World Pipelines November 2021 Issue

Page 1


Volume 21 Number 11 - November 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.





33. The importance of evolution

Make it strong and keep it secret

SCAIP S.p.A, Italy.

05. Pipeline news With news from Dominion Energy, Optilan, DOF Subsea, and more.

HYDROGEN PIPELINES 37. Making way for hydrogen: part two

REGIONAL REPORTS 08. Hope on the horizon

David Stordeur, T.D. Williamson, Belgium.

SAFETY 42. Staff safety: top of the agenda

The Mediterranean Basin represents a crucial source of natural gas for Europe. Despite ongoing tensions, there is cause for cautious optimism in the region’s pipeline industry, Gordon Cope explains.

Duncan Johns, Managing Director of ION Science, UK.

The Mediterranean Basin represents a crucial source of natural gas for Europe. Despite ongoing tensions, there is cause for cautious optimism in the region’s pipeline industry, Gordon Cope explains.


atural gas is of vital concern to Europe. The continent consumes over 550 billion m3/y, of which Russia supplies around one-third, or 180 billion m3/y. The reasons for the recent, unprecedented spike in prices are numerous, including an unexpected surge in demand, insufficient storage and dwindling domestic supplies, but the over-reliance on one major source dominates the debate. This is why attention will increasingly focus on the Mediterranean. The region has long been a pipeline conduit for energy products from North Africa to Europe, but the discovery of massive natural gas deposits in the eastern sector has fundamentally altered not only the energy landscape, but geopolitical and environmental concerns, as well.

Western Mediterranean For decades, the vast natural resources of North Africa have dominated the energy equation for the Mediterranean. Major gas lines include the 520 km Greenstream line (from Libya to Italy), the 1620 km Maghreb-Europe line (from Algeria to Spain via Morocco), the 2475 km TransMed line (running from Algeria via Tunisia to Sicily and mainland Italy), and the 575 km MedGaz line from Algeria to Spain. Algeria, especially, plays a key role. The North African country’s conventional gas reserves are approximately 140 trillion ft3. Gas production has remained steady at 9 billion ft3/d, the majority of which is shipped to Europe via the TransMed, Maghreb-Europe and Medgaz systems. 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. Although many of Libya’s oil and gas producing assets in the eastern portion of the country have suffered prolonged disruptions during its decade-long civil war, the major fields, pipelines and terminals in western Libya, under control of Tripoli’s Government of National Accord (GNA), have operated relatively unscathed. Italy’s Eni, which is the largest IOC producer in Libya, is 50% owner and operator of Greenstream (which has a name-plate capacity of 8 billion m3). Thanks to military support from the GNA, Eni has been able to maintain exports for the last five years at around 5.6 billion m3, slightly under 10% of Italy’s total gas demand. Since late 2020, when the internationally-coordinated cease-fire agreement between the GNA and General Haftar’s forces in eastern Libya came into place, oil production and exports have stabilised. Eni is pursuing projects to enhance its 320 000 boe/d production in Libya, including the Structures A&E project, designed to enhance gas production at Bahr Essalam. The latter is Libya’s largest gas field, with an estimated 8 trillion ft3 of reserves and 1.1 billion ft3/d of production. Although most new gas will be marked for domestic electricity and industrial needs, political stability in the country will allow for exploration of the country’s immense resources, with the eventual potential to increase exports.

Duncan Johns, Managing Director of ION Science, UK, details the measures managers can take to protect workers on oil and gas pipelines, and how these may change in the future.


rotecting workers is a requirement of any employer or workplace, but when your industry involves hazardous materials, difficult or dangerous working scenarios or risk of exposure to harmful compounds, the stakes are much higher. Worker health, wellbeing and protection are now high priority items for any business, regardless of the potential risk, thanks to legal requirements and advanced industry best practice. In the oil and gas sector, particularly for pipeline management, the risks workers (and potentially the public) can face are often much greater than the average workplace. Serious health issues can result from exposure to harmful chemical compounds, as well as the risk of fire, explosion and oxygen-deficient atmospheres. Ensuring protection and safety is implemented at the highest level possible is paramount. Laws dictate the legal limits and necessary protection, but private companies equally have a responsibility to deliver the best protection for their staff. Oil and gas pipelines are some of the most hazardous places to work, and managing, installing and maintaining them is critical to our infrastructure and economy. Mitigating and reducing the risks workers face through laws, technology, equipment, and training is the best method of creating a safe working environment that understands the risks involved.







13. A region of untapped potential Elfride Covarrubias Villegas, Head of Market Area, Italy & East Med Area, Energy Systems at DNV.


PIPELINE SURVEILLANCE 47. Unlocking aerial data Jeffrey Jones, SkyX’s Vice President, Global Sales and Business Development.

51. Many layers to RTP KEYNOTE 19. How do you prepare for a PHMSA audit?

Girish Babu Nounchi, C.Eng, IGEM-UK, Senior Pipeline Engineer (Saudi Arabia) and Chandragupthan Bahubali, Senior Principal Process Engineer (India), WOOD.

Hilary Cairns and Ryan Lavine, Shea Writing and Training Solutions Inc., USA.

FLOW CONTROL TECHNOLOGIES 24. Machine learning keeps things flowing Dr Yanfeng Liang, Mathematician at TÜV SÜD National Engineering Laboratory, UK.

CONSTRUCTION CHALLENGES 29. ICGB: challenge accepted Kotryna Žukauskaitė, Qapqa, Lithuania.



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ccording to new research, energy employees tend to use very weak passwords. The researchers analysed data from public third-party breaches that affected Fortune 500 companies and then categorised the data by industry sector.1 The top passwords used by energy folks include: password, 123456, pa55word, snowman, 12345, default, password1 and I could go on, but you get the picture. The research concludes that poor password hygiene is causing data breaches in the sector, and that these data breaches are often dangerous and costly. The password research was carried out by NordPass, a password manager technology company, and its advice is to create complex and unique passwords, update them regularly, store them somewhere safe (e.g. a password manager rather than a notebook), use multifactor authentication (for an added layer of security) or a single sign-on system (which promotes using one complex password and not writing it down), and educating employees on the risks of mixing passwords for work and personal accounts. The Colonial Pipeline hack earlier this year was possible because of poor password and cybersecurity practices. Back in June, Colonial Pipeline Chief Executive Joseph Blount told a US Senate committee that the attack occurred using a legacy Virtual Private Network (VPN) system that did not have multifactor authentication in place. That means it could be accessed through a password without a second step such as a text message, a common security safeguard in more recent software. Blount did stress that “in the case of this particular legacy VPN, it only had singlefactor authentication [but] it was a complicated password, I want to be clear on that. It was not a Colonial123-type password.” The password for Colonial’s compromised VPN has been discovered among a batch of passwords leaked on the dark web, which means a Colonial employee might have used the same password on another account that was previously hacked. To access the company’s network, the hacker needed only a compromised username and one password. In the age of working from home, the workforce is especially vulnerable to cyber security

issues. In a short span of time in 2020, as the COVID-19 pandemic set in, global stay-at-home mandates necessitated the deployment of digital tools to allow for remote collaboration and work. Virtual platforms replaced physical work settings, and work processes became remote, decentralised and increasingly self-managed. A blog on the abrupt shift to remote working (published on the LSE Business Review) states that: “The sudden shift to remote work has massively amplified the problem of protecting proprietary information. As companies had to implement remote access technologies fast (or upgrade existing infrastructures) to ensure business continuity, they often fell back on improvisation. This led to the frequent neglect of even the most basic security and compliance protocols.”2 Flashpoints include: the use of personal devices (laptops, phones, etc) for company purposes; remote access software that talks to telecontrol equipment stationed at the office; the movement of entire workstations to homes; the (mis)use of cloud storage; unsecured new devices being used on company networks; lack of security and privacy on home-based devices; and remote setups making the discovery of a cyber breach more difficult. The blog highlights a recent example from Munich, Germany: “The teenage daughter of a CEO of a leading real estate firm used her father’s corporate laptop to surf the web. There, she stumbled over an advertisement for a free IQ test. Curious, she downloaded the software and tested herself. The software, however, brought in a hidden program – a trojan horse – that drained the PC of work-related documents and tried to use the remote connection to the corporate network to infect other PCs in it. Fortunately, the damage could be discovered and limited to the single laptop (which needed a replacement) as the CEO had a direct line to the forensics team.” Three things recommended to all employers by the blog? Identify and then protect important company data. Give access to information on a ‘need-to-know’ basis. Establish state-of-the-art models to track information usage and actively deny suspicious access. And don’t forget to get creative with your passwords.


1. 2.

WORLD NEWS Dominion Energy announces agreement to sell Questar Pipelines Dominion Energy has announced the execution of a definitive agreement to sell Questar Pipelines to Southwest Gas Holdings Inc., in a transaction valued at US$1.975 billion, including the assumption of US$430 million of existing indebtedness. Questar Pipelines consists of FERC-regulated, long-term contracted, transportation and underground storage assets in Utah, Wyoming and Colorado, together with related services and processing entities. The transaction is expected to close in 4Q21, subject to regulatory approvals. Robert M. Blue, Dominion Energy Chair, President and Chief Executive Officer, said: “We are pleased with the result of our sale process for these high-quality assets. This transaction represents another significant step in our evolution as a company, allowing us to focus even more on fulfilling the energy needs of our utility customers and continuing growth of our clean-energy portfolio, including development of the largest offshore wind farm in North America. We appreciate the focus and professionalism of the Questar Pipelines employees, who have maintained safe and reliable operations. We look forward to closure by year’s end.” This announcement does not change Dominion Energy’s

existing financial guidance. Questar Pipelines will continue to be accounted for as discontinued operations. Proceeds from the sale will be used by Dominion Energy to reduce parentlevel debt, including retiring the 364 day term loan that was entered into in July, which Dominion Energy previously used to repay the approximately US$1.3 billion transaction deposit made by Berkshire Hathaway Energy. Proceeds from the sale of Questar Pipelines will also be used to support Dominion Energy’s robust regulated capital plan, as part of the largest regulated decarbonisation opportunity in the country. McGuireWoods LLP served as legal counsel to Dominion Energy. Barclays acted as the company’s financial advisor. Morrison & Foerster advised Southwest Gas Holdings, Inc. in connection with its agreement to acquire Questar Pipeline, consisting of Dominion Energy Questar Pipeline, LLC, its subsidiaries, and certain associated affiliates, including Overthrust Pipeline, White River Hub, and Questar Field Services from Dominion Energy, Inc. The MoFo team advising Southwest Gas Holdings was led by San Francisco corporate partner and global M&A co-chair Brandon C. Parris, together with Palo Alto M&A partner Michael Krigbaum.

Optilan wins new two year BTC crude oil pipeline contract

DOF Subsea and Ocean Floor Geophysics Inc. form strategic alliance

Optilan, a leading telecommunications and security systems integrator, has successfully completed the first year of operation on the BTC pipeline project, resulting in the award of the continued Support and Maintenance contract for the system. The Baku-Tbilisi-Ceyhan Pipeline Company Limited (BTC), a joint venture company whose major shareholder is BP, has awarded Optilan an additional two year contract for Years 2 and 3 Maintenance on the PIDS enhancement project. The pipeline transports crude oil from the Caspian Sea to the Mediterranean Sea. Optilan has partnered with BTC on these assets since 2012, when Optilan was appointed to install enhanced security along the 1076 km Turkey section on the pipeline. The new contract will now focus on long term sustainable collaboration to ensure the effective maintenance of the systems installed, for which safety and efficiency will remain central to execution. This will cover maintenance for the following systems: Pipeline Monitoring, Perimeter Security and CCTV, installed along the Turkey section of the pipeline with Control Centre. Bill Bayliss, Chief Executive Officer of Optilan, commented on the award, “We are exceptionally proud to be awarded the additional work for the BTC pipeline maintenance. Having installed the initial systems, it is great to continue our relationship with our client following the successful results on the project so far and I believe it is a testament of the hard work of our team to achieve this.”

Ocean Floor Geophysics Inc. (OFG) and DOF Subsea AS (DOF) have entered into a strategic alliance for autonomous underwater vehicle (AUV) services to the global offshore industry. The partnership will effectively leverage the two businesses’ recent collaboration in the development of the OFG AUV noncontact integrated Cathodic Protection (iCP) inspection system and enable the sharing of resources on several pipeline inspection and geohazard surveys. It will also provide the framework for a coordinated response to the increasing demand for AUV surveys. Marco Sclocchi, EVP of DOF North America said: “Since our first project together in 2018 to prove the iCP technology on an AUV pipeline inspection survey, we have found that there is a clear alignment between our two companies in performing safe operations and providing the highest quality data in the market. This alliance will also enhance the global footprint of both DOF and OFG through the coordination of asset utilisation enabling us to expand our existing operations.” Matthew Kowalczyk, CEO of OFG added: “DOF Subsea has a proven track record of performing AUV pipeline inspections around the globe and the introduction of iCP into the AUV market removes the final barrier for fully autonomous inspections. We have already worked together to successfully deploy the iCP systems on AUV and ROV projects for major oil and gas operators across three continents and we are excited to continue our work with DOF Subsea to build on this offering.”

