africa producing approximately 300 000 bpd of crude oil, this was no exception. Having previously inspected one of the pipelines gathering product from the platforms to the onshore tank storage and encountering significant corrosion, the integrity of the 42 in. export line going to the VLCCs became a concern; an inline inspection (ILI) was needed, especially since the line had not been inspected since its fabrication in 2009.

When constructed, this 42 in. line was designed to be piggable and fitted with an onshore launcher and a subsea receiver.

However, the receiver was not in operation, reversing the direction of the flow was not possible and the pipeline was, in fact, deemed unpiggable. In addition, the pipeline routing was challenging, as various horizontally and vertically oriented combinations were present. To put it simply, the pipeline runs from the onshore tank facility towards the sea; a flange is present before entering

27

the water, but it then dips directly downward, continuing vertically until it reaches the seabed, where it runs horizontally to the subsea loading buoy.

After additionally considering the cost of a subsea operation, the need for a one-way entry approach became clear, with access to the pipe from onshore. This would lead to either a bi-directional or a tethered inspection. Weighing all the options and considering all the factors, the operator and the ROSEN Group chose to utilise an ultrasound (UT) tethered inspection approach. KTN AS (a company of the ROSEN Group) provided this solution; a self-centralising crawler with UT sensors, equipped with a tether. The tether not only acts as a failsafe mechanism, it also provides much-needed power to the tool train. The solution also mitigates the need for product flow. In addition, a live data feed is transmitted to tool operators onshore who can monitor the inspection progress, noticing any pipeline particularities and monitoring the tool’s positioning in the pipeline using circumferential welds as guides. The unique tractor design with support wheels divided over the full circumference of the inner pipe wall allows for the negotiation of this unpiggable pipe. The KTN tethered solution was able to pass through all bends in this particularly complex pipeline route.

An additional benefit of the crawler approach is the ability to focus its attention on particular sections of the pipeline. In this case, for example, it was determined that the first 500 m from the launch site, including the riser section and the first few spools of the subsea line, would need a closer look. Given that this crawler can move back and forth, multiple passes could be made of this section.

The operation To access the pipeline for inspection, the operator provided a seven-day window. This would include fully decommissioning the line and returning it back to service, allowing for a five day ILI period. This window of opportunity was created by stacking various VLCCs. However, the onshore storage tanks would be filled after the seven-day period – from the offshore platforms that remained in operation – and the pipeline would be needed again to avoid a compete production shutdown.

More than usual, timing was key.

As seems to be the norm, the COVID-19 pandemic of course caused a series of difficulties and delays. Initially scheduled for June/July 2020, the project was postponed to November 2020. All required equipment was shipped by sea or airfreight to minimise its time onsite, allowing for additional testing of the ILI equipment in Bergen, Norway. During this time, additional trial runs allowed for validation of the ILI tool performance specifications according to API 1163. All personnel mobilised onsite two weeks prior to the inspection execution for mandatory self-isolation before going to the site.

With everything, and everyone, onsite, execution could begin. Due to operational challenges, the decision was made to divide the inspection into two sections. This would allow tool operators to start with the long-run inspection and then concentrate on the designated high-focus area. The inspection tool was launched through the onshore flange before the vertical dip into the ocean. Once the tool was in the pipeline,

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World Pipelines / APRIL 2021

24 hour operation ensured that as much of the line was inspected as possible. At 2.5 km per 12 hour shift (just over 200 m/hr), the tool crawled into and back out of the pipe.

All the while, onshore tool operators monitored the progress of the inspection. The tool traveled approximately 7.8 km offshore towards the loading buoy, covering enough distance to be able to perform an integrity assessment on the rest of the pipeline.

After the return inspection has been completed, the focus turned to the first 500 m after the launch site. Dedicated time was allocated to allow several inspection passes of this section – once again back and forth, much like the product.

The complex routing of the pipeline allowed the tool to rotate, making sure that the 480 sensors on the sensor ring inspected the complete inner pipe wall of this high-focus area.

The live feed from the tether assured that welds were marked as the ILI tool passed them, allowing data evaluators to mix and match several ILI data sets.

The technology on board the inspection solution was UT. Although UT has many upsides, especially for corrosion detection and sizing, one clear downside is the sensitivity of the sensors to debris. As this specific pipeline was unpiggable, no cleaning was conducted prior to the inspection. Lack of pipeline cleanliness, or rather the presence of debris, can create a series of challenges for inline inspection, including data loss due to UT signal attenuation.

In this case, it resulted in debris accumulation on the ILI tool’s sensor ring, which could result in data gaps. However, as the crawler is able to travel into and out of the pipe, data is recorded in both directions; therefore, full sensor coverage is made possible in the debris-covered sections of the inner pipe wall. The live monitoring of the inspection progress through the tether provides assurance that high-quality data is collected for precise data analysis of any anomalies. Ultrasound as a measurement technology also requires a liquid couplant. And although the crawler unit on the tool train propels itself – unlike conventional ILI, where the transport medium pushes the inspection tools through the pipe – a couplant was needed. To achieve this, the pipeline was drained to just below the level of the onshore flange, where the inspection tool was inserted.

The stagnant product was kept in the line to provide a couplant, remaining stationary throughout the inspection.

With time to spare within the inspection window, the tool was retrieved from the pipeline, allowing operations to return to normal. At no point during the inspection did the offshore platforms stop producing. The tanks were filled and once the inspection was complete, they were emptied into VLCCs as per usual operation. This meant no interruption of production.

Facilities like this one off the coast of West Africa must run a tight schedule to meet production demands; a vital part of operations is ensuring the safety of all involved assets. This tethered crawler approach provides a no-compromise solution for collecting the data needed to understand the integrity status of an asset, without interrupting valuable production time. The crawler moved back and forth through the line collecting data, so the product can safely move back and forth from tank to ship – all without a back and forth on safety vs. production.

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Dominic Giguere, Zetec, USA, explains how flexible ultrasonic probes and scanners are helping to make pipe elbow corrosion inspections faster and more effective.

U

ltrasound has been a game-changer for nondestructive examinations of internal pipeline corrosion. The latest phased array UT instruments are compact and portable, and can process a stream of inspection data to create vibrant high-resolution images of corrosion and other damage. Handheld scanners with magnetic encoded wheels and 2D array probes make it easy for technicians to monitor the probe position and orientation as they inspect curved surfaces. Any gaps in coverage show up on the instrument’s colour display in near-real-time, so technicians can feel confident that they’re covering the pipe’s entire inner topology with a high probability of detection.

