World Pipelines September Issue 2021

VERSATILE. Always a leading innovator, we supply customers with cutting-edge diagnostic and system integrity solutions. This, bound with our focus on flexibility, reliability, cost and quality, leads to offerings beyond your expectations.

www.rosen-group.com

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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 9 | SEPTEMBER 2021 03. Comment Driving down emissions

METERING AND MONITORING 36. On a mission to cut emissions

05. Pipeline news

Stephen Gibbons, Global Market Manager for Continuous Gas Analysers for ABB Measurement & Analytics.

With news from Strohm, T.D. Williamson, Michels Canada and more.

41. The why, when and how of calibration

REGIONAL REPORT 8. New opportunities, old challenges

Erik Smits, VSL, The National Metrology Institute of the Netherlands.

SEALING TECHNOLOGIES 45. Testing pipeline tapes

There is plenty of room for industry growth in the oil and gas-rich regions of Latin America, but also many hurdles to overcome along the way, as Gordon Cope discusses.

Thomas Kaiser, Managing Director, DENSO Group Germany.

49. Sealing materials in the hot seat Isabelle Strømme, MSc, Vipo, Norway.

L

atin America contains tremendous potential, with both the largest national reserves in the world (Venezuela), and the hottest offshore plays (Brazil, Guyana, Suriname). It also faces many challenges, including civil, regulatory, and external factors beyond its control.

PIPELINE CLOSURES 54. An open-and-shut case

Mexico

There is plenty of room for industry growth in the oil and gas-rich regions of Latin America, but also many hurdles to overcome along the way, as Gordon Cope discusses.

Mexico’s oil and gas sector has been on a roller-coaster ride for the last decade, first with the privatisation of the sector under President Pena Nieto, then the more nationalistic policies of his successor President Lopez Obrador (AMLO), and the scourge of COVID. First, the good news. Liberalisation of the sector has led to major investments by explorers and transportation companies.

International players have discovered several billion new bbls offshore, and helped to rejuvenate clapped-out onshore fields. In April 2021, CNH, the state hydrocarbons commission, announced that output involving private companies had reached 264 000 bpd. The amount includes both independent fields and those operated jointly by Pemex. That number is expected to grow at an average annual rate of 18%, reaching over 700 000 bpd by 2030, with the majority occurring in privately-run fields.

Morgan Sledd, Stark Solutions, USA.

Morgan Sledd, Stark Solutions, USA, discusses the importance of both the correct style and ease of operation when it comes to pipeline closures.

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ipeline integrity and maintenance depend upon ease of access to the inside of the pipelines. Today, that access could be in almost any part of the world; a residential area in middle America, the arid desert conditions of the Middle Eastern region, the cold climates of Canada or southern Australia, the corrosive offshore of the Pacific coastal nations, or even the wet and humid landscape of the tropical South American regions. It pays to have product options that fit your application, your media, and your region. Stark Solutions offers pipeline and pressure vessel quick opening closure solutions to meet those needs.

ROUTE SELECTION 15. View from the top

Quick opening closures Quick opening closures have been a mainstay in the oil and gas industry for many years. Starting off as flanged openings with a hinge or davit arm to support the removal of the blind flange, these openings were a means of entry into a pipeline or vessel for inspection and cleaning. Flanges have

Nomcebo Jele, SuperVision Earth, Germany.

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PIPELINE MATERIALS 23. Alloy application Rodrigo Signorelli, Outokumpu, Brazil.

OFFSHORE 58. Collaborating on an environmental code

PIPELINE INTEGRITY MANAGEMENT 29. Keeping tabs on deposits

Nadine Robinson, Technical Adviser – Environmental Sustainability, International Marine Contractors Association (IMCA).

Arto Voutilainen, Ossi Lehtikangas, Antti Nissinen, and Mika Tienhaara, Rocsole Ltd, Finland.

Matthew Grimes, Siemens Energy, USA.

Featuring Trencor.

ON THIS MONTH'S COVER Reader enquiries [www.worldpipelines.com]

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Volume 21 Number 9 - September 2021

RENEWABLE ENERGY COATINGS

ENERGY INFRASTRUCTURE COATINGS

STRUCTURE PROTECTION, FLOORING AND MAINTENANCE COATINGS

SAFETY AND INTEGRITY COATINGS

COMMODITY PIPELINE COATINGS

WATER AND DESALINATION PIPELINE COATINGS

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ONE COMPANY. INNOVATIVE COATING TECHNOLOGIES. ULTIMATE PROTECTION

One Coating Company Protecting the Future

ISSN 1472-7390

33. Leak detection with layers

PIPELINE MACHINERY REVIEW 63. Pipeline machinery review

COMMENT

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DRIVING DOWN EMISSIONS

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utomobile industry leaders were welcomed to the White House on 5 August for an announcement on vehicle emissions. US President Biden declared his intention to reinstate more ambitious Corporate Average Fuel Economy (CAFE) standards (that were rolled back by the Trump administration) and he unveiled the signing of an executive order for 50% of all new vehicles by 2030 to be either battery electric, plug-in hybrid electric, or fuel cell.

As the global economy shifts into electric vehicle technology and cleaner fuels, Biden made it clear that the US would need to strengthen its leadership on clean transport, in order to compete against overseas automakers. Biden promised to support union workers in his bid for the presidency and the event was strongly supportive of unionised auto workers in the quest for growth in the sector.

Electric vehicle (EV) and clean energy company Tesla was omitted from the list of invited parties: an article

by Tina Casey on Biden’s announcement suggests that it was “Tesla’s history of troubles relating to unions” that kept them off the guest list.1 She argues that “President Biden may also have used the event to send a message about his expectations for public-private collaboration and intra-industry co-operation.” Tesla has famously ploughed its own furrow, most recently when it comes to dealing with workers: co-founder and CEO Elon Musk has been criticised for Tesla’s worker safety policies during the COVID-19 pandemic. He has also been outspoken in his dismissal of hydrogen fuel cell technology, even as many automobile manufacturers pursue the use of fuel cells to electrify trucks, and larger construction vehicles and equipment, as well as cars.

In its annual Impact Report for 2020 (released in August 2021), Tesla claims that its EVs “helped avoid 5 million metric t of CO2-equivalent emissions”.

Tesla says that the average internal combustion engine vehicle emits 69 t of CO2-equivalent over its lifetime, but Tesla vehicles are just a fraction of this, particularly if they are used for ‘ride-sharing’ and are solar charged. This reduction in so-called ‘lifecyle emissions’ contributes handsome gains to a nation’s emissions profile. Tesla also reports that its “cars can convert electricity into power more efficiently than other equivalent EVs”, in part due to its long-lasting batteries, 100% of which will be recycled.

In July it was reported that Tesla had sold enough cars and energy products to make a profit even without counting the sale of emissions credits to other automakers, which was a milestone for the company. The company will increase production capacity when it commences making EVs at the two factories it is currently building in Austin, Texas and Berlin.

The annual report laid out Tesla’s plans to sell 20 million EVs per year by 2030 – from half a million in 2020 – and deploy 1500 GWh of energy storage per year, compared to 3 GWh last year. Sustainability really does drive the way the business is run: as Teslarati, a Tesla news source puts it, “Tesla’s products and services are focused on transportation and energy production and storage – segments that are traditionally the most polluting.”2 In this month’s issue of World Pipelines, Stephen Gibbons from ABB Measurement & Analytics discusses developments in process gas analyser technology that are helping to keep emissions to air under control. He explains that, globally, emissions regulations are being tightened and part of the picture is an increasing need to monitor, and control, the gases being released. Various continuous emission monitoring systems (CEMS) are on the market, using different techniques to measure gases. There are many variables for a pipeline operator to consider when specifying CEMS to stay within emissions limits: read the article on p. 36 to find out more, including some insight into digital solutions and condition monitoring using real-time data. Also in this issue, Trencor outlines the benefits of its T14 trencher in terms of engine rating and compliance to EPA and EU emission standards requirements. Read all about the updated machine packages in Trencor’s piece on p. 63. Finally, on p. 15, SuperVision Earth presents a look at the ways in which satellite technology can enhance oil and gas pipeline monitoring activities. The article stresses that “carbon dioxide emissions are not falling fast enough in developed countries, where they have already peaked, to counteract emissions growth elsewhere.” The company’s mission is to make oil and gas infrastructure safer and more efficient by utilising AI and satellite technology, harnessing both optical and radar data to build a detailed picture of an asset on – or in – the ground.

TESLA PLANS TO SELL 20 MILLION EV PER YEAR BY 2030

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https://www.triplepundit.com/story/2021/white-housetesla-ev/726596 https://www.teslarati.com/tesla-2020-impact-report-ecosystemexplained/

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WORLD NEWS Tracerco awarded subsea pipeline integrity inspections in Gulf of Mexico Industrial technology service provider, Tracerco, part of Johnson Matthey Plc, has recently been awarded three subsea inspection contracts to provide critical asset integrity data on pipelines of a major operator in the Gulf of Mexico. As pipelines age over time, a variety of pipeline integrity issues, including corrosion, pitting and wall thinning start to arise, and the integrity of the assets could be compromised. Regulatory and safety demands are the key drivers of regular inspection campaigns.

Tracerco’s multi award-winning DiscoveryTM, a subsea CT Scanner, will be deployed to carry out the subsea inspections providing the operator with detailed, high-resolution tomographic images of the pipe wall thickness and contents to gain an enhanced understanding of the pipelines’ condition. The tomographic image will identify any wall loss features within the

pipe as well as the location, amount and density of any material and/or deposits in the line and will allow the operator to plan for the future life of the pipelines. As CT scanning is a nonintrusive, external inspection method, all assets will remain fully operational throughout each project, eliminating interruption to production or the need for pipeline modifications.

“We are pleased to have been awarded these projects” said Jim Bramlett, Commercial Manager North America for Tracerco.

“Maintaining a pipeline’s integrity is invariably cheaper than performing significant repairs or pipeline replacement and we can help to ensure that potential failures are identified as early as possible. Through non-intrusive inspection, the Discovery allows us to assess the condition of the pipelines through any type of protective coating, while online and all in real-time.”

T.D. Williamson completes first pipeline inspection in Kenya using MDS technology T.D. Williamson (TDW), the global pipeline solutions provider, completed its first inline inspection (ILI) in Kenya using TDW multiple dataset (MDS) technology.

The MDS platform incorporates a variety of inspection technologies on a single platform. It is widely accepted as the most comprehensive system on the market to identify integrity threats through a single inline inspection run.

TDW performed the inspection on a new, 20 in. diameter refined multi-product transmission pipeline that runs 450 km (279 miles) from Mombasa to Nairobi. The pipeline is owned and operated by the Kenya Pipeline Company (KPC). The goal of the operation was to provide a baseline measurement to determine any threats that may impact future integrity, including mechanical damage, illegal hot taps, selective seam

weld corrosion and material property changes such as hard spots.

Prior to the MDS inspection, TDW and its Egyptian Channel Partner Engineering Petroleum Services (EPS) cleaned the pipeline to avoid potential ILI tool performance issues that can degrade inspection data. They performed 12 cleaning and gauging runs on the 450 km (279 miles) of pipeline, totalling 3600 km (2237 miles) of cleaning.

TDW Project Manager Jamie Bull oversaw the cleaning, gauging and inspection operations. Each achieved 100% success.

According to TDW Sales Manager Mohamed Hesham, the inspection prepared the pipeline to meet demand for petroleum products in Kenya and the region for years to come.

Strohm plans new TCP centre of excellence and office base in Brazil Leading global composite pipe technology company Strohm has opened a new office in Rio de Janeiro and is establishing a centre of excellence for engineering its Thermoplastic Composite Pipe (TCP) technology as part of its growth strategy in South America.

Strohm is extending its footprint in Brazil and gearing up for the execution of a significant contract, which is expected to be announced soon. The company is aiming to hire an additional ten local people over the next twelve months to bolster the engineering and back-office support teams to further enhance business development opportunities.

Once the operation ramps up in the coming years, there are also plans to establish a local TCP manufacturing capability to better support the clients in the region.

Strohm’s TCP technology outperforms existing solutions in terms of durability, corrosion resistance and total installed cost. Further cost reductions are possible by capitalising on the knock-on effects of using TCP. Renato Bastos, who has been Strohm’s Vice President in Brazil for the past three years, will head up the Rio de Janeiro site. He has over 20 years’ experience in the energy industry,

with a strong background in the installation of steel and flexible pipes.

Mr Bastos said: “With Brazil’s ultra deepwater market ramping up and an increasing number of independent operators acquiring fields from Petrobras, we see opportunities both in the highly demanding pre-salt applications as well as with the independents on the mature fields.

“With this move, we are in a great position to take advantage of these opportunities. Our TCP is perfectly suited as it’s non-corrosive and robust, offering up to 60% reduced CO2 footprint compared to steel alternatives. It also has reduced installation costs as it is so lightweight.

“Establishing a new office in Rio as well as a new TCP engineering centre is an important stepping stone towards our long-term vison of designing and manufacturing locally in Brazil. It also enables us to further pursue relevant research and development projects with the operators established in country, under Brazil’s National Agency of Petroleum framework, as well as demonstrates our commitment to our clients and the local economy.”

SEPTEMBER 2021 / World Pipelines

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WORLD NEWS EVENTS DIARY

Fugro completes subsea installation for GUPCO

NEW DATES AND LOCATION: 21 - 23 September 2021

Fugro has revolutionised a subsea installation programme for Gulf of Suez Petroleum Company (GUPCO) with its innovative QuickVision® technology. Used for the first time in Egypt, the contactless positioning solution replaced the conventional survey sensors typically attached to subsea structures during installation.

Under a contract with Dragon Oil (GUPCO), Fugro delivered subsea positioning support for the installation of multiple subsea structures off the coast of Egypt. To meet the requirements for improved safety and lower project costs, Fugro deployed their QuickVision solution.

This state-of-the art vision technology uses a smart camera, attached to a remotely operated vehicle, that can determine the heading and attitude of a subsea structure as it is landed. This

Gastech Exhibition & Conference 2021 Dubai, UAE https://www.gastechevent.com/

NEW DATES: 21 - 23 September 2021 Global Energy Show 2021 Calgary, Canada https://www.globalenergyshow.com/

18 - 19 October 2021 Transportation Oil and Gas Congress 2021 (TOGC 2021) Zurich, Switzerland https://togc.events/

20 October 2021 OpTech 2021 ONLINE CONFERENCE

eliminates the requirement to pre-install a sensor package on the structure, and retrieve it once installation is complete, which reduces the time and costs associated with a divesupport vessel.

Noting the benefits that real-time access to the positioning Geo-data brought to the project, Fugro’s Project Manager, Sherif Abd El Aziz, said: “Introducing the power of augmented reality has had a hugely positive impact on this project’s delivery.”

Lotfi Ibrahim, Drilling Operation Manager for Dragon Oil (GUPCO), added: “The conventional sensor method is time-consuming and is not without risk.

Fugro’s QuickVision allowed us to deliver safer and more sustainable operations, and within the desired accuracy. It has revolutionised our subsea installation programmes.”

Michels Canada completes Canada’s longest HDD installation

https://www.worldpipelines.com/optech2021/

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

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

7 - 9 December 2021 15th annual GPCA Forum Dubai, UAE www.gpcaforum.net

31 January - 2 February 2022 European Gas Conference (EGC) 2022 Vienna, Austria www.energycouncil.com/event-events/europeangas-conference/

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World Pipelines / SEPTEMBER 2021

Michels Canada used using horizontal directional drilling (HDD) to complete a 3540 m crossing in Burlington, Ontario, under the Hidden Lake Golf Club. The installation is part of Imperial’s Waterdown to Finch Project, a proactive replacement of approximately 63 km of the Sarnia Products Pipeline between the Waterdown pump station in rural Hamilton and the storage facility in Toronto’s North York area. The Hidden Lake HDD is the longest successful HDD installation in Canada to date, surpassing the previous record of 2195 m, also set by Michels Canada.

“The completion of record-length trenchless projects like this one demonstrate our capabilities for safe, environmentally sound ways of constructing new or replacing existing utility lines,” said Gary Ziehr, Vice President, Energy, Michels Canada. “When HDD and other trenchless methods are used to complement traditional open cut utility construction methods, we are able to support our clients in safely delivering needed energy supplies to their customers.”

Due to the length of the crossing, Michels Canada deployed a rig on each end of the alignment. Operators used the rigs to drill toward one other and then used gyroscopic survey and steering technology to complete the intersection of the two bore holes. The alignment follows the right-of-way of the original Sarnia pipeline, so the Michels Canada team had to carefully navigate the five horizontal curves along the alignment.