NOVEMBER 2021 / World Pipelines



United Energy announces major acquisition update

NEW DATES: 8 - 11 November 2021

United Energy has announced that it has signed a purchase agreement for a 140 mile natural gas pipeline in Wagoner County, Oklahoma, formerly owned by Red Fork Energy. This asset has 140+ miles of 3 to 16 in. transmission lines, including a 12 in. steel pipeline – capacity up to 20 000 ft3/d and comprises 5000+ acres leasehold, and 89 company-owned wells with substantial Woodford Shale development opportunities. Closing is expected in October pending final due diligence. “Natural gas midstream assets are true gems in the current environment. Acquisition of the Wagoner Pipeline also opens numerous opportunities for stranded gas that hasn’t been able to capitalise on current commodity prices,” said Brian Guinn, CEO of United Energy Corporation. In August 2021, UNRG announced the

Abu Dhabi International Petroleum Exhibition & Conference 2021 (ADIPEC) Abu Dhabi, UAE

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

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

acquisition of a strategic asset combination in the Cherokee Basin, located in Northeastern Oklahoma and Southeastern Kansas. The Company purchased Entransco Energy, LLC, serving as the Company’s licensed Operator in Oklahoma and Kansas, adding 250+ Coalbed Methane Gas (CBM) wells, 32 000 acres, 118 miles of pipeline and related oil and gas assets to its portfolio. In addition, UNRG acquired 80 wells and 10 000 acres of CBM-producing wells from Montclair Energy – a project formerly known as ROCCS, the Rogers County Coal Seam Project. The Entransco acquisition also included 49% ownership in an additional 200 000 acres of non-operated oil and gas leases, 2200+ wells and 1000+ miles of natural gas pipelines formerly owned by Constellation Energy Partners and Newfield Exploration.

31 January - 2 February 2022 European Gas Conference (EGC) 2022 Vienna, Austria european-gas-conference/

31 January - 4 February 2022 PPIM 2022 Houston, USA

21 - 22 February 2022 Transportation Oil and Gas Congress 2022 (TOGC 2022) Zurich, Switzerland

7 - 10 March 2022 17th Pipeline Technology Conference Berlin, Germany

10 - 12 May 2022 Canada Gas & LNG Exhibition & Conference Vancouver, Canada


World Pipelines / NOVEMBER 2021

Xodus acquires Ocean Geo Solutions Energy consultancy Xodus has continued its global expansion with the acquisition of Houston-based data interpretation consultancy Ocean Geo Solutions (OGS), adding capabilities in geophysical data processing, interpretation and reporting. OGS assesses seabed and subsurface conditions for hazards ahead of deepwater drilling operations and the installation of pipelines, cables and structures, providing its specialist services to oil and gas operators and offshore wind developers. OGS is well established in the region; 80% of its work is sourced from Houston-based clients, with approximately half of the total projects being international. OGS’ current workforce, including geophysicists, cartographers and support staff will continue to operate out of its Houston office. This includes managers and former owners, Michael Pentland and Andrew Haigh, who bring more than 70 years of combined experience to Xodus. Xodus currently has offices in Houston and Boston in the US. The OGS deal marks an important step in growing the company’s capabilities and services in the Gulf of Mexico with further plans to increase head count in the region over the coming months.


CEPA to cease operations

PRINOTH signs agreement to acquire Jarraff Industries

Global Infrastructure Partners invests in Easton Energy

Michels acquires J.D. Hair & Associates

Tallgrass Energy enters agreement with Project Canary

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The Mediterranean Basin represents a crucial source of natural gas for Europe. Despite ongoing tensions, there is cause for cautious optimism in the region’s pipeline industry, Gordon Cope explains.


atural gas is of vital concern to Europe. The continent consumes over 550 billion m3/y, of which Russia supplies around one-third, or 180 billion m3/y. The reasons for the recent, unprecedented spike in prices are numerous, including an unexpected surge in demand, insufficient storage and dwindling domestic supplies, but the over-reliance on one major source dominates the debate. This is why attention will increasingly focus on the Mediterranean. The region has long been a pipeline conduit for energy products from North Africa to Europe, but the discovery of massive natural gas deposits in the eastern sector has fundamentally altered not only the energy landscape, but geopolitical and environmental concerns, as well.

Western Mediterranean For decades, the vast natural resources of North Africa have dominated the energy equation for the Mediterranean. Major gas lines include the 520 km Greenstream line (from Libya to Italy), the 1620 km Maghreb-Europe line (from Algeria to Spain via Morocco), the 2475 km TransMed line (running from Algeria via Tunisia to Sicily and mainland Italy), and the 575 km MedGaz line from Algeria to Spain. Algeria, especially, plays a key role. The North African country’s conventional gas reserves are approximately 140 trillion ft3. Gas production has remained steady at 9 billion ft3/d, the majority of which is shipped to Europe via the TransMed, Maghreb-Europe and Medgaz systems. 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. Although many of Libya’s oil and gas producing assets in the eastern portion of the country have suffered prolonged disruptions during its decade-long civil war, the major fields, pipelines and terminals in western Libya, under control of Tripoli’s Government of National Accord (GNA), have operated relatively unscathed. Italy’s Eni, which is the largest IOC producer in Libya, is 50% owner and operator of Greenstream (which has a name-plate capacity of 8 billion m3). Thanks to military support from the GNA, Eni has been able to maintain exports for the last five years at around 5.6 billion m3, slightly under 10% of Italy’s total gas demand. Since late 2020, when the internationally-coordinated cease-fire agreement between the GNA and General Haftar’s forces in eastern Libya came into place, oil production and exports have stabilised. Eni is pursuing projects to enhance its 320 000 boe/d production in Libya, including the Structures A&E project, designed to enhance gas production at Bahr Essalam. The latter is Libya’s largest gas field, with an estimated 8 trillion ft3 of reserves and 1.1 billion ft3/d of production. Although most new gas will be marked for domestic electricity and industrial needs, political stability in the country will allow for exploration of the country’s immense resources, with the eventual potential to increase exports.


Eastern Mediterranean Over the last decade, exploration and drilling have uncovered vast natural gas reserves in the Levant. Egypt is home to the supergiant Zohr field, holding an estimate 30 trillion ft3 of non-associated gas. Israel lays claim to the Leviathan field (22 trillion ft3), and Tamar field (10 trillion ft3). Cyprus holds ownership of the Aphrodite field (7 trillion ft3), and the Calypso discovery region (10 trillion ft3). The discoveries have had various impacts in each jurisdiction. Egypt has fundamentally restructured its oil and gas sector, with the potential to become a regional energy hub. ) After its discovery in 2015, the Zohr field was quickly brought into production. Two 30 in. gas lines, each over 200 km long, connect the field to processing plants onshore; by 2019, the field was producing 2.7 billion ft3/d. ) 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 Eastern Gas Mediterranean (EGM) offshore pipeline network (Chevron recently agreed to spend US$225 million to increase the EGM infrastructure). ) In addition to meeting domestic needs, Egypt is looking

to revitalise up to 12 million tpy of LNG exports at its two mothballed trains. BP and Noble Union Fenosa have been examining plans to connect the Idku and Damietta LNG plants with dedicated offshore pipelines.

between the two nations has resulted in civil war, annexations and international sanctions against Russia). Approximately half the volume is expected to be used by Turkey, with the remainder exported to the Balkans and Central Europe. In early 2021, gas from Azerbaijan finally arrived in southern Europe with the completion of the Trans Adriatic Pipeline (TAP). The 880 km line running overland through Greece and Albania and under the Adriatic Sea to the Italian port of San Foca completes the Southern Gas Corridor project that has cost over US$30 billion and been seven years in the making. The Trans Anatolian Pipeline (TANAP), the western leg of the project running through Turkey, and the Trans Caucasus Pipeline (TSP) taps into Azerbaijan’s giant Shah Deniz 2 gas field in the Caspian Sea and runs westward for approximately 3500 km. The line, capable of delivering up to 10 billion m3 to southern Europe, is an alternative to Russian supplies. In June 2021, Malta obtained a derogation (relaxation of a rule of law), that will allow a proposed hydrogen-ready pipeline to be recognised as a project of common interest (PCI) by the European Union (EU). The ruling, which means the project is now eligible for EU funding, is the latest step in a contracted effort by the island-nation for a permanent energy link to the continent. The original proposal called for a 159 km gas pipeline from southern Italy to Malta, but the EU declined aid on the grounds that it was inconsistent with carbon-reduction targets. The €400 million line, which is expected to enter operations by 2024, would help Malta cut shipping vessel emissions by 50%.

Challenges In order to maintain the momentum in gas, Egypt is holding an offshore licensing round for nine blocks in the Eastern Mediterranean and three blocks in the Gulf of Suez, with bidding concluded on 1 August, 2021. Several of the Eastern Mediterranean blocks are near the supergiant Zohr. Other countries are working on large-scale pipeline systems designed to deliver billions of cubic metres of gas to Europe. In January 2020, Greece, Israel and Cyprus signed the final agreement for the Eastern Mediterranean (EastMed) project, a 1900 km gas pipeline designed to connect the participating country’s gas reserves to Europe. The US$6.7 billion line will have a capacity of 10 billion m3/y in the first phase, with the potential to double capacity in the second phase. An FID is expected in 2022, with potential commissioning in 2025. The ROW will start in Cyprus and run to Greece, and then to Italy, running roughly 1200 km offshore, and 600 km onshore. The pipeline has its advantages and disadvantages. The cost versus other sources is relatively high, but it monetises gas in the Leviathan and Aphrodite fields, and provides energy security to Europe by diversifying sources and routes. Turkey opposes EastMed for several reasons; it ignores its rights over natural resources in Cypriot territorial waters, as well as the maritime agreement with Libya to create an exclusive economic zone from Turkey’s Mediterranean shore to Libya’s north shoreline. Turkstream, a 960 km gas pipeline running beneath the Black Sea from Russia to western Turkey, came online in early 2020. The pipeline, with a capacity of over 31 billion m3/y, is designed to bypass the Ukraine (where long-standing animosity


World Pipelines / NOVEMBER 2021

In 2020, the UAE and companies in Israel signed a memorandum of understanding (MOU) to create a new crude supply route to Europe for Middle East oil. The agreement calls for the UAE to deliver oil by tanker to the Red Sea port of Eilat. An existing, under-utilised pipeline controlled by state-owned Europe-Asia Pipeline Company (EAPC) and Israeli-Emirati MED-RED Land Bridge Ltd, connects to the Mediterranean port of Ashkelon, where an estimated tens of millions of tonnes of crude could then be transported by tanker to Europe. Green activists have pointed out that EAPC has a poor environmental track record, and that the project could threaten coral reefs near Eilat. Israel’s Environmental Protection Ministry has put the deal on hold pending further government investigation. COVID-19 and environmental considerations have further delayed the Greece Bulgaria Interconnector (IGP) pipeline. The 182 km pipeline, which would allow Bulgaria to import up to 1 billion m3/y, was originally expected to be in operation by late 2020, but delayed construction-work and additional assessment for a section crossing under a dam have pushed the commission date back into latter 2022. The line connects between the TAP in Greece, and Sofia, Bulgaria. Bulgaria currently meets most of its 3 billion m3/y gas needs through Russia’s Gazprom. The region is a long-standing powder-keg of sectarianrelated animosity. In addition to a civil war in Syria and the subjugation of Lebanon by Iran surrogates, conflicts between Israel and various Arab jurisdictions remain a constant threat to energy infrastructure. In May 2021, Israel ordered Chevron to temporarily shut down operations at the Tamar gas field









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platform after violence between Israel and Gaza flared over a religious dispute regarding holy sites in Jerusalem. Chevron, which purchased Noble Energy and its Israeli holdings in 2020, was not ordered to shut-in the Leviathan field. The region is also replete with overlapping territorial claims. Thanks to Turkey’s general refusal to recognise Greek islands as part of the latter’s sovereignty, the two nations have a series of disagreements over waters in the northern parts of east Mediterranean. In addition, the ongoing diplomatic quarrel over the status of the self-declared Turkish Republic of Northern Cyprus and the government in Nicosia has resulted in clashes over exploration and drilling, which led to a standoff between Turkey, Greece and Cyprus in August 2020. Such aggressive moves by Ankara have pushed Greece, Cyprus and Egypt to strengthen ties and sign formal demarcation agreements to recognise each other’s exclusive economic zones. In addition, Egypt recently organised the Eastern Mediterranean Gas Forum that includes all eastern Mediterranean states and France, while excluding Turkey. The move, which coincides with the escalation of joint military exercises, underlies the importance of France as a major arms supplier to Greece and Egypt, as well as Egypt’s political and economic considerations.

The future Long-term supplies from Algeria are being challenged by several factors. While conventional production remains steady, Sonatrach has been squeezed by falling revenues during the COVID pandemic; funds for maintenance and development, let alone exploration, are in short supply. Domestic consumption is also rising dramatically, chipping away at export capacity. The country has an estimated 710 trillion ft3 of shale gas which could supply up to 2 billion ft3/d of production by 2030, but development efforts are hampered in this parched country by widespread opposition due to the millions of litres of water usage in fracking each well. Not all is doom-and-gloom. In August 2021, Iran announced that it had found an immense deposit of natural gas in its section of the Caspian Sea. The Chalous field is estimated to be the tenth largest gas deposit in the world, and Iranian officials speculate that it could eventually supply 20% of Europe’s gas needs. Such an undertaking would require an immense expansion of existing gas lines, as well as new projects. In conclusion, the growth in new gas deposits in the eastern Mediterranean Sea and adjacent territories offers significant opportunities to diversify Europe’s sources away from Russia. Long-standing regional disputes, however, raise risks and complicate multi-billion dollar projects like EastMed. However, opportunities to monetise gas resources and bolster economies are motivating countries like Egypt to improve diplomatic relations and commercial ties with neighbours in ways few thought possible even a few years ago. The spike in prices will only add urgency. While many significant challenges remain, cautious optimism is on the rise in the pipeline sector of the Mediterranean.

