World Pipelines October 2021 by PalladianPublications

Volume 21 Number 10 - October 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.

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CONTENTS WORLD PIPELINES | VOLUME 21 | NUMBER 10 | OCTOBER 2021 03. Comment Gambling with the grid

PIPELINE CLOSURES 37. Choosing the right closure for the job

05. Pipeline news

Morgan Sledd, Stark Solutions, USA.

With news from STATS Group, Enbridge, Subsea 7, and more.

REMOTE ASSET INSPECTION 39. The buzz around drones

REGIONAL REPORT 08. The cost of instability

Chris Johnson, Managing Director, SMB Bearings, UK.

Gordon Cope details the host of political and financial challenges still facing the oil and gas industries of MENA nations, even after post-COVID-19 market recovery.

HYDROGEN PIPELINES 43. Inline inspection: hydrogen edition Dr Aidan O’Donoghue, Pipeline Research Limited, UK.

49. Testing hydrogen pipe repairs Harri Williams, University of Edinburgh, Derek Muckle, Radius Systems Ltd, and Angus McIntosh, SGN.

AUTOMATION AND CONTROL 52. Game changing surface software Surface Corrosion Consultants Ltd, Northern Ireland, UK.

Gordon Cope details the host of political and financial challenges still facing the oil and gas industries of MENA nations, even after post-COVID-19 market recovery.

ations in the Middle East and North Africa are endowed with a major portion of the world’s oil and gas reserves, which can be both a blessing and a curse. The former encompasses the opportunity to build modern, prosperous economies for its citizens, and the latter the unpredictable nature of the market, including, most recently, a pandemic that seriously undermined demand (and revenues). While the aftereffects of COVID-19 are the primary woes currently besetting MENA, a plethora of other challenges awaits in the wings.

Middle East Saudi Arabia In June 2021, Saudi Aramco spun off control of its pipeline network to a new subsidiary, Aramco Oil Pipelines Co., and then, with the help of EIG Global Energy Partners, sold a 49% equity stake for US$12.4 billion to international investors, including China’s

Figure 1. With just a few taps of the screen, all saved readings from the gauge are instantly transferred to the app and synced with no need for manual data entry – just choose which zone the readings are from and the app does the rest.

Silk Road Fund and Abu Dhabi’s sovereign wealth fund. The subsidiary has the rights to tariff payments made for all crude flowing through the network for a period of 25 years. Aramco is also looking at a similar deal for its natural gas pipeline network as part of its plan to divest non-core assets.

Abu Dhabi Abu Dhabi National Oil Co (ADNOC), is working to make the Emirates a leading Middle East exporter. It has plans underway to increase its crude production by 1 million bpd, to 5 million bpd by 2030, as well as make the UAE self-sufficient in gas. In June 2021, it announced a US$510 million deal with Italian firm Saipem to expand its Shah Sour Gas Plant from 1.28 billion ft3/d processing capacity to 1.45 billion ft3/d by late 2023. The initiative goes hand-in-hand with plans to increase output from its Hail, Ghasha, Delma and other sour gas fields. Longer-term plans include working with US-based Occidental, a partner in the Shah plant, to develop petrochemical capacity using the natural gas and related feedstocks; ADNOC is planning to triple its current petrochemicals output to 12 million tpy by 2025. Abu Dhabi’s Supreme Petroleum Council estimates that the emirate has 173 trillion ft3 of conventional gas, and 160 trillion ft3 of unconventional gas. In late 2020, ADNOC announced that first gas from the Ruwais Diyab unconventional gas concession had

PAGE

Surface Corrosion Consultants Ltd, Northern Ireland, UK, on changing the face of corrosion and inspection management, via new web-based technology.

eading the way in web-based technology for the management of corrosion is specialist firm Surface Corrosion Consultants Ltd. The Belfast headquartered company, which specialises in comprehensive paint inspection, NDT inspection and corrosion prevention, has unveiled its innovative new app – Surface Asset Management (SAM) – that is set to transform how coating condition surveys and painting campaigns are recorded and managed. The groundbreaking SAM software is an easy to use, digital inspection application that streamlines all aspects of NDT management and coating inspection. The user friendly, highly intuitive programme can be applied across a range of industries including oil and gas, subsea, renewables, marine, transport and infrastructure as well as wider industrial sectors. The revolutionary software can also manage new build projects providing full cradle to grave traceability. SAM is a fresh and unique approach to corrosion prevention and has been designed by corrosion specialists for corrosion specialists. The technology has been developed with simplicity and efficiency at the forefront of its design. The software removes duplication of tasks and creates a single point of access to monitor corrosion and manage the execution of coating systems, passive fire protection and insulation instalment.

EPC AND ROW 14. The Greek-Bulgarian connection Daisy Jestico, on behalf of Volvo Construction Equipment (Volvo CE).

ACOUSTIC SENSING 20. 24/7 pipeline intelligence

A gap in the market The pioneering technology was developed in 2017 after a team of specialists at Surface Corrosion quickly realised the majority of service providers and major operators are still managing their corrosion protection using sub-contractors and colossal spreadsheets. Recording of maintenance campaigns was inefficient, often documented by creation of

The Fiber Optic Sensing Association (FOSA).

25. Linking up digital technologies

PAGE

Matt MacDonald, Fotech, a bp Launchpad company.

PIG LOCATION AND TRACKING 29. Making way for hydrogen Dr. Mike Kirkwood and Neil McKnight, T.D. Williamson, UK.

33. Advanced platform for pig tracking Geoff Wilkinson, Propipe UK and Chris Loadman, Propipe North America.

ON THIS MONTH'S COVER

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ISSN 1472-7390

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Volume 21 Number 10 - October 2021

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© 2020 – American Petroleum Institute, all rights reserved. API, PSMS Assessment, the API logo, and the PSMS Assessment mark are trademarks or registered trademarks of API in the United States and/or other countries. API Marketing & Communications: 2020-319 | PDF

COMMENT

GAMBLING WITH THE GRID

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wasi Kwarteng, the business secretary for the UK government, sought to assure the House of Commons last month that there is no danger of the UK running out of gas this winter, amid fears about a breakdown in the structure of the European and global gas markets. Welcome to an extraordinary autumn in the UK, in which spiralling gas and electricity prices and very low national gas reserves signal an impending energy crisis. The tightness in the global gas market is a result of several factors: 40% of US gas production was temporarily shut in during hurricane season; Latin America is experiencing its worst drought in a century and this has cut hydro power in Brazil, Argentina and Chile, forcing a move to LNG. China, the world’s biggest importer of gas, has been upping its LNG imports, in part due to drought, as well as a rise in domestic gas demand. As a result of this explosion in Asian demand, much less LNG is reaching Europe, and that’s before you take into account energy supply chain disruption due to COVID-19. As countries reopened from COVID-19 lockdowns this summer, high-thanexpected demand contributed to the shortage of gas, and also stunted domestic ability to stockpile gas during warmer months, when demand tends to be weaker. It’s worth noting that Gazprom chose not to bid for top up gas flows for the month of October in pipeline routes traversing Ukraine and Poland, placing more pressure on the Nord Stream and the (as yet uncertified) Nord Stream 2 pipelines. The global gas supply squeeze being felt all over the world is set to have a particularly forceful impact on the UK, since the UK is sitting on scant gas storage, having cut storage capacity to 1.7% of annual demand (a long way south of the normal buffer of 20%) and having outsourced the costly task of storage to countries in continental Europe (who are themselves low on stored reserves). A wet,

cold spring this year depleted European gas inventories. Poor wind power generation levels in recent months have certainly had an impact on the amount of energy the UK can extract from renewable sources. Now doom-filled headlines in UK newspapers warn of a return to a three-day working week and blackouts (as seen in the 1970s) as industrial stoppages become an increasing reality. High power prices are already curtailing operations: the gas price surge has triggered fertilizer plant closures, including US-owned CF Fertilizers, which has ceased output at two UK factories. Steelmakers have reported disruptions to production due to current energy costs. The European Steel Association has said that the bloc risks being priced out of the global market due to surging energy prices. The UK’s National Grid was forced to turn to coal-fired power stations at short notice early in September, asking EDF to fire up a power station that had been on standby. Consumer groups in the UK are urging households to be prepared for steeply rising bills and price pressures have led to a handful of utility suppliers going out of business, as they fail to meet the cost of purchasing raw energy. Kwarteng said that talk of a return to the three-day week is “alarmist, unhelpful and completely misguided”. The government has held emergency talks with Ofgem, the UK energy regulator. Speaking to MPs in the House of Commons about the issue of supply, Kwarteng said that the UK is not “at the mercy of Russian gas”. He argued that electricity security can be maintained under a wide range of scenarios and that the UK is not reliant on just one source of gas: “The UK also benefits from an excellent relationship with Norway, one of our most important and reliable energy partners and that delivers nearly 30% of our total gas supply ... [I] welcome the announcement from Equinor today that gas production will significantly increase from the 1st of October this year to support the UK and European demand.” The UK may need more than that to fend off a winter of discontent.

THE TIGHTNESS IN THE GLOBAL GAS MARKET IS A RESULT OF SEVERAL FACTORS

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WORLD NEWS AIOC supports Indigenous Communities in financing of Northern Courier Pipeline System Alberta Indigenous Opportunities Corporation (AIOC) has announced that it has provided up to a CAN$40 million loan guarantee to support eight Indigenous Communities in the Wood Buffalo Region, to finance a 14.25% ownership interest in the Northern Courier Pipeline System (NCP System) including the Pipeline and associated storage facilities. The participating Indigenous Communities are Athabasca Chipewyan First Nation, Chipewyan Prairie First Nation, Fort McMurray First Nation, Fort Chipewyan Metis Local 125, Fort McKay Metis Nation, Fort McMurray Local Council 1935, Willow Lake Metis Nation and Conklin Metis Local 193. The NCP System consists of 90 km of bitumen and diluent pipeline connecting the Fort Hills Oil Sands project in Northern Alberta with Suncor’s facilities in Fort McMurray. Originally constructed by TransCanada Pipeline Limited (TCPL) in January of 2018, TCPL will transfer ownership of the NCP system in 2021 to the newly formed Northern Courier Pipeline Limited Partnership (NCPLP), which will be 85% owned by the Alberta Investment Management Corporation (AIMCo) and 15% owned by a Limited Partnership between the Indigenous Communities and Suncor Energy. The Limited Partnership ownership stake will see 14.25% of the NCP system owned by the Indigenous Communities, with Suncor acting as operator and owner of the remaining 0.75%. “When evaluating proposals at AIOC, we are looking for projects that will result in long-term prosperity for the communities involved,” said Alicia Dubois, CEO of AIOC. “The NCP System will ensure that the eight Indigenous Communities involved have long term active participation and steady own-source revenue streams, the impacts of which will serve generations to come.” This loan guarantee secures direct Indigenous ownership of pipeline infrastructure within the traditional territories of the eight Indigenous Communities involved and will enhance the contributions of each Community in the local economy of the Wood Buffalo Region. “This investment is more than a financial transaction, it is a step forward for Canada,” said Ron Quintal, President of Fort McKay Métis Nation. “The future of responsible extractive resource development in Canada must be one where Indigenous Communities are real partners that derive long-term benefits for housing, training and education. This should be a model used across the country. Investment in the energy sector is a clear path for indigenous communities to finally realise economic reconciliation.”

STATS Group completes six concurrent North Sea pipeline shutdown campaigns Pipeline technology specialist, STATS Group, has successfully completed the largest number of simultaneous pipeline isolation projects in its 23 year history. During the 2021 summer shutdown season, STATS supported six separate Tecno Plug isolation deployments in the UK North Sea, on pipelines ranging from 20 in. to 36 in. in diameter. The projects were on critical pipeline systems on behalf of multiple clients, with the isolation periods ranging from 10 to 45 days. Isolation activities were carried out onshore and offshore at various locations and included the use of STATS Remote Monitoring System, which allowed Tecno Plug isolation tools to be monitored continuously via satellite from STATS Remote Monitoring Centre in Kintore, Aberdeenshire. The satellite monitoring technology enables customers to reduce site Personnel on Board (POB) requirements on their oil and gas installations during breaking of containment activities, whilst still ensuring that the isolation status is continually monitored. The summer shutdown period also saw a surge in demand for STATS Process Plant Solutions which supported both North Sea and international clients with the provision of vapour barrier and localised weld testing services, with many requirements being delivered in quick turnaround times, due to the inevitability of unforeseen scopes that appear. In addition, STATS worked closely with multiple North Sea Operators in the manufacture and installation of its Topside Mechanical Pipe Connectors.

Enbridge Inc. to acquire Moda Enbridge Inc. has announced that it has entered into a definitive purchase agreement with EnCap Flatrock Midstream to acquire Moda Midstream Operating, LLC for US$3 billion in cash, subject to closing adjustments. The acquisition will significantly advance the company’s US Gulf Coast export strategy and connectivity to lowcost and long-lived reserves in the Permian and Eagle Ford basins. “We’re very excited about acquiring North America’s premium, very large crude carrier (VLCC) capable, crude export terminal,” commented Al Monaco, President and Chief Executive Officer of Enbridge. “Over the last several years we’ve been building a strong position in the US Gulf Coast through both natural gas and crude infrastructure. Our strategy is driven by the important role that low cost, sustainable North America energy supply will play in meeting growing global demand. With close proximity to world-class Permian reserves, and with cost effective and efficient export infrastructure, our new Enbridge Ingleside terminal will be critical to capitalising on North America’s energy advantage.” Central to the transaction, Enbridge will acquire a 100% operating interest in the Ingleside Energy Center (to be renamed the Enbridge Ingleside Energy Center (EIEC)), located near Corpus Christi, Texas, US – one of North America’s largest crude export terminals, which loaded 25% of all US Gulf Coast crude exports in 2020. This state-of-the-art terminal, built in 2018, comprises 15.6 million bbls of storage and 1.5 million bpd of export capacity. Enbridge will also acquire a 20% interest in the 670 000 bpd Cactus II Pipeline, a 100% operating interest in the 300 000 bpd Viola pipeline, and a 100% operating interest in the 350 000 barrel Taft Terminal. Together with EIEC, these pipeline and storage assets provide a fully integrated light crude export platform.