While phased array UT has become a preferred way to test pipeline wall thickness, one type of degradation can still throw inspection teams a curve: flow accelerated corrosion (FAC) in pipe elbows and induction bends.

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What is FAC? FAC occurs in pipelines when the movement of fluid causes deterioration on the interior wall. One of the most common examples is carbon steel or low alloy steel pipe elbows, where the flow of water or wet steam gradually wears aways the protective oxide layer on the inside surface of the pipe.

The exposed bare metal starts to corrode, exhibiting grooves, striations, shallow pits and other signs of material loss. The pipe wall becomes thinner and the risk of metal failure increases.

A number of factors affect a material’s resistance to FAC, including the composition of the steel; the chemistry and temperature of the fluid; and the fluid’s velocity, pressure and turbulence as it moves through the pipe.

While the terms FAC and erosion corrosion are often used interchangeably during elbow inspections, FAC doesn’t necessarily include abrasion due to particles in the fluid, impingement caused by water droplets in steam or cavitation that occurs when a liquid is subjected to rapid pressure changes. However, these conditions can aggravate the problem.

With ultrasound, technicians and asset owners can monitor rates of material loss in straight pipe runs. However, pipe elbows are a unique challenge.

With a phased array UT probe, ultrasonic waves enter the material being tested at precise intervals and a set angle.

When a wave encounters a defect, some of that energy reflects back and generates an echo. The time it takes for this energy to come back to the probe is calculated and analysed by the UT instrument’s software and is presented on the display as a C-Scan for the technician to interpret.

However, it’s difficult for a rigid UT probe to traverse the intrados (inner radius) and extrados (outer radius) of a pipe elbow in a concentric position so ultrasonic signals reflect back properly. Technicians can use a combination of probes and wedges to accommodate the convex and concave shapes and variations in material thickness along the pipe elbow, but this adds time, complexity and cost to the inspection.

What’s the next step? Ultrasound technicians and asset owners have a handful of options if they want to check for FAC and other defects in pipe elbows.

Spot checks One approach is to draw a grid on the outside of the pipe to use as a reference for spot thickness measurements along the elbow – it’s referred to as a time-based scan mapped over a grid system.

The technician uses a standard 1D linear array probe to check the wall thickness wherever the grid lines cross, or to cover the entire interior of the box.

Either way, drawing a grid and taking thickness measurements by hand, box by box, is tedious work. The only record of examination it produces is a table listing the nominal wall thickness and the minimum thickness at each point on the grid, and there’s no code or standard to dictate grid spacing or the number of inspection points. Ultimately, this technique can leave a lot of area in the pipe elbow unchecked and undocumented.

Figure 1. UT scanner for pipe elbows.

Figure 2. Left: A 1D linear array probe is ideal for most inspections of welds and other defects. Right: The beam-skewing capability of 2D matrix array probes means more accurate wall thickness measurements and better detection of mis-oriented flaws.

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Radiography Another option is radiography. Radiographic inspections use either portable X-ray or gamma ray generators to direct a beam into the pipe elbow. A detecting device – an imaging plate (undeveloped film sealed in a cassette) – captures the beam after it penetrates the material. The process produces a twodimensional image (radiograph) of varying densities according to the amount of radiation that penetrates the material and reaches the film. Advancements in technology allow the ability to wrap image plates around pipes.

Unlike digital phased array ultrasound inspections which provide immediate results, the latent negative image on a radiograph must be processed using chemical developer, stop bath and fixer. Inspection quality depends on accurate alignment of the beam with the

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Types of ultrasonic probes When you hear the term ‘array’ applied to ultrasonic testing, you may just as well be talking about the range of transducer choices available for UT inspections.

Array probes come in a variety of shapes, sizes, frequencies and the number of elements. If you manage or direct nondestructive testing service providers for pipeline inspections, it’s important to understand two main types of probe technology.

1D linear array probes A 1D linear array probe is the most common type of array for straight beam and angle beam inspections.

Think of it as a long transducer that’s capable of generating and receiving a single ultrasonic beam. No matter how a 1D linear array probe is oriented, the focal point and angle of the beam are fixed.

A 1D linear array probe will meet the requirements for most weld and component-integrity inspections, including reliable detection of surface and subsurface defects and wall-thickness measurements. Because of their versatility and cost effectiveness, 1D probes are used in flexible array probes and scanners developed for the detection of flow accelerated corrosion in pipeline elbows.

2D matrix array probes 2D matrix array probes have elements along two directions. This enables the rapid acquisition of data and the ability to perform a complete volumetric inspection. By exciting each element in a highly controlled manner, a phased array UT instrument and software can produce a precise beam shape at multiple angles and generate two and threedimensional views of a flaw with speed and accuracy.

2D matrix array probe assemblies and portable phased array instruments are now common for pipeline inspections. These tools have powerful software that allows technicians to virtually position probes on the specimen to ensure maximum volumetric coverage, and then simulate an inspection step by step.

Ultimately, the technician’s choice of probe will depend on the job at hand. What kind of access does the inspecting technician have? What materials are used in the welds? What conditions exist around the inspection site (high temps, humidity, etc.)?

The wrong ultrasonic probe type can sometimes give you the same actionable results as having no probe at all. If you’re an asset owner, the more information you can provide to the technician, the more straightforward their probe choice will be.

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World Pipelines / APRIL 2021

material surface as well as proper exposure time based on the properties of the material.

Because of the safety issues surrounding radiation, a radiographic inspection may require permits and clearing the area of other personnel to ensure they are not accidentally exposed. Here, standards established by organisations like the American Society of Mechanical Engineers (ASME) and the American Petroleum Institute (API), as well as the experience and judgment of the technician, play a critical role in equipment setup and testing.

Flexible array probes A flexible ultrasonic array probe and scanner can map both straight and elbow aspects of a pipe, and significantly reduce inspection time compared to radiography and conventional UT and grid systems.

Introduced only within the past few years, flexible array probes have a pliable foam wedge that shapes the array of ultrasonic elements to meet the contour of the pipe elbow.

This allows the probe to stay concentric throughout the inspection.