Elfride Covarrubias Villegas, Head of Market Area, Italy & East Med Area, Energy Systems at DNV, details the findings of a report comparing the oil and gas industry in the Eastern Mediterranean region to the rest of the world.


he discovery of huge natural gas reserves in the East Mediterranean in recent years has whetted the appetite of neighbouring countries. Large fields in the region include the Tamar (discovered in 2009) and Leviathan (2010) in Israel; Zohr (2015) in Egypt; and Aphrodite (2012), Calypso (2018) and Glaucus (2019) in Cyprus. Collectively, they hold almost 200 billion m3 of gas, not including yet-to-find resources.1


Whilst the area has the potential to be a gas province of global significance and drive prosperity for the region’s bordering economies in the coming decades, the demand for oil and gas has exacerbated geopolitical tensions and raised scrutiny on the area’s intentions to address climate change. According to numerous news reports, there are growing concerns that the proposed EastMed pipeline linking the Aegean’s enormous gas reserves to Europe, which has won EU backing, could lead to more carbon emissions in one year than the Belchatòw coal-fired power plant in Poland, which is viewed as Europe’s most polluting energy

project. 2 Its aim is to transfer between 9 and 12 billion m 3 a year from offshore gas to be pumped between Israel and Cyprus to Greece, and then on to Italy and other southeastern European countries. As part of DNV’s annual outlook report for the global oil and gas industry: “Turmoil and Transformation: The outlook for the oil and gas industry in 2021” the independent energy expert and assurance provider produced a dedicated East Mediterranean report. 3 This presents an overview of the region’s activity, sentiment on digitalisation and decarbonisation, as well as future investment intentions.

East Mediterranean projects

Figure 1. Comparison of barriers to growth globally and in the East Mediterranean.

DNV’s Energy Transition Outlook estimates that global oil will decline gradually and still supply 16% of world energy in 2050.4 The important question is how the industry in the East Mediterranean can and will respond if demand grows or falls faster – or slower – than expected. With such a diversified industry, and organisations moving in a number of different strategic directions, there is no universal answer; what will be a driver of better prospects for some organisations in the industry, will be a barrier to growth for others. We see signs of this in DNV’s survey findings, where over a quarter (26%) of respondents say that the outlook for oil and gas supply and demand is the factor that most positively influenced their assessment of their own organisation’s prospects for 2021. The global economy and the oil price are the top barriers to growth for East Mediterranean respondents, with concerns around the global economy being significantly higher than globally (Figure 1). DNV’s forecast suggests an increasing pivot away from oil and towards gas. In the survey, 39% of respondents in the region say their organisation is increasing investments in gas projects (compared to 37% globally). The Levant basin has been an explorer’s paradise in the past decade, with giant low-cost gas discoveries. The opportunity to capitalise on these has made the region a magnet for major operators. However, there are challenges around the geopolitical situation and security of supply, which threaten to stall or even block full-scale commercialisation of the region’s resources. Furthermore, any potential investments come with risks, given the uncertainty around gas demand from the EU’s plan to be carbon neutral by 2050.

Connecting the Mediterranean

Figure 2. Industry confidence has fallen dramatically among East Mediterranean respondents, bringing it in line with global sentiment.


World Pipelines / NOVEMBER 2021

Across 1900 km, the EastMed pipeline project will link the gas reserves of the East Mediterranean to Greece, Italy and other South-east European countries. It will have an initial capacity to transport ten billion m 3/y of gas which is expected to be increased to a maximum of 20 billion m3/y in the second phase.5 In May 2021 it was announced that DNV has been appointed for the design appraisal of the front end engineering design (FEED) output




for the offshore and onshore pipeline, and accompanying structures and facilities. The energy ministers of Greece, Israel and Cyprus signed the final agreement for the £5.1 billion project in January 2020 and it is being developed by IGI Poseidon, a 50:50 joint venture between Public Gas Corporation of Greece and Edison International Holding.

The discussion over the economic viability of the EastMed pipeline has taken centre stage since the very beginning of the proposal.6 The ambition of the contentious project is to improve Europe’s energy security by diversifying its routes and sources and providing direct interconnection to the production fields. It will also support the economic development of Cyprus and Greece by providing a stable market for gas exports. Likewise, it will enable the development of gas trading hubs in Greece and Italy and facilitate gas trading in southeast Europe. In July, as part of the groundwork, Greece, Cyprus and Israel leased a research vessel to conduct seismic surveys between Cyprus and Crete, and also between Cyprus and Israel.7 Another major pipeline project is also being considered in Turkey. The country’s Energy and Natural Resources Minister Fatih Donmez, announced in July that it plans to construct 169 km of natural gas pipelines across the seabed at the 250 km 2 Sakarya Gas field in 2022. Discovered in 2020 and located 150 km from the Black Sea coast, reserves were initially announced as 320 billion m 3, and later increased to 405 billion m3 as a second deeper reservoir was located, with Ankara targeting delivering first gas to customers a year later. 8 In June 2021, Turkey’s state oil company unveiled another major deepwater gas discovery in the Black Sea that will be incorporated into its two-phase US$3.6 billion Sakarya gas project. 9 The fresh Amasra find has boosted discovered gas reserves in this frontier play to 540 billion m 3, almost on par with Chevron’s Leviathan gas discovery offshore Israel. Gas from the subsea wells on Sakarya will be sent to an onshore processing plant at Filyos in Zonguldak province via a pair of 155 km pipelines.

Crisis and competition

Figure 3. Green investment intentions differ between those surveyed in East Mediterranean than globally.

There’s no doubt that all oil and gas companies were challenged in 2020. Global demand for products and services had been decimated by the pandemic and the Russia-Saudi Arabia price war forced an oversupply disaster, collapsing prices and pushing US oil into

Figure 4. Compared to its global counterparts, the East Mediterranean is more focused on short-term rather than long-term strategies.


World Pipelines / NOVEMBER 2021

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more focused on the short-term (Figure 4). This is understandable as the pandemic and oil price crash created so many urgent and critical issues. As the crisis subsides, it may well revert to the relatively more even balance reported last year. DNV’s research reveals an industry that is increasingly shifting towards decarbonisation and the energy transition (Figure 5). Some 80% of respondents globally reported that they now plan to increase or maintain investments in renewable energy projects and portfolios in 2021 – up from 71% one year ago. Within that, the proportion that are planning increases (57%) is much higher than last year (44%), and far higher than those planning to finance either oil (21%) or gas (37%) in 2021. Overall, 63% of those respondents in the region are now actively looking for opportunities outside of oil and gas – up from 45% a year ago.

Changing attitudes towards a broader energy mix

Figure 5. The oil and gas industry is shifting towards a greener future.

negative territory for the first time in history. The market crash left the entire oil and gas value chain in disarray. As the year progressed, demand and prices slowly stabilised, but far below the levels at the start of the year. Like other regions, industry confidence has fallen dramatically among East Mediterranean respondents – this number is now close to the global level, after being significantly higher a year ago. Those surveyed are less confident than their peers globally, with 37% stating they were confident about industry growth. This is compared with just 39% globally (Figure 2).

Investing in a greener future The DNV study also shows that focusing growth on the renewables market is a significantly greater priority for oil and gas businesses than decarbonising fossil fuels and/ or operations. However, this is not the case for midstream organisations, where there is bigger emphasis on lowering carbon emissions and operations. Integrated oil companies especially, with operations across the value chain, place more importance in this area going forward. Respondents in the East Mediterranean region are less likely than the global sample to say their business will increase investment in oil projects/portfolios in 2021 (15% versus 21% globally). By contrast, 60% of respondents far more likely to invest in green/decarbonised gas projects/portfolios, compared to 48% globally (Figure 3). Over the past year, there has been a rise in the proportion of respondents saying their organisation is


World Pipelines / NOVEMBER 2021

It is worth noting that gas operations across the East Mediterranean area are intended to grow in the coming years as benefits from the expansion of new gas fields are realised. However, nearly nine in ten respondents in the region believe that the industry needs to develop new operating models to achieve further cost efficiencies, while three-quarters believe cost cutting will be more challenging than ever in 2021 and beyond. With political tensions abounding between the different players in the region, the East Mediterranean is a challenging and turbulent market, albeit one full of potential with trillions of cubic meters of gas to produce. Therefore, according to industry analysts, the prospects for the wide-scale development of the region remain uncertain, with drilling plans on hold, a setback for Lebanon’s fledgling exploration programme and stubborn geopolitical challenges.10 Ultimately, questions remain as to whether neighbouring nations can move past their differences and establish trustworthy supply routes before EU customers become far more exacting on carbon footprint ahead of 2050’s net zero deadline.

References 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Hilary Cairns and Ryan Lavine, Shea Writing and Training Solutions Inc., USA, offer some guidance for companies facing a PHMSA audit, including advice on requirements, preparation, documentation and tips for the day of the visit.


biquitous in the industry, the Pipeline and Hazardous Materials Safety Administration (PHMSA) is a United States Department of Transportation (DOT) agency that is charged with ensuring adequate safety precautions are taken for the transportation of hazardous materials. To help protect the people that rely on pipelines across the US, along with the properties and environments that surround them, PHMSA establishes regulations that govern the construction, operation, maintenance and records affiliated with these pipelines. Companies and their personnel are responsible for knowing and following these safety regulations to ensure that their facilities, documentation and training are ready for auditing at any point, especially since inspections can be conducted at random.

Who undergoes PHMSA audits? Inspections for compliance apply to companies that operate interstate pipelines, intrastate pipelines, LNG and underground natural gas storage. This can include “packaging manufacturers, requalifiers, reconditioners, and certifiers, shippers, freight consolidators and freight forwarders,” according to PHMSA. Every team within these organisations, including their contractors, are subject to participation in an audit: PHMSA views contractors and employees as the same, and does not excuse or overlook infractions that are a result of contractor


involvement in a project. Additionally, projects that cost more than US$10 million will be given priority by the administration.

What is required for a PHMSA audit? Inspectors will ensure that your practices are consistent with current regulations and may assess any element that is published in the regulations, guidance, standards and mandates issued by the organisation. Specific assessments will vary according to elements, such as the pipeline operator’s location, product type, pipeline design and construction materials. In broad strokes, companies should also be prepared for inspectors to evaluate the following aspects of their business.

for operations and increasing requirements for reporting. This new set of regulations is referred to as the ‘Gas Mega Rule,’ and came into effect across the industry 1 July 2020, published in three parts. This initiative is intended to increase the safety of the pipeline infrastructure by requiring companies to meet minimum inspection, reporting and integrity management requirements. Significant areas of focus for the Gas Mega Rule include: ) Outlining the required timelines and processes for reporting incidents, safety concerns and routine inspection data. ) Gathering pipeline material verification information. ) Reconfirming currently documented maximum allowable

Material integrity ) Pipe coating, construction and specification adherence. ) Logs of inspections performed and any findings. ) Defects, damage or corrosive degradation and records of


Personnel qualification ) Covered tasks associated with job responsibilities.

operating pressure (MAOP) and verifying MAOP on previously uninspected segments of pipe. ) Specifying the intervals for required pipeline tests ranging

from seven to 20 years based on the testing method and operation condition relative to the specified minimum yield strength (SMYS) percentage. ) Inspection method requirements and safety

considerations associated with the testing and pressure verification processes.

) Dates of qualification and training for personnel. ) New requirements and definitions for high-consequence ) Records of assessment and qualification methods used.

areas (HCAs) and medium-consequence areas (MCAs) and pipeline types operating in those areas.

Operational documentation ) Company programmes dedicated to integrity

management. ) Clear notification processes and formats for personnel to

report incidents. ) Cyclical assessments of operating pressures relative to

Collectively, these actions will help produce more thorough data on the conditions of pipe across different service areas, including previously ‘grandfathered’ pipelines, providing companies with a more complete picture of the material integrity and safety risks associated with each line.

How do you prepare for a PHMSA audit?

pipeline conditions.

Proper personnel orientation

Changes to requirements from PHMSA’s Gas Mega Rule Pipeline infrastructure in the US consists of millions of miles of pipe, with some core components now more than 80 years old. As technologies and techniques for development have advanced, many of these older components have fallen behind their original operational capabilities and are unable to meet the demands of a more expansive, modern pipeline network. The consequences of this discrepancy have become increasingly apparent over the last decade, resulting in incidents such as containment leaks both above and below ground, ensuing fires, and explosions that have produced hundreds of casualties and billions of dollars in damage. In response to these series of incidents, PHMSA has amended the existing federal Pipeline Safety Standard (49 CFR Parts 191 and 192) for gas transmission and gathering pipelines to improve pipeline safety by changing regulations


World Pipelines / NOVEMBER 2021

Every employee and contractor should take steps to follow guidelines and regulations continuously. This includes building an operator qualification programme in line with PHMSA’s specifications to ensure that personnel are competent and capable in their designated roles. Additionally, companies should facilitate proper training and information distribution when systems are updated, operations are modified or regulatory changes occur (such as the Gas Mega Rule). By the day of an audit, operators and contractors should routinely perform at a level that meets regulatory standards. When a PHMSA inspector visits your site, you must understand the inspector’s schedule, plan to deliver a safety orientation and provide the inspector with any current information about the operational status. All employees should be polite, but conversation between employees and the inspector should be kept to the questions asked during the audit. However, companies should also instruct their

employees to be truthful. Misrepresentation or mistakes can lead to misunderstandings. If a team member does not understand a question or doesn’t know the answer, the reply should be that they do not know, and they should direct the auditor to someone who does. Auditors should also be informed of any personal protective equipment (PPE) requirements particular to the area, equipment, or products they are inspecting. If a PHMSA audit happens at random, a contractor should contact the operator to facilitate this orientation and deliver any specific information, as needed. Clear communication between employees, management and PHMSA is key to a successful audit.

) Hydrotest records.

Mock audits

) Qualifications.

One of the best ways to ensure your company and employees are ready for any audits is to hold a mock audit. The mock inspector should be experienced in the industry, knowledgeable of the PHMSA regulations and intentionally check all the areas that could be assessed during a live inspection. In addition to reviewing material compliance, the mock auditor should practice assessing employees in the same manner so that if there are any issues regarding employees, safety or quality, they can be resolved immediately. Mock audits should be performed regularly in-person to ensure that operational site procedures are always in a state of readiness. Another best practice is to conduct the audit using current references and procedures issued by your company. This ensures that employees and contractors are following requirements and exposes any shortcomings in personnel performance or outdated procedures that do not align with real-world practices.