OCTOBER 2021 / World Pipelines

WORLD NEWS EVENTS DIARY

Subsea 7 awarded contract offshore Norway

20 October 2021

Subsea 7 S.A. has announced the award of a sizeable contract by OneSubsea®, the subsea technologies, production and processing systems division of Schlumberger, for a project at the Ormen Lange field operated by Shell in the Norwegian Sea. Subsea 7’s scope includes the engineering, procurement, construction, and installation of the subsea flowline system as well as the installation of OneSubsea’s multiphase compression system. The contract award follows completion of the front-end engineering design study (announced on 31 October 2019) and will be executed as a Subsea Integration Alliance project. Monica Th. Bjørkmann, Subsea 7’s Vice President Norway, said, “This award demonstrates the value Subsea Integration Alliance brings by combining the technologies and capabilities of OneSubsea

OpTech 2021 ONLINE CONFERENCE 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

and Subsea 7 into a seamless integrated offering, resulting in the delivery of optimised solutions with reduced execution and interface risk. Subsea 7 looks forward to progressing the execution phase of the project with a focus on safe, efficient and reliable operations.” Subsea Integration Alliance is a strategic global alliance between Subsea 7 and OneSubsea, the subsea technologies, production and processing systems division of Schlumberger, bringing together field development planning, project delivery and total lifecycle solutions under an extensive technology and services portfolio. As one team, Subsea Integration Alliance amplifies subsea performance by helping customers to define, select, install and operate the smartest subsea projects, that eliminate costly revisions, delays and reduces risk across the life of field.

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/ european-gas-conference/

31 January - 4 February 2022 PPIM 2022 Houston, USA https://www.ppimhouston.com/

21 - 22 February 2022 Transportation Oil and Gas Congress 2022 (TOGC 2022) Zurich, Switzerland https://togc.events/

10 - 12 May 2022 Canada Gas & LNG Exhibition & Conference Vancouver, Canada https://canadagaslng.com/

World Pipelines / OCTOBER 2021

TAP wins Gas Project of the Year at Gastech Awards 2021 Trans Adriatic Pipeline (TAP) has announced that it was named the winner in the “Gas, LNG, or Hydrogen Project of the Year” category at the Gastech Awards 2021 ceremony, which took place in Dubai, on 20 September. Luca Schieppati, TAP Managing Director, said: “We are thrilled to receive this important award and I would like to wholeheartedly thank our shareholders and teams, our contractors and suppliers, and everyone else involved in the project for their dedication and contribution to the successful completion, on time and on budget and with a world-class safety track record. I also want to thank the authorities in our host countries and at European level for their support during the project development and construction.” “We went the extra mile in making TAP a reality and becoming a reliable and sustainable TSO. This award underlines, once again, our commitment to safety, excellence and best practice when it comes to planning and implementing the project, cooperation with partners and stakeholders, social and environmental investments and delivering the project on target. This resulted in supplying Europe with a new source of energy, which will contribute to the sustainable transition for years to come,” Schieppati added.

THE MIDSTREAM UPDATE •

Sparrows Group announces global expansion

•

NERA partners with Wood on AI inspection solution

•

LYTT and Baker Hughes announce collaboration

•

UGI Corporation completes acquisition of Mountaineer Gas

•

Tennessee Gas Pipeline and Southwestern Energy Company announce natural gas agreement

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Gordon Cope details the host of political and financial challenges still facing the oil and gas industries of MENA nations, even after post-COVID-19 market recovery.

entered the pipeline network; the concession, a JV between ADNOC and Total, has a goal to produce 1 billion ft3/d by 2030.

Qatar In order to maintain its dominant position in the LNG market, Qatar has announced plans to increase its current capacity of 77 million tpy to 126 million tpy by 2027. It is entertaining overtures from supermajors (Shell, Eni, Total, ExxonMobil and others), eager to participate in the development of the supergiant North Dome field, a 6000 km2 (along with Iran’s 3700 km2 South Pars portion) structural trap holding at least 1800 trillion ft3 of gas and 50 billion bbls of gas condensates. The world’s largest nonassociated gas field allows Qatar to expand its capacity by 64% without compromising withdrawal rates. The country, which has the lowest break-even point for LNG, has signed major deals with China to take significant amounts of the new capacity.

Oman The Sultanate of Oman was in financial straits before COVID, needing a break-even price per barrel of almost US$90 to meet its fiscal needs. With only 5 billion bbls of reserves and no gas to speak of, it is reaching out to other MENA nations to develop new business models. In June 2021, it announced it was re-visiting plans to connect to Iranian gas via a pipeline under the Gulf of Oman. The deal was originally struck almost a decade ago, and envisioned Oman importing as much as 2.5 billion ft3/d for 15 years. A network of pipelines would move gas from Iran’s giant South Pars field to a port on the Gulf of Oman, where a 36 in. pipeline would run offshore for 196 km to the Omani port of Sohar. The gas would serve domestic needs, as well as have the potential to be converted into LNG and be shipped to Asia, specifically China, which has partnered with Oman on a number of refinery, petrochemical and infrastructure projects. While the deal still has many hurdles, the recent completion of the Goreh-Jask crude pipeline (see below), facilitates many aspects of the project by supplying complementary infrastructure on the ROW.

Iran Iran is in the process of commissioning its Goreh-Jask pipeline, an 1100 km crude line that runs from the major oilfields in Goreh southwest to the port of Jask, located on the Gulf of Oman. The project lets the sanctions-restricted country divert up to 1 million bpd around the chokepoint Strait of Hormuz and allows it to load VLCCs destined for Asian markets.

Iraq Iraq is nearing completion of a major project to modernise and expand a key import and export facility. As of mid-2021, work on installing equipment and a new oil pier at the Khor al-Zubair terminal was over 70% complete. The project is part of Iraq’s plans to increase exports. Since the beginning of 2021, exports have risen an average of 3.37 million bpd to

World Pipelines / OCTOBER 2021

3.39 million bpd, and are expected to rise further as OPEC+ plans to ease production cuts take effect. Iraq continues talks over its proposed 1700 km pipeline that would run from its oil-producing region in Basra to the Jordanian port of Aqaba, located on the northern end of the Red Sea. The line would carry up to 1 million bpd; Iraq’s Oil Ministry recently announced that it was discussing extending the line into Egypt.

North Africa Egypt Over the last decade, Egypt has had significant success finding and developing gas fields. Thus the supergiant Zohr field, which holds an estimated 30 trillion ft3 of non-associated gas, has allowed the country to fundamentally restructure its oil and gas sector, with the potential to become a regional energy hub. Egypt’s Dolphinus Holdings agreed to import 85 billion ft3 of Israeli gas worth almost US$20 billion over a 15 year period using the existing the EGM offshore pipeline network (Chevron recently agreed to spend US$225 million to increase the EGM infrastructure). The deal will allow Egypt to meet domestic demands and revitalise up to 12 million tpy of LNG exports at its two mothballed trains. In order to maintain the momentum in gas, Egypt is holding an offshore licensing round for nine offshore blocks in the Eastern Mediterranean and three blocks in the Gulf of Suez, with bidding concluding on 1 August, 2021. Several of the Eastern Mediterranean blocks are near the supergiant Zohr. Egypt’s Western Desert remains its major crude producing region, accounting for over half the country’s 650 000 bpd production. International oil companies are slowly decamping the play, however. In May 2021, Shell sold its Western Desert assets in a US$926 million deal to Cheiron Petroleum and Cairn Energy. The company said it was part of its divestment goal to focus more on core assets.

Libya After years of civil war disruption between the official GNA government and General Haftar’s Libya National Army (LNA), Libya’s oil and gas sector is finally getting back on its feet. After an interim coalition government (GNU) was appointed in March 2021, production at major oil fields resumed, with the National Oil Company (NOC) reporting over 1.1 million bpd being pumped in April 2021; the goal is to restore production to pre-war era of 1.6 million bpd by the end of 2021. Even if the peace holds, NOC’s goal may be complicated by a deteriorating infrastructure that has suffered over a decade’s neglect. In June 2021, a 32 in. pipeline that transports crude from the 285 000 bpd Al-Samah field to the port of Es Sider burst. Billions of dollars for repair and replacement of pipelines, tanks and port facilities are needed.

Algeria Algeria’s conventional gas reserves are approximately 140 trillion ft3. Gas production has remained steady at

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9 billion ft3/d, the majority of which is shipped to Europe. In July 2021, state-owned Sonatrach reached an agreement with Spain’s Naturgy to increase the capacity of the Medgaz natural gas pipeline that runs beneath the Mediterranean between the two nations. The US$90 million project will involve the installation of a fourth compressor capable of increasing capacity by 2 billion m3/y. When the work is completed in late 2021, the total capacity will be 10 billion m3/y, representing about 25% of Spain’s natural gas consumption.

Hydrogen The push is on to find alternatives to fossil-based fuels. BloombergNEF estimates that the market for ‘green’ hydrogen – a non-carbon emitting fuel produced through renewables and electrolysis – could be worth up to US$700 billion within three decades. Saudi Arabia is following a multi-pronged strategy to reduce its reliance on conventional crude. Various sources have projected that hydrogen could replace 25% of all oil demand by 2050. Saudi Aramco recently announced an initiative to develop hydrogen fuels through a number of methods. The country is already one of the world’s largest producer of ‘grey’ hydrogen, primarily for upgrading crude. A major focus will be to capture the carbon emitted during the production of grey hydrogen and sequester it in order to create ‘blue’, or carbon neutral, hydrogen. Saudi Arabia’s ACWA Power Corporation and US-based Air Products & Chemicals have entered into an agreement to construct a US$5 billion plant in the desert city of Noem to produce green hydrogen through the use of solar-powered electrolysis. While acknowledging that green hydrogen is much more expensive to produce than grey hydrogen, the country expects economies-of-scale and new technologies to reduce the price to comparable levels by the end of the decade. A comprehensive dedicated infrastructure, including speciallydesigned hydrogen pipelines, will be needed to service domestic and export markets. In May 2021, Dubai launched the first industrial-scale green hydrogen plant in the Gulf. In conjunction with Siemens Energy, the Dubai Electricity and Water Authority (DEWA), the Rashid Al Maktoum Solar Park uses solar power during the day to produce hydrogen, which is then burned at night to create electricity. Plans are to scale the plant up to produce 5GW of clean energy by 2030. Oman’s national oil company, OQ, has partnered with Hong-Kong based InterContinental Energy and a subsidiary of Kuwait to build a multi-billion dollar facility that would use 25 GW of renewable energy to produce green hydrogen, making it the largest proposed green hydrogen facility in the world. In early 2021, Helios Industries announced plans to build a green ammonia production facility in the Khalifa Industrial Zone Abu Dhabi. The plant, costing an estimated US$1 billion, will produce 40 000 tpy of green hydrogen using a solar grid and electrolysis. Output will be converted into 200 000 tpy of green ammonia, reducing CO2 emissions by 600 000 tpy. As part of its ambitious plans to be a world leader in renewables, Egypt’s Ministry of Electricity and Renewables

World Pipelines / OCTOBER 2021

announced that it was studying a plan to spend up to US$4 billion to build a green hydrogen plant. The initiative is part of the country’s goal to produce 42% of its energy from renewables by 2035.

The future Environmental pressure has resulted in several significant events over the course of 2021. In May, a Dutch court ordered Royal Dutch Shell to accelerate its carbon emission-reduction target, ruling that it had to reduce GHG emissions by 45% by 2030, based on 2019 levels. That same month, activist shareholders elected three candidates to ExxonMobil’s 12-member board. Three of the largest pension funds in the US supported the initiative, designed to accelerate the IOC’s transition from fossil fuels to clean energy in an effort to sustain long-term profitability. BP and Eni have announced that they will reduce oil and gas production and become net-zero energy businesses by 2050. But the victories against IOCs could end up handing control of fossil fuels to National Oil Companies (NOCs), such as those found in MENA. State-controlled oil companies are largely shielded from shareholder activism and NGO pressure. The use of oil and gas is expected to increase over the next several years before renewables and EVs make a dent in demand. In the meantime, Saudi Arabia, UAE, Iraq and others could see market share increase as Western oil companies recede from the marketplace. Armed conflict continues to roil the region. The longstanding war between Saudi Arabia and Yemen continues, with Houthi forces (seen as a proxy for Iran), remotely attacking Saudi Arabian petroleum assets; in March 2021, drone and missiles struck Saudi Aramco’s export facility at Ras Tanura refinery. In late August 2021, drones attacked a tanker in the north Arabian Sea off the coast of Oman, killing two. The US and UK governments condemned Iran for the attack. Many MENA countries also face financial worries. Wood Mackenzie estimates that OPEC+ saw approximately US$335 billion in ‘lost’ revenues due to the COVID-related collapse in demand. The shortfall is having a significant impact on countries that rely heavily on oil revenues. Oman’s deficit soared to an estimated 18% in 2020, fueling unrest; in May 2021, protests rocked the cash-strapped country as young citizens took to the streets to protest the poor economy and lack of jobs. For years, Algeria has suffered from poor governance and over-reliance on petroleum revenues; analysts estimate that the government needs US$135/bbl to break even. During July 2021, the country’s oil producing regions in the northeast were gripped by unrest as unemployed youth fought with security forces in the streets. Although the recovery in demand and prices and the sale of oil and gas related assets has relieved some of the immediate pressure, jurisdictions throughout MENA face difficult decisions; governments will have to make tough choices regarding public subsidies and greater political expression to ensure stability in the region.

Figure 1. Two of the four Volvo PL4809E pipelayers on site.