The combination of a flexible array probe and an encoded scanner enhances the technician’s ability to generate a complete map of the inner surface of the elbow and characterise corrosion. Flexible array probe scanners weigh 1 kg and are easy to handle: magnetic wheels keep the scanner firmly in place as the technician guides it along a scan line or the centreline of the pipe. An encoder maps the pipe’s scan axis while the technician can index increments in the second axis with the press of a single button on the scanner.

The newest flexible array scanner, Zetec’s ElbowFlex, has a 64 element array and is capable of surface-mapping the interior of pipe elbows from 4 in. nominal pipe size (NPS) to flat. Its encoded data can be saved at a high resolution to generate a detailed C-Scan image of the entire interior surface of the pipe elbow.

Choosing a couplant Like other ultrasonic probes, a flexible array probe requires a couplant to help ensure a reliable signal.

The most common approach is a water chamber, but water can be messy on a pipe elbow inspection, especially for the technician with a handheld scanner. There are alternatives to water, including acoustic-capable polymer materials that can be moulded around the pipe elbow.

Polymer membranes such as Aqualene – a soft, pliable thermoset elastomer – conform to the elbow’s convex and concave shapes and stay there, minimising the need for water while providing a reliable way to transfer ultrasonic energy.

Other options include standard coupling gel or a mixture of water and gel.

As ultrasound has become a proven technology for pipeline testing, flexible phased array probes and elbow scanners can eliminate a crucial blind spot. They can help technicians and asset owners make more informed decisions about managing FAC and other previously hidden wearrelated defects that may be just around the corner.

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Figure 1. Pipeline repair using DEXPAND®-CF70.

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Luc Perrad, DENSO Group Germany, discusses the company’s new carbon fibre-based repair system, designed to restore and extend the service life of pipelines.

L

ight and stable – for a long time, well-known technologies have made use of the properties of plastic fibres, such as rotor blades for wind turbines or solar panels in space travel. However, wing panels for aircraft or entire car bodies are also manufactured using carbon. Automotive manufacturers are aware that if you master lightweight construction using carbon fibres, you can build fast sports cars. And many tennis duels in Wimbledon would have been slower if carbon fibre reinforced plastics (CFRP) weren’t used in tennis rackets. Lighter than aluminium – harder than steel.

Quick and cost-effective pipeline repairs using CFRPs One of the special properties of so-called carbon composite materials is that some of them have a higher strength than steel. For this reason, they also play an important role in building pipelines. As temperatures, mechanical loads and long-term chemical influences have a permanent corrosive effect on the steel on the inside and on the outside, serious defects can occur in the pipe wall. Whether this is repaired with a steel sleeve or the damaged section is completely replaced, the pipeline must first be decommissioned at great expense.

However, this is entirely different if the pipeline is repaired with the help of carbon composite materials: DEXPAND®-CF70, the new composite repair system from DENSO Group Germany, allows repairs to be made to

37

The advantages of DEXPAND®-CF70 at a glance Because the repair is carried out during ongoing operations without shutting down the pipeline, there are clear advantages compared with repairs using steel components or replacing a damaged pipe section: ) Cost-effective: around 75% cost savings compared with replacing the section of pipe. ) Quick: more than 50% time savings. ) Simple: no work to do with additional machines. ) Safe: no gas flames for application, no welding

and therefore no fire or explosion hazard. This is particularly important for works in chemical plants and refineries.

the pipeline whilst operations are ongoing – a quick and cost-effective alternative to other processes.

This product, of tried-and-tested DENSO quality, was launched in May 2020, expanding the existing range of services for corrosion protection and road construction offered by DENSO Group Germany of Leverkusen.

DEXPAND-CF70 repairs damaged sections of steel pipes and restores the material’s original structural integrity, i.e. its intact state. The pipelines can then be recommissioned safely at the original operating pressure – guaranteeing long-lasting operation.

“Steel pipelines, whether they transport gas, water or oil, are very costly. For this reason, it is necessary to operate them for as long and as safely as possible. The question of the service life of such transport systems is therefore essential,” explains Thomas Kaiser, Managing Director of DENSO Group Germany. “With our new product DEXPAND-CF70, we are extending the service life of pipelines by many years. We are thus once again focusing on forward-looking solutions that contribute to safety.”

Sophisticated technology with verified safety

Figure 2. System structure of DEXPAND®-CF70.

Figure 3. Exceeded minimum hardness requirements.

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World Pipelines / APRIL 2021

The carbon fibres used in DEXPAND-CF70 are amongst the strongest industriallymanufactured fibres. Pipeline repair systems based on carbon fibres are currently the most resilient non-metallic systems. In long-term trials which correspond to the equivalent of 100 years of use, they demonstrate the highest levels of long-term durability.

Where is a product with such excellent properties used? The system is suitable for repairing defects where up to 80% of the original wall thickness has been lost. Only when even more extensive damage and leakages have taken place is the system not used. The good news for all operators is that with DEXPAND-CF70, almost all damage that occurs in practice in transportation pipelines can be quickly and easily repaired whilst the pipeline is in operation.

Gasunie Deutschland, the operator of the ETL 05 natural gas pipeline (pipe diameter DN 250, 10 in.) near Bielefeld, Germany, was already able to see this at the end of November 2020. STRABAG AG Directorate North, which was commissioned to carry out the construction work, repaired two defects with DEXPAND-CF70 on 30 November at an ambient temperature of 0˚C (+32˚F). The defects in the pipeline had led to a reduction in wall thickness of up to 32%. The repair was carried out with the line staying permanently in service within only three hours. The minimum requirements for Shore D hardness were even exceeded at both locations in less

than 24 hours: an excellent proof of the performance of DEXPAND-CF70. The following day, the gas pipeline could be operated again at its original operating pressure.

In general DEXPAND-CF70 system is suitable for operating temperatures of up to 70˚C (+158˚F). For quick repairs to the damaged areas, project-specific repair kits are available at short notice.

The independent laboratories of TÜV-Süd (certificate IS-AN11-Muc/ml-1915) have verified the fatigue strength of the section repaired using DEXPAND-CF70. Up until now, the planned usage period was generally up to 20 years.

However, DEXPAND-CF70 is one of the few systems which has been certified for an unrestricted service life.

and a high-strength, mechanical reinforcement consisting of DEXPAND®-CF70 Carbon fabric and DEXPAND®-CF70 Wetout. With the help of the Putty filler, dents in the pipe surface are first of all filled in and evened out.