Documentation Documented procedures, policies and user guides can make a profound difference in routine safety practices and operational productivity. Employees should be able to look up information using on-site and/or online resources at any point for daily work, questions, quality concerns or safety issues. There should also be clear records of any safety or quality violations and subsequent investigations to ensure your company can demonstrate its awareness and actions taken to prevent similar incidents in the future. In addition to these day-to-day procedures and manuals, some documentation your organisation should have on hand, especially for an audit, include: ) Certifications.

) Incident reports. ) Inspection reports. ) Job procedures. ) Material lists. ) Operational procedures. ) Public awareness plans.

) Safety plans. ) Training procedures.

The importance of documentation during audits cannot be understated. Proper records will allow your organisation to demonstrate procedures the inspector may seek to assess during their visit; there will be profoundly fewer inaccurate or incomplete responses when the operation is supported by written procedures, policies and guidelines. Many of these records, procedures, plans and reports are necessary to meet compliance requirements – failing to have them available at the time of an audit could result in a failure and consequential fine.

What are the consequences of a failed audit? If a PHMSA inspector sees a dangerous situation on your site, it will be flagged. Any concerns brought up during the audit should be communicated to the operator, and corrective actions should be taken. Generally, the inspector and PHMSA will focus on building outreach and education strategies to help ensure compliance is met if there were any errors or concerns. However, in some cases, there could be civil penalties. A civil penalty can be proposed after being presented to the PHMSA’s Office of Chief Council. Training violations, for example, could result in the minimum civil penalty of US$450, and the maximum for any violation is US$75 000. A company can respond by paying the penalty or providing further information or records that can be used to overturn the decision.

Summary ) Coating reports. ) Construction drawings. ) Damage prevention plans. ) Drug and alcohol policies. ) Emergency response procedures.


World Pipelines / NOVEMBER 2021

PHMSA helps to ensure that organisations are following regulations that support public safety. These regulations grow and respond to trends in the industry, and maintaining a current understanding of their requirements is crucial to daily operational conduct. Preparation is essential to performing well on any PHMSA audit, which can be achieved by having informed, well-trained employees and contractors with the resources and communication tools they need to demonstrate compliance.

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Dr Yanfeng Liang, Mathematician at TÜV SÜD National Engineering Laboratory, UK, profiles using machine learning models to predict flowmeter installation error type.


very day, vast amounts of data are generated across different sectors, containing valuable information that could aid businesses in their operational and strategical decision-making. In order to unlock and extract the value that lies within data, advanced modelling techniques such as machine learning models have become increasingly important, where information such as the condition of instruments, fault detection and diagnosis, and a forecast of future performance based on historical trends, can be obtained. Flowmeters, such as ultrasonic flowmeters (USMs), are capable of outputting digital data sets with the potential to be used for diagnostic purposes to indicate device performance and installation conditions. To maintain their accuracy and reliability, flowmeters are typically calibrated and maintained under fixed time-intervals, for example once every year; this is known as time-based monitoring. However, this type of calibration procedure is a crude method, neglecting many important factors, such as frequency of usage and operational conditions, that can directly impact the health of flowmeters and instrumentation. Failure to consider these factors can result in wasted time and money through unnecessary maintenance on flowmeters that are performing well, while neglecting those which require earlier inspection due to their operating in harsher environments. Advanced modelling techniques offer an opportunity to develop the next generation of flowmeter calibration and maintenance methods, by making better use of their diagnostic data to infer



the current condition of the meter; this is known as condition-based monitoring. TÜV SÜD National Engineering Laboratory holds the UK’s national standard for measurement for density and flow. Over the years, our data acquisition systems have logged and archived 20 years’ worth of data detailing various flowmeters’ performance, test facility configuration and operating conditions. It was observed that any potential flow measurement errors are usually manifested as drifts from baseline values. However, rectification actions are often delayed due to the inability to identify the error responsible for the drift. This is because different types of error can induce the same drift within the same diagnostic variables. Therefore, despite end-users being made aware of a potential problem, they are unable to pinpoint the most likely cause of error. This challenge is described visually in Figure 1. Using basic observational diagnostic assessments, it is difficult to distinguish between different errors. This could severely impact the operational efficiency of the facility and therefore increase the cost of operation for end-users. To correctly identify the potential cause of error, we cannot simply rely on one single variable; a combination of variables must be considered and as there often exists multiple interrelationships between variables, this requires advanced statistical analysis. To demonstrate the capability of using machine learning models to overcome the ambiguity challenge represented in Figure 1, a case study was conducted within TÜV SÜD National Engineering Laboratory, whereby a machine learning model was built and used to predict, with high confidence, the type of installation error that was responsible for the drifts seen in different diagnostic variables.

Case study: using machine learning models to predict the types of installation error in a USM In this case study, a USM was deliberately installed in four different configurations: ideal installation set-up as instructed by the meter manufacturer, vertical misalignment, horizontal misalignment, and step change.

Vertical misalignment and horizontal misalignment were achieved by deliberately using smaller bolts to connect the meter to the upstream pipe, causing the meters to misalign in a vertical or horizontal orientation. Step change error was induced by changing the line build which, due to the difference in pipe thickness, caused a small expansion in the pipe internals. Data was collected under each operating condition, where 70% of the data was used to build and train a machine learning model to learn the patterns, trends and correlations in variables when the USM was exposed to different installation set-ups. The remaining 30% of the data was then used to test the model’s prediction capability. When building a machine learning model, it is a common procedure to split the data into training data and validation data, to tune and verify the performance of the model. Based on the training data, the model had an error rate of 4.32% in predicting the correct installation condition responsible for the drifts seen in diagnostic variables, and an accuracy rate of 90.32% when testing with the validation data. To mimic the situation where we wish to use the model to predict the most likely cause of drifts, four different sets of data were set aside with the error condition unknown to the model, known as unseen data sets. The prediction results are given in Figure 2, where the x-axis denotes the four types of installation set-up and the y-axis denotes the probability or the likelihood of the stated condition to be the cause of patterns and drifts seen in data. For example, for Unseen Data 1, based on the trends and patterns detected within the diagnostic variables, the model predicted with a probability of 0.9933 that this data set was gathered when the USM was installed in the ideal set-up as instructed by the meter manufacturer. This is the correct prediction; this USM was operated with no underlying error and no further action is required. However, for Unseen Data 2, the model predicted with a probability of 0.8989 that this data set was most likely gathered when the USM was installed incorrectly (specifically vertical misalignment). In addition, the model had also predicted that the likelihood of this particular data to be collected when the USM was installed in other configurations to be highly unlikely. This is the correct prediction, enabling end-users to intervene and rectify the problem promptly. Similar interpretations can be made on the other unseen data sets, where results have the potential to improve end-users’ fault diagnosis and decisionmaking processes by pinpointing, with high certainty and confidence, the exact cause of drifts in diagnostic variables.

Using machine learning models to determine the significance and roles of variables

Figure 1. The challenge of determining the cause of drifts in diagnostic variables.


World Pipelines / NOVEMBER 2021

The data used to train and build the machine learning model contained 11 different diagnostic variables, where in practice, flowmeters can produce hundreds of different diagnostic variables, each containing different levels of information.

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affected variables under a specific condition or error, providing end-users with confidence on the role of each variable. For this case study, an additional modelling result was obtained which indicated which variables were the most crucial in identifying different installation conditions. Figure 3 presents the five most important variables in determining and distinguishing between the four installation set-ups, where the most important variable is listed at the top. The order of importance is based on how much prediction accuracy the model would lose if the said variable was removed. For example, if the variable Figure 2. Case study – USM prediction results from machine learning algorithm. “average speed of sound” was omitted in the modelling process, then the model’s mean prediction accuracy would decrease by approximately 66%, followed by a decrease of around 38% if the variable “symmetry” was omitted in the modelling algorithm. The more accuracy the model loses, then the more important that variable is to the prediction algorithm. By identifying the most important variables, end-users can focus on changes in key variables if they wish to identify if there are any specific installation related errors. Through the use of machine learning models like the one illustrated in this case study, end-users can identify and pinpoint with greater certainty, the most likely reasons for Figure 3. The most important variables in distinguishing different drifts seen in different diagnostic variables. In addition, such installation conditions in the case study. models can improve end-users’ understanding of the roles of variables under different operating conditions. For end-users who do not possess the necessary knowledge Results from advanced data-driven models can and experience in flow measurement, it is challenging enable condition-based monitoring to replace the to determine which variables are the most significant in less efficient time-based monitoring. It is important different operating conditions. to point out that each flowmeter has its own unique The accuracy of the model can sometimes be improved properties and different operating principles, where in further by reducing the number of variables; with previous studies, we have found that even the same fewer patterns and trends to learn, and less misleading type of flowmeter produced by different manufacturers, and confusing information, the model accuracy can be performed differently under the same operating enhanced. However, the ability to determine and decide conditions. Consequently, prediction results gathered which variables can be eliminated is difficult and often from one flowmeter type and manufacturer should not be requires expert input. In addition, the role of variables might generalised and applied to other flowmeters. At present, change depending on the operating conditions. For example, research being undertaken by the Digital Services Team Variable A might play a significant role in distinguishing at TÜV SÜD National Engineering Laboratory is focused between installation errors, but it might perform poorly in on creating a more generalised, reliable model, as well distinguishing erosion-related errors. as further enhancing our understanding of the effect of Machine learning models can be used to overcome different factors and operating conditions on different some of the described challenges, by highlighting the most flowmeters.


World Pipelines / NOVEMBER 2021

Kotryna Žukauskaitė, Qapqa, Lithuania, details the collaboration involved in the challenging construction of the Gas Interconnector Greece-Bulgaria (ICGB).


he Gas Interconnector Greece-Bulgaria gas pipeline (ICGB) is a 182 km long strategic pipeline project that will run from Komotini, Northeastern Greece, to Stara Zagora in Bulgaria. Interconnector project’s main contractor is the Greek company AVAX. ICGB is planned to be linked with the Trans-Adriatic Pipeline (TAP) route, offering Bulgaria and the wider Southeast European region access to Caspian gas as well as LNG. The project is a key part of the strategy

for greater integration of gas markets, which includes interconnection projects from Bulgaria – Greece, Bulgaria – Romania, Bulgaria – Serbia, and Romania – Hungary.

Cooperation between DS-1 and Qapqa DS-1 is a company specialising in all type of welding work for the international scope. Three years ago this fast-growing company had their first interconnector project, the so-called Baltic-connector, bridging from Estonia to Finland. The DS-1 team was responsible for

Figure 1. Automatic welding continues during Bulgarian winter. Photo taken by Qapqa technician Ferdinando Carnovale. Kardzali, Bulgaria.


automatic welding of onshore sections of pipeline as well as the construction of a complete cathodic protection system. A year later, they began working on the second interconnecting unit at the Gas Interconnection PolandLithuania (GIPL) project. Complete construction of a cathodic protection system for the pipeline as well as part of complete pipeline works was executed there. Such pace brought the company to a new level of distinguished expediency that built up their goals in the European market. Now the highest expectations are pointed towards Poland, where the company recently added local welding certificates and can perform full gas pipeline construction. For more than 25 years Qapqa has operated around the world. The family-owned company has rapidly developed itself, currently operating in more than 80 countries, as a trusted partner to pipeline contractors. It develops and manufactures automatic pipe welding equipment for both pipeline construction and fabrication applications. The PWT Auto XCS welding system allows contractors around the world to work independently, generating high quality welds

Figure 2. Start-up of new pipeline section at ICGB. Photo taken by automatic welding supervisor Lukas Sabaliauskas. Kirkovo, Bulgaria.

Figure 3. Early morning PWT Auto XCS automatic welding spread in action. Photo made by automatic welding supervisor Lukas Sabaliauskas. Stara Zagora, Bulgaria.


World Pipelines / NOVEMBER 2021

with excellent productivity and in the most challenging circumstances.

The challenge The ICGB pipeline is a demanding project, taking place in an environment where technical performance needed to be maintained in the face of challenging conditions. Carrying out operations in the steepest parts of the range, hybrid welding was being done in trenches. While the land itself was a true challenge, from flooding flatlands to a chain of scarps, the climate also added extra pressure. The extreme weather conditions, with temperatures from 45˚C to -20˚C, were followed by rain, flooding and snow, changing weekly. A team of multifunctional welding professionals had to face the most difficult changes. Surely, one of the crucial hardships at the start and during the project was the COVID-19 pandemic, which came with the consequence of international quarantine rules and the apprehension of a new reality. The progress of the ICGB project was at risk as many workers needing to regularly enter and exit Bulgaria were forced to quarantine, each time, for days. Unity in different departments and fields of knowledge had to be inspired and taken care of every single day due to the disruption and uncertainty. Constant testing and extra precautions had resulted in a minimum infection rate in the DS-1 team. As well, teams’ responsibility and deliberation resulted in 0 incidents for 3840 hours spent on the construction site. Managing the crew and equipment during these changes, and in these challenging situations, brought the DS-1 team to a new level. Constant qualification lifting and training paid off over and above while experiencing it all in real life. Successful management of such events was also a consequence of a long-lasting theoretical preparation that began in early 2020, back at the HQ of DS-1. Planning and simulations led to a solid technical foundation of the musthave tech solutions. “We are glad to be the ones who took care of the Bulgarian section, with top notch partner MAATS, who really went the extra mile and gave us all the support possible. As well our goal of efficiency could not be reached without the expertise of our partner – Qapqa,” said Tomas Jankauskas, International Project Manager at DS-1. For fully automatic welding, DS-1 teamed up with Qapqa in the Netherlands as they provide technological automatic welding solutions and support on pipeline projects. The PWT Auto XCS was used for maximum efficiency that reached around 1000 welds a month. Manual and hybrid welding were used in most difficult parts of the terrain having it done in trenches. In total DS-1 had 10 teams at once applying different welding types. All the missing engineering machinery was promptly provided by partner MAATS.