Daisy Jestico on behalf of Volvo Construction Equipment (Volvo CE), Sweden, presents a project showcasing cross-border collaboration and lowcarbon fuel.

he laying of a 182 km long pipeline between Greece and Bulgaria not only marks a milestone in cross-border collaboration but brings with it a more secure supply of low-carbon gas to Bulgaria, boosting economic development. Despite pandemic-related delays, the Gas Interconnector Greece-Bulgaria (ICGB) project is on track to be completed before the end of the year. With an annual transmission capacity set to be at least 3 billion m3 of natural gas, the pipeline has been designed to transport gas with forward and reverse flows to diversify routes and sources of gas imports for both countries, as well as the wider south-east Europe region. In doing so, the pipeline plays an important role in improving infrastructure integration with neighbouring regions while helping to meet the energy needs of the local population.

This supply of natural gas is also deemed a low carbon fuel. When used as a transportation fuel it can emit up to 25% less carbon per unit of energy than conventional gasoline and as it can be sourced domestically, its carbon impact is further reduced. Thanks also to its status as a ‘smart pipeline’ with remote monitoring capabilities across its daily construction work, the project has been able to keep the core operations team as tight as possible and keep costs as low as possible for a large-scale megaproject this size. Co-funded by the European Energy Programme for Recovery at a total cost of €240 million, both Bulgaria and Greece have invested heavily into the construction of the pipeline. Dubbed a “project of national importance” by both governments, the project is a key part of their united strategy for greater integration of gas markets, which includes interconnection projects between Bulgaria and Greece, Bulgaria and Romania and Romania and Hungary. The project, set to finish at the end of this year, will replace Bulgaria’s collaboration with Russia to supply its gas. It will deliver gas from the Shah Deniz 2 development in Azerjaijan’s Caspian Sea to Bulgaria.

Versatility and performance to keep the flow moving The mammoth task of helping to lay a series of 32 in. wide, 402 kg/m heavy and 18 m long pipes across a planned length of 182 km spanning two countries has been given to Volvo Construction Equipment (Volvo CE). Working for customer

Figure 2. The machines’ main tasks are the laying of huge 18 m long pipes.

Figure 3. The mountainous terrain is no match for the Volvo pipelayers.

World Pipelines / OCTOBER 2021

AVAX Group – one of the largest construction groups in Greece with a reputation for delivering major pipeline and natural gas networks – Volvo CE has provided four hard working Volvo PL4809E pipelayers to complete the job. On site since January this year, these versatile rotating machines are reliable and accurate enough to carefully pick up and lower the pipes into the already dug trenches. Delivering a competitive edge in even the most demanding conditions, these pipelayers benefit from an excavatorbased design, advanced load management and telematics systems and 360˚ swing capabilities, allowing them to manoeuvre easily for any number of pipe placement possibilities. These Volvo pipelayers also offer unsurpassed fuel efficiency, making them the most fuel efficient pipelayers currently available. The site conditions in which they are currently operating on site in Bulgaria is particularly challenging. Because the pipelayers are working mainly on mountain terrain, the ground is not only rocky – making the movement of the machines and the creation of the trenches difficult – but on a typical day these machines are expected to climb incredibly steep slopes and lift heavy loads while maintaining stability at an angle. In addition, the weather conditions can be harsh in every season. During the winter the mountain snow makes the operation of the machines even harder, while the summer heat can reach up to 45˚C. Furthermore, the rain throughout the year can make the ground extremely muddy. It’s important therefore to use machines with the power to carry out the task reliably and safely. “These pipelayers are perfect for challenging conditions like these,” says Jörg Breuer, Product Manager Pipelayers for Volvo CE. “Because of their 360˚ swing capacity, the operator can easily – and most importantly safely – rotate the superstructure to lift and place the large, heavy pipe no matter where it’s required and no matter the gradient. The pipelayers’ unique design, where the weight of the machine and load can be safely balanced even while moving, provides unshakeable stability absolutely essential for rugged sloped terrain such as this.”

Tapping into a demanding megaproject The pipelayers’ day-to-day tasks are to lift and hold the pipes in the spot welding places called ‘tie-ins’ and in the hybrid and automatic welding lines. When the welding process is completed, the machines then carry out the most difficult activity, which is the placing of the heavy and lengthy welded pipeline inside the trench. This requires the co-operation of multiple pipelayers, as the total suspended weight of each length of pipe exceeds one machine’s lifting capacity. With excellent stability and smooth hydraulics for simultaneous movements, the rotating pipelayers are the perfect choice for lowering-in applications of this kind. Capable of operating on slopes of up to 35˚, operators simply point the boom uphill to improve the stability and increase safety. Yiannis Panagiotopoulos, Mechanical Engineer for AVAX, says: “Our decision was easy: Volvo pipelayers are

Figure 4. When complete the pipeline will supply Bulgaria with low-carbon natural gas.

period for the new PL4809 before its global release in late 2014. The close collaboration between the two partners was further demonstrated by the recommendations and remarks from AVAX which informed the final touches to the PL4809 before it was released to the market. Now in its latest iteration, the versatile PL4809E pipelayer not only displays stability and safety no matter the conditions, but if required can also be converted into a standard excavator, thereby offering the benefits of two machines in one. While the digging kits for machine conversation were not required for this particular job with AVAX, hydraulics perfectly matched for both pipelaying and digging applications means there is no loss of power in either configuration.

Built on decades of engineering excellence

Figure 5. Kostas Plainos, Mechanical Engineer of AVAX Group, (left) with Haris Bailas of Sigma Bulgaria.

considered among the best and highest quality machines in the industry. We have been very satisfied with the way they have performed for the implementation of this demanding pipeline. We don’t face major breakdowns and the response of the service team is prompt when required. And according to our operators, the machines run smoothly and exhibit no difficulties in movement and pipe lifting. The controllers also have a very good response and are easy to use.” This is not the first time AVAX has worked with Volvo CE. The company also used Volvo pipelayers in the construction of the high pressure natural gas pipeline between Theodori and the Public Power Corporation’s Plant (PPC) at Megalopolis in South Greece, back in 2014. At the time deemed one of the most challenging pipeline projects in Europe, due to the mountainous terrain, extremely steep slopes and hard rock, it was important that the work for this megaproject was carried out with the utmost safety. So for this 24 in. and 30 in. pipeline measuring a total length of 158 km, AVAX acquired seven Volvo PL3005Ds, five Volvo PL4608s and the Volvo PL4809. Thanks to the machines’ capability of placing the boom uphill to stabilise the machine on steep slopes, single grousers to provide the right grip and traction, a cab riser for better visiability and easy to control and smooth hydraulics, safety always came first. Volvo CE also chose the project as a final test

World Pipelines / OCTOBER 2021

Volvo’s E-Series pipelayers are built to deliver equal measures of productivity and safety – starting with the Volvo cab. From the adjustable air-suspended seat, the operator is in total control of his comfort. The spacious, noise and climate-controlled environment is further enhanced by controls that fall easily to hand. The hydraulically-elevated ROPS-safety certified cab delivers a commanding view of the job site and trench and features the Intelligent Load Management System (LMS), which monitors the load and alerts the operator when the limit is reached, for optimum safety and efficiency. The sale of the machines for the ICGB project was completed through the Sigma Bulgaria dealership, a member of the Greek multinational group Saracakis, whose team of highly qualified specialists pride themselves on finding the right service and projects for its customers with guaranteed speed and reliability. Haris Bailas, Executive Director at Sigma Bulgaria, says: “As the first project that AVAX has won in the region of Bulgaria, it was important that we at Sigma Bulgaria delivered the best for the job and we are proud to have performed our best efforts to support the Greek company. The support of Volvo CE is invaluable during this process and I consider that all parties are not only committed, but also aligned, in order to perform to the highest possible global standards.” AVAX Group regularly participates in tender procedures for major projects and is a major contributor to the Greek economy with an acclaimed status in international markets. Furthermore, it is one of the few companies with specialised know-how and experience in mechanical, electrical and plumbing (MEP) works in the Middle East region. The group is also the only Greek construction company certified to implement high pressure large diameter pipeline projects – having successfully delivered 365 km of 48 in. pipeline for the Greek section of the mega pipeline project Trans Adriatic Pipeline Project (TAP) in 2019, as well as delivering 158 km of DESFA’s demanding high pressure natural gas pipeline from Theodori to Megalopolis in South Greece in 2014. Thanks to a strong collaboration across all parties, this latest ICGB project is yet another challenging pipeline project for AVAX that is being completed to the highest possible standards in safety, innovation and environmental issues.

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The Fiber Optic Sensing Association (FOSA) discusses how distributed fibre optic sensing technology is advancing safety and efficiency in pipeline operations.

ipeline integrity is critical for safe and efficient pipeline operation. There are several reasons why a pipeline network needs to be monitored: for example, leak detection, accidental or malicious damage, subsidence and theft. Distributed fibre optic sensing (DFOS) provides the unique ability to monitor in real-time several physical phenomena associated with these threats, such as temperature, strain and vibration. As such, the technology is increasingly being applied in the monitoring of pipeline networks as it overcomes many of the challenges associated with traditional discrete sensors and periodic monitoring and inspection approaches. This article by FOSA reviews the different technologies, their advantages, which applications they are most appropriate for and considerations to take when laying fibre.

Technology background DFOS uses a process whereby an interrogator sends pulses of laser radiation into a fibre and analyses the backscattered radiation. In this process, the term ‘distributed’ means that the signal is generated continuously along the whole optical fibre without the need for discrete sensors. As such, this is an ideal setup for long linear assets such as pipelines. Signals from different locations arrive at the interrogator with different delays, which are directly determined by the distance divided by speed of light inside the fibre. The signal is then sequentially sampled at thousands of locations along the entire monitored route. These signals allow pipeline operators to identify and

interpret physical events along the fibre route to determine the condition of the pipe. There are typically three scattering processes that provide measurements of temperature, strain and vibration (dynamic strain or sound) as shown in Table 1. Raman scattering is widely used in distributed temperature sensing (DTS). DTS uses a simple optical filter scheme to measure the amplitudes of anti-Stokes and Stokes components and then calculates temperature profiles from their ratio. Brillouin scattering is widely used in distributed strain sensing (DSS), mostly related to ground movements and its effects to infrastructure. Brillouin scattering creates a peak of energy at a characteristic frequency proportional to the amount of strain or temperature imposed. Since peak frequencies have some cross-sensitivity regarding temperature and strain, additional information like peak amplitude or frequency shifts from different types of fibres could be required to separate both quantities in applications where both are significantly varying. Distributed acoustic sensing (DAS) is commonly based on coherent Rayleigh scattering. Interference of Rayleigh scattered light from multiple scattering centres within the fibre leads to a speckle-like pattern that depends on the phase difference between the superposing light waves. This pattern is characteristic of the fibre itself but is modulated dynamically by the local environment. Repeating the process quickly enough permits acoustic information to be resolved. The amplitude of the signal is sufficient for sensitive detection of events with a

broad acoustic spectrum like walking, digging and tunnelling while use of the phase component allows quantitative acoustic measurements, precise frequency analysis as well as dynamic strain and temperature monitoring.

Applications of DFOS at pipelines Different DFOS technologies such as DAS, DSS and DTS have numerous fields of use and applications at pipelines, including condition monitoring, structural health and monitoring for third party interference (TPI) (see Table 2, Figure 1). The DFOS methods have many benefits compared with traditional monitoring technologies, being reliable, safe, secure, economical and scalable. DFOS therefore provides an attractive alternative providing 24/7 continuous monitoring over long distances of approximately 100 km from a single location. Multiple applications can be served by a single interrogator which can provide measurements of thousands of locations (Figure 1). As such, it is extremely cost-effective. Further advantages arise from the fact that DFOS requires no electricity to operate along the monitored asset. Power supply is only needed at the interrogator locations, e.g. every 50 to 100 km, which makes monitoring at remote sites much more feasible. The absence of electric energy eliminates the risk of ignition of explosive

fluids, which also helps to improve safety. In addition, fibre-optics are inherently immune to electromagnetic interference, thus providing reliable and accurate monitoring. This significantly reduces the rate of nuisance alarms. DFOS can use existing telecom fibres, which makes installation easy at locations where fibres are already present. Once fibre has been installed, it lasts for dozens of years, and interrogators can simply be upgraded in line with future monitoring needs without replacing the sensor. Localisation capabilities of DFOS are superior to most other technologies used in pipeline monitoring. Signals are sampled with meter resolution, and events like leaks, intrusion, theft of ground movements are precisely localised within a few metres.

Examples of DFOS at pipelines

Leak detection is one major application of DFOS for pipelines. Multiple thermal, strain and acoustic detection modes, such as orifice noise (OFN), negative pressure wave (NPW), ground heave and liquid impingement (Figure 2) can be employed for detecting leaks. They provide superior sensitivity compared with traditional technologies such as computational pipeline monitoring (CPM) based systems, which makes DFOS suitable for many different types of pipes and products in gas, liquid or mixed phases. Significant efforts have been made over the years to verify the leak detection capability of DFOS systems. Ultimately, the real test is the detection of leak on an active pipeline. Real leaks are thankfully quite rare but the evidence is emerging to show DFOS is proven in the field. A couple of years ago, an operator reported a leak alert on their system. This leak was confirmed as genuine and had occurred on one of the pipes around a pump facility. Post-analysis revealed that the alert had been raised as the result Figure 1. Schematic representation of the multiple fields of use at pipelines that of OFN and strain detections. can be covered by a DFOS system. Monitoring for TPI is another important application. In one case, an oil company was aware of a pipeline theft problem on a refined product line. Using their existing mass balance system, the thefts were observed with a regular pattern in the middle of the night, but the system was unable to detect the exact location. The company installed a DFOS monitoring system and on the first night, the DFOS system alerted the pipeline operator – through the detection of NPW and OFN – to repeated activity on the pipeline. The DFOS system was able to identify the location to within 10 m and the company Figure 2. Detection modes of DFOS for pipeline leak detection. was able to put measures in place to stop the theft. Heat trace monitoring is another successful use for DFOS on pipelines. Table 1: Optical measurands and physical parameters of scattering processes in optical fibres For example, pipelines transporting sulfur require heating to ensure that Scattering process Optical measurands Physical parameters the sulfur remains in liquid form. A skin Raman Amplitude (anti-Stokes, Stokes) Temperature effect heating system is commonly used and requires continuous temperature Brillouin Frequency, amplitude Temperature, strain monitoring to maintain and protect the Rayleigh Amplitude, phase Vibration, dynamic strain and pipelines, vessels, and instrumentation. temperature Fibre can be embedded within the pipe

World Pipelines / OCTOBER 2021

been dropped when this additional signal disappeared. The pipeline operator was informed and found the magnets at the location identified.