The Primer is a dual component epoxy adhesive, which ensures that the power of the repair system is perfectly transferred to the pipeline surface. The high strength mechanical reinforcement consists of the carbon fabric, a carbon fibre fabric, and the Wetout, a dual component resin. The Wetout forms a bond with the layers of the fabric and ensures that the mechanical loads are evenly distributed. Finally, an additional corrosion protection system based on PE/butyl rubber completes the

Clear advantages with DEXPAND-CF70 DEXPAND-CF70 restores the integrity of pipeline systems on a long-term basis, extending their service life. As the repair can be carried out during ongoing operations without shutting down the pipeline, there are clear advantages compared to replacement or repair with steel components.

“If we take into account the costs for shutdowns as well as the cost of materials and labour for replacement using a steel sleeve, there are cost savings of around 75% associated with the use of DEXPAND-CF70. In addition, the affected defect is repaired more than twice as quickly,” says Luc Perrad, Head of International Sales at DENSO. Replacing a section of pipeline or repairing it with a steel sleeve takes around four to five days. By comparison, the time required when using DEXPAND-CF70 is only two days as a maximum.

Since there is no need to empty the pipeline, or carry out welding operations, working with this innovative product is not only extremely economical, but also ecological, safe and simple.

A unique system for decades of pipeline operation DEXPAND-CF70 is a unique system consisting of only four components, which are guaranteed to repair the damaged pipe on a long-lasting basis. The system comprises the DEXPAND®-CF70 Putty, the DEXPAND®-CF70 Primer

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protection of the pipeline – for safe pipeline operation for decades.

The procedure – four steps to success If an operator is interested in using DEXPAND-CF70 when damage has occurred, the process is clearly structured according to responsibilities to ensure a smooth repair.

Step one begins with the damage assessment by the pipeline network operator: it determines the data

concerning the damaged pipe section as well as the current operating conditions (in addition to pressure and temperature, other conditions such as remaining pipe wall thickness, steel quality used or pressure range form part of this). These data provide the basis for the use of the DEXPAND-CF70 system.

The second step is the calculation of requirements by DENSO. Based on the operator’s data, a DENSO calculation tool calculates the materials required to restore the integrity of the pipeline, particularly with regard to the number of reinforcement layers. In the third step, DENSO produces and delivers the tailored, projectspecific repair kit to the pipeline operator. Then, the actual repair takes place: the pipeline network operator will have the pipeline repaired by qualified processing partners certified by DENSO, taking into account the currently valid processing information.

Conclusion

Figure 4. Easy application of DEXPAND-CF70.

From a family company to a family of companies

If a pipeline is repaired with the help of carbon composite materials, it does not have to be taken out of service beforehand in a cost-intensive manner, as is the case with other methods. DEXPAND-CF70, the new composite repair system from DENSO Group Germany, enables the pipeline to be repaired while it is still in operation and restores its original structural integrity.

This extends the service life of a pipeline by decades.

Almost any damage that occurs can be repaired quickly, economically, easily and safely with DEXPAND-CF70.

Shortly after its market launch, DEXPAND-CF70 was able to live up to its claim in practice. Gasunie Deutschland, as the operator of the ETL 05 natural gas pipeline, was very satisfied with both the application of the product and the speed of the entire process.

) Since it was founded in 1922, DENSO Group

Germany has grown into an international family of companies, with subsidiaries in six European countries and sales partners in more than 100 countries around the world. ) By 1927, the company was already revolutionising

the passive corrosion protection of pipelines with the invention of the DENSO tape (petrolatum tape). To this day, the company is considered to be synonymous with the world’s first reliable corrosion protection for pipelines. ) DENSO is now known as a specialist for product

and system solutions in corrosion protection and sealing technology. With the “Made in Germany” quality guarantee as well as its pioneering developments, DENSO offers greater security and durability for new builds and renovations.

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What are carbon fibres & why are they an ideal material?

Carbon fibres are industrially produced, high-tensile fibres. Fabrics made of carbon fibres bonded with a reactive resin are characterised by extremely high adhesive strength and stiffness with low elongation at break. ) The best results in long-term testing – corresponding to 100 years of use – are achieved using carbon fibres e.g. for pipeline repairs. ) They are among the strongest industrially

produced fibres, and their strength is sometimes higher than steel.

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Matt Green and Tim Mally, CSNRI, USA, describe the testing of a 25 year old repair completed with composite repair sleeves, that left pipe sections even stronger than before.

S

ince the first composite repairs were introduced to the industry more than 30 years ago, composite materials have been used to address a broad range of defects, from cracks, fractures, and leaks to internal and external corrosion, mechanical damage, abrasion, and axial defects. Composites evolved over the decades from repair sleeves that could be used on standard straight piping runs to flexible wraps that can be applied to wrinkle bends and components with complex shapes. Their versatility has made them the go-to solution for a broad range of anomalies, and they have been installed around the world to resolve asset integrity and safety concerns. Although many have been in service for years, there have been few occasions when a repair has been recovered to allow designers to see how it has endured the test of time. A rare opportunity at the end of 2020 provided just such a chance, when a pipeline owner replaced a section of pipe that had been repaired using a Clock Spring® composite repair sleeve in 1995.

In the beginning The Clock Spring coil is made up of eight layers of pretensioned unidirectional e-glass composite that is installed with a high-modulus filler material and a high lap-shear strength methyl methacrylate adhesive. Designed to structurally reinforce and permanently

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restore external anomalies, the sleeve can repair a broad range of mechanical damage and corrosion defects, and can restore a pipeline with up to 80% wall loss to full strength. It has been tested to 8000 psi internal pressure and has a design life beyond 50 years, qualifying it as a permanent repair by regulators around the world.

The repair sleeve was the subject of an extensive 10 year research and development programme, and was the pioneer for the approval of composite repairs across the

industry. In 1987, the Gas Research Institute (GRI), assembled a team of pipeline professionals and research organisations to direct a comprehensive programme to verify the sleeve’s effectiveness, durability, and performance characteristics.

The decade-long testing programme, which assumed worstcase conditions, included extensive burst testing, stress rupture tests, field validations, cathodic shielding testing, and cathodic disbondment test. Technical evidence of the sleeve’s performance was submitted to the United States Department of Transportation, which revised its code in the year 2000 to allow Clock Spring as a viable permanent repair. The GRI testing programme remains the most thorough and trusted composite testing programme ever conducted.