The team A team of qualified experts, still continuing work with ICGB, are focused on finishing the last welding works. Even

though the project was extreme and difficult at many levels, they have managed to fulfil the goals in a timely manner. “Teams have spent around a year already producing a historical construction to our company that meets the highest international quality requirements in a harsh environment. We are proud to have spent a considerable amount of time preparing and rethinking the possible challenges, as it made us stronger as a team and ready for the construction works at the Bulgarian side. Sure, our ‘legions of legends’, as we called them, were under hard conditions, but every question and challenge was solved in minutes due to advanced technical preparation and great partners. And surely, working in such picturesque surrounding makes every rest minute fulfilled with the great beauty of a sublime landscape – one that challenges and nurtures us,” added Jankauskas.

Technical details The automatic welding equipment used on the ICGB pipeline project is the Qapqa PWT Auto XCS welding system. ) Root-pass was welded by using the advanced root-pass welding process, fully automatic without the use of copper backing shoes. Copper backing for root-pass welding was prohibited on this project as it is on most gas pipeline construction projects in Europe. ) Fill and cap passes were welded by the advanced welding

pulse process, using an extreme high pulse which increases the deposition rate in combination with a 1.2 mm solid

welding wire. Even though a high pulse process is used, the heat input remains low. The above-mentioned welding processes are used on a closed butt joint, J-bevel pipe-end preparation with only a 5˚ bevel angle, which makes the total time loop per joint extremely fast and efficient. The choice for this new advanced welding technology was to reduce the quantity of machinery and manpower significantly, compared to manual welding or compared to semi-automatic root-pass welding process in combination with mechanised flux cored arc welding process for the fill and cap passes. “Our next level automatic welding solution provides a technological step forward for many pipeline contractors around the world. The excellent cooperation between both companies formed the basis of successful completion of the automatic welding works of this challenging pipeline project,” said Ralph Wijnholds, CEO at Qapqa.

Conclusion As the highest expectations are being delivered and the construction is at its final stage, sub-contractor DS-1 can put a tick in their bucket list and keep on working in these challenging times. The Gas Interconnector Greece-Bulgaria pipeline has been a great experience and international trust builder that also allowed an innovative and fast-growing company to continue its tech evolution, and focus on advanced solutions in other Europe-based gas piping projects.

SCAIP S.p.A, Italy, discusses how the company’s padding machine line has been improved over the course of two decades.


CAIP S.p.A is an Italian OEM manufacturer that has been designing and producing heavy machinery and equipment for over 60 years. The company was founded in 1958 as a service, maintenance, and repair shop for agricultural machines, specialising in crawler machines usually branded FIAT. As a result of the knowledge and know-how gathered by the firm in the heavy equipment machinery sector, partnerships with large Italian infrastructure construction companies emerged starting in the 1970s. These partnerships with large EPC companies such as SAIPEM and SICIM led SCAIP to begin manufacturing custom machinery and equipment, especially for the construction of pipelines. After years of experience obtained in this sector through these partnerships, SCAIP then began in the early 1990s to develop and engineer its own line of machinery aimed at the construction of pipelines. The first machines made by SCAIP that had been fully designed and manufactured in-house were the pipe bending machines available to the market by 1991. This was quickly followed by the conversion kits that SCAIP started offering in 1992 to convert regular mechanically winched pipelayers into hydraulic winch powered pipelayers, a product that increased SCAIP’s brand reputation and recognition significantly. To date, over 1000 of these kits have been fabricated and installed by SCAIP, demonstrating the popularity of the product. Another product fully developed, designed and manufactured in-house are the padding machines which SCAIP started manufacturing in the late 1990s. These introduced a new machine design compared to the standard in the industry, also proving to be a success


amongst the company’s customers. Throughout the following years of the late 1990s and early 2000s, SCAIP produced a full line of custom pipeline construction machinery, including their own design of pipelayers, pipe carriers and flatbed tractors. Heavy equipment used in pipeline construction such as internal line up clamps, beveling machines, padding buckets and vacuum lifts were also designed, developed, and manufactured in-house.

Figure 1. SPD 350 in Texas, USA.

Figure 2. SPD-350 EHD in New Mexico, USA.


World Pipelines / NOVEMBER 2021

Since the initial design of each new product line, SCAIP has constantly been revising and updating their design, always striving to achieve better performance and efficiency. On average, 10% of the company’s revenue is reinvested in research and development of the product lines. Such investments in improvements can be clearly seen when looking at the evolution of SCAIP’s padding machines. The product line began in 1997 with the first padding machine called the SPD-45. After some design changes and improvements, the original SPD-350 padding machine was constructed in 2002 and first put to work on a project in Russia before being sent to the US. This initial machine did not include a cabin and had a simple platform where the operator controls were located. The machine utilised pilot operated controls and a 3306 Caterpillar engine along with the original design of the escalator system. SCAIP’s first padding machine opened a new pathway for greatly improved padding machines over the past two decades. Since the first SCAIP padding machine, several technological advancements have been accomplished. The SPD-250/350/450 models now include a greatly improved cabin with ROPS/ FOPS for operator safety. The cabins are air conditioned and heated for the operator’s comfort. An ergonomic seat is also included whereby the operator is able to sit down and operate the machine compared to standing all day as with the previous models. Hydraulic functions have progressed to electrical displacement control and electric components from the previous hydraulic pilot controls. This particularly allows for the operator to control most functions with the use of only two joysticks compared to the multiple handles of the previous models. Another huge SCAIP improvement targets the cabin. The cabin can now raise up and down to allow for transportation of the machine without removal of the top cabin section, as with earlier models of the padding machine. The new style cabin can also be rotated 90˚ when in operation mode to allow the operator full view of the pipe and padding operation, regardless of whether the machine is being utilised on the backfill or ROW side of the trench.

Respective of safety considerations, SCAIP has now included in almost all parts of the world, and in all types of terrain and an ergonomic remote control system on all of the padding weather conditions, SCAIP has focused on further developing machine models. This allows the operator to safely control the international sales in recent years. Another of the company’s machine in adverse conditions where it may be safer to conduct goals is to establish a strong world-wide presence to facilitate operations from the ground. All machine functions can be the maintenance and support, as well as the world-wide sales controlled by the operator from the remote control. Emergency of the machinery. One of the first steps taken to achieve this stop buttons are located on the machine and in the cabin along was establishing a daughter company to take care of the large with one on the remote control. Another safety feature on the and strong North American market. This can also be seen with new machines is cameras that are installed on the machine to the addition of new dealers and distributors around the world assist the operator in observing critical areas of the machine. The such as Cross Country Infrastructure Services and the latest new padding machines with cabins include a digital screen installed in distributorship gained in Australia. SCAIP has recently decided to the cabin for observations of these critical areas. partner with Pipeline Equipment Rentals based in Perth, Australia, In recent years, SCAIP has added the SPD-160 and the to better cover the Australian market. SPD-150 to the padding machine model lineup. The SPD-160 is remote controlled only and does not have a cabin. This machine is not self-loading and requires an excavator to feed material to the separating system. The SPD-150 is also remote controlled and has a greatly improved escalator system since the first machines that were constructed in 2012. Since the first padding machine was constructed in 1997, SCAIP has produced over 170 units of this equipment line, illustrating the success and customer satisfaction with SCAIP’s padding machines. One of SCAIP’s newer goals has been to enter other markets apart from pipeline construction and agriculture. Some of the machines can and have been used in different applications other than pipeline construction. The SPD padding machines are a great example as they have been sold and used for projects such as solar or wind farm construction, general material separation for infrastructure projects and beach cleaning. Another product that has been extensively used in other construction industry sectors has been the line of flatbed tractors. These versatile vehicles have been used for the haulage of MEET THE PCRX materials and equipment to harder to reach locations, in solar and wind construction projects, as well as for Expanding on our industry-leading decoupler drilling applications. This goal has designs, the PCRX’s new camouflage been portrayed in SCAIP’s most recent technology uses sophisticated solid-state distributor contract signed with TA power electronics to deliver fast, accurate Drilling, a UK based company that readings during interrupted survey testing. focuses on drilling services. Even though SCAIP machines have already been sold and sent to operate

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Part one of this two-part series looked at how to clean and assess existing pipelines to ensure they’re ready for the transition to hydrogen. Here, David Stordeur, T.D. Williamson, Belgium, discusses how intervention and isolation can support the transition during the repair, transformation or extension of new and existing networks.


he promise of hydrogen as a clean future fuel depends in no small part on pipelines. Plans to build hydrogen infrastructure are underway, but that will take considerable time and money. The conversion of existing natural gas pipelines for pure or blended hydrogen service is a faster, more efficient alternative. This option is gaining momentum around the globe. Perhaps the best measure of its potential is presented in the recently released European Hydrogen Backbone (EHB) report.1 The EHB is a dedicated hydrogen transport network expected to have 39 700 km (24 600 miles) of pipelines in 21 countries by 2040 and more than two-thirds of them (69%) will be repurposed natural gas lines. To fully appreciate the significance of this effort, consider that currently there are only about 4500 km (2800 miles) of hydrogen pipelines in operation worldwide. More than half of them are concentrated along US Gulf Coast, primarily connecting production facilities to refineries and chemical plants and running at lower pressure than will be needed for long-distance transmission.2 There’s no question that changing pipeline service from natural gas to hydrogen is a less intensive process


than building a new network; still, making an existing pipeline hydrogen-ready is not a simple, one-step process. It’s not inexpensive, either: one estimate suggests the price tag for repurposing Europe’s natural gas pipelines for 100% hydrogen transportation will be between €43 billion and €81 billion.3

Differences at the molecular level With so much at stake – safety, quality and productivity, in addition to cost – there’s no room for cutting corners when it comes to converting a natural gas pipeline to hydrogen service. Even after cleaning and inline inspection (ILI) – both critical precursors to operation – there might still be considerable work to be done, including repairing defects identified during ILI, changing out valves, removing sections or connecting the pipeline to existing or new infrastructure while the pipeline is in operation.

Creating a safe work zone during those activities generally requires intervention and isolation, which includes hot tapping and plugging (HT&P). HT&P avoids the time, risk and expense of shutting down the pipeline system by avoiding decommissioning, depressurisation and any significant impact on product flow. HT&P also minimises gas loss to the atmosphere. Isolation and intervention operations have been performed successfully on all types of pipelines for decades, but it appears that hydrogen’s characteristics may increase some of the associated risks. For example, hydrogen molecules are smaller than those of natural gas, meaning they can escape more easily anywhere there is a connection or potential leak path. Plus, hydrogen is also much more volatile than natural gas; while the explosion and flammability concentration range for natural gas-air mixtures is 5% to 17%, it’s much wider for hydrogen-air mixtures, between 4% and 74%. In addition, although the US Department of Energy reports says the “long-term impact of hydrogen on materials and equipment is not well understood,” we do know that hydrogen attacks certain metals.4 Hydrogen embrittlement can lead to cracking and failure of pipelines and components, especially the isolation technology that becomes a permanent part of the pipeline, such as split tees and other fittings. Between the flammability of hydrogen and the risk of hydrogen embrittlement, the selection of hydrogen compatible isolation equipment is critically important. Isolation fittings must be able to withstand the pressures of operation while also being resistant to the hydrogen environment.

The right restrictions Figure 1. Hydrogen cracking requires product, stress and susceptible material.

Figure 2. LOCK-O-RING® plus completion plug. This plug is set in place with extended leaves that fit in the flange groove.


World Pipelines / NOVEMBER 2021

For hydrogen cracking to occur, there must be a combination of three things: hydrogen; material (with a susceptible microstructure); and stress (Figure 1). Avoiding hydrogen cracking, then, is a balancing act between steel grade, stress levels (primarily hoop stress), safety and cost effectiveness. In general, that has meant adhering to a conservative approach of choosing materials that are thicker (which reduces stress level) and avoiding certain higher-yield metals and alloys whose microstructure has been regarded as susceptible to hydrogen embrittlement. That isn’t much of a problem for the low-pressure hydrogen pipelines currently in place or, really, for any future low-pressure distribution network. However, those constraints become more of an issue when it comes to operating – and isolating – largediameter, high-pressure transmission pipelines that require the use of higher strength steels, hydrogen pipelines included. Fortunately, recent testing indicates that certain higher yield materials are more resistant to hydrogen embrittlement than previously believed. This work is consistent with ASME B31.12 option B, which allows operators to utilise a fracture mechanics approach to determine an acceptable stress range for hydrogen piping.5 ASME B31.12 was last published in 2019. It provides rules and guidelines applicable to piping in gaseous and liquid hydrogen service and to pipelines in gaseous hydrogen service. For example, a Greek pipe manufacturer supervised by thirdparty consultants validated the use of higher strength (API 5L X60 to X70) steels in pressurised hydrogen.6 In addition, a German pipe

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Figure 3. LOCK-O-RING® completion plug. This plug is held in place with segments that are extended with a screw mechanism drilled through the flange.

In addition to those serious risks, H2S is known to cause hydrogen embrittlement. What this means, of course, is that special care is required to protect people and the environment during HT&P operations such as in-service welding of the split tee to the pipeline. At T.D. Williamson (TDW), we have expertise and specialised procedures for both hand and mechanised welding in sour service applications, including the use of induction and resistance heating and volumetric non-destructive examination (NDE) of these welds. These solutions are easily transferred to enable the welding of split tees on pipelines carrying hydrogen and hydrogen blends; we have also worked on specific welding procedures for hydrogen service. Although for now, isolation service providers can plan on using the same conservative approach to hydrogen pipelines as they do for sour gas pipelines, that may not be the case for long. Testing and engineering studies are underway worldwide and international standards are evolving. As the industry learns more about how much caution is really required to tap into live hydrogen pipelines, today’s methods may someday actually be considered overly restrained. Having new standards with an appropriate level of requirements (meaning they are not too restrictive based on sour service experience) is crucial as the industry moves to convert existing lines that were built for natural gas.

