World Pipelines March 2022

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Volume 22 Number 3 - March 2022

From DESIGN to TEST to MANUFACTURE to PROJECT

The syntheses of diagnostics and integrity allows for the comprehensive understanding of an asset’s safety, lifetime, and performance. By bringing together technology, methods, and consultancy, we become your partner for reliable decision-making. | 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 enabling you to tackle any integrity management challenges you may face.

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PTC 2022 Berlin, Germany & Virtual

March 7–10

www.rosen-group.com

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CONTENTS WORLD PIPELINES | VOLUME 22 | NUMBER 3 | MARCH 2022

31. The rising case for horizontal dewatering

03. Editor's comment

Christopher Pett, Commercial Director, Mastenbroek, UK.

05. Pipeline news

CLEANING AND WELD PREPARATION 36. Multipass: avoiding weld-prep pitfalls

Updates on the Nord Stream 2 gas pipeline, LNG imports, and contract news from DESFA.

KEYNOTE ARTICLE: NORTH AMERICA 8. North America’s midstream sector is in the crosshairs: can it survive?

Igor Dobravc Mesarec, Production Line Leader (Slovenia), and Tony Hufford, Category Manager (USA) – Metal Fabrication, Weiler Abrasives.

As the economy transitions toward net-zero emissions, Gordon Cope discusses the impact the pandemic has had on the North American oil industry, and why ‘cleaner’ hydrogen pipelines may be a wise investment.

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ultipass welds used in oil and gas pipeline construction are critical since weld failure can be catastrophic.

In addition to being subject to stringent quality requirements, pipeline construction is often completed in challenging environments. Due to tight project timelines and the need to ensure proper penetration between weld passes, operators and helpers typically must grind and clean the welds while they are still hot.

All these factors make proper weld preparation and interpass cleaning crucial to the success of the overall process.

Knowing the common mistakes to avoid and which abrasive products can help get the work done is important to maintaining quality and staying on production timelines.

Igor Dobr Cate gory avc Mes gain ar ing th Manager ec, Prod e be (U uctio st pe SA) – Met n Line rform ance al Fabr Leader (Slo when icatio clean n, Wei venia), ing pi ler Ab and To ra pelin ny e we sives, di Huffo rd, lds. scus s

As the economy transitions toward net-zero emissions, Gordon Cope discusses the impact the pandemic has had on the North American oil industry, and why ‘cleaner’ hydrogen pipelines may be a wise investment.

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orth America relies on millions of miles of pipelines to deliver fossil fuels in a timely and cost-efficient manner. A raft of challenges, from the COVID-19 hangover to regulatory and environmental demands, are putting unprecedented pressure on the sector, however.

Canada Thanks to over 160 billion bbl of bitumen in the oilsands, Canada’s crude production and exports continue to climb. As of December 2021, it shipped slightly over 4 million bpd to the US (a record), but this also represents the current capacity of pipelines heading south. IHS Market projects oil sands production to rise a further 1 million bpd by 2030, placing a significant squeeze on infrastructure.

Several potential solutions are in the offing. For the last several years, Enbridge’s 760 000 bpd Line 3, which runs from Alberta to Minnesota, has been operating at half capacity due to advanced age. The refurbishment has been under attack as environmentalists protested its

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ILI, DATA AND DIGITALISATION 13. The snowball effect of integrity data compilation

Colin Scott PhD, PEng, Product Manager – Crack Management (IE), OneBridge Solutions, Canada.

HYDROGEN PIPELINES 17. “We are gradually moving to global industry decarbonisation”

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PIPELINE TESTING AND FAILURE 43. Testing for hard zones Andreas Thieme, Dillinger, Germany.

49. Surface elements

Stephen Petit, on behalf of Zetec.

CATHODIC PROTECTION 52. A logical companion to cathodic protection

Julie Holmquist (USA), Khalil Abed (UAE) and Philip Horsford (Southeast Asia), Cortec Corporation.

Vitaly Lipin, Severstal, Russia.

EMISSIONS 22. Battling methane emissions head-on

Adam Murray, Vice President, Performance Products, WeldFit, USA.

HEAVY EQUIPMENT FOCUS 27. One machine, several solutions Savannah Adkins-Heron, Terramac, USA.

MARCH 2022

Reader enquiries [www.worldpipelines.com]

WORLD PIPELINES

ON THIS MONTH'S COVER

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Volume 22 Number 3 - March 2022

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From DESIGN to TEST to MANUFACTURE to PROJECT

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Introducing the Palladian Energy Podcast Series 1: Digitalisation in the oil and gas sector

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n 22 February, German Chancellor Olaf Scholz put the Nord Stream 2 pipeline project on hold, in direct response to Russian aggressions against Ukraine. Scholz ordered a halt to the certification process for the pipeline, which is already completed and had been awaiting final approvals. He asked the Economy and Climate Ministry to withdraw the existing analysis of Germany’s supply security, asserting that, since Russia had invaded breakaway territories in Ukraine, SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com the supply security situation had changed.