Fibre installation

Figure 3. Proper fibre positions for DAS (left), DSS (middle) and DTS (right).

Table 2: Fields of use and applications of different DFOS technologies at pipelines Field of use

Application

DAS

DTS

Condition monitoring

Leak detection (single phase, multiphase, subsea)

Third party interference

Intrusion

Perimeter security

Hop tap theft

Valve theft / operation

Earthquake

Rockfall

Geo-technics

Soil erosion

Subsidence

Process monitoring

DSS

+ +

Landslip

Pig tracking

Slack line

Slug profiling

Process monitoring

Strain

Deformation

Trace heat

Heat trace monitoring

or heating element and sensitively detects any location with insufficient heating. In one application, four sulfur transport pipelines with a total length of 76 km required monitoring. High temperature optical cables - rated to 250˚C and capable of withstanding the demands of heating and cooling cycles - were installed with multiple DTS systems to enable redundancy and to accurately measure the temperature to within 1˚C along the full length of the pipeline with 1 m spatial resolution. Smart software clearly displays temperature conditions along the pipelines and sends alarms on pre-defined conditions to the operator so they can make well informed decisions. DFOS can also be used for the forensic post-analysis of events. In one example, a pipeline operator was running pigs through a pipeline and experienced an issue: a magnetic cleaning pig had lost several large magnets somewhere along the pipeline. Typically, a pig generates a characteristic signal as it passes across joints in a pipeline. Forensic inspection of these signals along the length of the pipeline allowed identification of where the magnets had come loose from the pig – through the observation of an additional signal component – and ultimately to identify where the magnets had

World Pipelines / OCTOBER 2021

As already mentioned, DFOS requires only a fibre-optic cable installed alongside the pipeline for continuous monitoring of the whole route. Optimum location and installation method of the cable depend on the interrogation method and sensing requirements. It is of course simpler to factor fibre installation in for new pipelines, but it is possible to retrofit fibre or utilise pre-existing fibre on older pipelines. The optimal position of the fibre with respect to the pipeline depends on the DFOS method and the application (Figure 3). For DAS on buried pipelines, a fibre position slightly above the centreline of the pipeline provides good sensitivity for leak detection as well as for third party intrusion. The fibre should also be buried for mechanical protection. For DSS, the fibre needs to be installed at the place where strain is to be monitored. A fibre attached directly to the pipe will detect pipe strain and bending. If the fibre is buried in soil in the vicinity of the pipe, DSS monitors ground movements. For DTS, the optimum fibre position for thermal leak detection depends on the fluid. Liquid seeps down through the soil and therefore the fibre should be placed somewhere below the pipe. However, gases expand upwards and a fibre above the pipe is better suited for gas leak detection. For heat trace monitoring by DTS, fibres are directly attached to the pipe or the heating element. For exposed pipelines, fibres should be directly attached to the pipe and protected from environmental effects such as direct sunlight or wind to ensure optimum performance in the application.

Conclusion DFOS is a powerful, maturing technology that enables permanent and efficient monitoring of long pipelines and associated infrastructure. Thanks to its continuous monitoring, DFOS provides a vital layer of additional intelligence, able to detect and to pinpoint the location of multiple threats simultaneously. DFOS requires only an optical fibre to provide readings from thousands of locations along the entire route of a pipe. DFOS is a reliable, safe, secure, economical and scalable technology with multiple fields of use at pipelines, enabling operators to accurately monitor their pipelines to protect their assets and improve safety.

Note FOSA would like to thank the following contributors: • Kent Wardley, VP Sales, Americas, Fotech/Chair, FOSA. • Pedro Barbosa, Product Owner, Fotech. • Chris Minto, Engineering Director, OptaSense. • Alasdair Murray, Senior Analyst, OptaSense. • Wieland Hill, Director Advanced Sensing, NKT Photonics/ Chair, FOSA Technology Committee.

Matt MacDonald, Fotech, a bp Launchpad company, reviews how advanced distributed acoustic sensing technologies incorporating machine learning support digitalisation of pipeline operations.

ipeline operators are under increased pressure to improve efficiencies, reliability and safety. Digitalisation – whereby digital technologies seamlessly connect together to advance processes throughout an organisation – is widely regarded as the way forward for oil and gas companies to realise these demands. One area that enables digitalisation is the use of advanced sensors for pipeline monitoring. There are various reasons why pipeline networks are monitored, for example, for detecting leaks or third-party interference and theft 'hot tapping'. However, regardless of the application, operators want confidence in their monitoring technology and assurance that it will perform to the highest levels, providing high accuracy, and with reduced false alarm rates They also need to be able to respond quickly to any threats. Distributed Acoustic Sensing (DAS) technology is key to achieving this.

The need for smart sensors The Colonial Pipeline leak incident in 2020 is a stark reminder of just how important pipeline monitoring is and why improved smart sensing is essential. When the US’s largest fuel pipeline leaked, at least 1.2 million gallons of fuel spilled into a nature reserve. It is thought that the leak went undetected for weeks without operators realising. It wasn’t until some local residents found a puddle of gasoline that the alarm was raised. Clearly, operators need reliable leak detection systems that will raise alerts fast. There are many types of existing monitoring and leak detection technologies available based on internal systems. For example, some use pressure and flow readings from supervisory control and data acquisition (SCADA) systems. There are also mass balance and real time transient modelling (RTTM) and sophisticated computational pipeline management (CPM) systems, which use metering and complex calculations. However, as these systems infer a leak by computing, they tend to have long detectability times and very low sensitivity to small leaks. Furthermore, existing leak detection systems don’t detect most spills. A 2012 study found that when pipelines had

Figure 1. Detecting a dig incident using DAS.

detection technology in control rooms, they flagged leaks about 28% of the time. Systems with CPM detected about 20% of leaks. Overall, PHMSA data shows more than 4000 spills on oil and fuel pipelines since the start of 2010, but leak detection systems identified only about 7%.1 Incorporating advanced sensing technologies such as DAS can help transform pipeline operations by more quickly and accurately identifying incidents.

Discovering DAS DAS technology is a modern smart sensing system that uses fibre optic cables that run adjacent to a pipeline network, and it is proving itself as an accurate method for pipeline monitoring. It is currently deployed on thousands of kilometres of pipelines worldwide. Compared to more traditional techniques it provides continuous monitoring 24/7, over long distances of up to 100 km, and it can detect a threat and raise an alarm within seconds.

The way DAS works DAS essentially turns a fibre optic cable into a sensor. The system is based on photonic technology to detect disturbances in the ground and there are two key processes. First, a laser sends thousands of pulses down a fibre optic cable and monitors the fine pattern of light reflected back every second. Any disturbance, for example ground displacement from mechanical digging or a leak, causes vibration in the soil. This results in a strain on the fibre optic cable, which in turn alters the reflected light pattern. This change in pattern indicates that an event has taken place. The second process takes advantage of the fact that each disturbance has its own signature and light pattern and incorporates advanced algorithms, processing techniques and machine learning to categorise the disturbances.

Machine learning is central to the system

Figure 2. Machine learning helps identify walking events quickly.

World Pipelines / OCTOBER 2021

Making sure that data from the sensor is meaningful, so operators can extract useful and actionable information, is vital. That is where machine learning (ML) comes in. ML techniques train neural networks to classify pieces of data, and they automatically find the patterns in data to turn information into knowledge. This information can then be used to perform complex decision making. There are two challenges for ML: ) Correctly identifying the type of incident that has occurred. For example, if digging is detected, it is highlighted as a dig event, rather than walking.

) Only alerting operators when an event of interest has

taken place. For example, learning which incidents are unusual activity and warrant a response and further investigation. A key issue to address with monitoring technology is nuisance alarms. For example, if spill detection technology is too sensitive, it can raise many false positives and operators stop paying attention to these. ML is critical to reducing these. The algorithms in DAS are smart enough to ignore activities that are of no concern, therefore reducing false alarms. With smart sensors that incorporate ML, an operator can know in real-time what happened, exactly where and when it happened and have confidence in their system.

Figure 3. DAS can automatically notify a UAV flight management system to a threat.

Integrating smart sensors and automatic responses ML plays a large part in advancing monitoring, but what if the alert could automatically feed into a dedicated response? That is the next step towards achieving true digitalisation, where digital technologies talk to each other to create efficiencies for operators. DAS technology can alert a pipeline operator of a threat within a few seconds, but the challenge is how personnel respond to the alarm. Pipelines cover long distances, often in remote and inhospitable terrain. They might pass through desert, forest or icy tundra, where response by road or by foot is not easy and

may take several hours or more. Response by helicopter might be the fastest and most direct route to the location of a detected incident, but this is a costly option and not suitable for pipelines where a tree canopy would make landing impossible. In this case, UAVs provide an attractive alternative to launch a fast response, to fly a direct route from base to the threat location. They can easily be used to capture visual and thermal images of activity and if there are theft attempts, let the criminals know that they have been detected.

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The lid of the storage box in which the UAV is kept on standby opens automatically to let the UAV out. The UAV takes off autonomously and flies to the designated co-ordinates with the flight monitored from an operations room either at the pipeline operator’s security centre, or at the UAV service provider.

Conclusion

Figure 4. DAS harnesses artificial intelligence and cutting-edge ML computing to detect, to classify and to raise the alarm on pipelines events.

The latest DAS systems, such as Fotech’s LivePIPE II, can be easily set up to operate with UAVs. DAS can automatically notify the UAV flight management system where the threat has been detected by providing GPS co-ordinates in a message. The flight management system automatically determines the flight path, taking into consideration the topology and obstacles, the endurance of the battery and the weather conditions.

Integrating DAS into a pipeline monitoring system enables operators to gain accurate intelligence quickly and efficiency, helping them to overcome one of their major challenges. These smart sensors, which incorporate ML techniques, allow pipeline networks to advance on their digitalisation journey ultimately to prevent commercial and environmental disasters, to streamline pipeline integrity maintenance while optimising pipeline efficiency. DAS harnesses artificial intelligence and cutting-edge ML computing to detect, to classify and to raise the alarm on security, integrity, and leak detection events along a pipeline as they happen. Further, integrating a DAS monitoring system with UAV technology creates a powerful detection and response system to help prevent pipeline threats, to safeguard security and to reduce potentially catastrophic events.

References 1.

Investigation: Giant N.C. spill shows gaps in pipeline safety – Thursday 25 February, 2021, www.eenews.net

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International Pipe Line & Offshore Contractors Association Geneva - Switzerland

Dr. Mike Kirkwood and Neil McKnight, T.D. Williamson, UK, discuss the pigging and inspection of repurposed pipelines prior to hydrogen service.

n energy-dense alternative fuel that produces no direct emissions of pollutants or greenhouse gases, hydrogen is being called the key to decarbonisation, the next big thing for generating electricity, power and light. However, since its discovery in 1766, hydrogen has had somewhat of a checkered past – a past that includes the infamous 1937 destruction of the Zeppelin Hindenburg, which exploded over Lakehurst, New Jersey, filling the sky with smoke and fire. There have been several theories as to the root cause of the failure, but one thing is not disputed: hydrogen leaked from the fuel cells, creating a highly flammable mixture that ignited. The reason for the leak and ignition has been subject to several hypotheses, including sabotage, a bomb, an arrow, lighting, electrostatic charge and even a weather phenomenon known as St. Elmo’s fire. Whatever the cause, the deadly accident influenced thinking about hydrogen at the time. Of course, people have short memories. Because hydrogen is clean and can be produced from diverse sources, new interest in a ‘hydrogen economy’ emerged with the environmental movement of the 1970s. At the time, though, there wasn’t enough widespread support to propel the idea forward. Today, however, Hydrogen

Economy 2.0 has government, regulatory and, most importantly, public backing. The question is, if the future’s going to run on hydrogen, how will we transport all the product the world will need? The answer, of course, is pipelines. Some of them will be new and designed specifically for hydrogen; others will be existing natural gas lines repurposed to carry hydrogen alone or in blended service. To ensure safety, prior to operation, those lines will need to be cleaned and inspected.

Converting isn’t easy Right now, there are approximately 4500 km (2800 miles) of operational hydrogen pipelines worldwide, mainly supplying feedstock hydrogen to chemical facilities. That number is slated to grow exponentially as hydrogen’s purpose expands. According to a recent study by the European Hydrogen Backbone (EHB) initiative, plans are underway to develop a dedicated hydrogen pipeline transport network spanning 10 European countries. By 2040, the proposed system will be 39 700 km (24 600 miles) long. Approximately three-quarters of it will be repurposed natural gas lines.

Converting an existing pipeline to hydrogen, either for blended or pure service, isn’t a simple task. There’s no on-off switch to make the transition fast and foolproof. For one thing, the calorific value of hydrogen is one-third that of methane. This means that a pure hydrogen pipeline requiring an operating pressure of 200 bar (2900 psi) will need a threefold increase in pressure to get the same energy transportation as a current gas pipeline. Another problem: hydrogen is eight times less dense than methane, meaning it requires eight times the energy to compress it. These operational difficulties are not insurmountable. A more significant concern is that hydrogen is known to adversely affect the steel most commonly used for natural gas pipelines. Hydrogen-induced cracking, hydrogen embrittlement and increase in fatigue crack growth are all potentially significant concerns. However, with careful preparation prior to and during pipeline repurposing, even those challenges can be brought under control.