The original repair

Figure 1. The testing programme for the 25-year old Clock Spring® repair was designed to gradually increase pressure to 1455 psi (100.3 bar), which is 1.5 times the MAOP of the pipeline, where the MAOP was 970 psi (66.9 bar). The composite repair showed no damage when the repaired pipeline section was pressurised to the target value of 1455 psi (100.3 bar) and held at that pressure for five minutes. (Photo courtesy of CSNRI).

Figure 2. The repaired pipeline section was pressurised to and then held at that pressure for five minutes. After successfully holding the repaired pipeline section at the target value of 1455 psi (100.3 bar) for five minutes, pressure was increased until the pipeline finally ruptured at 2180 psi (150.3 bar). Interestingly, the rupture was not on the Clock Spring repair but on a section of pipe outside of the repair area. (Photo courtesy of CSNRI).

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World Pipelines / APRIL 2021

In 1995, an owner, operator, and developer of an integrated portfolio of natural gas pipelines, found corrosion on a carbon steel pipeline operating at 750 psi (51.7 bar), with a maximum allowable operating pressure (MAOP) of 970 psi (66.9 bar). There were multiple corrosion defects in the pipeline, the worst of which was 12 in. (305 mm) long with 63% corrosion. The determination was made to repair the line using the Clock Spring composite repair sleeve.

With the pipeline in service, technicians cleaned and inspected the pipeline for any additional defects prior to molding filler into corroded areas. The filler acts as a load-transfer agent to transfer the stresses from the pipe to the composite sleeve. Following an inspection to ensure that the repair sleeve could be placed properly, technicians installed the sleeves and secured them to the damaged line. Within an hour, the composite repairs were fully cured, and the pipe was restored to safe service.

Withstanding the test of time After 25 years of continuous service, the section of composite-repaired pipe was scheduled for inspection and replacement to conduct validation tests. The pipeline company contacted CSNRI late in 2020 and asked if there was any interest in inspecting the repaired segment of pipe that was being removed from service. Because there are few opportunities to examine composite repairs that have been in service for a quarter of a century, the company was eager to subject the repair sleeves to testing.

Once the pipe section was received, it was fitted with end caps and fittings to conduct a full-scale pressure test. The testing programme was designed to gradually increase pressure to a target value of 1455 psi (100.3 bar), which is 1.5 times the MAOP of the pipeline, where the MAOP was 970 psi (66.9 bar). The repaired pipeline section was pressurised to 1455 psi (100.3 bar) and then held at that pressure for five minutes. After a successful hold at the target value, pressure was increased until the pipeline finally ruptured at 2180 psi (150.3 bar). It is noteworthy that the pipe ruptured not on the repaired section of pipe, but on a section of pipe outside of the repair area.

Additionally, samples of the Clock Spring repair were removed from the tested sections, and coupon-level

tensile testing was conducted. The results of the tensile testing on the samples removed from the tested pipeline, which had just successfully held up to the full-scale pressure test, showed that the tensile strength of the 25 year old repair sleeve was still 90 000 psi (6205.3 bar). This validates that no degradation occurred in the composite repair from the time of installation through continuous operation for 25 years.

This test programme validates the durability of the composite repair, underscoring the findings of the 10 year research and development programme led by GRI in 1987 that established the Clock Spring composite repair sleeve as a viable, permanent repair solution, and reinforcing the claims that the Clock Spring can last longer than 50 years in service.

and subjected to a burst test to determine their performance characteristics after exposure to wear. Testing from year zero to year 10 showed no degradation either in the appearance or the performance of the composite repair. In fact, the final burst pressures from each year of testing from one to 10 were within 3 - 5% of each other, showing remarkable consistency of results.

Many other studies have been undertaken – or are ongoing – to prove the value and longevity achievable with composite repair systems on high-pressure and highly cyclical pipelines. One such programme was carried out by the Gas Technology Institute (previously GRI) in 2013 in which a part of the study was dedicated to testing long-term tensile and adhesion strength of composite systems. The results further validate the durability of these types of repairs and illustrate why they are so valuable to asset owners.

Scores of testing programmes have been completed on composite repairs over the years by industry sponsors and third parties, as well as end users and composite system manufacturers. As more and more test results and data become available, there are additional reasons for industry confidence in the ability of composites to perform in the long term for a variety of defects to keep pipelines operating safely and efficiently.

More testing yields positive results Although there are not a lot of opportunities to carry out testing on 25 year old repairs, there are many ways to develop and execute test programmes to provide performance data for composite repairs. Ten years ago, CSNRI participated in third-party testing in conjunction with the Pipeline Research Council International (PRCI) and Stress Engineering Services on another of its composite repair solutions, Atlas™, to determine its efficacy in addressing external corrosion.

Atlas is a high-strength, high-stiffness carbon fibre solution for repairing pipeline and piping structures. Designed for repairs that require strain reduction induced by dynamic loading conditions, this composite repair system includes a bi-directional carbon fibre system installed using a highstrength epoxy resin. Field saturated and applied, this carbon-fibre system contours to seam and girth welds and when combined with high-strength load transfer filler, helps minimise strain on complex pipeline anomalies. This solution is most commonly used for pipelines and piping systems that have suffered external corrosion and pitting or third-party damage such as dents, gouges, and scratches and is also appropriate for wrinkle bends, imperfect welds, manufacturing flaws, and cracks or crack-like features.

The third-party testing for this product simulated external corrosion at depths of 40%, 60% and 75% in depth on hundreds of 12 in. (0.3 m) diameter pipe spools to test the longevity of the composite repair. Each specimen was wrapped with an engineered carbon fibre and epoxy composite repair and then buried in wet Texas soil under a coating and cathodic protection to simulate how a composite repair would perform under similar conditions in the field. The pipe segments were pressure cycled 900 times per year over a 10 year period. At the conclusion of each year of the test programme, pipe segments were recovered

Continuous improvement Composite technologies are not only safe and relatively simple to install, they also deliver benefits that other repair solutions cannot, allowing installation on active lines, enabling repair on complex geometries and in areas with tight access, and providing reliable performance for decades of service.

Continuous testing and validation are important for quality assurance, meeting regulatory requirements, and verifying manufacturing process, but the biggest benefit of extensive testing is that it removes the grey areas, providing industry with products it can trust. This 25 year test demonstrates that composites can be counted on to perform to the levels that the laboratory tests initially indicated and can be trusted to be reliable for decades to come.