Ahead of the hydrogen curve Generally speaking, successful pipeline isolation operators require: ) Isolation equipment that is compatible with the product and provides an effective seal. ) An appropriate procedure to purge, bleed and remove

product from the isolation equipment and the isolated section. ) Comprehensive monitoring and leak detection. ®

Figure 4. The TDW STOPPLE Train system.

company has developed a hydrogen-ready pipeline steel that may contribute to relaxing some of the restrictions of ASME B31.12 as they relate to higher-strength steels between X52 and X70.7 This isn’t the only area where industry groups are working to find the right level of requirements without being overly conservative. Because there are so few hydrogen pipelines in place, isolating them has yet to become a routine activity; however, there’s no question it can be done safely and effectively. Many of the conditions and precautions that will affect the isolation of hydrogen pipelines are already familiar to service providers experienced with pipelines carrying sour gas (natural gas containing hydrogen sulfide, H2S). Their proficiency is helping to provide insight into exactly what the guidelines should be.

Learning from sour gas To say that working with sour gas can be treacherous borders on understatement. After all, H2S is extremely flammable and highly toxic, making it one of the deadliest hazards in the oil and gas industry. In fact, it is second only to carbon monoxide as a cause of inhalation deaths.8


World Pipelines / NOVEMBER 2021

In addition, providing a safe HT&P operation calls for particular expertise and experience, including qualified specialists who will ensure the most appropriate approach and techniques are used start to finish. But long before technicians arrive on site, safety has to be built into the equipment. For isolation equipment manufacturers such as TDW, safety has always been a top priority when designing new products and developing new technologies. That’s even more important as the energy sector becomes more demanding and safety conscious as the use of new fuels arises. At TDW, for example, our Safe by Design protocol enables us to engineer out potential problems within the actual design, providing the strongest possible defense against accidents. What’s more, the innovations we create solve not only current issues, but they also provide a ready solution for tomorrow’s challenges. That’s why many of the isolation products available today are well-suited for hydrogen applications. For example, to satisfy the pipeline industry’s need for a completion plug without leak paths, TDW engineers created the LOCK-O-RING® Plus, which locks into place (Figure 3) rather than screwing into the flange (Figure 2). The design eliminates penetrations in the flange that would allow gas to seep through

– and it performs the same function for hydrogen. It doesn’t matter that hydrogen molecules are smaller; without a leak path, there’s no way for them to get out. Another example is double block and bleed (DB&B) isolation technology where two plugging heads with a bleed port in between can be inserted through a single split tee. The TDW STOPPLE® Train system (Figure 4) was developed well before the idea of high-pressure hydrogen pipelines became a potential reality, but it more than meets the criteria for hydrogen compatibility and leak protection. Among the advantages: it requires only a single tap into the pipeline, and the seals are fullpressure capable and independent of each other; failure of one seal does not jeopardise the other. This combination of seals and monitoring creates an even safer environment for working on the isolated section, making it suitable for higher-risk operations.

2. 3. 4. 5. 6. 7.

8. ASME B31.12. 2019. Hydrogen Piping and Pipelines. s.l. : American Society of Mehanical Engineers, 2019. BRAUER, HOLGER, et al. 2020. Energy Transition with Hydrogen Pipes: Mannesmann “H2ready” and the Changeover of Existing Gasunie Natural Gas Networks. [Online] 2020. footage/MEDIA/gesellschaften/smlp/Documents/Energy_transition_with_ hydrogen_pipes_Mannesmann_H2ready_and_the_changeover_of_existing_ Gasunie_natural_gas_networks.pdf.


Tomorrow’s challenges, solved today The world is beginning to unlock its hydrogen potential, and it’s exciting to be participating in and contributing to this historic tipping point. Pipeliners and service providers alike are witnessing remarkable changes in the industry, how we regard the environment and how we see renewables as part of the future energy mix. At the same time, TDW is helping to accelerate those changes. Whatever tomorrow looks like, one thing remains clear: pipelines will continue to play a significant part. They’re a proven, safe, reliable and cost-effective way to transport energy to people, businesses and industries. And companies like TDW, who value and are continuously working to improve pipeline safety, will keep innovating and expanding our product offerings. By leveraging our experience with natural gas, sour service and every other type of pipeline, we’re ready now for the challenges that hydrogen pipelines will present, with solutions for cleaning, inspection and intervention and isolation.

References 1.

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Duncan Johns, Managing Director of ION Science, UK, details the measures managers can take to protect workers on oil and gas pipelines, and how these may change in the future.


rotecting workers is a requirement of any employer or workplace, but when your industry involves hazardous materials, difficult or dangerous working scenarios or risk of exposure to harmful compounds, the stakes are much higher. Worker health, wellbeing and protection are now high priority items for any business, regardless of the potential risk, thanks to legal requirements and advanced industry best practice. In the oil and gas sector, particularly for pipeline management, the risks workers (and potentially the public) can face are often much greater than the average workplace. Serious health issues can result from exposure to harmful chemical compounds, as well as the risk of fire, explosion and oxygen-deficient atmospheres. Ensuring protection and safety is implemented at the highest level possible is paramount. Laws dictate the legal limits and necessary protection, but private companies equally have a responsibility to deliver the best protection for their staff. Oil and gas pipelines are some of the most hazardous places to work, and managing, installing and maintaining them is critical to our infrastructure and economy. Mitigating and reducing the risks workers face through laws, technology, equipment, and training is the best method of creating a safe working environment that understands the risks involved.



How to protect workers effectively? There are a number of ways to protect workers and reduce the risks they face when working on pipelines, at refineries or on compressor stations.

Training While many workers will have some knowledge of how to work safely, based on either previous experience or education, each pipeline location comes with its own unique set of challenges. Delivering training that is tailored to each work scenario allows workers to understand their daily tasks, how to respond in emergencies, and any specific challenges that the pipeline they work on faces. For example, a pipeline that is situated within a radius of a population may need additional air quality monitoring and reporting. A pipeline that is due for an upgrade will need more regular inspections to check the degradation is not causing harm to public health or the environment. Training also means staff are regularly updated with the latest advances in law, technology and safety procedures. Regular refresher training on key aspects of the job such as safe working practices, fire safety and air quality monitoring is also good to offer, with training records kept to demonstrate workers are kept informed and up to date in the event of an inspection, audit or inquiry. Training should be conducted at a level workers are familiar with, taking into consideration factors such as language and cultural differences, learning preferences and using methods such as interactive quizzes rather than just lectures or seminars.

Equipment Working with hazardous materials such as crude oil, natural gas and finished petroleum products means workers need to have the right type of equipment to protect them from exposure. These products are highly harmful to human health and life, and even minute exposure incidents can cause immediate or irreparable damage. Critical equipment such as respirators or face coverings, fireproof clothing, gloves, boots, goggles and other personal protective equipment (PPE) can help protect workers in the event of exposure or accident. However, equipment should extend beyond what a worker is responsible for wearing and look more widely at the workplace set-up. Appropriate equipment could include fire extinguishers, chemical spill kits, communications devices (radios, phones etc), and correctly serviced or appropriate tools for carrying out the job. While all these can help protect workers from direct exposure to hazardous materials or reduce the severity of an incident, they are implemented as standard because of the unknown risk factor. However, this is where technology, instrumentation, and detection come in.

Technology Advances in technology for monitoring and recording and transmission of data, as well as detection of volatile organic compounds (VOCs), has by far been the biggest leap forwards in protecting workers on pipelines. Rather than relying on manual inspection or weekly collated data uploads, gas


World Pipelines / NOVEMBER 2021

detection instruments can be deployed at key points on site, worn on the person or installed into units for advanced detection and monitoring. This kind of real-time monitoring means workers can be alerted to any potential exposure to VOCs in seconds. Data patterns can be tracked easily by occupational hygienists or site health and safety managers, allowing a potential incident or health risk to be spotted early and resolved before it becomes an issue. Fixed fence line detectors or remote telemetry units (RTUs) are particularly useful for pipeline management, as they can be placed at regular intervals and monitor VOC levels around the clock, alerting workers of any hazardous levels. Implementing these at compressor stations is also very effective, given that these stations can have high levels of dangerous VOC buildup and need careful monitoring. Depending on the sensitivity required, instruments that use the latest photoionisation detection sensors can detect VOCs in ppm or ppb, and trigger alerts to exposure in as little as 12 seconds. For sensors used on pipelines, choosing the right kind of sensor for detection is essential, as you want to be picking up the correct VOCs for monitoring. Pipelines and compressor stations are commonly at risk for harmful VOCs such as cyclohexane, benzene, xylene, and toluene. As these can have serious and long-lasting health effects for workers, the environment, and potentially local populations, monitoring and minimising the risk of VOC build-up is essential. With increasingly sensitive and nuanced instrumentation available, it’s possible to not only minimise the risk of exposure to harmful VOCs, but to even predict and avoid incidents in future. Taking an ‘internet of things’ (IoT) approach to data collection and monitoring not only allows for more efficient use of resources, but also helps protect workers from exposure to VOCs and safeguards their health and wellbeing effectively.

What challenges will the future bring for protecting workers? As technology advances to help improve the protection of worker health, safety, and wellbeing, the challenges of current infrastructure can be reduced or minimised. However, as we shift away from traditional power sources like natural gas and crude oil, new challenges will arise that pose an equal, and untested, threat to workers.

Decommissioning and decarbonisation Decommissioning of refineries, compressor stations, bulk storage facilities and more opens up the risk of VOC exposure if not handled correctly. There are likely to be few workers with advanced knowledge of how to safely decommission a large historic site, and so reliance on technology, such as PID sensors and gas detection instruments, will be essential to protect people at every step. Even after decommissioning, depending on the stability of the site, it may be necessary to monitor these long-term to ensure there is no residual VOC leakage or damage to health and the environment. Fitting monitoring devices like fence line detectors which can be synchronised with data alerts would be

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an ideal solution. Choosing a reliable and long-life instrument with a quality detection lamp would also be necessary to avoid unscheduled maintenance.

and technology to ensure they can carry out their tasks safely and with minimal impact to their health.

Biofuel and anaerobic fuel processing

Choosing gas detection instrumentation and PID sensors

Reusing food waste or growing crops to process into fuel is a fast-growing trend and one sectors are keen to explore for its sustainability and limited carbon impact. However, biofuel and anaerobic digestion plants need to be approached with the same amount of care and safety as oil rigs and refineries. Nitrous oxide is a risk at biofuel plants, as is ethanol and subsequent resulting VOCs. In anaerobic digestion plants and other waste-processing plants, dichloroethane, vinyl chloride and dimethyl sulfide are among some of the VOCs resulting from processing. The main issue that biofuel and anaerobic digestion plants face relates more to the noxious odours produced as a result of processing. This can be just as devastating to worker health and have a huge impact on local communities, if not properly managed. That is not to say that there is no risk of VOCs damaging respiratory systems or major organs if workers are exposed to them, but the types of VOC and levels measured varies greatly between the type of fuel being processed and the method of processing. As this type of recycling and waste-processing becomes more commonplace to provide energy, it will be essential to outfit sites with appropriate levels of gas detection instrumentation and monitoring for pipelines that supply the raw materials into plants. Workers will need training, equipment

Whether working on oil and gas pipelines now or managing waste processing plants in the future, it’s clear that using gas detection instruments and advanced PID sensor technology is key to keeping workers safe and healthy. Ensuring that the right type of gas detection instruments are being used effectively to monitor and reduce VOC exposure levels is also critical. ION Science, a leading global OEM in gas detection equipment, are experts at VOC monitoring and have been protecting workers and sites for over 30 years. Their range of gas detection equipment, including fixed fence line detectors for sitewide protection and portables/wearables for personal monitoring, are the best choice for businesses who want to ensure their staff are as protected as possible against exposure to harmful VOCs. Not only is their range of gas detection equipment the best on the market, but their patented MiniPID2 sensors are also widely regarded as the superior choice of sensor for monitoring and detecting VOCs. Protecting workers at every stage of the job is essential for companies. Maintaining good standards of health, providing the highest levels of protection and equipment and ensuring your staff wellbeing is the top of your business agenda are all things that will set you apart and reduce the risk of incident, now or in the future.

Jeffrey Jones, SkyX’s Vice President, Global Sales and Business Development, discusses how adding a critical layer of data can help operators when it comes to decision making.


t’s no secret that aging infrastructure is more susceptible to leaks and other structural integrity issues. It’s also no secret that it’s becoming increasingly difficult to prevent these issues and mitigate risk. Current inspection technologies just can’t keep up with decades-old infrastructure. Fortunately, there is a new layer of data that you can leverage to gain the insight you need to improve operations and reduce risk in 2022 and beyond.

A new layer of data Like most midstream oil and gas companies, you’re most likely using a combination of data from various sources to monitor your infrastructure including ‘smart’ pipeline inspection gauges (PIGs), SCADA control systems, fibre optic cables and aerial data collected by manned aircraft. What you’re missing is unique, high-quality aerial data collected using unmanned aerial vehicles (UAVs) on a regular cadence. This new layer of data provides insights that no other source can today. Layering this high-quality aerial data over your existing technology ecosystem


will give you a holistic view of your entire pipeline infrastructure, making it easier to identify, monitor and address potential problems along your pipeline before harmful and costly damage or disaster occurs. It’s the most innovative pipeline monitoring technology available today

and the key to holistic and proactive pipeline integrity management.