Pigging, before and after Pre-commissioning cleaning of hydrogen pipeline systems is normally accomplished by running conventional pigs using water, air or nitrogen. Generally, the goal is to achieve the same level of cleanliness as natural gas pipelines. During commissioning, standard pigs can be used for water fill and hydrotesting. Once the hydrogen pipeline is in service, pigging tools will continue to play an important part in the operators’ flow assurance and inspection plans. The European Industrial Gases Association (EIGA) suggests using only pigs fabricated from hydrogen-compatible materials, which will affect the overall design. Selecting the right components will ensure they are not damaged by the aggressive environment and will reduce the risk of sparking, which can be hazardous when hydrogen and air mix.

For example: ) Cups and discs should be carefully selected based on urethane

hardness, flexibility and wear resistance. ) Because of the spark risk and potential for damaging the

internal coating, conventional solutions for extending cup run time in dry environments, such as studs, cannot be used. ) To avoid damage from hydrogen embrittlement, brushes and

other metallic parts must be made from either austenitic steels or aluminum. ) Using non-intrusive pig signalers will eliminate any concerns

associated with direct contact with hydrogen in the line. However, intrusive varieties can still be used as long as the trigger/plug material is appropriate, such as stainless steel. ) When designing canisters that hold transmitters or data

loggers for pig tracking, it’s important to select the correct material for sealing elements and O-rings to ensure hydrogen compatibility. Elastomers in particular will exhibit swelling with hydrogen exposure.

Finding susceptible defects Defects that might be relatively low risk in natural gas pipelines can be more dangerous in hydrogen service. That’s why, prior to repurposing a pipeline, it’s imperative to first detect, size and characterise defects susceptible to hydrogen attack or degradation then remove or inactivate them. Deploying a variety of ILI technology can help find everything from manufacturing defects and corrosion to metal fatigue and interacting threats – defects that are more serious combined than they are individually. ILI technology for hydrogen pipelines includes: ) High resolution deformation (DEF). ) High field axial magnetic flux leakage (MFL). ) Low field axial magnetic flux leakage (LFM). ) Helical/spiral magnetic flux leakage (SMFL). ) Electromagnetic acoustic transducer (EMAT).

Figure 1. Rare earth magnets, like those used in ILI tools, before and after exposure to hydrogen environment.

) Ultrasonic wall measurement (UTWM). ) Ultrasonic crack detection (UTCD). ) XYZ mapping. ) Inertial measurement unit (IMU).

Figure 2. Combination tool using DEF - MFL - LFM - SMFL - XYZ provides most defect detection, excluding cracks.

Figure 3. Electromagnetic Acoustic Transducer (EMAT) tool for detection of cracks.

World Pipelines / OCTOBER 2021

Multiple datasets improve threat characterisation Running multiple tools then aligning the data is a common method of identifying interacting defects, although the process isn’t failsafe and it’s possible to miss defects this way. Combining

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several of these technologies on a single tool ensures the best data alignment while also minimising the number of inspection runs. Specifically, running a combination of DEF, MFL, LFM, SMFL and XYZ – referred to as a multiple dataset (MDS) tool (Figure 2) – then contrasting the results against EMAT (Figure 3) or an alternative crack detection technology improves the characterisation of interacting threats and enables the prioritisation of remedial action. Once the pipeline enters hydrogen service, routine inspection remains essential to integrity. Minimising the effect of hydrogen on sensitive ILI tools requires significant design changes, including:

) New magnet assemblies to prevent hydrogen intrusion

(Figure 1). ) New sealing approach to protect the sensitive electronics and

batteries within the pressure vessels of the tool. ) New MFL brushes to support the magnetiser and couple the

magnetic flux to the pipe wall. ) A complete reengineering of all high-strength steel

components that were in previous designs, including the tool’s body-to-body coupling system.

Table 1. Summary of defects considered important for hydrogen service, and the suggested inline inspection technology to find them Deflect class

Tool technology

Defect detection

Mill/ manufacturing defects

DEF - MFL - LFM - SMFL - EMAT/UTCD

Many mill/manufacturing defects can be hydrogen-susceptible, including laminations, voids, seam weld defects and spalling. Most can be found by combining DEF, MFL, LFM and SMFL, although there are exceptions that will also require a crack detection technology such as EMAT/UTCD.

Construction defects

DEF - MFL - LFM - SMFL

During construction, it’s possible to introduce defects such as dents, gouges, scratches, spalling, wrinkles, ripples, grinding marks and weld strikes. Though not all of these are injurious for gas service, they can present issues for hydrogen. Combined DEF, MFL, LFM and SMFL will catch most.

Mechanical properties

DEF - MFL - LFM - SMFL

Prior to hydrogen service it is necessary to assess each pipe spool for hydrogen susceptibility as well as for anything that is not as per installed or different (rogue). A combination run of DEF, MFL, LFM and SMFL is a good way to achieve this.

Mechanical damage

DEF - MFL - LFM - SMFL - EMAT/UTCD

Mechanical damage in hydrogen pipelines is more critical due to the nature of material changes that make dents more susceptible to cracking. A combination of DEF, MFL, LFM and SMFL and EMAT/UTCD is the best detection solution. Re-rounded dents are also more critical where plastic strain exists; this is something conventional DEF and MFL might miss.

Corrosion

MFL - SMFL

Although metal loss is important, the shape and class of corrosion is more critical. That’s because long, narrow and sharp corrosion is more susceptible to crack formation due to hydrogen embrittlement.

Trapped hydrogen

DEF - MFL - LFM - SMFL - EMAT/UTCD

Trapped hydrogen occurs in areas such as mill defects. DEF, MFL, LFM, SMFL and EMAT/ UTCD combined will be able to see defects such as laminations and seam weld anomalies where hydrogen can collect.

Hard spots

DEF - MFL - LFM - SMFL

Combined MFL, SMFL and LFM has already proven the best tool for hard spot detection. It can produce a hardness map permitting prioritization of hard spots in the pipeline.

Blisters

DEF - MFL - LFM - SMFL - EMAT/UTCD

Blisters may form as shallow geometric anomalies but then segregate as they get larger. Although geometry tools (e.g., DEF) might be early indicators, combining with DEF, MFL, SMFL, LFM and EMAT/UTCD will determine the extent of damage.

Hydrogen embrittlement

DEF - MFL - LFM - SMFL - EMAT/UTCD

Hydrogen embrittlement may be seen by the LFM through the change in magnetic response as the steel changes properties. Magnetic technology may also be able to view crack-like features. Pure crack detection combined with DEF, MFL, LFM, SMFL and EMAT/UTCD will provide the whole picture.

Environmental assisted cracking

DEF - MFL - LFM - SMFL - EMAT/UTCD

EMAT is already being used for crack detection; it will be able to see hydrogen induced cracking (HIC).

Fatigue

EMAT/UTCD

EMAT/UTCD is already capable of finding fatigue cracks, making it the best solution for cyclic cracking. Given that fatigue in hydrogen grows 10 times faster than cracks in natural gas, frequent repeat runs are required to assess the formation of new cracks.

High bending strains

XYZ mapping

IMU included on other tool platforms will also be a mandatory requirement to assess line movement, thermal effects and other loadings inducing strain. High strain = high stress = higher potential for crack initiation and growth.

High axial strains

Axial Strain/Stress Sensor

The primary strain in pipelines is in the hoop direction. This can be easily calculated. and IMU can determine bending strains. However, hydrogen does not care about strain direction, so high axial strains may be much more of an issue, especially combined with girth weld material impact of welding.

World Pipelines / OCTOBER 2021

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Geoff Wilkinson, Propipe UK and Chris Loadman, Propipe North America, define a new generation of pig tracking technology.

ow, more than ever, pipeline operators are demanding safe and cost-effective approaches to pipeline maintenance. Pigging operations, in the form of routine cleaning or intelligent pigging for integrity management, require reliable pig tracking data to maximise efficiency. Dependable, accurate, and timely pig tracking data minimises impact to normal operations, as well as minimising the time between any inspection runs and subsequent maintenance on potential defects.

Traditional approach Pipeline pigs are routinely launched and run through pipelines to separate batches, clean and inspect the pipe. There are several reasons why it is critical to always know pig location

during the run. Pigs have a risk of getting stuck and preventing flow; stations and valves often require adjustments to allow the pig to pass; and inspection runs need reference markers deployed along the pipeline as the pig passes. Pig tracking onshore is usually performed by a team of technicians who are responsible for intercepting the pig throughout the run. Pig passage is determined through use of specialist receiving equipment and typically through use of an electromagnetic (EM) transmitter fitted to the pig. In recent years there have been relatively few advances in the communication of pig tracking information to the pipeline operators. Propipe has advanced this technology by providing a system that is designed to enable live remote tracking of pigs over the internet,

real-time streaming access to pre-deployed equipment, and online management of all pig tracking data.

Above ground markers (AGM) Historically, AGMs have been used as the workhorse product for detection of pigs at pre-determined survey locations above onshore pipelines. Traditional AGM products can detect the passage of pigs with permanent magnetic signatures and electromagnetic transmitters. Pig passages are recorded to internal memory and time stamped, and this data

can later be recovered and combined with inspection data to provide accurate positioning of inspection tools to precisely locate any pipeline defects. Tracking pig location in realtime has typically relied on handheld receiver products and geophones deployed by field technicians local to the AGM box. Recovering AGM data, managing true and false passage information, and fusing this data with survey information requires logistical and operational overhead that can be expensive and slow.

Next generation AGM

Figure 1. Propipe APEX.

Propipe’s APEX and accompanying web-based software portal allows pigs to be tracked anywhere in the world where the user has an internet connection and web-browser. Pig tracking reports are built in real-time as live sensor data, real-time passage information and even geophone audio can be streamed to users instantly. The need to download and organise data after a pig run is eliminated through this unique system, which drastically reduces the overhead of managing data from pig runs, this leads to faster and more efficient pigging operations. The APEX is built on a solid foundation of custom hardware and low power electronics. APEX is designed in an all-weather waterproof housing with folding electromagnetic antenna, which makes it easy to travel with, while at the same time provides optimal detection performance.

Detection of pigs

Figure 2. PigView Web – a typical pipeline run.

APEX can simultaneously detect pigs with attached permanent magnets and emissions from up to three different EM transmitter frequencies at the same time, making it useable in the most difficult electromagnetic environments and with multiple pigs. With all pig detection equipment, receivers can be subjected to harsh environments with EM interference that could otherwise be considered a pig passage. To combat this, APEX integrates a combination of temporal and statistical signal processing methods to accurately detect pigs and reject false alarms. In addition, an extremely low noise geophone input is provided with built in variable gain amplifier, so passive detection of pigs through acoustic means is also possible with this AGM. Geophone audio and waveforms can be transmitted in real-time over the internet. Data can then be sent to the end user over several flexible communication channels including cellular, satellite, Bluetooth and WiFi. All data is recorded raw to internal memory and is time stamped with GPS hardware synchronised time.

Web based platform

Figure 3. PigView, Web data streaming and analysis view of a 22 Hz pig passage.

World Pipelines / OCTOBER 2021

To allow for complete remote pig tracking, a dedicated platform (PigView) has been developed to handle and manage all information related to the pigging runs. PigView Web software provides the user with an interface for configuring APEX AGMs, collecting real-time data from APEX devices, storing, and managing historical pig tracking data records as well as managing live real-time pig runs over the internet. Each user has all APEX data and pig run records stored in their own cloud-based database.

PigView Web allows the user to track real-time pig location online. Users can import pipeline survey data (Figure 2), configure SMS and email notifications, and group all pig passage information from deployed AGMs with surveyed locations so that pig tracking reports are produced instantly at the completion of a run. Users and clients can be notified in real-time of pig launch, pig receipt, pig passage information and even updates on pig speed. In addition, a real-time data stream and analysis window is part of the PigView Web package. By enabling a streaming session to a deployed AGM (Figure 3) the user can track a pig over the internet as though they were located on site with a handheld receiver and geophone. Real-time graphs of the raw electromagnetic signal, raw geophone waveforms, processed signal strength, and a spectrogram display of received electromagnetic power vs frequency vs time are given. Real-time geophone audio is also provided and streamed into the web browser, enabling the remote user to listen to the acoustics of a passing pig.

Reliable detection In a recent application in the UK, the value of the multi-sensor detection system within the APEX system was truly realised. Upon launching a cleaning pig, the operator confessed to not installing the EM transmitter within the pig, meaning that only tracking by magnets and geophone would be possible. As the majority of the pipeline was buried in depths greater than 2 m, the geophone would be the primary method for detection. With traditional tracking this would have meant that the teams would need to be deployed to listen locally for pig passages. APEX, however, provides the facility to stream this audio live through the web based software, meaning fully autonomous pig tracking could still be performed.

Enhanced safety As discussed previously, the conventional method of pig tracking is to set up tracking locations and move down the pipeline with the pig. This

Figure 4. APEX deployed at a remote location.

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can be quite a difficult process for the team and will often present difficult and dangerous situations.

Length of pig run Recent projects have had pigging runs spanning over a several days, meaning that both day/night shift crews are required to track the pig. Long hours and working in the dark present safety challenges.

Pig speed For some pipelines, speed control of the pig is unpredictable or subject to change. Therefore, sometimes resulting in the tracking team having to ‘chase the pig’ in order to catch up – which can lead to safety incidents.

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Onshore pipelines can traverse remote locations, leading to these sites being more difficult to access and reducing the time the pig tracking team has to get into position (Figure 4). Utilising the APEX system, the risks outlined above can be significantly reduced by tracking the pig remotely. The pig tracking technicians are only on site when the pigging run is ‘offline’ to deploy the equipment, therefore minimising risk associated with ‘pig chasing’ and also 24 hour working.

Reduced costs Using traditional pig tracking methods that utilise teams of technicians can be expensive and can introduce risk. During remote tracking runs that utilise APEX, a technician is only required to deploy and collect the equipment. The management of the pig run itself is performed online by a single user. All of this results in a reduction of: ) Manpower and therefore cost. ) Vehicles required to transport technicians. ) Environmental footprint.

When using remote tracking methods, the cost savings are not only reflected in reduced technician hours, but also in terms of reduced costs relating to reducing travel, etc. It also eliminates the need for long field shifts and night shifts, making it the safe alternative to traditional tracking. While many pipeline companies still use traditional methods, bestin-class integrity programmes are now leveraging remote pig tracking to reduce cost and increase safety.