Over the years, successful composite repair installations have changed the way owners and operators extend the field life of their assets. Tested, validated, and field-proven composite solutions are readily available, and continuing R&D efforts are creating even more advanced products. As the superior performance of composite solutions becomes more well-known, more companies will look to composites to deliver long-lasting, reliable performance.

Table 1. Third-party test results for the Atlas™ Carbon Fiber Repair System (data courtesty of CSNRI) Manufacturer

Corrosion Defect

Burst Pressure (psi) Year 0

Burst Pressure (psi) Year 1

Burst Pressure (psi) Year 2

Burst Pressure (psi) Year 3

Burst Pressure (psi) Year 5

Burst Pressure (psi) Year 7.5

Burst Pressure (psi) Year 10

CSNRI

40

4125

4040

4087

4123

4188

4177

4247

60

4118

4089

4084

4191

4241

4089

4122

75

4296

4263

4388

4397

4316

4328

4322

APRIL 2021 / World Pipelines

45

A. S. Tazedakis, N. Voudouris, E. Dourdounis, Corinth Pipeworks, Greece, and G. Mannucci, L. F. Di Vito, and A. Fonzo, RINA Consulting – Centro Sviluppo Materiali SpA, Italy, discuss the certification of steel pipelines for the transportation of hydrogen.

46

Image: Corinth’s plant in Thisvi, Greece, including four pipe mills, coatings/CWC and own port.

H

ydrogen is the most environmentally friendly carrier of energy: when consumed it solely emits water. Energy carrier means that its potential role has similarities with that of electricity. Both hydrogen and electricity can be produced by means of various energy sources and technologies. Both are versatile and can be used in many different applications. No greenhouse gases, particulates, sulfur oxides or ground level

ozone are produced from the use of either hydrogen or electricity.1 Consequently, hydrogen is currently enjoying unprecedented political and business momentum, with the number of policies and projects around the world expanding rapidly; in July 2020, the EU Commission adopted a new dedicated strategy on hydrogen in Europe, which explores actions to support the production and use of clean hydrogen, focusing in particular on the mainstreaming of renewable hydrogen.

47

The transport of gaseous hydrogen through pipelines is not a novel concept. It has been indeed realised by use of mild carbon steel for almost a century and it is estimated that there are over 4500 km of hydrogen linepipes in operation worldwide.2 Typical pipeline size is 300 mm or less, manufactured with X52 or lower strength steels and in comparison to natural gas, H2 pipelines normally operate at relatively conservative conditions.3 However, owing to the low volumetric energy density of hydrogen (0.0108 MJ/L) in comparison to natural gas (0.0364 MJ/L) and the forecasted expansive utilisation of renewable energy sources, it will be necessary to transmit hydrogen at high pressures using large pipelines in order to be financially competitive. The combination of high pressure and large size pipe demands the use of higher strength steels.

) International/European standardisation bodies are

working on revising EN 1594, EN 16348 and EN 12732 in order to consider H2 and H2/natural gas (NG) mixtures also. ) EIGA (European Industrial Gases Association) published

a document (IGC Doc 121/14) which recommends maximum steel grade to be used and suggests testing to be carried out, but without specific instructions on how to qualify the material. ) ASME B31.12 is a US standard for material qualification

for use with H2 and H2/NG mixtures. Two basic approaches are adopted: Design Options A and B, which are briefly described in the following section.

It is worth highlighting that the EIGA document makes specific suggestions to limit the effects of hydrogen There is a limited number of standards that can be used embrittlement on materials, such as appropriate material for material qualification for pipeline gaseous hydrogen classes, compositional and strength limits, and suggests transportation: appropriate testing methods, but is a recommended practice and not a standard. At the same time, new EN/ ISO standards under revision are expected to follow the ASME B31.12 approach for the material qualification of pipelines for high pressure gaseous hydrogen transportation; ASME B31.12 is now the most used standard for material qualification and can be expected to be the reference one also in the future.

The ASME B31.12 Hydrogen Piping and Pipeline Code was initially published in 2008, in order to deal with design, construction, operation, and maintenance requirements for piping, pipelines, and distribution systems in hydrogen service.4 The B31.12 committee has developed two design methods that can be considered in conjunction with steel/ piping specifications (i.e. API 5L PSL2) and acceptable manufacturing routes for welded Figure 1. Design pressure factors for X60M for Option B vs Option A in areas pipes (HFW, SAWL or SAWH).5 characterised as Location Class 1, Division 2.

The first (Option A) is prescriptive and similar to design processes contained in ASME B31.8 Natural Gas Pipeline Code. It considers the use of lower basic design factors, F, and a material performance derating factor, Hf, derived from pressure and tensile strength relationships.

The second (Option B) is performance based, using a fracture mechanics approach (on the basis of ASME Section VIII, Div. 3 – Alternative Rules for Construction of High Pressure Figure 2. Outline of KIH testing procedure.

Vessels). The qualification of

Applicable standards and practices

48

World Pipelines / APRIL 2021

Figure 3. Compact tension specimens in RINA laboratory.

Table 1. Overview of CPW pipes tested for fracture toughness (KIH) in pressurised hydrogen.

the pipeline materials is performed by use of fracture mechanics and crack propagation testing that empowers the use of enhanced design factors and withdraws the limitations on pressure due to the use of the Hf derating factor.

When designing a pipeline for hydrogen transportation, the benefits of compliance with ASME B31.12 Option B can be substantial. This is illustrated in Figure 1 for an API X60M grade: the design factor for Option B can be 72% of the specified yield strength for all applicable pressures up to 20.7 MPa (3000 psi). On the contrary, the same design factor for Option A is limited to a maximum yield strength percentage of 43,7% or even lower, due to additional limitations of the material performance (Hf) factor when the design pressure approaches 3000 psi (20.7 MPa).

The latest version of ASME B31.12, specifies for Option B that fracture toughness qualification testing is required to validate the minimum threshold stress intensity factor (KIH) at the design pressure and 100% H2 concentration.

The test on the pipes should be performed at the base metal, weld metal and heat affected zone positions, on three heats of the pipe material, in compliance with ASTM E1681 according to the constant displacement configuration, with the additional prescriptions of ASME B31.12 and ASME BPVC Section VIII, Division 3. 6,4,7,8 The KIH value that qualifies the material in accordance with ASME B31.12 Option B is 50 ksi√in (or 55 MPa√m) unless otherwise specified by design analysis. It should be noted that the latest version of the ASME B31.12 code has removed the requirement to perform specific FCGR

50

World Pipelines / APRIL 2021

testing for the qualification of a hydrogen line pipe and generic curves are provided, applicable for all carbon steels in gaseous hydrogen up to 20.7 MPa (3000 psi) service pressure.