Shift from reactive to proactive decision making Aerial data collected by UAVs empowers midstream oil and gas companies to make a transformational shift from reactive to proactive pipeline management, by having regularly scheduled flights proactively monitor their entire asset infrastructure. The dynamic system captures, accumulates and compares new data to historical data over time, and brings operators’ attention to potential anomalies before they manifest, reducing risk and costs. This leads to more intelligence, more informed decisions about issues discovered on your asset – and higher confidence throughout the organisation that these decisions are based on complete and accurate information.

Detect common midstream pipeline hazards early Figure 1. Aerial photo of pipeline showing areas of pooling liquid and reflective pooling liquid which could indicate an oil spill.

There are many midstream pipeline hazards that can be detected early using aerial data acquired by UAVs. Here’s how it can help you prevent four of the most common hazards.

1. Pipeline failures, leaks and spills

Figure 2. Aerial photo of pipeline showing third-party activity, excavation.

UAVs are able to source imagery with incredible spatial resolution and accuracy, and from these images, a multicategory anomaly detector can spot the signs of a failure. These include pools of oil, gas plumes, abnormal ground discolouration, dying vegetation, and oil slicks in bodies of water. All of these anomalies can be spotted via standard RGB imagery, but there are a variety of specialised UAV sensors that can help you be 100% sure. For instance, say there’s a strange-looking patch of ground colouration along your right-of-way (ROW), but you’re not quite sure it’s a spill. With an infrared sensor and its thermal imagery, you can identify specific changes in ground temperature that can verify whether it’s actionable.

2. Unauthorised third-party activity Year-over-year, PHMSA’s Significant Incident Report shows that third-party excavation continues to be one of the most persistent threats to pipeline safety. Why is this? The traditional inline technologies you likely rely on will only notify you after damage has already occurred. You may contract manned aerial inspections for this very reason, but these inspections usually don’t happen with the frequency needed to reliably identify these issues. An aerial data solution using UAVs can bring reliability to your visual monitoring efforts.

3. Environmental health Figure 3. Aerial photo of pipeline showing areas of dead vegetation and pooling liquid that could signal an underground pipeline leak.


World Pipelines / NOVEMBER 2021

Collecting high quality aerial data on a consistent basis makes vegetation management much more straightforward. With accurate 3D models of vegetation canopies around

your ROW and change detection capabilities, it’s easy to analyse the growth of vegetation from inspection to inspection, and get notified when and where unacceptable levels of encroachment are taking place.

4. Pipeline product theft In recent years, illegal tappers have adopted careful theft methods proven to evade traditional leak detection technologies. Increasingly, illegal tappers are using sophisticated, professional methods to extract product from pipelines virtually undetected. This can be prevented using aerial data, arming you with the intelligence you need to identify, monitor and take action on the hotspots of illegal activity, significantly reducing costs associated with stolen product and theftrelated damage.

Key reasons to adopt ongoing aerial monitoring in 2022 If you’re not already convinced that having access to unique, high-quality aerial data on an ongoing basis could greatly enhance your pipeline integrity, here are five compelling reasons. ) Midstream oil and gas companies are lacking access to reliable and quality data. Current technologies for data capture provide lowquality and inadequate data which often remains disconnected and hard to access without excessive manual effort. ) Technologies for solving

the data issue already exist. Layering highquality aerial data over your existing ecosystem provides a holistic view of your entire pipeline infrastructure. This is the best way to solve the data issue currently experienced by many pipeline operators. ) The data captured and

analysed by today’s technologies help asset operators shift from reactive to proactive

decision making, for better outcomes and higher confidence in decision making. ) Being able to visually assess anomalies using high-

resolution visual data captured by long-range aerial systems can help reduce the likelihood that inspection crews will be dispatched to potentially dangerous conditions. ) Long-range aerial systems that are equipped to do

routine flights and gather data on an ongoing basis inform operators of potential problems before they happen, reducing cost and mitigating risk.

) Storing and analysing thousands of high-

resolution images to identify anomalies. Since these requirements fall outside of core competencies, forward-thinking midstream oil and gas companies are engaging expert solution providers like SkyX. The SkyX system is an end-to-end aerial data solution that includes the provisioning of unmanned vehicles, operations, ongoing support, data analysis, and high-impact reports for longrange asset inspection and monitoring. Some of the benefits offered by SkyX include:

Detailed change detection At SkyX, we know it’s very difficult for a person on foot or in a truck, or even a pilot in a traditional aircraft to pick up subtle changes that change month-over-month, year-over-year, along a ROW. The SkyX system compares images from previous flights for every single foot the right of way so we know when there is a change. It could be man-made change, like digging near a ROW, or it could be a naturally occurring change like a shift or crack in the ground.

Figure 4. Aerial photo of pipeline showing illegal activity, hot tap.

Targeted, collaborative approach We work very closely with our customers to identify the areas they’d like to monitor. Then, we come up with a concept of operations of how we’ll fly the unmanned vehicles to capture the data. We work hand-in-hand with the customers’ health, safety and environment (HSE) and security maintenance teams on an ongoing basis.

Intuitive system The aerial data our vehicles acquire gets fed into our proprietary software system, SkyVision. This system processes the images, highlights areas of interest or anomalies and then shows them to the customer on a map in a very intuitive way, making it easy for them to see where the issues are. The customer can then export the data and load it into the system that they use to monitor their assets, whether it’s ArcGIS or another platform.

Figure 5. SkyX’s SkyVision software showing area of interest marked as high priority.

Trust the experts in long-range aerial pipeline data Once you’ve decided that you’re ready to integrate ongoing aerial monitoring to your pipeline integrity management programme, the next step is to decide whether or not to manage the operation in-house or bring in the experts. It pays to know about the capital investment, staff and training that are part of that commitment. Ongoing systematic aerial pipeline monitoring requires: ) Sourcing, purchasing and operating your fleet of drones.

Complete solution

) Servicing, repairing and maintaining the fleet.

What SkyX has brought to the market is a complete solution that includes the hardware to capture the data over long distances and the software system that converts all of that data to actionable insights. By flying unmanned vehicles on a regular basis and comparing data over time, we identify potential issues that would often go undetected.

) Training drone pilots and operators.

Start the aerial data conversation

) Planning and executing flights on a regular basis. ) Managing regulatory compliance and ensuring

certifications are always up-to-date.


World Pipelines / NOVEMBER 2021

Now is the time to start the conversation about adding a new layer of data to your pipeline integrity programme. Changing to a more proactive pipeline monitoring method will not only protect the health of your aging asset, but also protect people and the planet today and in the future.

Girish Babu Nounchi, C.Eng, IGEM-UK, Senior Pipeline Engineer (Saudi Arabia) and Chandragupthan Bahubali, Senior Principal Process Engineer (India), WOOD, discuss the design, construction and testing of RTP pipelines.


lobally, some oil and gas operating companies are using reinforced thermoplastic pipe (RTP) or flexible composite pipe (FCP) in place of carbon steel pipes (API 5L Grades) due to their performance in severe corrosive environments (H2S/CO2/salts). Steel pipelines face corrosion challenges both internally and externally. Airborne, a Netherlandsbased company, says that an estimated 50% of leakage issues are caused by corrosion.1 A study from 2010 stated that 50% of all pipeline cost are related to corrosion.2 In order to overcome this corrosion, hydrocarbon industries initially opted for composites made up of thermoset matrices, which offer better corrosion resistance than steel, and later chose RTP, which are more flexible, offer ultra-low permeability, are less damage-prone and give higher temperature resistance than the thermosets. RTP lines not only reduce the cost of laying, operation and maintenance, they have additional advantages such as: flexibility, reusability, superior hydraulic behaviour, a reduced lead time, and reliability. They also avoid the necessity of cathodic protection (CP), reduce the number of joints, are easy to install and uninstall with less manpower, and are easy


to transport in tough terrain in comparison with steel pipes. RTP lines are considered mainly in production flowlines/ gathering lines, multiphase, gas and water injection/ disposal lines, well intervention, corrosive fluids, chemicals and wherever HP/HT flow conditions exist. Spoolable RTP are now fulfilling the increased demands of oil and gas companies, especially for transportation of various fluids like sweet and sour crude, gas, gas condensate, multiphase, CO2 and disposable water. RTPs have low surface roughness (0.0015 mm) and a high flow co-efficient (Hazen William flow coefficient 150) which causes low drop in pressure, reduces back pressure and produces a high flowrate in comparison with steel pipe. The initial cost of RTP is 30% lower than carbon steel pipeline. Overall, it is 27% cheaper to construct, repair and maintain.3

Materials RTP mainly consists of a liner with helically non-metallic reinforcing elements or wrapped steel, and an outer cover. The helical reinforcing elements should be a single material. Additional non-helical reinforcing elements are acceptable.

Liner A thermoplastic liner is used to provide a leak free and corrosion resistant containment for the transported fluid. It should be compatible to the fluid composition and design conditions to sustain against the deterioration of the plastic material under the influence of the service environment. An engineering assessment (based on testing and experience) is strictly recommended to verify that the liner will retain integrity and fitness for purpose at the design conditions. As a minimum polymer ageing estimates should consider temperature, water cut and pH. Special attention should be given to de-plasticisation, loss and/ or degradation of additive formulation components, fluid absorption, and changes of dimensions. PPI TR-19 can be used as a screening tool for evaluating fluid compatibility. ISO 23936-2 and NORSOK M-710 provide a methodology for performing fluid compatibility testing. The liner material (includes adhesion between the layers in case of multi-layer) shall not blister or sustain other damage visible with the unaided eye during rapid depressurisation from the Nominal Pressure Rating (NPR) and service conditions according to methods described by API 17J. 11 The polymer materials are polyethylene (PE), polypropylene (PP), polyamide (PA) or polyvinylidenefluoride (PVDF) and international standards are referred to in Table 1 of API SPEC 15S. High Density Poly Ethylene (HDPE) is four times more corrosion resistant than regular steel pipe. Poly Phenylene Sulfide (PPS) and Nylon are two to three times more resistant than HDPE. HDPE as an inner layer is a costeffective solution for produced water, production fluid and gas gathering. Nylon as an inner layer offers good resistance to crude oil and paraffin build-up and erosion, along with reduced maintenance downtime, and expenditure on chemical treatment and hot oiling. PPS as an inner layer offers excellent permeation resistance to H2S, CO2, CH4,


World Pipelines / NOVEMBER 2021

excellent chemical compatibility, resistance to crude oil and paraffin build up and erosion.

Reinforcement layer This comprises an even number of helical windings of continuous reinforcement to contain the applied inner pressure and other loads. As mentioned in reference 4, the continuous reinforcement material usually consists of carbon, aramid or glass fibres, plastic of the same material or metallic compound such as steel strips, armored wire or cords. This reinforcement avoids abrasion between the outer layer and the inner layer and provides extra axial strain properties, adding strength to the liner material. The fibres can be either single filaments, yarns or braided. Each has its own merits and demerits in different environmental situations. Carbon fibre reinforced layers exhibit characteristics such as low weight, high strength and high stiffness in the reinforced pipeline. Glass fibre has low or limited chemical resistance and must normally be protected by a thin layer of resin that is applied during the construction of the RTP. Generally, glass fibre is inexpensive and has good mechanical properties. Aramid or para-aramid has low weight, high strength and moderate stiffness. Reinforced structure steel strips, on the other hand, are used for lighter types of loads such as water irrigation and power cables. 5 Like carbon fibre, aramid fibres are high-performance fibres. Aramid is a synthetic organic polymer produced by a spinning process. After that, the fibres are heated and stretched to achieve high strength. 5 However, the stiffness of the aramid fibres are lower compared to carbon fibre or fibre-reinforced PE due to the fact that aramid fibres will stretch when flexural stress in applied to it.6 The aramid reinforced layer has good axial mechanical properties such as axial strain and does not provide much flexural stress.7 The presence of aramid fibres as reinforced layers prevents the HDPE from undergoing sudden cracking and bursting because of it being a very brittle material.8

Outer layer An outer cover layer protects the fibre layers from external damage. Thermoplastic compounds should conform to the requirements of the material standards listed in Table 1 and fitness for the purpose shall be established based upon tests as specified in Table 2 of API SPEC 15S. 10 The cover should have sufficient low temperature ductility for the intended installation conditions and operating temperature ranges. Resistance to installation loads and environmental conditions shall be documented if required by the application or by the purchaser (examples include solar radiation (UV) and wear resistance). The cover shall meet the test requirements of solar radiation resistance (Code C or Code E as defined in ASTM D3350 or ISO 4437 if PE is used as cover material) and impact resistance (ASTM D2444 using Tup B or an equivalent test) followed by 1000 hr constant pressure test. For steel reinforcement pipe, short-term burst pressure testing should be carried out in accordance with API 17B or ASTM D1599, Method-A, as

defined in API SPEC 15S and it must always be higher than Maximum Pressure Rating (MPR). Brittleness temperature shall be at, or below, the minimum design temperature when tested in accordance with ASTM D746. 10

Connectors and fittings Spoolable RTP is supplied in long sections and transported via reel. The length of the sections vary with pipe size and depends on the manufacturer. RTP outer diameter may vary from supplier to supplier, however minimum inner diameter should be maintained as mentioned in Table 5 of API SPEC 15S. Hence buyers must co-ordinate with the manufacturer based on their flow assurance results. Both pipe to pipe (in line couplers) connectors and end connectors (flanged end/weld stub with various ratings) are mostly in-house manufactured by a supplier or outsourced and supplied by them to perfectly suit their RTP product. Electrofusion methodology or a combination of butt welding and electrofusion should be considered in order to join the RTP by inline couplers or with other jointing system, be it valve end, flanged end or welded stub end, or steel pipe by end connectors. The general standard coupler material is plain carbon steel. End users should consider and determine whether standard carbon steel couplers will provide adequate service life in the service fluid before specifying an appropriate material. Available alternative material options include organic protective coatings such as thin fluoro-

polymersor, poly-tetra-fluoro-ethylene (PTFE). Some manufacturers offer their steel couplers with an Electro Nickel Coated (ENC), while in some cases the entire coupler can be made from Corrosion Resistance Alloy (CRA) such as stainless steel, duplex or nickel alloys. Where highly corrosive service fluids – such as oilfield brines – are present, the use of some thin metallic or plastic protective coatings may not provide adequate corrosion protection, therefore solid CRA couplers may need to be considered. External coating on the coupler will resist the corrosion usually ranging from polyethylene sleeves or tape to liquid epoxies and visco-elastic mastics. It is recommended that external coatings are used on all coupler materials and field-applied pipeline coatings can be optional in accordance with the operating company’s standards. For additional protection, spot CP can be achieved by magnesium or zinc sacrificial anodes, specially designed and sized based on soil conditions and design life, to offer the required protection to the coupler. 9 The same concept is applicable for the selection of service end connector material by considering other mating component. Other fittings like elbows, tees etc, should be specified based on fit with the RTP inner diameter, to avoid leaks, and must be compatible with the fluid service and environment conditions. In case of sour service, materials should be selected in accordance with NACE MR0175/ ISO 15156. Where qualification testing of materials or weldments is required, it shall be conducted according to

the test procedure NACE TM0177 and NACE TM0284 and the same is applicable for steel reinforced RTP. 10

collapse pressure and minimum bend radius (MBR) even if there is an increase in MOT.