Internet based pig tracking The use of Propipe’s APEX internet based pig tracking system has been proven to reduce the costs and risks associated with deployment of pig tracking teams on projects. Furthermore, the live streaming of data has resulted in more accurate and reliable tracking of pigs. When considering projects with long pigging runs or multiple pigging runs concurrently, then the system provides a significant advantage. There may be occasions when traditional methods can still be employed but the future of pig tracking is certainly internet based and APEX is leading the way.

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Morgan Sledd, Stark Solutions, USA, explores a range of closure technologies suitable for different pipeline applications.

he pigging and tracking of inspection tools in pipelines have a variety of technologies and options. These options start, and end, with how to get the tools in and out the pipelines. Quick opening closures can be chosen and configured to help work with the pipeline operators’ needs. The first way to optimise the process is to choose the right closure for the application. The main types of closures include threaded, clamp ring, and internal door. Each type has its own strengths and selecting the correct type can play a part in keeping the pigging operation safe and efficient for everyone involved. Threaded closures like Stark Solutions S-500 are easily identified by the fact the door (commonly called the cap) screws on to the mating portion welded to the pipe (commonly called the hub). The appearance of the cap and hub vary, but generally come with an o-ring seal and some sort of hinging to hold the cap’s weight, when the weight becomes a safety issue. Like most closures, they come with a warning device to prevent the cap from being opened while the closure is under pressure, keeping the operator safe from accidental or unintended pressure release. These closures can be used in applications sized from 2 in. (DN50) through 52 in. (DN1300), in a variety of pressure ranges from full vacuum all the way up to 3705psi (25.5MPag) operating pressure. As the units

increase in size, a variety of options become available. These include additional port openings for valves or sensors, as well as the ability to be specified in horizontal, vertical, or inclined applications. The ease of operation, and the intuitive nature of the opening and closing operations have helped to contribute to the popularity of this type of closure over the many years it’s been in the industry. Also helpful is the often cost-effective nature of this closure’s design, as it has only two pressure parts. These parts are typically low weight as well, compared to the other closure types, making them a favourite in applications where overall project weight is a consideration. Either the cap only, or both components (cap and hub) can be provided with ASME BPVC Section VIII, Div.1 U-stamp should the application require it. While this closure therefore has a very robust design, the threading and unthreading of the unit does require that it is properly maintained with each opening, including greasing of the threads. While this style of closure doesn’t lend itself to stainless steel construction, as the threading and unthreading can gall or damage the threads, with proper preventative operational steps, stainless or alloy materials can be entertained and discussed for quote. Clamp ring closures have a clamp that holds the hub and door components together, as seen on the Stark Solutions S-2000. Once the safety device is properly operated, these

closures often have rapid opening and closing times due to simple latch mechanisms providing the clamping and unclamping action. These closures also have an o-ring seal, allowing for many o-ring materials to be chosen, depending on what the application requires. This closure has a large cross section o-ring to help achieve sealing when the surfaces have small amounts of surface corrosion or pitting. Most often built to ASME B31.8, B31.4, and B31.3 pipeline requirements as a standard, the ability to U-stamp the door exists, as well as the option to have a fully stamped closure should the application require it. These closures are most used in horizontal applications but have been seen in some specialty vertical applications as well. Since they are side hinged, the closure hinging direction needs to be specified. Starting at 4 in. (DN100) in nominal size, and going up to 48 in. (DN1200), the variety of sizes makes them a good choice for most pigging applications. These closures are readily available for pressures ranging from full vacuum to 2220psi (15.3MPag). Having a flat door face, these designs will be heavier than the threaded closures on a size-to-size comparison, but typically have an easier-to-operate singe pivot point hinge that makes opening simpler, and adjustments easy. The flat door provides a large surface for additional port options, and also keeps the overall length of the closure shorter than a threaded closure. Due to the nature of the heavier steel, and the three pressure retaining components (hub, door, clamp), this closure type is generally more expensive than the threaded closure. Unlike the threaded closure, there is no rubbing of components together during the opening and closing cycles, so all acceptable metal varieties can be considered in the quoting process, and most maintenance steps are done externally (no thread greasing). Internal door closures, of which the Stark Solutions S-3000 is one, are characterised by a door that is inserted into the hub, and then a ring or series of ring-segments expand to prevent the door from being removed. Due to the nature of the closure, the doors are slightly smaller than the clamp ring products, but the hubs are larger. The safety devices on these closures are generally an integral part of the ring expanding/ collapsing mechanism to ensure that the ring can’t be disengaged without being made aware of any residual internal pressure. A great benefit to this design is that if the operation mechanism fails, the closure will not open due to the ring still being expanded in place. This is often referred to as a fail-safe

design. To handle the weight of the door and ring, the hinging is usually more robust. The hinging on these units also typically have more than one pivot point, allowing the door to be controlled more easily while being inserted into the hub. The internal door closures are offered with o-ring seals that work well with full vacuum and pressures up to 2220psi (15.3MPag) or with lip seals that work better in higher pressure applications. These closures are ideal in applications where frequent use and high pressures are common. The flat doors provide much the same advantages as the clamp product do with regard to being able to add additional ports. These closures also benefit the job when corrosion resistant materials are requested, as they are robust enough to have weld overlay added easily or can be made completely from the specialty materials. Due to their robustness, these closures are often the heaviest, when compared to the threaded or clamp ring. This design does scale very well, allowing sizes ranging from 6 in. (DN150) up to 84 in. (DN2100) and beyond in pressure from full vacuum to 3705psi (25.5MPag). While they are often seen on filter vessels, these closures also work very well on launcher and receiver lines and can be provided with U-stamped doors or a fully stamped closure. All three closures can be offered already welded onto a flange from the factory, and all can be hydrotested at the factory if required. As standard closures usually are provided with a weld bevel and are welded onto a larger assembly, it’s considered best and most cost effective for the fabricator to perform the hydrotest. Additionally, since the closure is typically welded, customer specific paint jobs are recommended to be done after fabrication but can be done by the factory if required. The reason for this is that the welding process, as well as various handling processes, usually damage the coating. Hydrotesting and special coatings make more sense if the closures are shipping from the manufacturer already welded to a flange of course. Each closure has its own strengths and operational conditions that should be considered when choosing what closure is to be used. It is always recommended to contact the supplier if there are questions, or custom requests, and Stark Solutions has inside and outside sales staff, along with dedicated engineering support, ready to help answer questions or quote to meet project requirements.

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

World Pipelines / OCTOBER 2021

Chris Johnson, Managing Director, SMB Bearings, UK, explains the challenges and opportunities when using drones to monitor and inspect oil and gas pipelines.

bee can travel over five miles and then remember its way home, despite possessing a brain the size of a pinhead. Scientists have been putting them in virtual reality simulators to help improve unmanned aerial vehicle (UAV) or drone technology. While the honey bee currently has the edge, drone technology is catching up. The small UAV market was worth approximately US$2.84 billion in 2019 and is projected to grow to US$11.3 billion by 2027, according to Precedence Research.1 Currently, around 70% of this market is made up from rotary blade type UAVs. For the oil and gas drone service market specifically, ReportLinker has forecast a 60% compound annual growth rate between 2020 and 2025.2

Drones are being employed in a wider range of sectors and for myriad purposes. As a technology that was nurtured by the military, it is no surprise that they are widely used in defence applications. In 2018, they were even used in an attempted assassination of Venezuelan President Nicolas Maduro.3 Less sinister uses of the technology include assisting with policing, fire-fighting, search and rescue missions and delivery of medical supplies in remote locations. The technology has also

spawned a cohort of enthusiastic hobbyists. The nascent sport of drone racing is also rapidly taking off. The further growth and adoption of this technology will be encouraged by consumer market growth, spill overs from the military sector and the possibilities opened up by 5G. The potential for drones to revolutionise the world of maintenance is clear. They certainly pass the ‘D test’: tasks that are dirty, dangerous and dull could all be left to drones. BP, Shell and Exxon have already begun using drones for asset inspection and other tasks. Following an incident in 2008, where Exxon’s use of sonar technology was implicated in the deaths of 100 whales near Madagascar, the company recently used drones to help monitor the locations of whales off the coast of Santa Barbara.4 But what about the benefits for pipelines?

Opportunity in pipelines From Alaska to the Niger Delta, oil pipelines are often located in inhospitable or even dangerous environments. In addition to their vast size, this fact makes maintenance through visual inspection a dangerous task. By handing the task of visual inspection over to drones, human workers are no longer in harm’s way. Improved safety is one of the key benefits being touted by advocates of drone uptake in the oil and gas industry. Making the task of maintenance safer is not the only incentive. Early investors in the technology are seeing significant cost savings. Although it is difficult to quantify the precise saving, research by Roland Berger has estimated that drone-based inspection of oil and gas rigs leads to cost savings of around 90%. The same research estimated that the use of drones has cut maintenance times from eight weeks to five days.5 Calculating the precise costs for pipeline inspection and maintenance is not easy. It will vary from pipeline to pipeline. That’s why many companies begin testing or piloting the use of UAV systems before fully committing to their adoption. However, precise calculations seem superfluous. The bottom line is that drones will provide a more cost-effective alternative to traditional asset inspection methods such as helicopters and ground vehicles. Furthermore, drones are not simply replacing existing methods. Their agility allows them to offer visualisation and data analysis that existing methods cannot compete with. For example, satellites are limited by their orbit and weather can disrupt the accuracy of the images they provide. An engineer would have to assemble scaffolding to physically access a potential problem. Drones, in contrast, can provide thousands of images from every conceivable vantage point, generally unhindered from the restraints imposed by traditional methods. In addition to helping improve safety and cut costs, they also improve the efficiency of asset inspection and maintenance programmes. Scientists now claim that sophisticated sensors are developed enough and small enough to be mounted on UAV systems.6 As well as capturing high resolution visual data, drones can be equipped with other sensors to monitor pipelines, such as thermal imaging or ultrasound inspection.

World Pipelines / OCTOBER 2021

Challenges for take off Given the evident benefits of drone-based asset inspection, what is holding companies back from adopting this technology? One issue is regulation. As with any new technology, there is a struggle for regulators to keep up with the pace of innovation. Companies wanting to adopt this technology must also make sure they understand this evolving regulatory environment. Those that already use aviation, for example with helicopters, are probably in a better position to confront this hurdle due to their existing knowledge of aviation regulation.7 Beyond visual line of sight (BVLOS) is among the most discussed things in the drone industry. This refers to where a drone is operating beyond the pilot’s line of sight. BVLOS activity will be necessary to enjoy the full benefits this technology could offer for asset inspection of pipelines, but in some countries it is not permitted. In the United States, for smaller drones flying below 400 ft above ground level (AGL), BVLOS is currently not permitted without the necessary authorisation from the Federal Aviation Administration (FAA). To navigate around this restriction an FAA waiver is required. According to Geospatial World, 99% of waiver applications fail.8 The restrictions are different when you enter different airspace classifications (those above 400 AGL). Here, operators require either an FAA authorisation or waiver to enter controlled airspace. The necessity of understanding these rules is another obstacle that slows the uptake of drone technology in many commercial applications. For pipelines that traverse national boundaries, these regulatory issues become even more complex. Another consideration many businesses must make is what business model to adopt. In its guidance for the industry, the American Petroleum Industry outlines three alternative models.9 The first model is an ‘internal model’. As the name suggests, this means utilising internal assets, purchasing equipment and training pilots to develop drone capabilities in house. The second, alternative model is an external model. This means outsourcing to a company that specialises in running UAV programmes for this purpose. Although companies would still need to understand operator liability and insurance, this reduces some of the risk and means fewer costs up front. The third option is a hybrid model, containing elements of both. Although the technology is constantly improving, there are limitations that are relevant to their potential for surveying pipelines. The limitations of the batteries that power the vehicles gives rise to range anxiety, a problem that is more significant for pipelines that cover significant distances. It is likely the industry will focus on using drones for inspection of oil rigs and other infrastructure before taking on the challenge of vast pipelines. Another key issue that cannot be overlooked is that of cyber security. Cyber vulnerabilities can impact both the operation of the drones themselves and the data they gather and store. This is another risk factor that has to be properly calculated for any company embarking on the path toward adoption.

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Something to bear in mind If maintenance engineers are to exploit the benefits of UAV technology, keeping the drones in tip-top condition will be essential. Understanding the maintenance needs of these vehicles will be important for those companies who adopt the internal model referred to above. Engineers will need to be quick to acquire fresh expertise in this area. Maintaining and replacing the bearings in drones will be an essential part of this. Many oil installations face significant risks from corrosion. Bearings too, need protection from corrosion. If your drone is operating in an environment where this risk exists, speak to a reputable supplier like SMB Bearings for the best information on bearing choice for your application. 10 In applications where the cost of bearing failure is high, quality precision bearings are required. The bearings for drone motors should offer inherent low noise and vibration characteristics. Many suppliers of drone bearings would offer lifetime lubrication to reduce the risk of accidentally over lubricating or under lubricating your bearings, as this is among the leading causes of bearing failure. Drones and honey bees are becoming more alike. The buzz surrounding drones is only set to grow and their use in monitoring and maintaining oil installations will allow the oil industry to improve worker safety, reduce the time taken to complete key maintenance tasks and realise

substantial cost savings. If you are thinking of adopting an unmanned aerial vehicle programme to monitor your assets, consider the benefits of partnering with a reliable supplier of high quality precision bearings to help keep your drones in the air.

References 1.

2. 3.

9. 10.