THE MIDSTREAM UPDATE •

Plains All American announces governance enhancement

•

Centurion Pipeline L.P. releases inaugural sustainability report

•

Decom solutions company expands into Aberdeen

•

SkyX to provide Denbury with aerial monitoring solution

Follow us on LinkedIn to read more about the articles linkedin.com/showcase/worldpipelines

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There is plenty of room for industry growth in the oil and gas-rich regions of Latin America, but also many hurdles to overcome along the way, as Gordon Cope discusses.

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atin America contains tremendous potential, with both the largest national reserves in the world (Venezuela), and the hottest offshore plays (Brazil, Guyana, Suriname). It also faces many challenges, including civil, regulatory, and external factors beyond its control.

Mexico Mexico’s oil and gas sector has been on a roller-coaster ride for the last decade, first with the privatisation of the sector under President Pena Nieto, then the more nationalistic policies of his successor President Lopez Obrador (AMLO), and the scourge of COVID-19.

First, the good news. Liberalisation of the sector has led to major investments by explorers and transportation companies.

International players have discovered several billion new bbls offshore, and helped to rejuvenate clapped-out onshore fields. In April 2021, CNH, the state hydrocarbons commission, announced that output involving private companies had reached 264 000 bpd. The amount includes both independent fields and those operated jointly by Pemex. That number is expected to grow at an average annual rate of 18%, reaching over 700 000 bpd by 2030, with the majority occurring in privately-run fields.

9

Mexico has also shifted its industrial and utility energy consumption patterns toward natural gas. Over the last decade, the major gas transmission network running from Texas to the heartland of Mexico has expanded at a tremendous clip; import capacity now stands at 11 billion ft3/d. In April 2021, exports from the US to Mexico reached an all-time high of 7 billion ft3/d due to high temperatures experienced in the Mexico City region. As a result, pipelines heading south saw significant load increases.

While the 2.6 billion ft3/d Texas-Tuxpan line began operations in late 2019, it has yet to reach capacity; in April, 2021, however, one third of the month saw flows above 1 billion ft3/d, a high mark for the system so far, and a harbinger for increased flows as summer temperatures peak.

Further domestic buildout is expected to keep demand on the increase. In late 2020, Mexico-based Fermaca completed the final leg of its 5 billion ft3/d Wahalajara pipeline network stretching from Waha, Texas to Guadalajara. Cenagas plans to add 1 billion ft3/d incremental capacity to its Montegrande interconnect in central Mexico, as well as alterations to the 1.3 billion ft3/d Cempoala compressor station that will allow US gas to reach southern Mexico.

Additionally, various companies are exploring gas export opportunities from Mexico. Sempra Energy’s Mexican subsidiary is advancing plans to convert the Energia Costa Azul (ECA) LNG import terminal on the Pacific coast to a liquefaction facility. The US$1.9 billion project has plans to build two trains that will convert US gas into LNG. Manzanillo’s import terminal (also on the Pacific coast), could likewise be converted, using gas supplied by the Wahalajara pipeline.

While COVID caused a temporary collapse in demand in 2020, consumption has gradually returned to previous levels. Of more concern are the nationalistic policies of AMLO, who wishes to see Pemex return to its days of glory. The government has cancelled lease auctions, while at the same time injecting approximately US$17 billion into Pemex to keep the highly-indebted company afloat. A bill was also introduced into the lower house of Mexico’s parliament to remove a law that instructed CRE, the state energy market regulator, to prioritise private fuel sales to create a level playing field with the state-owned oil company. Other changes would limit fuel imports by private companies. “Conditions for private sector operators could become much more complicated, and Pemex could perhaps undercut the competition,” noted a Mexico City-based analyst.

Weather had a major impact on gas exports to Mexico.

In February 2021, a polar vortex hit the state of Texas, causing gas wells to freeze and production to drop from around 24 billion ft3/d to as low as 11 billion ft3/d, causing the Texas governor to temporarily cancel exports. Deliveries to Mexico dropped from an average of 5.7 billion ft3/d to 3.8 billion ft3/d.

The company scrambled for replacements using its LNG import facilities on the Pacific and Gulf of Mexico coasts, but it took over a week for deliveries to return to normal. Utilities are looking at increasing gas storage facilities to ameliorate similar disruptions in the future.

Venezuela Venezuela’s oil and gas sector continues to face a spectrum of self-imposed woes, as well as sanctions from the US. OPEC

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World Pipelines / SEPTEMBER 2021

estimated that Venezuela produced 521 000 bpd in early 2021, up from the average of 500 000 bpd in 2020, but still down from 800 000 bpd for 2019. Infrastructure continues to deteriorate; in March 2021, a pipeline that transports associated gas to a reinjection plant burst and caught fire, forcing PDVSA to suspend 30 000 bpd production from a light crude oil field.

While Venezuela continues to export crude in spite of US sanctions, it was dealt a serious blow in May 2021, when China imposed punitive taxes on substandard diluted bitumen being imported from third parties in Malaysia. Analysts estimate that around 400 000 bpd of Venezuelan crude had been following the circuitous route; the Chinese move, which will add around US$30/bbl in taxes, will make the source unprofitable, orphaning a huge amount of Venezuelan exports.

Colombia Colombia’s COVID-related lockdown and loss in demand (as well as low prices), significantly affected the country’s oil and gas sector. Oil production went from almost 900 000 bpd in early 2020 to 750 000 bpd, where it has languished, in spite of a recovery in demand as lockdowns are lifted. Part of the reason is a lack of investment, which dropped from US$4 billion in 2019 to US$2 billion in 2020, before climbing back to an estimated US$3 billion in 2021. As a result, drill rig counts have dropped from 30 in 2019 to half that in 2020 and 2021. Colombian crude has a breakeven price of US$45/bbl; the heavy, sour grades require discounts to sell to markets that are looking for low sulfur feedstocks.

Strife remains a major impediment to current and future foreign investment needed to encourage a healthy oil and gas sector. Although peace deals were brokered between the main guerrilla groups, including FARC, violence still continues as splinter groups continue to attack oilfields and the 210 000 bpd Caño Limon-Covenas pipeline.

A bright note; while conventional reserves sit at 2 billion bbls, the USGS estimates that the Middle Magdalena Valley contains shale oil resources; up to 7 billion bbls of crude and 13 trillion ft3 of gas. While a fracking ban has been in effect for several years, the country’s Council of State recently allowed for experimental tests to proceed. Ecopetrol and ExxonMobil have announced pilot fracking projects with a combined budget exceeding US$130 million. The Colombian Petroleum Association estimates that commercial fracking could add as much as 450 000 bbls of daily production and attract US$5 billion of investment.

Brazil Brazil has been a beacon of light through the COVID pandemic.

Although production dropped 3% during the worst of the pandemic in 2020, it has since surged back; in May 2021, the national regulator reported that output had increased 8.5% yearover-year, to a new high of 3.8 million boe/d. Much of that gain has been through the continued development of the presalt fields, which reached 2.7 million bpd in May 2021, as well as high demand from Asia for the low-sulfur crude.

While Petrobras is the lead crude producer in Brazil, the NOC’s heavy debt burden has impeded the monetisation of natural gas production in offshore waters. In April 2021, Brazil’s output of gas associated with presalt production reached

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3.25 billion ft3/d (out of a total of 4.6 billion ft3/d for the country).

Due to a lack of infrastructure, however, most of the offshore gas is either reinjected or flared.

A new regulatory framework recently passed by the federal government allows for the liberalisation of the gas sector, providing third-party access to pipelines and other infrastructure owned by Petrobras.

In September 2020, Petrobras signed contracts with Repsol Sinopec and Shell to share gas pipeline and infrastructure. The contracts allow interconnection and sharing of Santos Basin assets, including Rota lines 1, 2 and 3. When line 3 comes online in 2022, it will deliver up to 750 million ft3/d from the Santos Basin to a processing terminal in Rio de Janeiro state. Equinor and Repsol Sinopec have also contracted with Petrobras to co-develop the BM-C-33 presalt block, located 200 km offshore of Rio de Janeiro state. An FPSO will produce up to 125 000 bpd of crude and 500 million ft3/d of gas that will be transported by a new pipeline to shore. In all, federal agencies have mapped out a total of 11 gas lines to connect various offshore fields to onshore facilities. If all goes to plan, marketable natural gas production is expected to increase to 6.1 billion ft3/d by 2025.

In the meantime, the most severe drought in almost a century is motivating Brazil to instigate talks with Argentina to build a US$5 billion natural gas pipeline between Argentina’s Vaca Muerta shale play in Neuquen province and the country’s populous southern region. Brazil relies on hydroelectric power for around 75% of its electricity needs, and the lack of rain has pushed reservoirs to dangerously low levels. Brazil normally relies on LNG to meet gas shortfalls, but demand in Asia has pushed prices to unacceptable levels, and the government is looking for long-term alternatives to meet its gas import needs.

Argentina Protests and strikes have swept across Argentina in recent months, some affecting oil and gas producing regions. In April 2021, health care workers seeking higher wages targeted portions of the Vaca Muerta shale oil play in Neuquen province. Roadblocks prevented supplies from reaching rigs and fracking crews, temporarily hindering development.

In order to bolster the economy and dampen protests, the administration of President Fernandez announced that the government will place a priority on the energy sector in order to attract investment, boost production, and bolster exports. In 2019, investors pumped US$4.4 billion into the play; that dropped to US$2 billion in 2020 as COVID took hold, but is expected to return to US$3.8 billion in 2021 as government support attracts new capital expenditures.

Argentina is also benefiting from higher Brent prices, which have been above US$60 for the last several months. Analysts estimate that the Vaca Muerta play has a breakeven range of US$45 - 50, encouraging developers to complete wells at a record rate; Neuquen production (from both conventional and unconventional wells), is expected to almost double over the course of 2021, to 235 000 bpd.

The expected growth in production is also igniting interest in takeaway pipeline capacity. Currently, the province is served by the 260 000 Oldelval pipeline, which connects Neuquen to Puerto Rosales in Buenos Aires province. The 100 000 bpd Otasa pipeline,

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World Pipelines / SEPTEMBER 2021

which runs 400 km from Neuquen province to a 116 000 bpd refinery in Chile, is currently mothballed, but Omar Gutierrez, the governor of Neuquen, says that it is imperative that work to restart the line should begin. “It is very likely we are going to need to use that pipeline next year,” he noted.

Pipeline pilfering Gangs find a new source of income Pipeline theft of crude and refined products has been an ongoing problem in Latin America. In Mexico, fuel theft especially has been occurring on a large scale for over two decades. In 2017, Pemex estimated that it was losing almost 75 000 bpd, costing approximately US$3 billion annually. In 2018, incoming President Lopez Obrador ordered a crackdown, shutting down illicit pipelines that Pemex staff and criminal gangs had been using to siphon product directly from refineries. The state-owned oil company now estimates that theft stands at around 5600 bpd.

In other regions of South America, Washington’s focus on eradicating drug traffic has resulted in narcotics gangs switching focus to petroleum theft.

By September 2020, Ecopetrol reported that it had discovered 900 illegal valves in the first eight months of the year, compared to 747 for the same period in 2019; approximately 2500 bpd of oil and derivatives were being stolen, costing the state-owned oil company approximately US$40 million per year. Most was stolen from the Caño Limon-Covenas pipeline; Colombian police believe about one-third ends up in neighbouring Venezuela.

In Brazil, Petrobras reported that crude and fuel thefts had soared from one reported case in 2014, to over 250 by 2018. In 2020, Petrobras officials revealed that theft was costing the transportation segment US$28 million annually; concerted efforts are underway by the company and federal authorities to reduce incidents.

While the theft of petroleum in Argentina has not achieved the scale experienced in Mexico, federal police discovered that thieves tapped into YPF’s 325 000 bpd Rosales-La Plata crude pipeline between the port of Rosales and YPF’s La Plata refinery. While no volumes stolen have been announced, 21 suspects were arrested, including YPF employees, pointing to a sophisticated, large-scale operation.

While most jurisdictions are moving to ameliorate theft, security forces in many jurisdictions are stretched thin by more pressing issues, such as civil war, unrest and violent crime. Fuel theft is seen as a victimless crime; complications arising from COVID and the loss of state revenues hinder the efforts of authorities to reign in the criminal activity.

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In July 2021, Shell Argentina announced the construction of a 105 km crude pipeline in the Vaca Muerta in order to eliminate a transportation bottleneck. The 16 in. line will transport up to 120 000 bpd between Neuquen and Rio Negro provinces. The US$80 million project is expected to enter service at the end of 2022.

bring offshore production to almost 800 000 bpd by 2025. Exxon and partner Hess have a total of six projects and up to 10 FPSOs planned for Guyana by 2027. The light, sweet crude being pumped makes it relatively easy to create high-quality fuels; break-even prices for the play are estimated to be as low as US$25/bbl.

Suriname Guyana In Guyana, the prospects for the oil and gas sector continue to brighten. In May 2021, ExxonMobil announced a new discovery in its offshore Starbroek block, Uara-2, which now places its reserves above 9 billion bbl of oil. Currently, Guyana’s production stands at approximately 130 000 bpd at the Liza-1 FPSO, with Liza-2 expected to begin 220 000 bpd production in 2022. Exxon has two more projects; the 220 000 bpd Payara project and the 220 000 bpd Yellowtail project, which, when completed, will

The former Dutch colony of Suriname shares much of the offshore Guyana-Suriname Basin in which ExxonMobil and partners have made major discoveries. Total and Apache, which hold the Block 58 lease in Suriname waters, have made four oil discoveries contiguous with Exxon’s Stabroek Block. Rystad Energy estimates that recoverable reserves now stand at almost 2 billion bbls. The consultancy further expects that production from the impoverished country could begin as soon as middecade, with output rising to 650 000 bpd by 2030.

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The prospects for oil and gas remain bright, especially for natural gas pipelines.

In addition to Brazil’s liberalisation, new producing jurisdictions such as Guyana and Suriname hold tremendous potential for the monetisation of associated gas.

Even Mexico’s phenomenal network expansion still has a long way to go; government agencies note that many aspects are still ‘20-30 years behind’ US infrastructure. A sign of renewed opportunity has already emerged; in August 2021, CFE announced a memorandum of understanding (MOU) with TC Energy, stating that it would work to resolve social conflicts over the 268 km Tuxpan-Tula pipeline; construction was halted on the 886 million ft3/d line amid worries that the ROW would trespass sacred lands. In addition, CFE and TC Energy are also working to extend the country’s natural gas network to the south in order to deliver commercial quantities of gas to the Yucatan peninsula. A new offshore pipeline will be built from the Tuxpan terminal in the state of Veracruz to connect to the Mayakan pipeline system in the states of Campeche and Tabasco. The developments are seen as positive steps toward reconciliation between the pipeline sector and AMLO after the latter renegotiated pipeline contracts in 2019 that he asserted were unfair to Mexican taxpayers.

In conclusion, as the scourge of COVID recedes and demand once again resumes, countries in Latin America will continue to explore and develop their rich endowment of energy resources in an effort to build their economies and improve the wellbeing of their citizens.

Nomcebo Jele, SuperVision Earth, Germany, discusses how satellite technology can help to enhance the monitoring of oil and gas pipelines.

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ipelines are commonly used to transport hydrocarbon fluids across thousands of kilometres around the world. With over a million kilometres of high-pressure pipelines worldwide, oil and gas infrastructure are naturally vulnerable to threats. Although pipeline structures are “designed to withstand several environmental loading conditions, to ensure safe and reliable distribution from the point of production to the shore or distribution depot”, leaks in pipeline networks are a significant source of loss for pipeline operators and the environment.

The causes of pipeline damage vary. Third-party activity, vegetation, and ground movement are all frequent threats to pipeline networks today. Similarly, activities such as construction and drilling near or on pipelines are the major cause of pipeline infrastructure incidents.

To avoid such threats and maintain a secure and reliable pipeline system, SuperVision Earth is developing an innovative

network monitoring solution that offers effectiveness and consistency through the integration of satellite images into pipeline leak detection and risk management workflows.

Review of current pipeline monitoring systems A leak detection system (LDS) is designed to assist pipeline controllers in detecting and locating leaks. Alarms, displays, and other associated data are provided to pipeline controllers to aid in decision-making. This results in reduced downtime and inspection times, increasing productivity and reliability of the pipeline network.

In recent years, natural gas has become one of the world’s most vital energy resources and demand for it is predicted to be growing. Nevertheless, as the demand for natural gas has grown, the problem of pipeline leak detection has become more relevant.

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Most traditional leak detection technologies rely on periodic inspections by helicopter, on foot monitoring, optic sensors, drones and so on. Some more examples include: acoustic emission (Meng, Yuxing, Wuchang, & Juntao, 2014), fibre optic sensor (Lim, Wong, Chiu, & Kodikara, 2016), ground penetration radar (Hoarau, Ginolhac, Atto, & Nicolas, 2017), negative pressure wave (Delgado & Mendoza, 2017), vapour sampling, infrared thermography, digital signal processing, and mass-volume balance (Manekiya & Arulmozhivarman, 2016). Many authors categorise them differently.