Fracture toughness qualification testing Aiming to validate the performance characteristics of high grade API 5L pipes in pressurised hydrogen, CPW organised a number of fracture toughness qualification (KIH) tests under the ASME B31.12 code Option B scheme, including both High Frequency Welded (HFW) and Longitudinal Submerged Arc Welded (SAWL) pipes. All tested pipe material is presented in Table 1.

All ASME-based hydrogen material tests were performed in RINA Consulting – Centro Sviluppo Materiali SpA, an acknowledged European company specialised in the development of new materials and in the performance assessment of materials and equipment in new operating windows; with regard to the subject, RINA has specific skills and laboratories specialised to evaluate materials and components performance in presence of gaseous hydrogen up to 1000 bar external pressure.

The procedure for KIH fracture toughness testing is presented schematically in Figure 2. Samples are machined in bolt-load compact configuration (Figure 3).

The determination of the threshold stress intensity factor involves a specimen containing a machined notch, which is placed in base material and, for HFW pipes, in bond line or, for SAWL pipes in weld metal and Heat Affected Zone crossing the fusion line (Coarse Grain HAZ) at the

maximum extent. This notch is extended by fatigue cracking under controlled conditions for maximum loading. The fatigue pre-cracked specimen is then placed in a glovebox filled with a nitrogen atmosphere, under very low oxygen and moisture levels as required per ASME code. The specimen is then loaded by means of a bolt to the attainment of the target Crack Mouth Opening Displacement, established on the basis of the target stress intensity KIAPP for plain strain conditions.

After loading, the samples are put inside the test chamber under controlled conditions and the test chamber is then charged with pure hydrogen gas at the target test pressure and maintained at this pressure for 1000 hours. After the specified test period, the specimen is examined to assess whether the initial fatigue crack did or did not grow. The specimens are heat tinted and broken open in liquid nitrogen.

The fracture surface is then examined by optical observation and scanning electron microscope.

Figure 4. Visual and SEM examination of representative post-exposure examination results from the 26 in. x 15.9 mm HFW test item.

Results and evaluation The results of all validated fracture toughness KIH tests are summarised in Table 2. Four samples per material/ notch were prepared in order to obtain at least three valid results per position.

According to KD-1047 clause of ASME code for the constant displacement method, if the average measured crack growth does not exceed 0.01 in.

Figure 5. Representative micrographs of X70M HFW pipe on PM (left) and weld seam (right) presenting a fine polygonal ferrite microstructure. Etching: Nital 2%.

Table 2. Results of fracture toughness ASME KIH testing.

APRIL 2021 / World Pipelines

51

Table 3. Chemical analysis of tested pipes (% WT.).

ASME B31.12 Option B & Appendix G: steel chemistry requirements and recommendations ) Desired microstructure of polygonal and

acicular ferrite. ) TMCP made steel is recommended. ) Phosphorus content ≤ 0.015% wt. ) Recommended carbon content ≤ 0.07% WT. ) Recommended carbon equivalent (Pcm) X52-

X60 ≤ 0.15% WT, X65-X80 ≤ 0.17% WT. ) Maximum UTS 110 ksi (758 MPa). ) Nb micro alloyed steel is recommended.

(0.25mm) KIH is equal to 50% of KIAPP.7 Taking this clause into consideration, the KIAPP initial stress was selected to be at least double of the minimum threshold stress intensity value required by the code of 55 MPa√m.

No hydrogen crack growth was noticed at any specimen after visual and SEM examination at high resolution. In all cases also the SEM micrographs highlighted a dimpled fracture surface in front of the fatigue pre-crack, extending a few microns (Figure 4). Presence of this surface represents an evidence of a newly generated surface, formed as a consequence of the load application by the bolt and serving as a site for hydrogen permeation during the hydrogen 1000 hr exposure.

Conclusions According to the up-to-date test results for HFW and SAWL pipes in grades up to L485M/X70M, all tested specimens in base metal, weld and HAZ (where applicable) positions demonstrated high resistance against hydrogen-assisted crack growth and the measured values for the KIH fracture

52

World Pipelines / APRIL 2021

toughness property were always higher than the minimum required value of 55 MPa√m. Furthermore, the observed fracture mechanism does not pose any evidence of brittle or low-energy cracking phenomena.

The excellent resistance of the tested pipes against hydrogen embrittlement was endorsed by the chemical analysis characteristics of the tested pipes (Table 3) as in all cases the steel quality was characterised by low carbon content and carbon equivalent (PCM) and high levels of cleanliness (very low P, S). In addition, the TMCP processed coils (or plates, for the case of the SAWL pipe) presented in all cases a fine polygonal or acicular ferrite microstructure with finely dispersed pearlite and no or minimal banding (Figure 5). Such characteristics in steel chemical composition and microstructure are in-line with the recommendations of the hydrogen linepipe code (side bar).

The certification of pipes for the transportation of pure gaseous hydrogen or H2/NG gas mixtures without additional design pressure limitations can be therefore achieved, on the basis of pipe material’s fracture resistance properties qualification following design ‘Option B’ requirements of code ASME B31.12.

It has been therefore demonstrated that the requirements of the code for the pipe material are consistently feasible, thus certification of a higher grade line pipe for 100% hydrogen transportation using Option B can be provided. This certification can be the first step towards the efficient transportation of larger volumes of hydrogen through the steel pipeline network in the future.

References 1.

2.

3.

4.

5.

6.

7.

IEA Report for the G20, “The future of hydrogen: Seizing today’s opportunities,” June 2019.

Pacific Northwest National Laboratory, “https://h2tools.org,” H2 Tools.

[Online].

XU, K., “Hydrogen Embrittlement of carbon steels and their welds,” in Gaseous hydrogen embrittlement of materials in energy technologies, Oxford, Woodhead Publishing, 2012.

ASM B31.12-2019, “Hydrogen Piping and Pipelines,” 2019.

HAYDEN, L. E. and STALHEIM, D., “ASME B31.12 Hydrogen pipeing and pipeline code design rules and their interaction with pipeline materials. Concerns, issues and research,” Prague, Czech Republic, 2009.