Global Newswire (2021) ‘Small UAV market size worth around US$11.3 billion by 2027,’ 6 January, available at: https://www.globenewswire.com/newsrelease/2021/01/06/2154368/0/en/Small-UAV-Market-Size-Worth-AroundUS-11-31-Billion-by-2027.html ReportLinker (2019) Oil and Gas Drone Services Market – Growth, Trends, and Forecast (2019-2024). BBC News (2018) ‘Venezuela President Maduro survives ‘‘drone assassination attempt’’,’ 5 August, available at: https://www.bbc.co.uk/news/world-latinamerica-45073385 ROKER, S. (2016), ‘Exxon Mobil using drones to track whales,’ 13 July, available at: https://www.worldpipelines.com/equipment-and-safety/13072016/ exxon-mobil-using-drones-to-track-whales/ BERGER, R. (2019) ‘Drones: the future of asset inspection,’ available at: https://www.rolandberger.com/de/Insights/Publications/Drones-Thefuture-of-asset-inspection.html ROKER, S. (2017), ‘Scientists advocate the use of drones in monitoring oil and gas pipelines’, World Pipelines, 7 June, available at: https://www. worldpipelines.com/equipment-and-safety/07062017/scientists-advocatethe-use-of-drones-in-monitoring-oil-and-gas-pipelines/ American Petroleum Institute (2019) API Guide to Developing an Unmanned Aircraft System, available at: https://www.api.org/~/media/Files/Policy/ Safety/API-Guide-for-Developing-a-UAS-Program-in-the-Oil-and-NaturalGas-Industry.pdf CHOUDHARY, M. (2019) ‘What is BVLOS and why is it important for drone industry?’ Geospatial World, 11 June, available at: https://www. geospatialworld.net/blogs/what-is-bvlos-and-why-is-it-important-fordrone-industry/ American Petroleum Institude, API Guide. https://www.smbbearings.com/

Dr Aidan O’Donoghue, Pipeline Research Limited, UK, outlines a study examining pipeline pig motion and behaviour in pure hydrogen and hydrocarbon/ hydrogen mixtures.

ydrogen is likely to be one part of a greener future in combination with other green technologies and existing fossil fuels, at least in the near term. Burning hydrogen only produces water vapour and this is an important step in emission reductions. Since hydrogen does not exist in a natural state, how the hydrogen is produced will determine its green credentials – if formed from water or electrolysis, then when using renewable energy, this is close to zero ‘carbon intensity’, whereas if formed from hydrocarbons, it is less than that of the natural gas but certainly not zero.1

Figure 1. Model used for dynamic pigging. The line is 16 in. and is 118 km in length. An inlet flow is provided and the outlet pressure is controlled. The middle graph shows the pig differential pressure along the pipeline (an input file). The nominal pig differential pressure (DP) is 1 bar but with 2.5 bar at river and road crossings due to thicker walled pipe. The pipeline elevation profile is shown on the lower graph.

Transportation of hydrogen efficiently using existing gas infrastructure is an attractive prospect either as 100% hydrogen or in a mix with natural gas. Such pipelines will still require inspection and servicing and as a result pigging will be required. At atmospheric pressure, hydrogen is very light and even at high pressure, the density is much less than that of natural gas. Since pig motion in gas pipelines relies on pressure (or more specifically density) to dampen the motion and keep speed under control, then pig motion in hydrogen lines is likely to be less controlled. Barker provides a good example in his paper of high peak velocities during inspection of hydrogen lines with an MFL (magnetic flux leakage) tool.2 A study has been undertaken and the initial results are published in this paper. Several aspects of pigging in hydrogen have been examined but only velocity and leakage are covered in this article. Wear and material selection are not presented at this stage. Firstly, a description of the pig motion model (PIGLAB) is provided.

Pig motion model

Figure 2. Steady state output with pressure (top), gas velocity (middle) and pipeline elevation profile (bottom).

To determine the gas behaviour upstream and downstream of the pig or indeed with no pig in the system, it is necessary to solve a couple of partial differential equations (PDEs), namely the continuity and momentum equations. These equations couple pressure and gas velocity and allow their variation with distance and time to be calculated. Solving for pressure, p and gas velocity u in space (x) and time (t) enables the behaviour of the gas upstream and downstream of the pig to be determined. Inlet and outlet boundary conditions set the incoming flowrates and pressures for the line but can also change with time. This upstream and downstream pressure around the pig can be determined. An overview of the pipeline in question is as shown in Figure 1. The elevation profile of the line against distance and the pig differential pressure against distance are inputs in the form of a data file.

Cases It is assumed that an ideal mixture of the hydrogen and hydrocarbon gas occurs and that the specific gravity and molecular weight are based on a combination of the gas properties.3 This is a realistic starting point. The base case input for the pipeline is as follows: • 100% hydrogen. • 50 bar outlet pressure. • 500 kg pig mass. • Inlet velocity is 2 m/s and for the sake of this study, the flow is adjusted such that this is the maintained for all cases considered to facilitate comparison. The following cases are then examined using the model: Figure 3. PIGLAB output for the base case 500 kg pig run in 50 bars pure hydrogen. The top graph shows the pig velocity profile along the route. The middle graph shows the pig differential pressure with peaks at the river and road crossings. The lower graph is the line elevation profile.

World Pipelines / OCTOBER 2021

Effect of hydrocarbon content • BASE CASE: 100% hydrogen, 50 bara outlet pressure,

inlet flow of 1 Sm3/sec with 500 kg pig mass. • 75% hydrogen, 25% hydrocarbon gas.

• 50% hydrogen, 50% hydrocarbon gas. • 25% hydrogen, 75% hydrocarbon gas. • 100% hydrocarbon gas.

Effect of pipeline pressure • Reduce outlet pressure from base case to 25 bara. • Increase outlet pressure to 100 bara. • Increase outlet pressure to 150 bara.

Effect of pig mass

In general, the pig velocity remains at approximately 2 m/s for most of the run. This is due to the steady differential pressure. In the real world, small changes in friction could be expected between one spool and the next or at the welds – this could also be included in the model but is omitted at this time for clarity. As the pig enters the tight location (thicker walled pipe) at the road and river crossings, it stalls (for example at kilometre point, KP 53) since additional pressure is required to build up. When sufficient pressure is available,

• Increase pig mass to

1000 kg. • Increase pig mass to

2000 kg.

Use of speed vontrol • Speed control with

speed set to 2.5 m/s peak. • Fixed bypass with 2 x 20 mm bypass ports. The base case output and sensitivities are presented on the following section.

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Output Initially, the model is run to achieve a steady state as an agreed starting point for the analysis. Although transient events are allowed during the pig passage, for comparison’s sake in this analysis, the only transience introduced was the passage of the pig.

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Steady state The graph in Figure 2 shows the steady state velocity and pressure profile along the pipeline route with no pig running in the line. The pipeline elevation profile shows some hilly regions in the latter half of the line but the height is low overall. Note that this profile is with 100% hydrogen.

Base case output Initially, the pig is run with 100% hydrogen and at 50 bara outlet pressure to give a velocity profile to compare other analyses against. The output is shown in Figure 3.

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Effect of hydrogen and hydrocarbon content

Figure 4. Reduction in peak velocity (labelled) at KP 53 as the line is run with increasing hydrocarbon gas content. The hydrogen content results in a less dense gas and less control on the pig speed.

The base case is with 100% hydrogen. A further four cases were examined with reducing hydrogen content and increasing hydrocarbon gas content (mainly methane). All other aspects were kept the same and the flowrate was altered slightly to maintain a nominal 2 m/s flow speed. The output is shown in Figure 4. Hydrogen has a low molecular weight and low density. For example, at 50 bara and 10 degrees C, the density of 100% hydrogen is 4 kg/m3. In comparison, the density of hydrocarbon gas at the same conditions is circa 45 kg/m3. Since the density of the gas acts as a damper to the pig motion, then the dampening is lower with hydrogen and higher velocities are achieved, as can be seen in the graph. The peak velocity in this case is over 13 m/s against a peak with 100% hydrocarbons of 5.6 m/s. If the maximum permitted velocity for the inspection technique is 4 m/s for instance, then the hydrogen case will exceed this for 0.7 km in the output shown compared to 25 m for the hydrocarbon case in Figure 5. For this reason, other steps may be required to get a full and complete inspection of the pipeline to ensure safety.

Effect of pipeline pressure In general, the higher the pipeline pressure, then the more controlled the pig motion. The analysis is repeated with 100% hydrogen but with 25 bara, 50 bara, 100 bara and 150 bara line pressure, as shown in Figure 5. It may be necessary to stipulate a higher minimum operating pressure for pigging with hydrogen. Increasing pressure reduces the peak velocity. Indications are that there will eventually be limited returns with a peak of 7.8 m/s at 100 bara and 6.4 m/s at 150 bara, for example. The lower pressure does give cause for concern. It has also been observed that elevation slope has more effect on velocity at low pressure whereas it is negligible at high pressure.

Effect of pig mass Figure 5. Due to low pressure, the velocity excursions at 25 bara are extreme – up to 21 m/s. Pressure helps to control this with 150 bara reducing the peak to 6.5 m/s. The data is shown at KP 80 this time.

A further sensitivity has been performed using the pig mass. The base case is with a pig mass of 500 kg (a relatively light inspection tool for instance). Two further runs with 1000 kg and 2000 kg have been examined (Figure 6).

the pig moves and once clear of the thick-walled pipe, this additional pressure energy must be dispelled. This is in the form of an acceleration or a velocity excursion. The peak velocity recorded was 13.2 m/s (43.3 ft/sec). For an inspection pig this can mean loss of data and possible damage (to the pig or pipeline). The velocity excursion is marked by a rapid increase in velocity to a peak and then a slower decline back to nominal flow velocity. The peak velocity is a function of line pressure or density – the higher the density, then the lower the peak velocity as it acts as a dampener. The elevation profile has a small impact on the pig velocity but some fluctuations are noted which tie up with steeper inclination, for example from KP 96 to 100.

Use of bypass

World Pipelines / OCTOBER 2021

Since the hydrogen is less dense, there is a possibility of higher leakage or that more gas will pass through than expected with bypass pigging. This presents a possible risk of stalling but also presents an opportunity for speed control. Speed control valves could provide a reasonably efficient way of controlling the speed of the pig even with modest pig differentials. Note that leakage is defined as undesired flow of fluid past the pig, whereas bypass is a desirable or deliberate flow of fluids through the pig. This needs to be weighed against the risk of stalling due to excess flow through the pig (Figure 7). It is not possible to remove the velocity excursion completely, as the acceleration takes the pig to high velocity before any control system has a chance to react.

Nevertheless, the length of time that the pig is above undesirable velocity is reduced using active bypass. The risk is excessive bypass due to the low density of hydrogen. For a modest fixed bypass, the steady state bypass by flow percentage is 50%. This makes the bypass in the road crossing very high (approximately 80% by flow with a subsequent risk of stalling). An equivalent case with 100% hydrocarbon gas would only result in 15% bypass by flow. Care must be taken with leakage and bypass when working in hydrogen, and the next section of this paper suggests how this might be tested.

Leakage past the pig Since hydrogen has a low density, it is possible for it to leak past small gaps and openings. This is especially true for the pig seals – given the differential pressure across the pig, then any small leakage path or weakness in the sealing system can lead to a potential loss of drive. To avoid problems when pigging, it is required to test the pigs to ensure that the leakage paths are not excessive. Since pig testing is normally performed using water, then there is a mismatch given the high density of water compared to low pressure hydrogen. Although testing with gas is possible, it is seen as difficult and expensive and it is not easy to get meaningful results as the test is performed in a closed loop. To overcome this issue during tests, it is recommended to do the following:

Figure 6. Heavier pigs take longer to reach a peak velocity. In this time, the line pressure adjusts and adds dampening making the peak velocity lower than for lighter pigs. The elevation profile of the line makes the heavier pig motion more erratic.

) Leakage with water drive during testing will become

more of an issue at low velocity. A scaling factor can be used to determine the correct velocity with water to mimic the conditions in the actual pipeline. The following is suggested:

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Where:

Vwater, test = Vhydrogen, pipeline ρgas ρwater

Figure 7. Modest fixed bypass can result in a large percentage bypass by flow. Pigs need to seal well for use in hydrogen – to guard against leakage and stalling. The ability to control the pig velocity may be possible with active bypass control (using a control valve and feedback loop).

= =

Equivalent test velocity using water drive. = Expected flow velocity in the hydrogen pipeline. Density of hydrogen in the pipeline. Density of water.

Figure 8 provides an example. Any leakage paths through the pig body during the tests can be eliminated using silicone sealant and capping off bolts once the final pig configuration is determined. Testing should be performed open ended to get a clear view of the front of the pig and assess visually any leakage. The aim should be for no visual leakage (with bypass blocked to assess any leakage). Open ended tests require that any air is vented from the pig launcher prior to commencing the tests. If this is done, then the pig should be under control and can be assessed by photographs, visually and using a video camera. Wear of sealing discs and components may be a root cause of leakage which may not be apparent until the pig is run in the line. Since the hydrogen is expected to be dry and not provide any lubrication for the seals, then this is another aspect that needs to be considered.

Summary

Figure 8. Curve for equivalent water velocity for test against actual expected pigging velocity in the pipeline. For instance, if the pig is expected to move at 3 m/s in a 100 bara hydrogen line, then the tests should be performed at 0.3 m/s or less.

Initial output from a review of pigging in hydrogen pipelines shows that pig motion can be more difficult to control because of the low gas density. Minimum operating pressures may have to be higher or use of tools with lower pig DP and changes in DP (a ‘lighter touch’) would be advantageous. The consequence of increasing hydrogen content produces peak velocity excursions up to three time that of a 100% hydrocarbon line equivalent. This can damage to the tool or the pipeline. An assessment of velocity must be included in any risk evaluation. Higher pressures can aid the situation but may not be possible. Bypass has the potential for reducing tool speed as the lighter hydrogen gas can pass through the pig efficiently. This makes speed control a possibility even on low friction tools. This indicates another problem that needs to be considered carefully. Low density means that gas can leak past the tool and cause the pig to stall in the line. Any bypass through the pig must be carefully engineered and other possible leakage paths eliminated. Testing at low velocity and open ended with water is an effective method to understand the problem and make the pig work as required. Other factors such as wear and material selection required to be understood but are not included in this paper.

References 1. 2.

Figure 9. Still from video of open-ended test showing pig negotiating a bend and leakage through the pig body and bolts. This leakage would be difficult to measure using a flowmeter and pig signallers due to errors.