For example, fibre optic sensing can provide quicker detection if the leak secretes smaller amounts of the substance, as this method takes direct measurements of different response dynamics. Although fibre optic sensing detection offers many advantages within structural monitoring contexts, it has limitations such as costs of installation, complex and unfamiliar detection systems and the precision required for installation, making it a complicated system to incorporate into existing pipeline leak detection systems (Frings & Walk, 2010).

Right-of-way surveillance – also known as ground patrols and aircraft surveillance – is employed to notice any unexpected behaviour, but they provide neither continuous nor real-time detection. As a result, significant portions of pipeline may go unmonitored for long periods of time,

Figure 1. Statistics on the major causes of pipeline failure (Adegboye, Fung, & Karnik, 2019).

leaving them exposed to unintentional damage or even criminal threats.

According to Barbosa (2021), there is a standard requirement in North America to identify a leak equivalent to 1% of the pipeline’s flowrate. That 1% translates to 1000 bbls in a pipeline moving 100 000 bpd of oil.

Some 250 bbls will have escaped in six hours if a leak is discovered. This emphasises the need for real-time, reliable and accurate pipeline monitoring systems.

A continuous monitoring solution is urgently needed to enable operators to detect breaches and theft attempts more precisely and rapidly, assisting pipeline operators in their efforts to reduce product loss. However, all pipeline leak detection systems currently available fail to enable realtime pipeline monitoring and risk prevention, resulting in delayed leak detection reaction time, system dependability, leak detection sensitivity, positioning accuracy, and system cost (Xu, Zhao, & Bai, 2020). Furthermore, high costs, planning complexities and insufficient access to pipeline routes remain major hindrances to reaching full pipeline security and monitoring.

Satellite monitoring in pipeline leak detection The pipeline industry’s best strategy for dealing with public and environmental safety is risk management.

Satellite technology allows for most threats on and along pipeline routes to be observed from space. The leaks and movements on or near the pipelines can be detected daily by this real-time pipeline monitoring system.

With the use of satellite technology and AI-driven data processing techniques, it is now possible to remotely monitor thousands of kilometres of pipelines for third party activity to prevent hydrocarbon and methane leakage.

Satellites can also assist in identifying new buildings, farms, machinery, and other objects that are encroaching on the right-of-way or pipeline route. Furthermore, satellites are versatile and scalable to use to monitor vegetation along pipelines, including determining the health and growth of various plant species.

Currently, helicopters and airplanes and vehicles with heavy cross-country traffic capabilities are used as a form of remote monitoring for pipeline conditions. These traditional methods are not only time-consuming, but also costly. Research efforts and investments are being injected into more cost-effective remote monitoring methods such as unmanned systems and satellite imaging. Although unmanned aerial vehicles (UAVs) have some advantages in terms of ultra-high spatial resolution, their deployment still necessitates the direct flight of professionals to the location, which incurs additional costs (INNOTER, 2021).

Importance of monitoring Figure 2. Annual CO2 emissions from the burning of fossil fuels for energy and cement production. Land use charge is not included. Source: Global Carbon Project; Carbon Dioxide Information Analysis Centre (CDIAC, 2019).

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World Pipelines / SEPTEMBER 2021

One of the most important reasons for regularly inspecting pipelines is to protect the environment and the human life in the area where the pipeline runs through. The pipeline system, which is buried below, receives less attention than other infrastructure systems such as roadways and bridges.

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Furthermore, depending on what is being transported, regulatory control of pipeline safety, operations, and worthiness is varied.

By offering deep learning in the classification of satellite imagery, in combination with the most recent breakthroughs in AI-based technology, pipelines can now be monitored at great speed and with even higher accuracy. A GIS specialist, for example, can evaluate and record extraneous objects, violations of diversion zones, and air pollution faster than with traditional visual monitoring techniques by executing the algorithm for analysing satellite photos (INNOTER, 2021).

According to INNOTER (2021) the only problem with automatic decryption and detection is the accumulation of geographical patterns and/or training and test data sets. Machine learning algorithms learn from data. The algorithms use training data to form relationships, gain understanding, make judgements and to assess their confidence. In actuality, the quality and quantity of machine learning training data is just as important as the algorithms themselves and the model or algorithm works better when the training data is good (Appen, 2020).

Emissions Since 1990, annual global greenhouse gas emissions have increased by 41% and are continually rising. Energy consumption is by far the most significant source of human-caused greenhouse gas emissions, accounting for 73% of global emissions (Mengpin & Friedrich, 2020). Transportation, electricity and heat, buildings, manufacturing and construction, fugitive emissions, and other fuel combustion are all part of the energy industry.

Carbon dioxide emissions are not falling fast enough in developed countries, where they have already peaked, to counteract emissions growth elsewhere. Emissions in the

EU and the US were projected to fall by 1.7% in 2019, while emissions in India were expected to rise 1.8% (significantly lower than the past five-year growth rate of 5.1%). China’s were expected to rise 2.6% – larger than the global total increase – and finally, emissions in the rest of the world are expected to rise 0.5% (Hausfather, 2019).

Figure 2 is a map that shows the annual CO2 emissions by country, with the highest emitting country being China accounting for a share of 10.17 billion t from the world +36.41 billion t. The Global Carbon Project illustrates how global carbon dioxide emissions from fossil fuels have already reached new heights in 2019, putting the planet at risk of catastrophic climate change due to the heattrapping gases (CDIAC, 2019).

According to the new Global Energy Review 2021 report from the International Energy Agency, energyrelated carbon dioxide emissions are expected to rise by 1.5 billion t this year, the second-largest increase in history (IEA, 2021). According to the report, CO 2 emissions are likely to grow about 5% to 33 billion t in 2021, reversing the estimated drop in emissions from 2020 which was caused by the COVID-19 pandemic. The increase in greenhouse gas (gases that trap heat in the atmosphere) emissions this year will be the highest yearly increase since the global financial crisis ended in 2010.

The IEA claims that the rise in coal use is the primary cause of the increase in emissions, predicting that coal use in 2021 will be close to its all-time high of 2014. According to the International Energy Agency, global CO 2 emissions will rise considerably this year, despite a predicted increase in wind-power output and solar-power generation. In 2021, renewable energy, including hydropower, is predicted to account for 30% of global electricity generation.

Nonetheless, CO2 emissions are rising due to global developing economies, particularly Asia and specifically China, where coal-fired power plant building is on the rise (Global CO2 Emissions set to Surge in 2021 Post-COVID Economic Rebound, 2021).

Patricia Espinosa, the UN’s top Climate official, said: “it’s time to wrap up outstanding negotiations and implement the Paris agreement. Time is running out for the world to achieve the goals of the Paris agreement.

Unleashing its full potential will not only address climate change but [it will] help the world build forward from COVID-19 and drive transformation towards a cleaner, greener and more sustainable future” (Harvey, 2021).

Combining AI and satellite technology

Figure 3. SuperVision Space (SVS) app location detection.

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World Pipelines / SEPTEMBER 2021

Our objective at SuperVision Earth is to make gas infrastructure safer. To do so, we are working on an innovative network monitoring solution that promises efficacy and consistency through the integration of satellite imagery. We can discover dangers such as third-party interference (e.g. construction operations), vegetation change, and ground deformation by analysing satellite data. Our algorithms, which are easily deployed on the cloud, analyse the data and provide alerts that can be directly integrated into the operator’s pipeline monitoring

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but they can also detect changes in soil moisture, for example. Interferometric techniques can also be used to identify and, in certain situations, anticipate large-scale ground deformations and landslides.

Figure 4 illustrates the added value of SuperVision Earth’s service. SuperVision Earth’s AI-innovation detected the threats in the images below. The before and after images were captured one month apart, respectively. They reveal construction activity near the protected area of a high-pressure gas pipeline path. The images provided have the spatial resolution of 0.5 m. Prices of satellite images vary depending on the chosen resolution and range between 0.3 - 0.5 m. In this case, detection from a 0.5 m distance is adequate as data can still be extracted from the image. The yellow line lies on what would be the actual pipeline in real life.

In the case of a traditional aerial survey, valuable time (up to several weeks) would have passed before this was revealed. This solution provides the operator with more time to investigate whether the stored equipment is registered and, if in question, to advise the personnel on site about the nearby pipeline and the related risks, thanks to the earlier warning and detection.

SuperVision Earth’s proprietary technology employs algorithms that detect and classify changes between two photos to achieve these results. The optical data as well as the radar data are both processed. For optical data, all accessible spectral bands are used to produce several indices that distinguish between relevant (e.g., a construction site) and irrelevant changes (e.g., the harvesting of an agricultural field). In order to improve the classification, historical photographs are added in addition to current images. In addition to the optical data, radar data is considered.

This, when combined with the optical data, results in optimum detection. In this method, the number of mistakenly recognised dangers (‘false positives’) can be reduced, resulting in fewer unwanted warnings and expenditures owing to the operator’s superfluous reactions. Our algorithms are continually evolving with the help of machine learning technologies in order to be able to interpret vast amounts of data, and hence recognise various hazards, even better.

Once threats are detected, the information is automatically and immediately sent to the pipeline integrity manager or engineer’s profile on the SuperVision Space app, which also incorporates the customer’s chosen GIS or PIMS software. The SuperVision Space (SVS) app is an AI-based innovation Figure 4. Left: Before – detected construction of a residential house. Right: After – showing that uses earth observation and ongoing construction activity along pipeline route. remote sensing technology to software, long before they would have been reported by traditional monitoring.

Pipeline disasters are usually severe enough to put many lives in danger, devastate the environment, and cost millions in damages. To ensure the protection of the environment and people alike, the safety of pipelines should be paramount in the maintenance of a pipeline.

Whilst pipelines generally go through a variety of geographical areas and are often in remote, isolated areas, the potential impact of a disaster could result in large scale catastrophic damage to its surroundings. Therefore, more stringent and regular monitoring is required. Techniques which are not optimised by the already existing monitoring methods. Pipeline operators require more than routine inspections; they require a continuous pipeline monitoring system that analyses satellite imagery and informs them of any unexpected activities or changes in the vicinity or routes of their pipelines. This is achievable with GIS-enabled services and high-resolution imagery (Roberts, 2019).

An advantage of SuperVision Earth’s innovation is high temporal resolution. Here, satellites acquire images of the same section of the surface of the earth to achieve high temporal resolution. Optical images from space employ reflected light from the Earth’s surface as a source of radiation. Radar satellites, on the other hand, work in a different way: they actively generate radiation that can penetrate clouds. This allows for reliable monitoring regardless of the weather conditions (Hilsenbek, 2020).

Small satellites are being used by commercial suppliers to acquire optical images daily. Aside from the increased temporal resolution, another advantage is that the satellite sensors gather data that is not visible to the naked eye.

This additional data allows for a more detailed perspective than the human eye can provide. As a result, dangers that might normally go unnoticed during aerial surveys can be identified.

Further changes on the surface can be observed using radar data. They can not only provide information on the surface structure/roughness and thus the kind of subsoil,

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World Pipelines / SEPTEMBER 2021

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monitor threats along pipeline routes and transmission lines.

7.

Ensuring the future safety of pipelines globally

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The transportation of hydrocarbons involves a complex network of pipelines that are designed to be fast and efficient. The above discussed factors only prove this fact; it requires meticulous planning, surveying and monitoring as the probability of leakages and pollution stands high during pipeline deployment.

SuperVision is committed to enhance the monitoring of pipeline routes and pipeline construction to prevent pipeline incidents and ensure safe supply of energy.

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Bibliography 1.

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ADEGBOYE, M. A., FUNG, W.K., & KARNIK, A. (4 June 2019). Recent Adances in Pipeline Monitoring and Oil Leakage Detection Technologies: Principles and Approaches. Sensors, 11, 2548. https://www.ncbi.nlm.nih.gov/pmc/ articles/PMC6603558/ abgerufen APPEN. (14 April 2020). What is Training data? https://appen.com/blog/ training-data/ abgerufen BARBOSA, P. (June 2021). Monitoring Pipelines to Protect Against Theft, Leaks. Pipeline and Gas Journal. https://pgjonline.com/magazine/2021/ june-2021-vol-248-no-6/features/monitoring-pipelines-to-protect-againsttheft-leaks abgerufen CDIAC. (2019). Annual CO 2 emissions per country. Our World in Data: https://ourworldindata.org/grapher/annual-co2-emissions-per-country abgerufen DELGADO, M. R., & MENDOZA, O. B. (2017). A comparison between leak location methods based on the negative pressure wave. 14th International Conference on Electrical Engineering, Computing Science and Automatic Control (CCE) (S. 1-6). Mexico City: IEEE. Global CO2 Emissions set to Surge in 2021 Post-Covid Economic Rebound.

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(20 April 2021). Von Yale Environment 360 Digest: https://e360.yale.edu/digest/ global-co2-emissions-set-to-surge-in-2021-in-post-covid-economic-rebound abgerufen HARVEY, F. (31 May 2021). Greenhouse Gas emissions. The Guardian: https:// www.theguardian.com/environment/2021/may/31/eus-greenhouse-gasemissions-fell-in-2019-data-shows abgerufen HILSENBEK, H. (1 December 2020). Mit KI Pipelines effectiv überwachen und instand halten. B_I medien: https://bi-medien.de/fachzeitschriften/ umweltbau/leitungsbau/mit-ki-pipelines-effektiv-ueberwachen-und-instandhalten abgerufen HOARAU, Q., GINOLHAC, G., ATTO, A. M., & NICOLAS, J. (2017). Robust adaptive detection of buried pipes using GPR. Signal Process, 293 - 305.

IEA. (2021). Global Energy Review. Paris: IEA. https://www.iea.org/reports/ global-energy-review-2021 abgerufen INNOTER. (2021) https://innoter.com/en/articles/monitoring-the-condition-ofpipelinesb-ased-on-satellite-imagery/ abgerufen LIM, K., WONG, L., CHIU, W. K., & KODIKARA, J. (2016). Distributed fibre optic sensors for monitoring pressure and stiffness in out-of-round pipes. Structural Control Health Monitoring, 303 - 314.

MANEKIYA, M., & ARULMOZHIVARMAN, P. (2016). Leakage detection and estimates using IR thermography. 2016 International Conference on Communication and Signal Processing (ICCSP) (S. 1516-1519). Melmaruvathur: IEEE. MENG, L., YUXING, L., WUCHANG, W., & JUNTAO, E. (2014). Experimental study on leak detection and location for gas pipeline based on acoustic method.

J.Loss Prev. Process Ind., 74 - 88.

MENGPIN, G., & FRIEDRICH, J. (6 February 2020). 4 Charts Explain Greenhouse Gas Emissions by Country and Sectors. World Resources Institute: https:// www.wri.org/insights/4-charts-explain-greenhouse-gas-emissions-countriesand-sectors abgerufen ROBERTS, C. (4 August 2019). How Satellite Technology is Helping to Keep Pipelines Safe. Submar: https://submar.com/how-satellite-technology-ishelping-to-keep-pipelines-safe/ abgerufen TURNER, N. C. (1991). Hardware and Software Techniques for Pipeline Integrity and Leak Detection Monitoring. Soc.Pet.Eng, 139 - 148. https://doi. org/10.2118/23044-MS abgerufen XU, L., ZHAO, Y., & BAI, X. (2020). Leakage Monitoring Technology of Oil Pipeline and Its Application. IOP Conference Series: Earth and Environmental Science. 440. Resources and Geological Engineering.

ZHANG, S., GAO, T., XU, H., & WANG, Z. (2009). Study on New Methods of Improving the Accuracy of Leak Detection and Location of Natural Gas Pipeline. Proceedings of International Conference on Measuring Technology and Mechatronics Automation, 360 - 363.

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Rodrigo Signorelli, Outokumpu, Brazil, discusses the material challenges for engineers when specifying flowlines and risers, and shares insight into pipeline technologies and the role of corrosion resistant alloys (CRA).

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n the field, corrosion resistance provides safety, long life, process continuity, and control of risk. However, purchasing priorities vary widely depending on the application, the environment, and the preferences of the end customer and its supply chain partners.

Engineers typically start thinking about pipeline materials early in the project cycle when they need to produce budget estimates for risers, flowlines, jumpers, and fluid transfer lines. They need CRAs in the form of strip, coil and plate for fabrication into flexible pipes, tubes for umbilicals, mechanically lined pipe (MLP), and clad pipe.

Figure 1. Handling stainless steel plate.

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Competing flowline technologies When it comes to flowlines, clad pipes, MLP, and flexible pipe can all be used to transport oil and gas from the seabed to the oil platform. Each has its own pros and cons and the choice between them often comes down to the preferences and standard specifications of the oil and gas operator.

All three rely on CRAs to protect the flow from corrosion. In the case of MLP and clad pipe, the strength relies on carbon steel, whereas the manufacturers of flexible pipes rely on duplex stainless steels strength to avoid pipe collapse in deep waters.