Material properties

Qualification and testing

This covers mechanical/physical properties (resistance to creep, yield/ultimate strengths, stress relaxation properties, modulus of elasticity, compression strength, impact strength, density, notch sensitivity), thermal properties (brittleness temperature and melting point), permeation characteristics (fluid permeability and blistering resistance), and compatibility and ageing (fluid compatibility, ageing tests and weather resistance) along with standards which are mentioned in Table 2 of API SPEC 15S.10 These are essential for understanding the quality of the RTP and must be provided by the manufacturer in a product data sheet. Nominal ultimate burst pressure, nominal ultimate tensile load and nominal ultimate compressive load will decrease when there is a raise in maximum operating temperature (MOT). There will not be any change in nominal ultimate

The quality qualification process follows international qualification approach (API SPEC 15S), which includes extensive laboratory tests ensuring product suitability for the intended service.

Design considerations Basic design data such as pipe diameter, length, design life, design and operating parameters, fluid service conditions, fittings metallurgy, external pressure and soil loading conditions should be considered. Operational requirements such as inspection internal/external, pigging, and CP requirements for connector/fittings also need to be considered while selecting the RTP and its components. Sometimes additional tests are advised in section 5.5 of API SPEC 15S.

Table 1. Qualification tests Tests for RTP Pipe



Long term hydrostatic strength test

API SPEC 15S/ 15 HR, ASTM D2992, Procedure B (static), at the maximum rated temperature

20 year design life and a minimum 0.67 service factor (refer Annexure F of API SPEC 15S).

Short term burst test

ASTM D 1599 Procedure A

Five replicate samples, with minimum test length of 5 times pipe diameter and unrestrained ends at Standard Laboratory Temperature (SLT).10

Mill hydrostatic test

API SPEC 15S/15 HR or manufacturer manual incase its stringent than the API SPEC 15S

1.3 to 1.5 times the nominal pressure rating (NPR) at ambient temperature by maintaining 2 min. holding period on minimum test length of five times pipe diameter.

1000 hours qualification tests

ASTM D 1598, TP1000h = 2 x NPR (up to 65˚C)

Two replicate samples (pipe + joint) shall be preconditioned at SLT by a total of at least 10 bending cycles.

Cure tests (DSC or DMA)


The average Tg of all samples (minimum 18) used to qualify the product components minus three standard deviations; and Minimum of 15˚C above the maximum rating temperature of the product when the Tg is measured by the on-set value of the DSC thermogram; or 20˚C when the Tg is measured by the on-set value of the storage modulus of the DMA curves.

Tensile strength (TS) tests

ASTM D2105, ASTM A370

The TS of the product family representative shall be taken as the lower deviated (two standard deviations) value of the five replicate samples. Testing shall be at SLT.

Vacuum tests

API SPEC 15S/ 15 HR or manufacturer manual incase its stringent than the API SPEC 15S

The test duration shall be at least 1h. Test pipes with a length of at least five times the pipe diameter, and not more than 3000 mm, shall be used Vacuum testing shall be performed after 1000 hours internal exposure testing to pentane fluid at 65˚C or design temperature if higher.

Fibre content (at a frequency of 1% of continuous production)

ISO 1172

The fibre content (mass fraction) of reinforced wall shall be ± 5% of mean value quoted by the manufacturer.

Cathodic charging (only for steel fittings to confirm no hydrogen blistering or cracking


The testing (minimum of 150 hours) shall be conducted on degreased samples loaded to 75% actual yield stress and immersed in de-aerated seawater (minimum 3% NaCl) with an applied potential of 1.05 V versus SCE.

Thermal expansion co-efficient (axial and hoop)


Temperature range of at least 50˚F (28˚C).


World Pipelines / NOVEMBER 2021

RTP has low axial stiffness compared to steel, so forces exerted on end fittings from temperature changes will be almost negligible, hence thrust blocks are not required. Nonetheless, it is good pipeline design practice to calculate these loads and make sure that sufficient margins are provided to accommodate this loading. Pigs can be run through RTP to remove deposits and blockages. However, because the thermoplastic pressure barriers in RTP are softer than steel, sharp-edged scrapertype pigs should be avoided and soft pigs should be used. Typical low- to medium-density foam pigs or soft urethane cup-type pigs are mostly suitable. Effects of permeation on the pipe properties for gas or multiphase services; high cyclic pressure services; MBR; minimum allowable operating temperature test; slow or rapid crack propagation resistance test; rapid gas decompression test for resistance to liner collapse shall be conducted at the highest nominal pressure rating and the maximum design temperature of the product family.10 The manufacturer should determine the load deflection characteristics, pipe stiffness, stiffness factor and the load at the specific deflection for the RTP line pipe under parallel plate loading in accordance with ASTM D2412. The manufacturer must specify the allowable deflection for

the RTP. The operating companies can cross check with their available data on external load transformation to the pipe based on the size, depth, soil and type of vehicle load with the manufacturer-provided value. Otherwise, some additional protection measures like casing pipes are suggested at the crossings.

Construction The RTP manufacturer develops the installation manual, which includes handling, storage, transportation, laying, installation, field testing, commissioning and the safety precautionary measures. Proper care must be taken while handling the spoolable line pipe, which is supplied in large reels through trailers. It should be visually inspected and ensured free from water and any kinks. It should be stored based on the product manual. The construction contractor should follow the guidelines and install the pipe in the field as described in the product manual. Line pipe can be buried either by conventional ‘trench and backfill’ methods using conventional trenching equipment, surface installations, directional drilling, or ‘plowing in’ with specialised trenching plows. The manufacturer should also provide guidelines for installing pipe for other applications including shallow water,

Table 2. Installation methods Installation methods



Buried Installation benefits low labour/safe deployment, minimal fittings, lower cost, faster installation and hook-ups.9,10

Consideration should be given to method of attachment to the surface equipment at each pipe end. Criticality in the areas subjected to soil movement or heave.

Compaction techniques, operating bending radius (minimum 1.5 times of product MBR), depth of bed, bedding materials and backfill to avoid pipe damage from external loads (includes traffic and environmentally induced loads).

Plowing methodology can be a very highproductivity and economical installation method, reduces 30 - 50% cost of trenching. However relatively high deployment costs, viable use of plowing requires a large project, uninterrupted runs with few line crossings.

It must be restricted to predictable areas and good soil conditions. Advantages in narrower right of ways and multiple lines installation in single pass and less surface damage.

During winter season RTP pipe stiffness may increase if temperature falls negative and leads pipe damage while plowing. Avoid rocky ground, frozen ground or locations with severe elevation changes.9,10 Due to the nature of the installation, the pipe cannot be inspected after plow-in.

Surface Installation method can be retrievable and reusable, rapid installation and fast hook-ups.

During the design phase, the designer should evaluate pressure and thermal expansion or contraction, and anticipated temperature swings (including black-body absorption of the line pipe), although expansion loops are generally not necessary. The manufacturer should provide sufficient details regarding expansion coefficients for the designer to adequately compensate for the effects based upon the intended installation environment. Since it is not restrained in a surface installation, the pipe may shrink considerably during hydro-test. Care should be taken to ensure that the pipe cannot move and be damaged from pinch or kink points as a result of the shrinkage.

Acceptable distance between the pipe supports shall be preferred. Bends in the pipe should always be made with a radius greater than the operating MBR of the product. The pipe shall have additional impact & abrasion resistance in case of rough, harshy and rocky terrain and UV protected since its exposed to the sun. Vehicles should not be driven over the pipe crossing points should be provided.9,10

Pull-through remediation/relining methodology is ideally suited to repair leaking or failed steel lines by pulling fibre/ steel RTP in a continuous length inside of existing pipelines.

Consideration should be given to obstructions in the steel pipeline, e.g. any unexpected sharp turns, dents or kinks in the pipe, or internal weld material. Such defects can reduce the effective inner diameter of the steel line and damage the plastic line pipe. Procedures and guidelines published by the Manufacturer should specify acceptable ‘damage’ allowance of the cover material.

The manufacturer should provide guidance regarding the use of fittings that may reside within a host pipe as part of a relining process. Upon exit at the termination end of the pull, a sufficient amount of pipe should be pulled through the host pipe to allow for a 360˚ evaluation of the pipe to ensure the pull through the host has not caused any damage that will affect the serviceability of the new pipeline as well as to allow for pipe relaxation.9,10

NOVEMBER 2021 / World Pipelines




3X Engineering






Böhmer GmbH


Dairyland Electrical Industries




Electrochemical Devices, Inc.


Energy Global


Europipeline Equipment


Girard Industries


Intero Integrity


Lincoln Electric




wetlands, swamps, muskeg, etc. as applicable and proper recommendations such as geo textile, additional weights or cover or casing pipe with end seals shall be suggested.9

Conclusion Spoolable RTP significantly reduces CAPEX and OPEX in comparison with conventional steel pipe in terms of welding, coating, corrosion inhibition, pigging, CP, installation, time of commissioning and reusability. One major strategic importance of RTP is its major contribution in increasing the hydrocarbon value chain, since its raw materials are made from hydrocarbon. At present fibre/ steel RTPs have few limitations such as in terms of size (less than 8 in.), temperature (180˚F) and pressure (3000 psig) in continuous operation (design life) of 20 years. Carbon steel line pipes design and selection is based on stressbased design theory which is limited by specified minimum yield stress, whereas RTP limited by pressure. This allows RTP to overcome high built-up pressures sometimes during the overflow or surge pressure, but design life diminishes. Moreover, carbon steel pipelines have thermal expansion which causes requirements of anchor blocks, but in RTP flowlines those are not needed. RTP/FCP pipe manufacturers are delivering the highest quality of products by considering the essential international standard requirements of API SPEC 15S, API 15 HR, API RP 17J, API RP 17B, CSA Z662, ASTM D 2996, ASTM D 2992, ASTM D 2517, ISO 14692 and ISO 4437 are few among them. Further R&D by manufacturers such as Soluforce, Fiberspar, and Flexsteel etc., will be helpful in improving the material capabilities for oil and gas applications.

References 1.



Pigs Unlimited International LLC





Pipeline Inspection Company








Stark Solutions





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9. 10.

STATS Group Winn & Coales International Ltd World Pipelines

21 OFC, 4 27

11. 12. 13. 14. 15.

OSBORNE, J., Thermoplastic pipes – lighter, more flexible solutions for oil and gas extraction. Reinforced Plastics, 2013. 57(1): pp. 33 - 38. PARSONS, W., Pipeline Construction Drivers. Corrosion Cost and Engineering Issues, 2010. GIBSON, AG,. Development of glass fibre reinforced polyethylene pipes for pressure applications. Plast,Rubber Compos 2000; 29(10): pp. 509 - 19. FROST, SR., The development of RTP for use in the oil industry. In:Composite materials for offshore operations-2. Houston: American Bureau of Shipping; 1999 pp. 341 - 60. BAI, Q., 28 – Collapse of RTP Pipelines, in Subsea Pipeline Design, Analysis, and Installation, Q.B. Bai, Editor. 2014, Gulf Professional Publishing: Boston. pp. 621 636. LUHRSEN, H., Reinforced Thermoplastic Pipes. State of Development, Situation on the World Market and System Introduction in Germany, 2001. BAI, Q., 26 – Tensile and Compressive Strengths of RTP Pipelines, in Subsea Pipeline Design, Analysis, and Installation, Q.B. Bai, Editor. 2014, Gulf Professional Publishing: Boston. pp. 599 - 609. ZHENG, J., et al., Short-term burst pressure of polyethylene pipe reinforced by winding steel wires under various temperatures. Composite Structures, 2015. 121: pp. 163 - 171. Canada’s Oil & Natural Gas Producers, Best Management Practice, Use of Reinforced Composite Pipe (Non-Metallic Pipelines), April 2017. API Specification 15S, Spoolable Reinforced Plastic Line Pipe, 2nd Edition, July 2016. API RP 17J, Specification for Unbonded Flexible Pipe, 4th Edition. API RP 17B, Recommended Practice for Flexible Pipe, 5th Edition. ASTM D2412-11, Test Method for Determination of External Loading Characteristics of Plastic Pipe by Parallel-PlateLoading, 2018. PPI TR-19, Chemical Resistance of Thermoplastic Piping Materials. NORSOK M-710, Qualification of non-metallic sealing materials and manufacturers, Rev.2, October 2001.

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