World Pipelines / OCTOBER 2021

3. 4.

‘Injecting hydrogen into the gas network’, a literature search, UK Health and Safety Executive, RR1047, 2015. ‘HyDeploy: The UK’s First Hydrogen Blending Deployment Project’, Journal of Clean Energy, Vol. 3 Issue 2, June 2019. BARKER, T., TD Williamson, ‘Inline Inspection Tool Design and Assessment of Hydrogen Pipelines’, PPSA Seminar 2020. HASSANPOURYOUZBAND, A., JOONAKI, E., EDLMANN, K., HEINEMANN, N., YANG, J., ‘Thermodynamic and transport properties of hydrogen containing streams’, Nature.com.

In the second of a two part series, Harri Williams, University of Edinburgh, Derek Muckle, Radius Systems Ltd, and Angus McIntosh, SGN, discuss the assessment of polyethylene systems used for hydrogen gas distribution.

n the following article, the results from testing repairability and leak tightness of polyethylene (PE) systems are reported. The investigation provides evidence to support the quantitative risk assessment on the suitability of connecting fittings and welding practices for use in the distribution of hydrogen gas. The construction of a bespoke leak tightness testing facility within a laboratory environment has allowed the safe testing of sample products using pressurised hydrogen gas. Results demonstrate evidence that contemporary PE materials exposed to hydrogen can be repaired, altered and diverted (with connecting joints) with normal industry practices, ensuring the lifetime expectation of at least 50 years is upheld. The work was scoped and funded by SGN, a UK gas distribution company who supplies gas to over 5.9 million customers. The work is essential to support the case for safety for the first of a kind H100 project from SGN who seek to deliver hydrogen produced by renewable energy to 300 homes in Fife, Scotland.

Leak tightness The UK gas distribution networks are currently replacing old ageing metallic gas mains and services to PE as part of the Iron Mains Risk Reduction Replacement Programme. Therefore, ensuring hydrogen gas can be distributed safely with no

adverse effects to contemporary PE materials, connections and fusion types is paramount to decarbonisation of the gas network and ultimately a ‘net-zero’ future. Due to the physical properties of hydrogen being different to methane (the main constituent of natural gas), leak tightness with joints and fittings needs to be investigated. Electrofusion tapping tee saddles (Figure 1) are used to connect the gas distribution main to the service pipe connected to habitable dwellings. They are the most frequently occurring type joints to be proximal to habitable dwellings and therefore pose the most likely prospect to exhibit a leak. An elastomeric sealing ring (present below the top screw cap) (Figure 1) is the primary means of providing a seal from the top of the fitting. The fitting is described in the gas industry specification GIS/PL2-4, which also describes the fittings long term stability for leak tightness. Testing will demonstrate the leak tightness of the fitting with regards to hydrogen gas.

Future connections by welding Polyethylene pipes will undergo alterations and repairs throughout their operational lifetime due to property developments, network diversions and expansions. They will therefore likely be subject to flow-stopping techniques and welding operations. Connecting techniques must be adequately sealing without damaging the structural characteristics of the original PE material. The ability of PE material to perform future connections and repairs using electrofusion welding techniques after the long-term exposure to hydrogen gas was assessed. During repair or connection-welding the primary risks considered were: ) The risk of ignition, charring or blistering of the PE material as a consequence of prior hydrogen saturation. This would pose a direct health and safety risk to the field operative as well as risk damaging PE materials and connections. ) The absorption of hydrogen into PE pipes over time has the

potential to react when future repairs or connections are made. This has been observed during the transportation and subsequent absorption of liquid propane gas (LPG). During subsequent repair, the PE pipe has been shown to swell in the area of welding, due to the reaction of the absorbed gas constituents. This phenomenon has been shown to create defects and resulting areas of slow crack growth development within the welds and connecting areas. This process is regarded as one of the most likely modes of failure within PE pipelines and therefore testing these practices is vital for future asset management.

Methods of assessment Leak tightness Leak tightness testing of the tapping tee fittings is conducted on the fitting closure cap (Figure 1). Leak tightness testing has been conducted in accordance with GIS/PL2-4 leak tightness testing. Three tapping tee cap specimens manufactured by Radius Systems Ltd have been selected from a single production batch. Tapping tee fittings are first installed in accordance with Radius Systems installation instructions. Tapping tee caps are then tightened to a maximum torque of 4 N.m. The fittings are internally pressurised with air at 4 bar for a period of 24 hours. A leak is detected by immersing the fittings at a depth not exceeding 250 mm in a water bath. Any leak, defined as ‘the appearance of a bubble or steam of bubbles from the cap’ is captured with a tube positioned over the bubble source. Leakage volumes are then calculated. Specimens are maintained at a temperature of 23˚C throughout the testing procedure. Tests are then repeated using hydrogen as the pressurising gas. Tapping tee caps are tightened to a torque of 4 N.m and 6 N.m with all other experimental procedures remaining the same. To conduct these tests using hydrogen, a bespoke system has been designed for the tests to be conducted safely in a laboratory environment.

Repairability 63 SDR 11 PE80 pipes were exposed and saturated with hydrogen to replicate the PE conditions in a real-life installation scenario. Industry standard welding techniques such as tapping tee and electrofusion socket fittings for pipe-to-pipe connections were then performed in accordance with supplier installation instructions at laboratory temperatures of 23˚C. A squeeze off operation was held for 1 hour at a temperature of 0˚C (+0/- 5). Reference specimens (not exposed to hydrogen) were also prepared to provide a benchmark for the results. All processes and materials were chosen to represent industry norms in 2018. Stress resistance cracking was then preformed upon the samples to determine if absorbed gas constituents had been introduced into the welding zone, potentially compromising the 50-year asset lifetime expectation. Samples were exposed to accelerated aging techniques by immersion in an 80˚C water bath, in accordance with industry specifications GIS/PL2-2. To gauge short term performance, squeeze off, tapping tee and coupler connection samples were tested at a hoop stress (the tangential stress at the internal wall of the pipe) of 4.5MPa for 165 hours. Tapping tee and coupler connections were also tested at 4.0MPa for 1000 hours, replicating the conditions for the asset lifetime. Samples were then inspected using X-Ray non-destructive examination techniques and dye penetrating techniques.

Preliminary findings Leak tightness

Figure 1. Electrofusion tapping tee saddle fitting.

World Pipelines / OCTOBER 2021

During the first round of testing, pressurising the tapping tee fittings with air at 4 bar pressure showed no evidence of leaking within a 24-hour test period. When repeating the test with hydrogen, all samples showed a leakage volume of approximately 25 mm of hydrogen over a 24 hour test period. The test is designed to

determine the long-term resistance to creep relaxation of the facility has allowed for the accurate detection of hydrogen PE fitting. The 4 N.m of torque used to tighten the tapping tee leakage from tapping tee fittings over a 24 hour test period. caps represents the minimum torque likely to be applied by field Hydrogen appears to have a greater affinity to leakage operatives. This level of torque is considered a conservative number, compare to air. Design solutions such as increasing the level with the minimum amount of torque applied by field operatives of torque applied to tapping tee caps is shown to improve likely to be 1.5 times higher (calculated through ad hoc testing). leak tightness. This will be achieved by the utilisation of When increasing the cap tightness to approximately 6 N.m of torque wrenches. These design solutions will be applied torque, no leakage was evident over the 24 hour test period. Given to hydrogen specific training programmes and installation the hydraulic properties of hydrogen and observed greater mobility, instructions. it is evident that manufacturers testing leak tightness should not use Testing performed within this study gives confidence in the compressed air, but either hydrogen or an inert gas with comparable ability of hydrogen infused PE piping to receive reliable repairs, flow characteristics to that of hydrogen. Modifying assembly alterations and diversions. The results show that no safety procedures to ensure a minimum tightening torque of 6 N.m concerns have been identified with regards to electrofusion (accuracy provided by the use of a torque wrench) provides a means welding and damage and defects to pipe fitting. There is of evidencing leak tightness for hydrogen. evidence shown within this study that pipe alterations through Further safety factors are applied in testing when considering electrofusion welding will not damage the long-term lifetime the pipe operation pressure. The majority of gas distribution expectancy of the PE material. assets operate at pressures of less than 2 bar, with many operating at 75 millibar or less. Reduced service pressures are calculated to significantly reduce leakage rates. Short term leak tightness for Visit vermeer.com/thetrenchereffect to learn more. hydrogen was observed when the cap tightness was increased to a closing torque of 6 N.m. The next stage of assessment is currently underway; the above test is repeated at this new minimum torque tightness (6 N.m.) to determine whether the initially leak tight fitting will subsequently develop a leak due to relaxation of the fitting components over time. To ensure a lifetime expectation of 50 years, the tapping tee fittings are currently being assessed for evidence of leaking due to relaxation over a test period of 2500 hours. This test period is expected to conclude in 3Q21.

Repairability Applying electrofusion welding techniques to hydrogen infused PE80 piping showed no observable evidence of combustion, charring or blistering. Accelerated ageing techniques performed on hydrogen infused fitting assemblages showed no defects had been observed within the samples which had been tested to a 50 year service period. No failure due to slow crack production was observed within any samples.

Conclusion

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Surface Corrosion Consultants Ltd, Northern Ireland, UK, on changing the face of corrosion and inspection management, via new web-based technology.

hard copy reports, which proved almost impossible to track and monitor. The team of entrepreneurs identified a clear gap in the market for a digital solution for recording and saving inspection report data in real-time. Rab Grainger, Surface Corrosion Consultants’ Technical Director, says: “Working with steel fabricators, it was obvious that there was a gap. We use SAM as a matter of course for all the recording of surface preparation and coatings; it is fundamental to our business. “SAM surveys are succinct and to the point and provide a snapshot of each asset at the push of a button. “SAM removes the lengthy process of manual data input and our intuitive software has a fundamental role to play in the future of the energy and construction industries. Survey data needs to be concise, easy to understand, as well as simple to manage and monitor. With SAM, reporting is instantaneous. Continuing with a philosophy of keeping things simple, the inspection of any fabricated steelwork with SAM is one continuous process.

Keeping it simple In the constant drive for efficiency, the app now interfaces directly to Elcometer gauges that are Bluetooth enabled. Using a tablet and Bluetooth technology the coatings inspector and technician digitally records all inspection requirements from NDT onwards including MPI, UT, Visual, environmental readings, DFTs, images and much more in real-time onsite. Reports generated can be adapted and edited to suit the user’s specific requirements. With just a few taps of the screen, all saved readings from the gauge are instantly transferred to the app and synced with no need for manual data entry – just choose which zone the readings are from and the app does the rest. There is no man in the middle to navigate. Every piece of inspection data collected via the web or tablet is instantly saved to secure servers. SAM creates skilfully formatted and concise documentation that is available anytime to download or send direct from the desktop or tablet. Some of the work the app covers include: ) Conditional surveys. ) Campaign and scope management. ) Survey and inspection reviews. ) Analysis and reporting. ) Critical repair management.

Speed and efficiency

Figure 2. Using a tablet and Bluetooth technology, the coatings inspector and technician digitally records all inspection requirements from NDT onwards including MPI, UT, Visual, environmental readings, DFTs, images and much more in realtime onsite.

SAM is available on Android and iOS devices for use in fabrication halls. The user interface is simple to use with clearly defined menus. The app offers data entry efficiency and by using an interactive online system, it reduces the amount of time inspectors spend sitting behind a desk painstakingly inputting data. SAM offers real power in speed and efficiency in four key ways: ) PROTECT – SAM helps to preserve assets. Delivering an expert corrosion and inspection management web-based solution. ) INSPECT – SAM captures MPI, visual and UT survey data in

real-time. Full documentation and a snapshot of an assets’ corrosion is available immediately at the push of a button. ) RECORD – Survey data is concise, easy to understand, and

simple to manage and monitor. With SAM, reporting is instantaneous. ) CONTROL – SAM provides complete control of data for

maintenance planning and scheduling. Clients have optimum control of budgets ensuring funds are correctly allocated where required.

The future of surface corrosion Figure 3. SAM accurately estimates how much material you will need for every project, zone or even single items as well as estimating costs for projects.

World Pipelines / OCTOBER 2021

The benefits of SAM versus traditional methods are: ) Subcontractors use the system ensuring data is always

updated and owned by the owner/operator.

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) SAM is designed to be managed by you or your

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SAM automatically generates dashboards providing insights, intelligence and overviews of all data collected during surveys allowing the user to view scopes in detail and see a clear picture of the critical path ahead. The app can also be used to set priorities which gives the operator the chance to set their own critical repair threshold for the surveyed items. Furthermore, the manning levels can be scrutinised with ease to help assemble the most effective team balance on any project. Data accuracy is assured as data is recorded directly within the device and instantly imported offering improved assurance and accuracy. Rab explains: “SAM is tailored to each individual customer requirement and each user has their own clearly defined roles and responsibilities. Every change made within SAM is timestamped to a known user. The correctly qualified person is then able to verify compliance within their expertise.” The software offers the added benefit of historical data storage to ensure the client’s third-party inspector can confirm each stage in the process or simply verify compliance by load at the end of production. SAM logs coating product, blast media, and all other essential variables for successful and concise reports. The software can generate reports based on user defined selections by asset, zone, structure type, RE values, planned year, dates and items not yet included offering clients the chance to get a better handle on their data. Additionally, the app can accurately estimate how much material you will need for every project, zone or even single items as well as estimating costs for projects. “SAM really is the most versatile and innovative software available on the market today with regards to NDT management and coating inspection. It is a game changer for the future of the management of corrosion in the oil and gas and construction industries.”

ULTRASONIC CRACK INSPECTION Modular design with advanced axial and circumferential crack inspection technology

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World Pipelines October 2021

Articles inside

Game changing surface software

Testing hydrogen pipe repairs

Inline inspection: hydrogen edition

Linking up digital technologies

The buzz around drones

Advanced platform for pig tracking

Pipeline news

24/7 pipeline intelligence

The Greek-Bulgarian connection

Choosing the right closure for the job

Making way for hydrogen