The approach makes a lot of economic sense. Clad pipes and MLP cost around half the price of pipes manufactured entirely from CRA and flexible pipes save costs in the field as they are relatively straightforward to lay.

Clad pipe Engineers specify clad pipe when they want to minimise risk in high pressure and high temperature applications.

It provides security thanks to a metallurgical bond formed between the CRA and the carbon steel shell.

This eliminates the potential for a void forming between the two layers, which product could seep into, initiating corrosion and leading to failure.

One route to market for clad pipe is via specialist plate manufacturers. They purchase alloys as quarto plate around 10 - 30 mm thick. They match this with a thicker carbon steel backing plate and pass the two plates together multiple times through their mill.

The intense pressure and heat of rolling creates a composite plate of around 15 - 70 mm thickness with the all-important metallurgical bond between the layers.

Explosion bonding is an alternative process to manufacture clad plates. It offers high flexibility with respect to possible material combinations. This method is mainly used for high clad plate thicknesses and small batch sizes.

Clad pipes can also be produced by weld overlay. The corrosion resistant metal layer is deposited on the inner surface of a carbon steel pipe by using CRA welding wire or welding strip.

Tube and pipe mills take delivery of these plates to form into pipe and fittings. These are combined into packages to meet the specifications of the engineering, procurement and construction (EPC) companies that deliver projects on behalf of the end customer.

Mechanically lined pipe

Figure 2. Nyby is one of Outokumpu’s mills that are certified to produce material for the oil and gas industry.

While it is similar to clad pipe, MLP is less costly. The most common manufacturing process involves inserting a CRA liner pipe into an outer carbon steel pipe (pipe-in-pipe solution).

The liner is then hydraulically or mechanically expanded inside the outer pipe and later held in place by the mechanical forces of the shrinking fit. The liner pipe is seal welded to the outer backing steel pipe at both ends to avoid moisture ingress between the backing steel and the liner pipe.

Other methods make use of heating the outer pipe or using an adhesive layer to strengthen the bond between the two layers. In another process, a spinning mandrel creates the bonding between the inner CRA pipe and the outer backing steel pipe.

Flexible pipe

Figure 3. Production of strip for flexible pipe and umbilicals.

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Engineers use flexible pipes either as flowlines to transport oil and gas along the seabed or when they need a riser to transport product up to the surface. It can handle dynamic movements from the action of the tide and waves, and is delivered in long lengths and requires less jointing than the standard 12 m lengths of solid pipe.

CRAs form a carcass to protect the pipe against corrosion from the fluid it carries and collapse due to the high external pressure. It comes in the form of strips 25 mm to 200 mm wide and up to 4 mm thick, depending on the specification and the diameter of the pipe.

Flexible pipe manufacturers form this strip into special profiles that interlock in a spiral to form a long flexible tube. They add multiple additional layers to provide

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mechanical strength and flexibility, with each manufacturer taking its own approach to the number and design of the layers and their arrangement in the overall cross section.

When it comes to flexible pipe, consistent mechanical dimensions are essential for the strips. This ensures the profiles are manufactured consistently and will lock

together as intended. Variation in the thickness, width or flatness of the strip material could impact the integrity of the carcass, posing risk to safety and environmental security.

With risks like these, traceability is extremely important to oil and gas operators. It helps them control risk. Many stainless steel producers can supply the right grades – but few can consistently produce identical mechanical and dimensional properties.

To help us achieve this, customers provide extensive specifications and certifications that combine the technical requirements of the oil company as the end customer with those set by the flexible pipe producer. Technicians use these to produce material to very fine tolerances and mechanical specifications.

Welded pipe gaining ground for umbilicals

Figure 4. Stainless steel melt shop.

Figure 5. Specialist mills combine corrosion resistant alloy in quarto plates with carbon steel backing plates for clad pipe.

Another interesting trend over the last five years is that engineers have been turning to longitudinally welded stainless steel tube instead of seamless tube for umbilicals.

Umbilicals are packaged subsea lines to carry multiple services such as flow lines, water, chemical feeds, power and data cables, as well as hydraulic fluid or pneumatic air lines.

Traditionally, only seamless stainless steel tube was used for umbilicals. However, seamless tube is costly and only available in short lengths that need regular buttwelded joints. Manufacturers carry out ultrasonic testing of the entire tube and X-ray qualification of the butt welds as non-destructive testing to qualify tubes before installation in the field.

In comparison, longitudinally welded tubes only need butt welded joints at the end of each strip. This gives them higher mechanical strength and for some applications, it may be possible to reduce the thickness of tubes, saving weight and material.

When supplying for umbilicals, tube fabricators order CRA up to 5 mm thick and at least 25 mm wide, depending on the diameter of the pipe. They deliver the welded tube to umbilical manufacturers, who create the packaged bundle of lines and cables required for the project.

Certifications

Figure 6. Cold rolling produces sheet coil to precise dimensional tolerances.

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The most challenging aspect of delivering material for oil and gas projects, and particularly for flexible pipe and umbilicals, is meeting the specifications, standards, qualifications and certifications for each project. Requirements include ASTM and EN standards, qualification bodies such as Norsok and the BS EN 10204 standard that covers traceability and certification by independent third party auditors.

Oil and gas companies all have their own specifications and company standards, as do the fabricators and EPC companies in the supply chain. The industry also demands complete consistency of mechanical properties and dimensions, within very tight tolerances.

When combined, these create a stringent and unique set of specifications for each project. It’s only possible

to meet these by being flexible and adapting to the customers’ ways of working.

Having supplied to oil and gas customers for more than 20 years, Outokumpu have developed strong project management to ensure clear communication from the customer to the technicians on the shop floor. In addition, the company invests in state-of-the-art equipment and qualification of production sites to meet the stringent standards of the industry.

Rolling steel to fine tolerances For all steel projects, the maximum length of a coil or strip will depend on the required thickness. The company’s melt shop in Avesta, Sweden, produces slabs of stainless steel, which are then passed through a hot rolling mill to produce hot-rolled coil several millimeters thick.

Fine dimensional tolerances are achieved for the oil and gas industry at Outokumpu’s cold rolling mills in Sweden, Germany and Finland. Machinery at these facilities will roll the coils to precise thicknesses and split it into strip form, if needed.

Choosing a suitable alloy When it comes to alloy selection, operators are keen to avoid over-engineering their lines. In the past, they could afford the cost of adhering to standard specifications with the very highest levels of performance.

Today’s oil and gas engineers are looking at a wider range of alloys to achieve the right level of corrosion

Figure 7. Strip coil is used to produce flexible pipe and longitudinally welded tube for umbilicals.

resistance at the right cost. Alternative alloys can deliver the same performance and might have a lower carbon footprint so it’s worth choosing alloys on a project-byproject basis.

For MLP, clad pipe and flexible pipe in shallow seas, high strength is not important.

For less corrosive environments and onshore projects, CRAs might be competing with painted carbon steel. In these cases, fabricators and manufacturers can specify an austenitic stainless steel such as 316L. This provides the

Figure 8. Corrosion resistant alloy strip is used to produce longitudinallywelded tube for umbilicals.

shallow seas, engineers can choose from the same range of alloys as clad pipe or MLP. However, for flexible pipe in deepwater projects, it’s important to choose an alloy that provides high mechanical strength in addition to corrosion resistance. This will give both a seabed pipeline and risers the capability to withstand the hydrostatic pressure of deepwater.

Duplex or super duplex stainless steel provides the right performance for deepwater projects and for umbilicals. On a microstructural level, duplex grades are a combination of austenitic and ferritic stainless steel. As a result, they provide the combination of high corrosion resistance and high strength.

Lean duplex grades such as Forta LDX 2101 contain relatively low levels of alloying elements such as nickel and molybdenum and are suitable for less corrosive environments. However, duplex grades such as Forta DX 2205 and Forta DX 2304 are used widely in a range of applications and super duplex grades such as Forta SDX 2507 or Forta SDX 100 provide excellent corrosion resistance and high strength.

Sustainability Another big driving force today is sustainability.

Targets to achieve net zero by 2050 are creating pressure on the supply chain to control the carbon footprint of projects and assets. This is set to grow during 2021, with the COP26 conference due to take place in November.

Materials such as steel are produced by using large amounts of energy and so often contain high levels of embodied carbon dioxide. That is the term for the equivalent carbon dioxide emissions required to build or manufacture an asset.

However, material from different suppliers can Figure 9. Outokumpu’s production has a relatively low carbon footprint as it have widely varying carbon footprints. For example, is based on more than 85% recycled content.

Outokumpu’s alloys have a carbon footprint five times lower than some other suppliers. This is achieved by extensive recycling of scrap and by using right level of corrosion resistance to minimise maintenance low-carbon electricity to power the mills. Every tonne of over a long life. austenitic stainless steel scrap saves 4.3 t of CO2 emissions.

A key thing for engineers to be aware of when Moving up the scale, the high-molybdenum version comparing carbon footprint is that they should make sure 316L provides moderate corrosion resistance for offshore they are comparing the ‘cradle to gate’ carbon footprint. environments.

That includes their suppliers’ direct emissions, for example However, for offshore environments such as shallow from the burning of fossil fuels to heat furnaces. It should seas with high salt content, the Ultra 6XN and Ultra 254 also cover CO2 released from the generation of electricity.

SMO alloys may be suitable. The latter has a cost advantage Importantly, it must also include emissions from the material thanks to having high strength and a relatively low nickel supply chain, which is sometimes overlooked but is typically content compared with other 6Mo types of stainless steel. the largest source of CO2 in a product.

At the high end, alloys such as Ultra 904L and Ultra So, while oil and gas engineers have many competing Alloy 825 can be used in sour gas applications. priorities for pipeline projects, there is no one ideal choice Alloys for deepwater projects and umbilicals of material or technology. It is a question of optimising Choice of grade for flexible pipes depends on the depth strength, corrosion resistance and cost to deliver the end of the sea and the corrosiveness of the application. In customer’s preferred solution.

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Arto Voutilainen, Ossi Lehtikangas, Antti Nissinen, and Mika Tienhaara, Rocsole Ltd, Finland, explain how the company’s deposition inline inspection tool can contribute to effective pipeline monitoring.

T

he key objective in flow assurance in the oil and gas industry is to enable and maintain continuous, safe and cost-effective flow of fluids in different stages of hydrocarbon production and transportation. One of the main issues in this field is the control and management of deposits, such as waxes, scales, asphaltenes and hydrates, since they can lead to severe production inefficiencies and even catastrophic blockages, causing significant losses.

Deposition management The presence of deposition buildups in pipelines has many unwanted effects. Most importantly, they constrict the flow and therefore reduce the throughput, causing pressure abnormalities and increased risk of equipment failures. In the worst case, excessive amounts of deposits can even cause blockages that mean production needs to be suspended for a long time and extensive remediation effort may be needed. Deposits may also

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weaken the effect of corrosion inhibitors so that lifetime of pipelines becomes shorter, due to under deposit corrosion and the increased risk of integrity issues.

Deposits in pipelines are controlled in many ways, the most important of which are regular mechanical cleaning, chemical dissolution, and various chemical inhibitors to decrease the deposit formation rate and controlling process temperature at a level that does not favour deposit formation or even dissolves existing deposits.1 In general, these preventative and cleaning actions can be very costly, and the natural ambition is to do them cost-effectively so that unnecessarily frequent cleanings or overdosing of chemicals can be avoided. Therefore, comprehensive information of deposit buildups in pipelines plays an important role in deposition management to minimise disturbances in production and to ensure effective use of resources. Most importantly, it helps operators to understand factors affecting deposit formation in their processes and, as a result, optimise preventative and cleaning procedures.

Several techniques have been proposed for investigating deposit conditions in pipelines. These include analysis of deposits scraped by cleaning pigs, monitoring of flow speed and pressure levels, and monitoring heat transfer from process fluid to surroundings. Caliper pigs can be used for mechanical quantification of deposits, and in some cases, ultrasound techniques may give indications on deposits even though accurate quantification may be challenging. Intentionally generated pressure pulses can be launched along the pipeline and by monitoring the returning pulse it is possible to obtain information on deposits and blockages. In addition, gamma-ray transmission measurement provides information on the presence of deposits, but their accuracy may also be affected by other factors. Tomographic gamma ray methods are very effective for accurate quantification of deposits but their applicability is often limited. Other tomographic methods include electrical tomography (ET) which can provide cross-sectional images of the interior of a pipeline in the sensor installation location. In addition, numerical models can be implemented for predicting deposit conditions in pipelines, but their accuracy can be limited due to the complexity of deposit formation processes and some experimental validation data is needed in the model development phase.2, 3, 4

Electrical tomography and inline inspection Rocsole Ltd has been advancing ET-based measurement technologies for deposit monitoring and is well aware of the limitations of fixed ET sensors. For instance, there can be different process conditions (both physical and chemical) in different parts of the pipeline and therefore deposit conditions can vary accordingly.

It is clear that a small number of ET or any other deposit measurement sensors cannot give a comprehensive picture of deposits, especially if large portions of the pipeline are inaccessible, which is often the case, for example, with subsea pipelines.

In order to have a comprehensive picture of deposits in pipelines, Rocsole has developed a deposition inline inspection (DILI) tool relying on ET technology. The fundamental idea of the DILI tool is that it travels through a pipeline collecting information on deposits in the inner wall. The tool consists of one or more cylindrical modules, and arrays of measurement electrodes are mounted onto the cylindrical surface of the measurement module.

Electrodes are used to feed electrical signals to surroundings and electric potential of one or more electrodes is raised while other electrodes and the sensor vessel are kept grounded. This configuration generates a potential field and therefore electric current distribution to the surrounding area of interest, and induced electric currents are measured with grounded electrodes.

Potential field and current density distributions in the surrounding area depend on underlying material properties and their distributions, as well as on the orientation of the DILI tool with respect to the central axis of the pipeline. Hence, electric currents measured from the grounded electrodes do provide information on the presence of deposits and their characteristics.

DILI tool specifications

The DILI sensor vessel is built to carry all necessary components needed for measurements. In addition to the measurement electrodes, other main items are the battery pack, power controlling electronics, measurement electronics and data logger.

The DILI system is also equipped with pressure and temperature sensors on both ends of the tool, and typically with an odometer.

Depending on the operation environment and tracking needs, the tool can also be equipped with either an EM transmitter, an external radioactive source or both. All equipment does not need to be included into a single sensor vessel but, if necessary, they can be divided into multiple modules that are mechanically and electrically connected. Such multi-module systems may be needed especially in pipelines with small ID and tight bends, which can dramatically limit the size of an individual module. For unexpected issues in operation, the tool is designed to be bi-directional so that it can be run in both directions if needed.

A DILI sensor is built such that its overall density (i.e. mass per volume) matches the liquid in the operating environment. Neutral buoyancy makes it possible for the DILI tool to be easily driven by the flow and no tight sealing is needed to guarantee sufficient driving force. This is essential since interaction with pipeline walls and deposits therein should be minimal, so that deposits are Figure 1. Dual-module DILI tool for 12 in. pipelines (top) and three test sections of the flow loop (bottom). not affected or even collected by the DILI sensor.

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to the central axis of the pipeline. In such cases the computational cost of conventional ET imaging algorithms would be very high.

However, Rocsole has developed an AI based approach for DILI data processing, which enables very efficient data processing and quick reporting after inspection runs.

Rocsole’s latest DILI tool was designed for 12 in. pipelines (nominal ID 303.2 mm) and it is required to pass 1.5D bends. Thus the system was divided into two modules, namely battery unit and measurement unit, and they were mechanically connected by a flexible towbar (Figure 1). The total length of the system was approximately 1300 mm and its maximum hard OD was 220 mm.

The objective in field deployment is to run the DILI tool in water and characterise wax deposits in 0 - 10 mm thickness range.

Performance validation Figure 2. True and estimated deposit thicknesses from a single DILI test run.

To avoid direct contacts with pipeline walls and damages to the electrodes, soft brush-type centralisers are used.

Sizes of pipelines where DILI sensors can be used vary in the range of 8 - 28 in. Design pressure of 100 bar can be reached even for the largest sizes. Common stainless steel grades are preferred in vessel manufacturing but the requirement of neutral buoyancy may necessitate the use of low-density materials such as highstrength aluminum and titanium alloys, especially in high-pressure operating environments to achieve both sufficient strength and sufficiently low overall density.

Operating time of about four hours can be achieved with relatively small-sized battery packs, but operation times of several days can be achieved if sufficient space can be made for larger battery packs. Electronics components have limited tolerance against high temperatures and the maximum temperature of operating environment for the DILI tool is approximately +60˚C, to ensure that heat produced by electronics can be dissipated into the surrounding liquid to avoid overheating of critical components.