ASTM E1681-03 (2013), “Standard Test Method for Determining Threshold Stress Intensity Factor for Environment-Assisted Cracking of Metallic Materials,” 2013.

ASME Boiler and Pressure Vessel Code, Section VIII, “Rules for Construction of Pressure Vessels, Division 3, Alternative Rules for Construction of High Pressure Vessels.”, 2013.

Neil Gordon, Subsea UK, explains how firms developing new technologies for the subsea industry can improve their access to crucial funding for their R&D drives.

T

he unprecedented events of 2020 and the repercussions on the oil and gas industry have been well-documented. The year itself is behind us, but the impact of the litany of global challenges which came together to create a perfect storm – affecting economies around the world – will remain with us for some time.

The focus is, however, on the future and how we best position and prepare ourselves for recovery. A crucial element of that recovery will be driven by the subsea supply chain and the innovative, disruptive technology which it is developing to meet the challenges post-COVID-19 of the energy transition and race to net-zero.

In the ongoing demand for a safer, more efficient, cost-effective and lower carbon industry, a weakened subsea supply chain could be one of the biggest threats we face. The devastation caused by the pandemic, coming on the back of a fragile recovery in oil and gas, has been too much for many companies with several casualties, inevitable redundancies and restructuring and a subsequent lack of capital to invest in people, equipment and research and development.

53

Protecting, supporting and positioning the supply chain so that it has the capability to rise to the challenges and help deliver the energy transition must therefore be a priority for all stakeholders.

There are three points in the recently announced UK Government 10 point energy plan which are of major interest to the underwater engineering industry and its supply chain.

These are offshore wind, hydrogen and carbon capture (CCUS) – all of which will, in some form or other, rely on the subsea expertise, particularly around pipelines, which has been honed in the North Sea oil and gas sector and now leads the way around the world.

When these pilot projects start emerging, it is crucial that the subsea supply chain is involved from the outset in order for it to develop the technology and skills that will be needed to make these pilots successful and, once proven, exported around the world.

The depth of experience built up over the decades to support the subsea pipeline infrastructure will have a vital role to play in bringing these new technologies to market.

Our oil and gas pipelines traverse the deepest and harshest seas throughout the world. Constantly subjected to undersea hazards and a changing environment, ongoing research and development into new technologies which advance and overcome the challenges of internal and external subsea inspection and monitoring, is vital and will have a place in the growing blue economy industry.

As pipelines age, smarter and more sophisticated methods of corrosion mapping and inspection are essential, with the technology being developed having applications across the wider sphere of subsea activity.

Advances in underwater robotics and AUVs are pushing the boundaries of our capabilities further than ever before.

Analysis techniques which can monitor and identify changes in the seabed and how they impact on pipeline infrastructure are continuously being developed and refined, building

Figure 1. Blue Ocean Monitoring – light class AUV pipeline inspection.

54

World Pipelines / APRIL 2021

our knowledge and enhancing our underwater engineering expertise.

As a trade body, which represents the UK’s underwater engineering sector, Subsea UK’s role is to help members identify where opportunities lie in the UK and around the world to support these existing and emerging industries. One of the ways we do that is by making sure that companies have all the tools they need to identify and capitalise on those opportunities.

Funding Against the backdrop of the current economic climate, where resources are constrained due to the oil price collapse and the global pandemic, one of the most important tools to hand will be access to funding. The ability to identify and secure sources of funding, which will support the R&D activity that ambitious companies need to take their ideas and innovation to the next level, will be key.

In the UK, funding from UKRI (UK Research and Innovation) alone is worth around £6 billion per year. Add to that, the availability of grants from sources as diverse as Innovate UK, the European Space Agency, the UK government’s Defence and Security Accelerator and Eurostars, and the potential to apply for and secure vital funds for R&D activity is huge. Multiply that by the availability of R&D funding and grants in nations around the world, and the potential is truly immense.

However, for many companies that funding pot can seem like an elusive, almost unattainable prize. The subsea sector has, to a large extent, been built on the ingenuity of SMEs. Capable of developing technologies that operate in the deepest, harshest underwater environments in the world, many of these companies’ engineering expertise does not extend to the specifics of successfully completing a funding bid – a skill in its own right.

A survey of the UK’s subsea SMEs found that in many cases, they miss out on securing funding support because

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they do not know it exists, they believe the process for applying is too complex or they have tried and been knocked back before. It is likely subsea companies around the world are confronted with the same challenges and frustrations.

Improving funding applications To help address this and to increase the number of firms able to access funding for vital R&D, Subsea UK has developed a series of webinars – the de facto way of communicating in current times – which are providing real, practical advice to equip companies with the knowledge to help give them a better chance of success.

We partnered with Scottish Enterprise and the wider Enterprise Europe Network to deliver these. Despite the name, its reach goes well beyond Europe, taking in 60 countries from North America to the Far East.

Within those 60 countries is a network of more than 600 partner organisations, and their expertise in helping the SME community navigate the complexities of the various funding programmes is invaluable.

This is a highly competitive market, so much so that the average success rate for companies applying for UK and international funding is 10% across most streams. That figure sounds, and is, low until we understand why. Quite simply in many cases it comes down to a lack of adequate preparation and often sloppy submissions which have not been given the care and attention they deserve and demand.

To have any chance of success, funding applications which are submitted must have the competitive edge. They must be clear, complete, well-prepared, and they must include all the information that has been asked for. The mantra, repeated time and time again by the experts, is read the question, and make sure you fully understand it before answering.

Much too often, opportunities to secure potential funding – no matter how good the concept is – slip away because applicants do not answer the question in the way those assessing it are looking for, or they gloss over the answer because they think it might preclude a funding award.

If a funding stream requires a collaboration with partners, do not make an application if you do not have that collaboration in place. If your project costs exceed the stated value, this is not the funding opportunity for you. If you think your concept is so good that the rest does not really matter, you’re wrong.

Being confident that you are on the cusp of unleashing cutting edge technology on the world is not enough. That confidence has to be backed by a sound, deliverable business plan, and there must be identified and researched market potential with a clear indication of commercialisation.

Access to funding which supports R&D programmes can transform a ground-breaking idea or concept into a proven, commercialised solution for pipelines. Alongside this, the results of this R&D will be critical when it comes to achieving net-zero and developing hydrogen and CCUS projects at a scale to deliver the energy transition.

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