The DILI tool can be operated in hazardous environments and there are mechanisms to ensure its safe use. In such environments sensor vessels are charged with inert gas to prevent hazards due to potential electronics failures, and two redundant power controlling systems make sure that power is switched on only when the pressure in the pipeline has reached a pre-set threshold value. For the case of a severe battery failure or other incidents that can pressurise the vessel(s), each sensor module is equipped with PRVs or bursting discs so that excessive pressure is released out in a controlled and safe manner.

During an inspection run, no external communication or data transfer is possible but the powering state of the system can be checked in the launcher or receiver from the signal sent by a dualrate EM transmitter. ET measurement data and data from other sensors are stored by the data logger, and data packages can be downloaded for the analysis phase via an external connector. In the data analysis phase the main objective is to extract deposit characteristics and properties from ET measurements. An extra challenge in data processing is that the position of the DILI tool is not tightly centralised but it is in random movement with respect

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Before field tests, the DILI tool was tested and validated in a controlled flow loop environment simulating field test conditions.

The flow loop consists of a 12 in. pipeline with three 66 cm test sections that can be easily removed and equipped with artificial deposits of various thicknesses. Artificial deposits of 8 mm and 4 mm were built into two test sections, while the third section and rest of the pipeline was without any deposits.

After filling the flow loop with tap water and setting flow speed approximately to 0.5 m/s, the DILI tool was switched on and launched into the pipeline. Actual deposit thickness and estimated thickness from a single test run are shown in Figure 2.

It can be seen that estimated values are very close to the true thicknesses, and estimation error in this case seems to be well less than 1 mm. In the regions where deposit thickness changes, there can be some inaccuracies as the electrodes have a physical length of 100 mm and the effect of both deposits is measured at the same time. This particular DILI tool was not equipped with an odometer so the results are as a function of time, not function of distance as it would normally be.

Conclusion Validation tests showed that the proposed DILI tool can provide valuable information on deposits in pipelines and is therefore a noteworthy technology to complement deposit monitoring techniques. Cost-efficiency, inspection coverage and reliability are clear competitive advantages of DILI tools as the need for information on deposits is continuously increasing. Understanding deposition conditions can enable significant cost and energy savings in optimising maintenance procedures. Additionally, deposit control and management is becoming an increasingly important question in flow assurance, since the focus in oil exploration and production is shifting towards unconventional reserves where crude oil properties and production circumstances are prone to cause more severe deposition issues.

References 1.

2.

3.

4.

OLAJIRE, A. A., Review of wax deposition in subsea oil pipeline systems and mitigation technologies in the petroleum industry. Chemical Engineering Journal Advances 6, 100104, 2021.

ROSTRON, P., Critical Review on Pipeline Scale Measurement Technologies.

Indian Journal of Science and Technology 11(7), 1-18, 2018.

DRUMMOND, K., Nonintrusive Pipeline Internal Deposition Mapping Service Provides Insight to Operators. Pipeline Technology Conference 2018, Berlin, Germany.

WANG, W. and HUANG, Q., Prediction for wax deposition in oil pipelines validated by field pigging. Journal of the Energy Institute 87, 196-207, 2014.

Figure 1. Siemens Energy has exclusive access

to ProFlex Technologies’ digital Pipe-Safe™ advanced leak detection technology which, when combined with Siemens Energy’s IoT system, will enable pipeline operators to minimise unplanned releases of product into the ecosystem.

Matthew Grimes, Siemens Energy, and Stuart Mitchell, ProFlex Technologies, USA, describe how IoT and digitalisation are paving the way for new data-driven leak detection techniques.

S

pontaneous leaks represent a significant financial and environmental, health, and safety (EHS) risk for the oil and gas industry. This is particularly the case for companies that own and operate an older pipeline infrastructure. In the US alone, it’s estimated that roughly half of the nation’s 2.6 million miles of gathering, distribution, and transmission lines are more than 50 years old.1 Accurately detecting and locating leaks in both new and existing pipe networks has historically been an arduous and expensive undertaking – one that has been made even more difficult in today’s CAPEX-constrained environment. Digitalisation and the Internet of Things (IoT) are paving the way for new data-driven techniques and engagement models that make leak detection more economical, robust, and simpler to deploy.

Leak detection challenges Minimising unplanned product releases has always been a priority for pipeline operators. However, in recent years, as scrutiny surrounding the oil and gas industry’s environmental footprint has increased, leak detection has become even more critical.

According to the Pipeline and Hazardous Materials Safety Administration (PHMSA), from 2010 - 2019, there were nearly 3000 serious pipeline incidents (defined as fatality or injury; US$50 000 or more in total costs [1984 dollars]; volatile liquid releases of 5 bbls or other liquid releases of 50 bbls or more; or liquid releases resulting in a fire or explosion) which cost the industry over US$7 billion.2 In each of the top 20 incidents ranked by financial impact, a supervisory, control, and data acquisition (SCADA) system was in place. Despite this, leaks were detected only about half of the time.

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These figures make clear the inherent challenges that operators face when it comes to spontaneous leak detection. After all, it is not just a matter of detecting the leak after it occurs, but also identifying its location with some degree of precision. The longer it takes, the more product that is lost.

Over the years, several methods have been developed to minimise the impact of unintentional releases – some more advanced than others. Mass-volume balance calculation continues to be a widely used technique that is based on the principle of mass conservation (i.e. measuring and comparing the amount of product that passes through multiple meters along a route).

Cost-effective and straightforward, mass-volume balancing as a standalone solution does not constitute a comprehensive leak detection strategy because it often fails to detect small product releases. Additionally, the location of the leak is typically localised in between two metering stations, which can be tens or even hundreds of miles apart. Narrowing the location entails dispatching technicians in trucks or conducting aerial flights via a drone/UAV equipped with a specialised camera – both of which take time.

Modern techniques, such as fibre optic sensing, can resolve this problem. However, laying fibre optic cable is highly cost-prohibitive.

This is especially the case for existing lines that may have a limited number of service years remaining and routes that traverse harsh and/or remote terrain. Other leak detection methods that have been used in the past with some degree of success include vibroacoustic monitoring with accelerometers, pressure point analysis, and dynamic-model based detection (among others).

and measuring the time it takes the wave to reach each sensor, the leak’s location can be determined with a high degree of precision.

Because the pressure wave travels at a high rate of speed, leaks can be detected within seconds.

NPW-based sensing has become an attractive leak detection option for operators whose capital budgets have been compressed amidst the low-price environment.

For one, NPW sensing requires very little hardware, making it relatively painless to deploy. In long-distance transmission lines, nodes can be installed via hot tapping at access points without interrupting service to the line. The distance between the nodes is dependent on several variables (e.g. fluid characteristics of the product being transported, the size of the line, pressure, leak size, etc.); however, for a natural gas or crude transmission line, nodes can typically be installed every 15 - 30 miles.

In the past, an oft-cited concern associated with NPW-based detection has been the high rate of false positives. The natural fluid flow within pipelines is an extremely dynamic environment and can result in constant small pressure fluctuations. Detecting negative pressure waves caused by spontaneous leaks amidst this background ‘noise’ has traditionally been a complex undertaking that requires the use of advanced signal processing and data filtering methods.

In recent years, advancements in analytics and cloud computing have drastically improved signal processing, leading to a much lower incidence of false positives. NPW-based detection now represents the best available technology (BAT) for spontaneous leak detection.

Leak detection ‘as a service’ Enabling real-time leak detection

In addition to improving the accuracy and speed of leak detection, IoT-based methods pave the way for new engagement models that minimise and even eliminate the requirement for an upfront capital investment from pipeline operators. For example, Siemens Energy and ProFlex Technologies recently partnered to provide operators with spontaneous leak detection as-a-service (Siemens Energy Spontaneous Leak Detection powered by ProFlex).

The solution leverages ProFlex Technologies’ novel NPWbased advanced signal processing algorithms to rapidly detect and localise small pipeline leaks. Once a leak event has been identified, Siemens Energy’s cloud-based IoT system analyses the leak data in realtime, notifying users through mobile devices, laptops, or via desktop or SCADA system. Leak location in the form of latitude and longitude coordinates is presented on a pipeline asset map and has proven to be accurate to around 20 - 50 ft.

Because it utilises a subscriptionbased model, the solution is easily scalable. It can also be deployed on virtually any type of pipeline asset (new build or brownfield), including those carrying products other than oil and gas, such as produced water, hydrogen, or hazardous materials.

Critical applications aside from Figure 2. Leak location data can be sent to a PC or mobile device in real-time. long-distance transmission lines Negative pressure wave (NPW) based leak detection is a proven technique that has been in practice for decades. The method is based on the premise that when a spontaneous leak occurs, there is a rapid decrease in the oil or gas density where the product escapes from the line. This creates a negative pressure wave (originating at the location of the leak) that propagates along the path of product flow in both the upstream and downstream directions. By installing specialised sensors (i.e. nodes) at multiple locations along the route

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include production gathering networks at well sites and offshore operations.

Layered detection Although it is possible to deploy modern leak detection methods like NPW- and fibre optic-based sensing as standalone solutions, a multi-layered approach can often provide increased security and reduce the impact of an unplanned product release.

Evaluating when and where it is economical to utilise multiple leak detection methods will depend on numerous variables, including the route, the size of the line, proximity to sensitive areas, the product being transported, etc. For instance, an operator may have a pipeline section that routes through a populated area or protected wetland. In such cases, NPW-based sensing combined with traditional methods, such as mass balancing or point pressure analysis, would constitute an effective and costefficient strategy.

In some cases, operators may wish to target a section that is deemed high risk for a leak either because of possible corrosion or due to external factors, such as nearby construction/excavation activities.

In the event of a leak, the system would send automated messages to pre-determined personnel, eliminating the need for a field technician to be physically monitoring or patrolling the route. Users would also be able to retrieve data from the sensors remotely in real-time or shut them off if the line is temporarily being taken out of service for maintenance.

Conclusion Pipeline operators are under intense pressure from investors, activists, and regulatory bodies to reduce environmental impacts and improve sustainability. Although the first line of defense in mitigating the risk of accidental product releases has always been to maintain infrastructure proactively, spontaneous leaks will inevitably occur.

The PHMSA ‘Mega Rule’, which took effect on 1 July 2020, extended the required use of

leak detection systems beyond high consequence areas to all regulated, non-gathering hazardous liquid pipelines.3 As operators look to ensure compliance, they face the inevitable question of cost.

With recent advancements in cloud computing and data analytics, NPW sensing now represents a highly effective and economical means of detecting the presence and location of small spontaneous leaks in real-time. It is likely that it, along with fibre optic sensing and other IoT-based techniques, will eventually become the standard as the industry drives toward a greener and more environmentally conscious future.

Figure 1. ABB AbilityTM Condition Monitoring software solution.

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Stephen Gibbons, Global Market Manager for Continuous Gas Analysers for ABB Measurement & Analytics, explains the developments in process gas analyser technology that are helping governments and companies worldwide to keep emissions to air under tight control.

O

ne of the interesting aspects of the COVID19 pandemic has been its impact on industrial emissions. As lockdowns and other measures led to factories closing and transportation grinding to a halt, emissions levels worldwide fell significantly. While this reduction is likely to have only been temporary, it has led to a realisation of just how much impact emissions from activities such as industry and transport can have on air quality, and, more importantly, what should be done to rein them in.

Even before the pandemic, legislation was already in motion to find ways to cut emissions. The Paris Agreement in 2015, for example, set a global target for countries to significantly reduce their industrial emissions to air to help limit global temperature increases to 1.5˚C. Many industrialised nations have already made significant progress in tackling their emissions, while developing nations are also increasingly demonstrating their ability to achieve growth while minimising their environmental impact.

Globally, regulations are being tightened, requiring polluting facilities and plants to install Continuous Emission Monitoring Systems (CEMS) to ensure compliance. The European Union (EU), for example, has introduced its Medium Combustion Plant Directive (MCPD) to bridge the gap

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between large combustion plants and smaller appliances like boilers. The Directive is designed to control emissions of sulfur dioxide (SO2), nitrogen oxides (NOX) and dust and applies to approximately 143 000 plants with a rated thermal input equal to or greater than 1 Megawatt thermal (MWth) and less than 50 MWth. The EU is also bringing large combustion plants for solid fuels such as biomass into line with waste incineration plants. The latest Industrial Emissions Directive (IED) adds further CEMS gas analysis requirements, including mercury, hydrogen chloride, hydrogen fluoride, carbon monoxide, ammonia and total Volatile Organic Compounds (VOCs).

Other parts of the world are also following suit. The US has introduced various measures to reduce emissions from oil and gas pipelines, including the PIPES Act, which includes a provision for operators to monitor emissions from gas distribution systems. In India, many industries such as metal processing, oil and pesticides production have been required to invest in CEMS solutions to monitor particulates, ammonia, sulfur dioxide, oxides of nitrogen, chlorine, hydrogen chloride and carbon monoxide, amongst others.

A wide range of solutions When it comes to CEMS solutions, users can select from a diverse choice of technologies. Options range from simpler systems for natural gas fired boilers to measure carbon monoxide, carbon dioxide and oxides of nitrogen through to highly sophisticated multiple component systems measuring exotic pollutants such as hydrogen fluoride, hydrogen chloride and ammonia. This broad range

Figure 2. ACF5000 hot/wet extractive system.

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of options allows emissions to be accurately measured in a wide variety of industrial applications, including power generation and waste incineration, metals and minerals, refineries and chemicals, pulp and paper and marine.

When it comes to measuring stack emissions, operators have a choice of techniques.

Extractive techniques Commonly used for measuring gases, extractive techniques consist of two main methods. Heated extraction involves extracting the sample gas from the stack using a sample probe, heated line, gas conditioning equipment and a heated sample pump. Before analysis, condensate is usually removed from the sample and the temperature is reduced to protect the analysers, commonly referred to as ‘cold/ dry’ measurement.

The alternative is to keep the gas hot all the way through the system, known as ‘hot/wet’. The sample must arrive at the analyser inlet in a representative state that reflects conditions in the stack. The design of the sampling system must also protect against any sample loss or degradation. Typically, multi-gas analysers are used with this method but can be combined with single-component analysers.

In-situ measurement In-situ analysers are directly mounted at the measurement point. Most in-situ systems use infrared measurement techniques. While in-situ analysers can be installed directly on the stack with no sample handling, around 80 - 90% of plants worldwide have a strong preference for extractive methods, which tend to offer a lower cost of ownership.

In comparison to in-situ measurement, extracting a sample means only the probe is in contact with the gas and not any delicate optical components. After conditioning, a clean and dry sample is presented to the analyser. The system can then be installed in an air-conditioned cabinet or shelter, protecting against potentially harsh ambient conditions.

Also, whereas in-situ devices are usually limited to one or two components, multiple components can be measured simultaneously using a sequence of sensors in an extractive system, requiring less holes in the stack.

With the analyser system usually installed at ground level in a clean and accessible environment, maintenance is much more convenient too, with components easy to work on and remove, and test gas cylinders available nearby to easily calibrate the devices.

Another popular technique is cross-duct analysers.

These analysers project IR or UV (ultraviolet) energy across the stack and detect the change in energy state of the gas molecules as they absorb this energy at characteristic wavelengths. Most cross-duct systems measure one to two gases over a range of wavelengths. Furthermore, as there is no contact with the target gases, they can require less maintenance and operator involvement.

One drawback is that cross-duct systems can be more complicated to calibrate, although this can sometimes be

overcome using an automatic calibration system that can demonstrate accurate and reliable calibration checking.

Maximising performance Several criteria determine the choice of CEMS for a particular monitoring application. In the UK, for example, the CEMS must be MCERTS certified for the determinands specified in the IED and must also be certified for a measurement range that is suitable for the application.1 The operator must also ensure that any CEMS being considered will not have its performance degraded by any specific site conditions and that the intended CEMS is proven on comparable installations.

All CEMS must allow the performance of zero, span and linearity tests following installation, while new, extractive CEMs must have a facility for leak checks. Particulate monitors may be sensitive to factors such as changes in flowrate, as well as particle size and shape. Operators with a need for particulate monitoring should determine whether stack conditions could degrade the monitoring data.

Some substances, for example organic pollutants such as dioxins, and inorganic pollutants such as mercury, can exist in both gaseous and particulate forms simultaneously. The monitoring method must therefore be able to sample the selected phase or both phases, as needed.

As well as choosing the right technology, facilities needing to monitor air emissions must ensure the right conditions exist and that correct procedures are adhered to. A major factor is the variability of the emissions. In general, greater variability means increasing the frequency of monitoring, an area where CEMS wins over more intermittent, periodic monitoring techniques. CEMS are the correct choice where emissions levels vary so significantly that intermittent sampling would lead to unrepresentative results or too many samples would be needed.

An appropriate data recording system must also be in place.

Instrument-based methods such as CEMS provide real-time data, which must be recorded to allow interpretation and reporting. A variety of systems can be used for onsite storage, from the most basic, such as a simple chart recorder, through to automatic data loggers that can send emissions data to a remote central processing unit.

with appropriate data processing software. Systems that can measure multiple components reduce the cost of ownership, with fewer detection elements and less equipment to maintain and calibrate.

Calibration is a significant cost for CEMS operators, accounting for some 24% of operating expenses. It is needed for all types of gas analysers but the frequency of calibration can be much higher in some types than for others, while the effort and costs involved can also vary widely depending on the approach. For example, the cost of calibration gas cylinders is often underestimated, while the US EPA regulations demand daily calibration.

One solution is to use internal gas filled cells. Proven to cut calibration costs by up to 95%, these cells are filled with a test gas of known concentration and are sealed to prevent them leaking, allowing them to offer a stable sample against which to test instrumentation performance. They are also accepted as a viable alternative to flowing test gas, meeting the requirements of both EN 14181 and US EPA 40 CFR part 60 regulations.

An alternative is to use internal validation cells, which use films or cells for all FTIR components. Particularly suited to FTIR based CEMS, these cells conduct automated drift checks by rotating into the optical path to check precision and drift of all FTIR components.

Digital solutions are also making their way into CEMS applications. The ABB AbilityTM range of digital solutions, for example, enable operators to ensure regulatory compliance, reduce complexity and get the most from their CAPEX investments. These innovations include remote assistance.

Allowing rapid problem solving, this solution cuts costs and downtime and reduces the training needs of staff. Remote Insights is a solution that makes maintenance safer and more effective, while features such as dynamic QR codes allow the user to share diagnostic information to enable remote trouble shooting.

Another development is remote condition monitoring using real-time data. ABB’s condition monitoring system, for example, enables emissions equipment condition data to be relayed to its service experts for analysis. By allowing potential issues to be identified in advance, the risk of unplanned outages and downtime is reduced, providing system uptimes of 98% or more and enabling users to ensure continued compliance with availability requirements through optimum performance.

Trends and expectations In the past, systems that monitored a single gas were popular with many CEMS users, who believed they were less complex than systems that can measure multiple gases and so less prone to failure. This situation has now changed, as the requirement for more plants to monitor a greater range of gases has increased. One technology that is becoming increasingly popular as a result is FTIR spectroscopy, a technique that can measure multiple gases without the need for frequent calibration.

For example, the most recent Chinese ‘Blue Sky’ legislation demands the measurement of particulate matter, carbon monoxide, chlorine, oxides of nitrogen, sulfur dioxide, hydrogen chloride, and ammonia, amongst others. Most of these can be monitored with modern FTIR gas analysers

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Conclusion As the world increasingly returns to normal, there is a need to ensure that emissions can be maintained within sustainable limits, with reductions made wherever possible. With new technologies that are more capable and accurate than ever and the support of vendors offering digital services to keep CEMS operational, the mission of keeping your emissions within limits is becoming increasingly manageable.

References 1.

2.

https://assets.publishing.service.gov.uk/government/uploads/system/uploads/ attachment_data/file/730225/TGN_M20_Quality_assurance_of_continuous_ emission_monitoring_systems.pdf https://assets.publishing.service.gov.uk/government/uploads/system/uploads/ attachment_data/file/725557/Performance_Standards_and_Test_Procedures_ for_Continuous_Emission_Monitoring_Systems.pdf

I

f you need to calibrate, what do you need to think about? In many different industries the flow in pipelines needs to be measured with different accuracies.

Accuracy is defined based on the importance of the amount of liquid, gas or a combination of these, measured in a process. A process can be for safety; for example a minimum amount of cooling water in a nuclear plant or quality control in a dairy factory to make sure the product is safe to consume. Next to safety and quality control, a measurement process can be for billing the amount of fluid passed through a custody transfer application; for example natural gas crossing the border of two countries. If you are responsible for maintaining flowmeters within the required accuracy for these processes, would you calibrate these meters?

Improved measurement technologies Flowmeters are initially calibrated to prove accuracy, but flowmeters are also calibrated when standards, legislation, contracts or other written documents require mandatory calibrations to demonstrate possible drift or other expected changes to the flowmeter reading. Over time, flowmeter measurement technologies have improved and newer types have been developed and put into operation. The question is when improvements are made if an annual calibration is still needed, especially if built-in diagnostics can predict when a calibration is needed. Would you wait for a calibration until the flowmeter tells you it needs to be calibrated, do you strictly follow annual calibration requirements or do you do something else?

Re-calibration period In the past, attempts have been made to create a standard, recommendation and/or guideline to determine re-calibration intervals for flowmeters. End users, manufacturers, metrology institutes and calibration companies worked together, but the commercial interests of all these parties are different. Many of us in the flow

Erik Smits, VSL, The National Metrology Institute of the Netherlands, details the factors to be considered when calibrating flowmeters on pipelines.

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measurement community have participated in committees to develop standards and we know compromises are needed to come to a common goal: namely, what would be the best solution for your applications and the investment needed for calibrations. It may be that fully independent organisations like universities, that base the re-calibration period on scientific evidence of independent testing and data provided, would be required to write such a standard.

The one thing we need to ensure is that the flowmeters we control keep performing within the accuracies and/or tolerances the companies we work for set in their procedures.

As in the examples above, where not enough cooling can cause a major accident, bad quality control can lead to customers getting ill or where a lot of money can be lost.

Once we have determined a re-calibration interval there are other things to consider. For simplicity, from this point forward we will focus on custody transfer of liquids in pipelines.

Custody transfer Pipelines can be smaller than one inch or larger than one hundred inches. Typical custody transfer applications are not this large and in a case of a larger pipeline it is often split up into more pipelines. This makes it possible to use flowmeters that can be calibrated at their maximum flowrate. With multiple meters it is a good practice to have an additional meter that can be rotated through for normal operation. Then every flowmeter can be sent for calibration to a calibration facility/laboratory without interruption of the process.

How to calibrate So now you know your flowmeter needs calibration and you need to know how to calibrate it. In some cases, the application the flowmeter is operating in was designed for a calibration possibility. In case of a natural gas application, this can be a master meter in a so-called Z configuration. The to-be-calibrated (or proved) flowmeter is set in series with the master meter in the Z configuration. Be aware that the master meter needs to be sent on a regular basis to a calibration facility/laboratory. If the master meter is of the same type, size, manufacturer etc, it might change in the same direction as the flowmeter used in the application for the custody transfer, so regular calibration is an essential step. Also be aware that the master meter needs a much better accuracy, preferably three to five times better depending on the standard to be applied. What happens a lot of times is that companies who sell these applications claim the master meters have the same accuracies defined in standards and provide recommendations for which accuracies the duty flowmeters should be working at. All standards about calibration tell us that instruments and measurement standards need to be used with better accuracy to prove the instrument to be calibrated.

In liquid flowmetering applications next to a master meter it is possible to have a pipe prover available for the calibration or even a proving tank. In this case the volumes of the pipe prover and proving tank need to be calibrated on a regular basis based on standards. The calibrations of these volume instruments can be done both at the location of the application or in a calibration laboratory. One thing to consider is that no damage can occur for transport if calibrated on location. The good thing about these instruments is that they are a different technology than the flowmeter.

Onsite calibrations

Figure 1. Master meter section in VSL flowmeter calibration facility.

Mobile units for all three calibration methods are available in some areas of the world. Calibration services are provided by a variety of companies on the location of the application. They bring calibrated master meters, pipe provers or proving tanks to calibrate your meters.

For onsite calibrations special connections need to be in place to connect the mobile equipment. Access to these connection points is essential as calibration units can be larger than you expect. Calibration in your application is a common practice in liquid flow operations but less so in gas flow.

Calibration facility

Figure 2. VSL LNG flowmeter calibration facility.

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World Pipelines / SEPTEMBER 2021

When onsite calibration is not possible you could choose to send the flowmeter for calibration to a calibration facility/laboratory or even back to the manufacturer. If you choose to send the flowmeter to a laboratory you need to make sure the laboratory can match or get close to the conditions your flowmeters are operating at. There are a variety of facilities available around the world so choose wisely. Most of the time there is more than one facility that you can use. There are enough cases where it will be difficult to find a facility that can match the field condition of your application. In the world few facilities are available

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Figure 3. European Center for Flow Measurement, VSL.

for flow calibration at elevated temperatures or even cryogenic temperatures. The same is true for high pressure, low or high viscosities and high and low densities. In your application one of these parameters can influence your flowmeter. Make sure to investigate these influences a bit more when someone is telling you that it is no problem. This person might have a commercial interest and want to sell you a flowmeter or a calibration. Good advice can save your company a lot of money and problems in business operation. Always think about the accuracy you need, to prove at what kind of conditions and how many flow rates are needed to demonstrate this.

Metrological design When you design a new custody transfer application, think ahead about what the best situation for your re-calibration needs would be. We call this the metrological design. The metrological design is a service many companies ask VSL to help with as an independent institute who can advise on metering. The initial cost for your calibration equipment and training of staff can be higher but your return on investment will be within a short reasonable period of time, due to the better results. The advice can result in a better solution to send flowmeters for calibration to a calibration facility or in having someone with a mobile unit to connect to your application. In many cases this independent advice can give insight into the correct decision at the time of the investment.

This starts preferably at the moment you need to put the first lines on paper.

VSL At VSL we have a long history in calibration of flowmeters (predecessors of VSL started around 1900) both with mobile units and in the laboratory. Next to flowmeters, the standards used for these calibrations as previously mentioned (pipe provers, proving tanks and master meters) are all calibrated

by VSL, in our laboratories or at your location. Due to our role as the National Metrology Institute we have developed calibration facilities for ourselves as well as others. VSL maintains all the measurement standards for the Netherlands and this means the standards in flow measurement for high pressure natural gas flow up to 60 bar, a cryogenic standard that can calibrate flowmeters with LNG and liquid nitrogen and standards for gas flow calibration around atmospheric conditions.

The VSL LNG flowmeter calibration facility is a unique facility and the only one of its kind in the world. Flowmeters can be calibrated at temperatures as low as -190˚C or at -165˚C

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World Pipelines / SEPTEMBER 2021

when we fill the facility with LNG. Due to the extreme cold temperature, flowmeters and other equipment behave differently from what you expect based on ambient conditions. Next to flowmeters, sampling systems for LNG are tested with this facility.

There are still a lot of unknowns for flow metering and composition determination at cryogenic conditions so the facility is very important for R&D projects.

European Center for Flow Measurement VSL’s newest design is a brand new facility for liquid flow meter calibrations that will be realised in the port of Rotterdam, the Netherlands. It will replace the current facility in Dordrecht and will increase the flow to 2500 m3/h.

The new liquid flowmeter calibration facility realised in the “European Center for Flow Measurement” for high flow will be ready in the second part of 2022. In this facility, larger flowmeters can be calibrated independent with high accuracy. This is a good thing if you need mobile master meters to be calibrated. It is difficult for the industry to find independent calibration facilities for larger flowmeters. It is even more difficult to get these calibrations performed at National Metrology Institutes. With this facility VSL will fulfill these wishes from different industries, both end users in all kind of industries and the manufacturers of flow meters. A one stop shop for large and small flowmeters is essential for business operations of these companies. The facility will be using water as test liquid. Water has always been the main liquid for R&D purposes of newly designed flowmeters. It is also possible to test other equipment used in pipelines in this new facility.

Why would you calibrate your flowmeters?

Well, you calibrate only when it is needed for your business operation and when it will benefit your company. It will only benefit your company by choosing the correct calibration.

For this calibration you need the best solution for your flowmeters. It needs to be suitable in terms of a correct location, the fluid, the calibration accuracy, etc. When designing an application for safety, quality control or custody transfer, do not forget to think about calibration in the future of all instruments in the application, ‘metrological design’.

With a solid metrological design calibration might not be needed as much as in an older design where the metrological aspects are not considered completely. Many times we see that an application that always needs to be in use and the flow or indication cubic meters per hour or kilograms per hour is crucial in the application, but the flowmeters can’t be calibrated in the application or can’t be taken out. In that case you can’t calibrate until the application shuts down. This delay in calibration can have an impact on your safety, your health or the financial risks of your company.

If you do not know how to answer the question stated, feel free to contact VSL or another independent party to advise you about accuracies needed for your application and how to maintain this for as long as possible.

Corrosion protection tapes: lamination vs coextrusion. Thomas Kaiser, Managing Director, DENSO Group Germany asks: which production technology wins-out in the long-term?

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teel pipelines are capital-intensive, so their service life is critical. DENSO Group Germany impressively demonstrates the vital role that superior production technology plays in the operating life of a pipeline with the exceptionally long life of its three-ply corrosion protection tapes: even after 40 years in the field, the coating with a coextruded tape system still far exceeds the current corrosion protection requirements.

But why do some tapes protect the pipe better than others over long periods? What influence does the production technology have on the material properties and how does this change the quality of corrosion protection tapes? The following comparison of the lamination and coextrusion manufacturing procedures provides the answers.

To prevent a corrosive medium from gaining access to the steel surface, steel pipelines are protected against corrosion by a coating.

Special corrosion protection tapes are used for the construction of new and rehabilitation of existing pipelines. These tapes consist of at least two layers, while high-quality tapes even have three different layers, which satisfy the required properties and functions.

In a three-ply tape, the middle layer gives the tape high mechanical strength and durability; it is called the carrier layer. The inner layer in contact with the pipe establishes a secure connection to the pipe surface and is called the corrosion protection layer. The outside layer, combined with the corrosion protection layer, ensures the interlinking of the spiral-wound tapes (link layer). The wound tape creates a closed tube, as the outer layer of the bottom tape fuses with the inner layer of the overlapping tape. This is something that two-ply tapes cannot do.

But even comparisons between three-ply tapes lead to significant differences that are not apparent to the human eye: so tape is not just tape. A key distinguishing feature is the production technology, which has a significant effect on the long-term behaviour of the tape system.

The different layers of the tapes consist of different materials that are interlinked by lamination or coextrusion during the production

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process. The one thing that all lamination technologies have in common is that at least one layer has already cooled before it is covered by another layer: a material is applied to a cold, solidified carrier film, which adheres to the carrier material similar to gluing. The different layers create a bond but are still separate from one another.

Coextrusion: a type of welding It’s a different story in coextrusion: in this case, different materials are present in molten form during the joining and bonding process. In the coextrusion process, the different melt flows flow into a multi-layer die via different channels. What makes this so special is that along the flow path, the individual melt flows – and therefore the macromolecules of the molten materials – increasingly combined with each other and mix to the extent that they penetrate into each other (Figure 1). At the end of the process you get a single material line that consists of several layers. The bond established between the materials is now so strong that the strength of the material line can be compared to welding. The carrier and coating material form an inseparable unit. As a result, the film cannot separate into its individual functional layers, as is sometimes the case with laminated tapes.

Coextrusion requires expertise and a great deal of experience: every melt flow must flow at the same speed across the entire width to ensure a constant and correct thickness distribution of the material.

A simple test can be used to determine whether you are dealing with a laminated or coextruded tape: after immersing the tapes in petrol for at least two hours, the remains of the corrosion protection layer of a laminated tape can easily be mechanically removed; the carrier film is smooth or shiny.

By contrast, the remains of coextruded tape are difficult to remove, even with the aid of heavy-duty mechanical tools.

Figure 1. Coextrusion: a type of welding.

Figure 2. Coextrusion: advantages in layer to layer adhesion.

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World Pipelines / SEPTEMBER 2021

Benefits of coextruded tapes During installation and subsequent operation of the pipelines, the coating does not just need to withstand mechanical attacks caused by movements of the pipe and traffic loads, it also needs to offer reliable protection under extremely diverse climatic conditions. High-quality corrosion protection tapes therefore need to have excellent bonding between layers, a high lap shear strength and a high elongation at break. Taking a closer look at these material requirements shows clear differences between laminated and coextruded tapes.

In long-term use in particular, there is the risk that the carrier film will detach from the corrosion protection layer of laminated tapes, as the layers are merely ‘glued’ to one another. The individual layers then delaminate at this kind of predetermined breaking point (adhesive separation pattern). A coextruded tape does not fail: the macromolecules flow into each other, the individual layers penetrate into each other and create a bond (Figure 2).

As a result, the bond between layers is outstanding. A coextruded tape will not detach at the interface between the carrier material and corrosion protection layer even under extreme tensile force. Instead, a fracture would occur within the layers (cohesive separation pattern). The bonding of the link layer to the carrier film could also represent a weak point, if it were not coextruded to this layer to establish a permanent bond.

Lap shear strength and elongation at break as success criteria As the installed pipeline is subject to temperature fluctuations, it expands and contracts. The pipeline moves relative to the surrounding soil: this creates lap shear stress.

Coextruded tapes can withstand this stress: the individual layers do not slide over one another because the macromolecules between the individual layers are mixed and interlocked during the manufacturing process. By contrast, laminated tapes risk delamination as they only provide a ‘glued’ bond (Figure 3). The ageing process accelerates this with a significant influence on the long-term properties. The lack of lap shear strength of laminated tapes leads to weak resistance to soil stresses – with far-reaching consequences for corrosion protection: the tapes no longer cover the entire steel surface; the protection is no longer diffusion resistant and allows corrosive media to reach the steel surface.

In addition to excellent lap shear strength, high elongation at break is another quality feature of coextruded tapes – and an indication of the use of high-quality materials and an optimal extrusion process: as opposed to lower-quality tapes, high-quality coextruded tapes can stretch much further before they tear (Figure 4).

“A direct comparison of the material properties shows that there are considerable differences in corrosion protection tapes. Coextruded tapes have a significantly higher long-term durability and are superior to laminated tapes”, explains Dr Reha Cetinkaya, Director Engineering DENSO Group Germany.

“These days, pipelines have a life of at least 50 years, ideally up to 100 years. The use of high-quality tapes is essential to ensure corrosion protection over this very long timeframe.”

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Proving durability DENSO impressively showed the superior durability of coextruded tapes in practice using the tried-and-tested DENSOLEN® tape: in 2015, a modern logistics centre was built in Bavaria – precisely where the ISARSCHIENE highpressure natural gas pipeline was installed in 1976. As part of the necessary re-routing of the gas line, the operator Energienetze Bayern GmbH excavated the 39 year old pipes: a unique opportunity to check the durability and quality of the DENSOLEN tapes that had been used at the time.

Two coextruded three-ply tapes with a polyethylene carrier material with a butyl rubber coating on both sides had been used. A spiral-shaped winding of the three-ply tapes around the pipe allowed the butyl layers to fuse together in the overlapping areas. They formed a homogeneous, tube-like coating and were inseparably bonded to each other.

The analysis of the pipe section, which had been in continuous operation for 39 years, showed very impressive results: the pipe had no corrosion damage in the areas protected by the tape. The butyl rubber corrosion protection layer remained securely affixed to the steel, providing full protection for the pipe.

Laboratory findings

Figure 3. High lap shear resistance of coextruded tapes.

Figure 4. Failure of laminated two-ply tapes. Poor lap shear resistance: poor soil stress resistance.

Laboratory analyses of excavated weld seam no. 584 with a pipe diameter of DN 300 were particularly revealing.

Although the pipeline is located in Germany’s grainproducing region, where ground vibrations are to be expected due to heavy tractors and harvesting machinery, the coating of the high-pressure pipeline showed no defects, even after four decades of use. The weld seam of the steel pipe remained protected against corrosion by the DENSOLEN three-ply tape.

In 1976, the tape was applied with a standard specification for peel strength of 8 N/cm in accordance with DIN 30672. The current standard tests in accordance with EN 12068 and ISO 21809-3 require a higher peel strength of 10 N/cm. After 39 years, measurements showed a cohesive separation pattern with a phenomenal peel strength of 18.3 N/cm. The results of the analysis therefore exceed today’s requirements by 83% (Figure 5).

Conclusion

Even after 39 years in use, coextruded tapes still meet the current standard requirements for corrosion protection coatings. They continue to provide outstanding corrosion protection just as they have from the very first day, impressively demonstrating their long-term durability. The unique production technology has a positive impact on the material properties and performance. The outstanding bonding between layers and high lap shear strength of coextruded tapes permanently protect the pipeline. They are not susceptible to delamination or slipping apart of the layers due to pipeline movements (Table 1).

As a result, coextruded tapes are far superior to laminated tapes and have a much better long-term durability. “As has been proven and recognised in many Figure 5. Cohesive separation after 39 years in the field. areas, the use of high-quality materials and products in pipeline construction makes a big difference to value preservation and long-term operation.

Table 1. Superiority of coextruded tapes Using the right corrosion protection products Tape properties Coextruded three-ply tapes Laminated three-ply tapes from the start will generate immense cost Long-term performances High Low savings in the years to come. These are (ageing) costs that would become necessary if the Layer-to-layer adhesion Higher than ISO & EN ISO & EN pipeline had to be repaired due to lowLap shear resistance Higher than ISO & EN ISO & EN quality corrosion protection”, concludes Max Layer-to-layer failure mode 100% cohesive Adhesive-cohesive Wedekind, Managing Director, DENSO Group Steel coverage Excellent Limited Germany.

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World Pipelines / SEPTEMBER 2021

Isabelle Strømme, MSc, Vipo, Norway, discusses sealing technologies from a passive fire protection material perspective.

S

ealing is a technology that covers a wide range of products and solutions in a variety of sizes and shapes. Most commonly, seals are known as small O-rings and gaskets that are used to prevent gas and fluid leaks in static and dynamic applications.

However, there is so much more to seals and they are not always what we expect them to be. The technology itself is one thing, but material expertise, development and testing is currently pushing the limits across all industries. When it comes to the world of materials and the increasing variety of choice for sealing technologies, elastomer-based seals are in high demand. They are maintenance-free, watertight, resistant to ozone, seawater and UV-light as well as suited for use in harsh and cold environments, absorbing and preventing stress and strain transfer within structures.

Background Working with elastomer materials is a fascinating field; seeing how different fillers in a compound can alter the material properties completely and due to the material’s unique properties, it has been the obvious choice in the development of seals.

Elastomer (otherwise known as rubber) product development and production has been Vipo’s main business for more than 125 years, with a factory that houses the

49

entire manufacturing line – from developing the material and small-scale testing, qualifying and full-scale compounding to manufacturing and delivering finished products. Most of the material development has been customer-driven, as well the need for fire protection materials in offshore installations.

Fire protection is often divided into two types of systems – active fire protection (AFP) is either triggered by a sensor when exposed to, for example, smoke and heat, or you must manually activate to operate. These systems include sprinkler, deluge, water spray, fire extinguishers and more. The other type is the passive fire protection (PFP) system, which exists as an integrated part of a component or as part of a structure on buildings, offshore oil platforms, or ships. PFP contains the fire within an area, thus limiting the fire and smoke spread in a given time period.

When it comes to extending the life of assets and supporting operations, the focus on technical safety in oil

and gas production has increased immensely during the last few decades. The solutions must demonstrate excellent performance across a range of fire scenarios, often in conjunction with higher heat load, and documented success through certification, type approvals and test reports that illustrate not only fire protection properties, but also provide installation and handling information.

Due to the need for PFP in different applications in the oil and gas segment, the Firestop technology was developed.

The material was developed to protect risers, transporting oil and gas in offshore installations, in the event of fire. If a crack happens in a gas-filled pipe, and a gas leak occurs, a small spark can transpire into a severe jet fire scenario. Thus, the Firestop material was developed to handle the harshest fire scenario that the industry could foresee.

The material was later qualified for use in several other applications and architectural PFP seals has been a large area of development. Since structures and equipment rarely have the same requirement with regards to fire ratings, dimensions and movement, they often need to be tailormade and designed for each installation.

Sealing and elastomers

Figure 1. Pipe penetration seal (HPT).

Elastomer-based, passive fire protection seals offer a flexible connection between rigid metal sections. Capable of handling large displacements, they connect modules, maintaining a fireproof partition, absorbing misalignments, angular deviations and eliminating concentrations of stress.

Elastomer-based seals used in escape tunnels and door seals offer protection of door frames and connecting fire-safe escape areas.

The benefits of elastomeric seals include: ) Elimination of the propagation of vibrations, dynamic loads and deviations caused by a fabrication process. ) Customisation to fit any shape and size to suit individual

project requirements. ) Installation on a variety of structures.

In areas where drainage is required, elastomer-based seals can be made as a drain gully that supports the design of a closed deck, eliminating the need for fireproofing of process deck structures. Drain gullies allow hydrocarbons spillage from process modules to drain, eliminating the requirement for multiple drainage boxes and integrated overflow. As the properties of each material vary, finding the most effective material and technical solution for a project is crucial.

Passive fire and corrosion protection in the offshore industry

Figure 2. Radial firestop seal.

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World Pipelines / SEPTEMBER 2021

Factors to consider when choosing the right material include the potential source of a fire, duration, temperature, and blast, along with qualifications, certificates, and material properties.

The objective of PFP is to prevent or mitigate the serious consequences of fire: ) Prevent escalation of fire to adjacent areas.

) Ensure a temporary refuge is intact for a specified amount

of time. ) Protect people from the fire (heat and smoke) and make

escape or evacuation possible. ) Protect essential systems and equipment. ) Maintain structural integrity for a set period.

The most extreme fire scenarios are hydrocarbon, jet fire and high heat flux – all distinctive to topsides on offshore platforms. Elastomer materials can be used alone or in various combinations to meet specific requirements. Vipo specialises in developing bespoke combinations to meet industry requirements and has, over decades, developed and adapted rubber materials to meet the harsh environmental and safety requirements in the offshore industry.

Elastomer-based materials are also well suited for protection against corrosion. External corrosion in carbon and low-alloy steel is a serious challenge in the oil and gas and other highly corrosive environments. Vipo has developed a rubber-based material that provides sealing against corrosion. The steel is rubbed or sand blasted, then primer and or adhesive is used before the rubber is applied by machines or by hand. It is completed through a vulcanisation process, by cross-linking the rubber to the steel providing excellent bonding. This gives corrosion protection superior to any paint system available.

different applications, geometries, and sizes, and are easily installed and dismantled with hand-held tools.

PPS is made in one piece with an overlapping joint and is typically fixed and secured with stainless steel hose clamps that are easy to remove for inspection, and can be reused, reducing wastage as seals are not damaged during the processes. The material can also be used to seal in other applications and can be fixed by bolting it to structure or it can be tailor-made as wraparound jackets to fit any geometry, structure or component.

Testing advances and qualifications During the development of any new PFP material, manufacturers must ensure the solution is qualified against the harsh fire

Developing a bespoke sealing solution for pipe penetration Seals can also be used in conjunction with wall penetrations where the customer has a need to be able to inspect the steel structure, and thus a requirement for a flexible, re-mountable solution that must also withstand tough fire.

Vipo’s Pipe Penetration Seal (PPS) is a thin and flexible seal, consisting of layers of tough and durable materials that offers protection against fire, blast and weather. With a thickness of approximately 10 mm, requiring minimal space, the wrap-around seal closes the pipe penetration and allows movement of the pipe during operation. Seals are tailormade to fit a wide range of

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requirements in the given industry, such as cellulosic, pool fire, hydrocarbon fire (HC fire) and jet fire. In recent years, the industry became gradually more aware that a jet fire has a higher heat load than permitted in standard jet fire testing.

This required the development of an extended jet fire test, also known as high heat flux (HHF) testing.

Fire classifications are characterized by heat fluxes around 150kW/m2 with temperatures reaching approximately

Figure 3. Vipo’s 350kW/m2 Jet fire test rig.

+1100˚C in hydrocarbon fires, and around 250kW/m2 with temperatures around +1200˚C for jet fires. Hydrocarbon, or pool fires, may occur when combustible liquids (oil, gas) leak from a pipeline, forming a fluid pit or reservoir which ignites.

Fire integrity in these cases, is measured using H-fire ratings, showing the material’s ability to resist fire and remain intact during a given time frame, usually for 120 minutes.

The heat fluxes given for a jet fire are dependent on different boundaries such as type of fuel, a mix of fuel/ oxygen, and flame size. The ISO22899 standard describes a set-up with a pressurised gas release giving a severe combination of erosive forces and heat. This mixture can be highly destructive to some PFP systems, resulting in potential failure of the system to act as a barrier between areas. The test setup is sufficient when giving an indication of the performance of a wide range of PFP materials and systems, with the heat flux achieved limited to 250kW/m2.

The now recognised higher heat flux and temperatures of jet fires created the need for new HHF testing standards to be created. For both jet fire and HC fire testing, standards have been developed over decades and are well known to the industry, including ISO834, ISO22899, IMO FTP Code. HHF testing, often performed sequentially with HC fire testing, currently has no standardised test protocols or programmes, and it is often left to individual suppliers to demonstrate HHF material or system compliance.

Vipo’s operation in Norway has created a large-scale bespoke HHF testing rig to assess its rubber based PFP materials in higher temperatures and heat fluxes. A chamber measuring 3 x 3 x 2.7 m with pressurised gas input to the same standard as stated in ISO22899, was constructed. For comparison, Vipo’s standard hydrocarbon jet fire test chamber was built and operated in accordance to ISO22899 measures 1.5 x 1.5 x 0.5 m. Air is added to the chamber to higher the temperature, creating a high heat flux environment of 350kW/m2 with a temperature of approximately +1300˚C.

Conclusion

Figure 4. Drain gully firestop seals.

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Sealing technology has come a long way and is still undergoing rapid development in specific industries operating within demanding environments. Material choice, specifically when dealing with active and passive fire protection systems, is a crucial element to maintaining and protecting structures. Elastomers are a common choice when developing solutions to sealing challenges due to their distinct properties. Due to the nature of where seals are often used, the demanding environment requires the highest level of testing and qualification. Therefore, when developing new, innovative sealing technologies and solutions, it is necessary for engineers around the world to be very aware of both what exactly the seal is being used for, and the range of material options and their specific properties.

Wherever you are, World Pipelines is with you.

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Morgan Sledd, Stark Solutions, USA, discusses the importance of both the correct style and ease of operation when it comes to pipeline closures.

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ipeline integrity and maintenance depend upon ease of access to the inside of the pipelines. Today, that access could be in almost any part of the world; a residential area in middle America, the arid desert conditions of the Middle Eastern region, the cold climates of Canada or southern Australia, the corrosive offshore of the Pacific coastal nations, or even the wet and humid landscape of the tropical South American regions. It pays to have product options that fit your application, your media, and your region. Stark Solutions offers pipeline and pressure vessel quick opening closure solutions to meet those needs.

Quick opening closures Quick opening closures have been a mainstay in the oil and gas industry for many years. Starting off as flanged openings with a hinge or davit arm to support the removal of the blind flange, these openings were a means of entry into a pipeline or vessel for inspection and cleaning. Flanges have

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a number of bolts that must be removed before the pipe can be accessed. Often times due to the size of the bolts, it requires large specialty tools to be used, which leads to extended down time to open while also factoring in an added potential for operator injury.

Another downfall is that flanges have no inherent safety features to alert the operator when lines are not properly vented.

Once loosened, the media can directly escape, causing leakage and a potential safety hazard for the operator and anyone in the surrounding area. Closures have been designed to make access faster, easier and safer. Integrated features of closures set the operators’ safety as a top priority, by providing a warning device, such as a pressure alert valve (PAV), to alert the operator if there is internal pressure before they operate the closure. Once opened, closures are closed with minimal tooling and do not require extended procedures like the bolt tightening processes that are used on flanged connections. Closures, therefore, provide safety to the operator, and significant time savings overall.

Historically, quick opening closures have been offered in different form factors, with some of the most popular being the threaded closure, the clamp ring closure, and the internal door closure. The threaded closure has a cap that threads onto a hub, compressing an O-ring by turning the cap tightly. This closure type offers ease of access at an economical price point. The clamp ring closure has a door and hub held together by a clamp that closes onto both components from the outside. Access is quick and easy where frequent opening is needed. The internal door closure has a door that swings into the hub component, and then has a ring that expands inside the hub, securing the door in place. This closure style works well on large size pipes, higher pressures, and allows for additional customisations relatively easily. To answer the industry demands for these closure styles, Stark Solutions supports the market’s needs by manufacturing the S-500 threaded closure, the S-2000 clamp ring closure, and the S-3000 internal door closure.

S-500 threaded closure The S-500 threaded closure product offering draws on a long history in the oil and gas industry of providing an economical product for a wide range of uses. The simplicity of a cap screwing onto a mating hub allows the product to be easily used by operators who are either new to using this design or are already familiar with it. The hinging is bi-directional, allowing for ease of operation as well as flexibility on the project site. There are added features (including a raised square boss) to allow for more methods

of opening without requiring a hammer or product impact. The proven O-ring sealing method allows for a wide variety of material options to meet the most demanding product and process requirements. The threaded product can be provided for the most common requirements as well as custom applications in sizes 2 in. to 52 in. (DN50 to DN1300).

S-2000 clamp ring The S-2000 clamp ring product line is made primarily for horizontal pipeline applications, conforming to the ASME B31.8 and B31.4 codes as well as the US DOT requirements, in addition to the CSA Z662 Cat 1 rules. Designed to be easily operated in the field, the latch mechanism and door hinging allow for simple, frequent operation common to pipeline applications. Hinging and opening latch assemblies have grease fittings for ease of maintenance lubrication to ensure trouble-free operation. These closures use an O-ring seal, safely located on the hub away from the through-bore, to help prevent damage or buildup during repeated pigging operations.

Having an O-ring allows them to work with a wide variety of media profiles by simply specifying the appropriate O-ring material. This product is offered in sizes 4 in. to 48 in. (DN100 to DN1200). As the scale of the pipeline increases, so do the options for operation, to meet a wide variety of needs; from simple manual operation, to heavily mechanically advantaged operation, to designs that allow for ease of opening with only handheld power tools.

S-3000 internal door closure The S-3000 internal door closure product can be used equally well on pipeline or pressure vessel applications. Designed with a lockring component that prevents the door from being removed from inside the closure hub, any unlikely failure keeps the door firmly closed. This closure type can be manufactured in 6 in. (DN150), with no upper limit, to fit a number of applications. The internal door product is designed to come in O-ring or lip seal styles, depending on the design criteria and orientation. It has conveniently located handles and mechanical aids to ensure opening and closing are easy, no matter the size. The lockring components are visible during inspection to ensure there is no question about the state of the unit. Horizontal hinging can be specified either left- or right-handed.

In addition, a variety of vertical hinging options are available, such as a wire rope winch, a chain hoist, a hydraulic cylinder, and more. This provides options for operators with different resources available at the job site. This closure also allows flexibility in the number of

Figure 1. From left to right: Stark Solutions’ S-500 Threaded Closure, S-2000 Clamp Ring Closure, S-3000 Internal Door Closure.

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World Pipelines / SEPTEMBER 2021

additional ports or taps available, as well as different hub weld bevel Engineering, and Service staff located together, working collectively, configurations. to ensure the best quality product reaches the customer with every Pipeline integrity ensures the safety and reliability of the order. pipelines. That extends to all aspects of the pipelines, including Pipeline integrity is dependent on the reliability of the closures. To maintain the safety of the operators working with components the pipeline is constructed with. Not only should them, all of Stark Solutions’ closure products 6 in. (DN150) and components be made from high quality materials with quality above are provided with PAVs, and they can be provided on workmanship, but they should provide the operator with the safest smaller units as well. These PAVs provide positive warning prior to and most efficient experience when using those components. For opening the closure should there be any residual pressure left, as closures, that experience should include having the correct closure required by ASME BPVC Sec. VIII, Div.1 UG-35.2. With these PAVs, style for the location and application, as well as that closure having the operator can be sure the internal pressure of the unit has been safe, easy, and quick operation.. properly vented before opening the closure. Additionally, only once the PAV has been properly operated can the closure be opened, keeping the operator safe in the event the pipeline had not been completely depressurised.

Customisation options are available to fit the specific needs of each customer on any of Stark HDPE PIPING SYSTEM Solutions’ quick opening closures.

FOR HIGH VOLUME FLOW Closures can be provided with OUTSTANDING LIFE SPAN extended hubs, with flanges already Corrosion-free PE reduces lifecycle costs welded on, or with lengths of pipe of large diameter pipes significantly already welded on. Additional ports FAST AND EASY INSTALLATION High flexibility, low weight and safe can be added for various gauges or joining methods valves in the cap/door or in the hub.

FOR HIGH-VOLUME FLOWS Hub geometries can be customised Compatible fittings and pipes available with double bevels for ease of up to OD 3500 mm installation welding, or internal tapers HIGH-QUALITY MATERIALS to allow for use of smaller closure Selection of raw materials according to the PE 100+ Association guidelines sizes on non-standard geometry EXPERTISE IN PLASTICS PROCESSING projects. Internal weld overlay of Decades of experience in plastics stainless steel or Inconel metal can processing, research & development be provided, as well as sourcing pressure part raw materials out of various grades of stainless steel or duplex stainless steel. These material options allow for more corrosion resistance to internal media, and longer product life. Similarly, hinging and actuation components can be specified in various materials to allow for ease of use in environments that would typically cause severe external corrosion. On-site engineering staff can assist with other options as well during the product quote.

At its facility north of Houston, Texas, Stark Solutions machines all the pressure parts and performs all the assembly work. The facility is ISO quality certified and ASME certified with “U” and “R” stamps for Section VIII, Div.1 production. The Stark team supports their customers with Sales, Heated tool butt welding machines Manufacturing, Quality Control, from OD 20 mm up to OD 3500 mm

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Nadine Robinson, Technical Adviser – Environmental Sustainability, International Marine Contractors Association (IMCA) presents a new voluntary IMCA Code that promotes environmental stewardship.

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orking with its members IMCA has reached a significant landmark with its recently published ‘Recommended Code of Practice on Environmental Sustainability’ (IMCA ES 001), making it the first membership organisation in the industries IMCA serves to produce such a document. Reaction amongst members, and their clients, has already proved very positive, with one oil major representative declaring the IMCA Code has applications for other industries.

As a leading international trade association with some 700 member companies, IMCA represents the vast majority of marine contractors and the associated supply chain in

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the worldwide offshore marine construction industry. The association has a strong reputation for setting leading industry standards of technical and operating guidance; and is fully engaged in the energy transition to a sustainable, low carbon future, collaborating to advance environmental sustainability.

Through its ‘Code of Conduct for Members’, launched in 2018, all IMCA members commit to, and sign up to, adhering to applicable laws and complying with accepted standards of ethical and responsible business conduct, including those related to environmental protection.

In the new Code, we put pen to paper for the first time on what environmental sustainability means for our industry,

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identifying industry-specific material topics and highlighting some preliminary steps that can be taken to make progress, and signposting additional related resources available. It is a marker in the sand – a foundation document on which to build.

IMCA ES 001 sets expectations on our industry to manage key environmental and climate topics associated with offshore marine construction. Naturally IMCA members are at different stages of their environmental sustainability journey, but there are some common actions all members can take in principle and in practice. These are detailed in the Code.

As IMCA’s CEO, Allen Leatt writes in the foreword to IMCA ES 001: “Championing environmental sustainability and reducing our carbon footprint are fundamental to long-term value creation for not only our industry, but also for the wider public good. This Recommended Code of Practice on Environmental Sustainability is a first step in the right direction and to building resilience.”

As he explained in launching the voluntary Code in late May: “IMCA started its environmental sustainability journey with its members four years ago. Since then, a great deal of groundwork has been accomplished and I would like to thank all our committee members for their sustained effort in the past year in developing this Code, which although voluntary is strongly encouraged for our membership.”

The dedicated Environmental Sustainability Committee (which became an IMCA core committee in September 2020 having previously been a subcommittee reporting to the HSSE Committee) is chaired by Peter de Bree, Director of Strategy and Technology at Heerema Marine Contractors. The Environmental Sustainability Committee draws on members from 13 member companies. It brings together environmental and climate change experts from marine contractors operating around the world, and provides a forum for discussion, exchange of experiences and good practices, and sharing of knowledge to help achieve individual and collective goals. Its work is ongoing, IMCA ES 001 is just the start of the journey – much lies ahead.

Getting down to work In producing the new Code to promote environmental stewardship an overall workgroup, involving members from 10 countries, was formed and so too were sub-groups under the auspices of the Environmental Sustainability Committee.

As with all IMCA committees they were led by members. All IMCA guidance is produced by members for members.

Member companies instrumental in developing the Code included DeepOcean, DEME Offshore, DOF, Fugro, Global Maritime, Heerema Marine Contractors, McDermott, Saipem, SBM Offshore, Subsea 7 and TechnipFMC. The sub-groups covered greenhouse gas emissions reduction; energy efficiency and management; the circular economy; supply chain engagement; and reporting and disclosure. We called on additional experts to assist with the section on managing life below water and environmental impacts, which will be of particular interest to readers of World Pipelines.

The final step was a consultation process with comments received assessed by the Review Committee. Like all IMCA documents the Code will be regularly reviewed and revised to take account of key regulatory and market developments, new technologies, stakeholder demands, adoption rates and changes in industry practice. IMCA’s Board has closely followed the Code’s development and welcomes its publication.

The meetings and production of the Code was all achieved during the pandemic. We are immensely grateful for the time and expertise of the dedicated experts in our membership who convened to develop and write the Code during this challenging time.

Principles and practice

Figure 1. The newly published voluntary Code.

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Every two years IMCA holds a member survey and the one carried out in 2021 clearly emphasised the importance of environmental sustainability and the energy transition. Almost 80% of respondents said environmental sustainability was critical or very important in IMCA’s strategy and more than four-fifths acknowledged their client base was increasingly using environmental sustainability in evaluating contractors and suppliers; so, our timing for providing them with signposts by means of the new Code is impeccable.

IMCA’s ‘Environmental Sustainability at a Glance’ document, readily available for wide dissemination from

the IMCA website, provides a bird’s eye view of the Code; and identifies several principles for possible adoption by members, as well as good practices, Throughout the Code we highlight around 50 suggestions as ‘recommended’ or ‘good practices’, we want to encourage members to consider, recognising that each of them will have their own objectives, and create ambition throughout the industry: ) Developing Paris Agreement aligned marine emissions reduction strategies, consistent with the International Maritime Organisation’s (IMO) 2018 initial Greenhouse Gas Strategy. It is suggested in the Code that members should, where possible, develop Paris-aligned GHG emissions strategies and set specific, measurable, achievable, realistic and time-bound (SMART) targets consistent with the IMO’s initial strategy. Members can review their decarbonisation roadmap regularly, taking into account advances in technologies, adoption rates, economics, and regulatory and other developments. ) Committing, prioritising and planning for sustained

energy efficient operations. Key practices in this area include establishing a baseline for energy consumption and recording and consolidating of data at regular intervals. Members are encouraged to keep abreast of technological advancements that may enhance vessel energy efficiency and consider these in the overall strategy to improve energy performance. Various operational and technical measures for enhancing energy management are noted in the Code. For example,

operational measures include optimising operational modes (without compromising safety), preventive asset management and optimised voyage planning. Technical measures to promote energy efficiency could include more efficient vessel power systems, greater energy efficiency through use of digitalisation and, where feasible, use of shore power. ) Managing the process of protecting life below water (the

14th United Nations’ Sustainable Development Goal (SDG 14)) and other environmental impacts associated with offshore construction. Marine contractors operating offshore need to carefully manage the process of protecting life below water and other environmental impacts (e.g. underwater noise or invasive species).

Members are encouraged to adopt good practices, such as implementing environmental management systems (EMS) and environmental management plans (EMP), which outline commitments, responsibilities and mitigation measures in place for specific activities. ) Applying the principle of circularity and adopting a

circular economy approach to asset lifecycling, and waste and resources management. The Code offers strategies of how this approach may be applied to both waste management and End-of-Life (EOL) assets, drawing on the internationally recognised 9Rs Framework of the MacArthur Foundation. This concept can also be promoted within the supply chain.

Figure 2. It is vital to protect life below water.

) Collaborating with and cascading environmental objectives

to the supply chain, and considering collaborating with others, for example through participation in relevant multi-stakeholder initiatives. Engagement with the supply chain, including undertaking due diligence, is key to helping advance environmental sustainability across the offshore marine contracting industry, although it is recognised that the nature and level of engagement will vary across the IMCA membership and will be dependent on the supplier level of criticality. To be successful in our shared environmental journey will also require learnings from others. In this respect, several multi-stakeholder initiatives, in which members are engaged, are noted such as the United Nations Global Compact, the Seabed 2030 Project, and the Oil and Gas Climate Initiative. ) Raising awareness and advancing competence of key

environmental issues within our industry. It will be increasing important for members to deliver on their responsibility to respect and protect the environment. This is not only the right thing to do but is also governed by regulation to varying degrees. To do so effectively, requires an informed and engaged workforce and supply chain.

IMCA will engage further with members and Committees to explore what support is needed, including any further guidance, awareness-raising, and training. ) Measuring, disclosing and self-assessing progress on

environmental sustainability. Members are encouraged to report progress on the most material environmental aspects through their chosen disclosure vehicle and to regularly self-evaluate or reflect on how to improve their environmental performance. Multiple international frameworks and standards are included in the Code to help members communicate environmental performance in a consistent, comparable and decision-useful way.

Managing life below water The entire Code has relevance to the pipelaying, and O&M community however, as mentioned above, members

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involved with pipelines have an important role to play in supporting the achievement of SDG14 by demonstrating good environmental stewardship in the marine environment in which they operate.

Members recognise that the world is facing not only a climate, but a biodiversity crisis. October 2021 sees the UN Convention on Biodiversity (UN CBD 15) taking place in China. It is expected that the world will agree on a post-2020 global biodiversity framework including related targets.

For example, members may encounter marine mammals and other biodiversity in operating their vessels.

The associated potential impacts vary dependent on the environmental characteristics and ecosystems where the activity is taking place, and on the engineering solutions delivered. The Code dives into much fuller details on these points.

The Code adds: It is also important to distinguish between the impact of members on ‘life below water’ (e.g. through ballast water, on hulls and in intakes/outlets, oily water discharge, hydraulic spills from thrusters and hoses, and underwater noise from machinery, etc. Fuller information is given) and the much larger impact, made on behalf of clients (e.g. seabed disturbance through dredging, ploughing, trenching and rock installation; chemical discharge through Ready for Operations (RFO) on pipelines, drill cuttings from drill rigs; underwater noise from piling and seismic activities).

It should be recognised that many of these activities are conducted under the client’s environmental plan and associated requirements and approvals. Where practicable, members should adopt ‘Best Available Techniques’ and ALARP principles, even in areas where client or government requirements are not stringent.

What comes next?

Publication of the Code is just a first step on IMCA’s environmental sustainability journey. Guidance documents on specific aspects figure in the Environmental Sustainability Committee’s work programme as does ensuring all relevant existing IMCA documents are updated to include salient points.

Developing a self-assessment tool so members can reflect on the ‘asks’ in the Code and determine how they are doing, both individually and as an organisation, is high on the action list. It is too early for benchmarking, but the time will come.

On 28 September a technical and motivational seminar will be held to disseminate the Code; with external speakers homing in on specific topics to provide a different lens and view. We are eager to raise awareness throughout the industries we and our members serve. We have also produced a related podcast and broadcast.

In many ways, the process of producing the Code was as important as the Code itself. Members have come together, developed a relationship and a network which has cemented the Environmental Sustainability Committee and are looking forward to the next steps in making progress on environmental sustainability across our industry.

PIPELINE MACHINERY review World Pipelines’ quarterly pipeline machinery focus, featuring Trencor.

Trencor

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o two jobsites are created the same. The ground conditions, climate and regulatory standards differ drastically from West Salem, Ohio to Sydney, Australia and at every jobsite in between. This presents pipeline construction professionals with difficult challenges to overcome. While there are no easy solutions for these challenges, knowing that your equipment can handle your jobsite conditions while meeting regulatory standards is a great start.

Newly equipped with the CAT C18 Trencor T14 Trencher. engine, the Trencor T14 trencher can help pipeline construction professionals improve efficiency and decrease costs on each jobsite. Compared to the previous T4F engine offering, this CAT C18 engine offers spend more time on the jobsite and less time on machine substantially more horsepower with an increase from 613 maintenance. hp to 755 hp. This significant 22% increase in gross power Additionally, the C18 engine allows for the T14 to be allows operators to tackle large-diameter pipeline installation compliant with both EPA Tier 4 Final and European Union projects and tough ground conditions.

Stage 5 requirements. Meeting these high regulatory Due to this CAT C18 engine being rated above 750 hp, requirements means that the machine can be used on more it is able to avoid the diesel exhaust fluid (DEF) and AdBlue jobsites around the world. regulations, eliminating a customer maintenance point and The engine also features a simple aftertreatment system, the potential service needs associated with DEF systems, pusher fan and easy-to-use pump drive, as well as removing contamination and reliability. This enables operators to the lower power take-off (PTO) shaft to direct mount the

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pump to the PTO and incorporating the high-speed chain kit into the standard unit. Each of these enhancements helps to improve the ease of use, operator experience and machine power.

“At Trencor, we understand the challenges that come with pipeline installation, and they are top of mind when we make changes and improvements to our machines,” said Steve Seabolt, Trencor Product Manager. “That is why we made the decision to equip the T14 with a CAT C18 engine. This engine has the needed horsepower, meets emission requirements and provides operators with the necessary features to get the job done efficiently.”

The updated machine packages the engine, transmission, pumps and cooler all together onto one modular skid that can be more easily installed in or removed from the unit. This simplifies repairs, but also makes all of our inventories more flexible. For example, if operators encounter a situation where a T4F unit is in stock, it can be reconfigured into a T3.

The size and weight of this machine eases transportation time and costs. Based on the configuration of the T14, pipeline construction professionals have the ability to transport the machine in fewer parts. This improves efficiency, productivity and cost by reducing the time needed to disassemble and reassemble the machine, while decreasing the number of vehicles needed for transportation.

Regardless of jobsite location, time of day or machine specifications, there is no time to wait on a jobsite when machine assistance is needed. Equipment operators need access to quick and reliable equipment. That is why Trencor has a global dealer network to provide world-class parts, service and support to all underground construction professionals at each and every stage of the machine’s lifecycle. Visit the Trencor website to learn more about how the T14 can help you efficiently complete your job and find a dealer near you.

Keep Updated

Bound insert OFC, 13 4 47 2 14 7

Keep up to date with us to hear the latest pipeline news

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