Approval for the additional Nord Stream lines rests on two things: certification by the Federal Network Agency (BNetzA) and the examination of supply security. Germany has always maintained that the project is primarily a commercial endeavour, necessary to diversify energy supplies for Europe. Speaking after Chancellor Scholz’s announcement, Economy and Climate Minister Robert Habeck said that the “one-sidedness of dependence on one supplier, who has also proven to be unreliable, must be overcome”. He went on to say: “The supply security examination was completed by the previous government in October 2021 and found that Nord Stream 2 did not endanger Germany’s supply security.

I am of the opinion that the geopolitical situation but also the situation on the gas markets are making a re-assessment a must.” Washington has welcomed the move, as have other western nations, and Ukraine. US President Joseph Biden has announced plans to impose sanctions on Nord Stream 2 AG, the company that built the pipeline.

The geopolitical ramifications of Russia’s incursion into Ukraine include the risk of disruption to European gas supplies, which will put more pressure on UK and European gas and power prices. Energy users were already facing price hikes due to high demand and a shortage of gas storage, but more shocks are surely to come.

Oil prices are also being affected: the price of Brent crude oil, an international benchmark, hit a seven year high of more than US$99/bbl (£73/bbl) on the day that Nord Stream 2 was halted, before falling back the next day.

In the wake of the Nord Stream 2 postponement, Russian President Vladimir Putin pledged to continue uninterrupted natural gas supplies to world markets.

Russian gas accounted for 42% of EU imports via pipelines in 2021; the addition of Nord Stream 2 capacity (an extra 150 million m3/d) had been set to ease the pressure on European consumers facing record energy prices amid a wider postpandemic cost of living crisis. Gas transit through Ukrainian trunklines is currently 100 billion m3/y, and these supply lines are obviously under serious threat.

With Nord Stream 2 now paused indefinitely, analysts are adjusting their outlooks for gas supply in 2022. S&P Global Platts Analytics, which previously expected Nord Stream 2 to start service in October 2022, removed the project from its outlook on 22 February. It now expects lower Russian gas flows to Europe. “Most of that volume will have to be replaced by LNG on the back of demand switching and destruction in Asia,” comments James Huckstepp, Platts Analytics Manager of EMEA Gas Analytics.1 “In Europe, we will also need to see continued fuel switching in power and refining, with coal generation capacity returning and having its lifespan extended, along with the ongoing prioritisation of gas over oil exports in Norway, which will all require higher gas prices.”

1.

https://www.spglobal.com/platts/en/market-insights/latest-news/natural-gas/022322-biden-orders-ussanctions-on-nord-stream-2-gas-pipeline-corporate-officers

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WORLD NEWS Nord Stream 2 pipeline halted

US imposes sanctions on Nord Stream AG

German Chancellor Olaf Scholz announced on 22 February that Germany is halting the certification of the Nord Stream 2 gas pipeline from Russia.

Scholz has announced that the approval process for the Nord Stream 2 pipeline has been halted, in response to Russia’s incursion into Ukraine. Describing Russia’s actions as a “grave breach of international law”, Mr Scholz said his government had blocked the approval process and the pipeline would not be allowed to go into operation.

The decision ends weeks of ambiguity over whether Scholz was prepared to block the €9.5 billion (£8 billion) pipeline in the event of Russian aggression. The USA has repeatedly warned that the pipeline would be stopped if Russia invades, a position publicly backed by the German Foreign Minister, Annalena Baerbock.

Completed last year, Nord Stream 2 was not yet operational but was awaiting approval from German regulators. That approval process has now been suspended indefinitely, and is unlikely to start again while Russian forces remain in Ukraine.

The United States is to impose sanctions on the company in charge of building Russia’s Nord Stream 2 gas pipeline, President Joseph Biden has announced, following Russia’s aggressions towards Ukraine.

The sanctions, which target the Nord Stream 2 AG company and its corporate officers, add to pressure on the Baltic Sea project that was designed to double the gas flow capacity from Russia to Germany.

Nord Stream 2 AG is a registered Swiss firm whose parent company is the Russian state-owned gas giant Gazprom.

Gazprom owns the entire pipeline but paid half the costs, with the rest shared by Shell, Austria’s OMV, France’s Engie and Germany’s Uniper and Wintershall DEA. In a statement, Biden wrote: “Through his actions, President Putin has provided the world with an overwhelming incentive to move away from Russian gas and to other forms of energy.”

Biden’s announcement on sanctions against Nord Stream AG are what he said was the “first tranche” of sanctions against Russia. Further sanctionsare expected.

IHS Markit: LNG imports to Europe sufficient to overcome shut-off of Russia gas through Ukraine Supplies of Russian gas to Europe via Ukraine have already fallen – and been replaced by LNG imports – to such a degree that shutting off the remaining gas that is still flowing through Ukraine would have relatively limited additional impact on European supply, according to a new report by IHS Markit, a world leader in critical information, analytics and solutions.

The report, entitled ‘Putting Europe’s Security of Gas Supply to the Test’ by the IHS Markit Global Gas service highlights the reduced role of Ukrainian gas transit in Europe’s gas supply. The report says Russian gas flows through Ukraine fell to historical lows in January – 50 million m3/d, less than half of levels from a year ago. While flows through the Ukraine have swung back up with the beginning of February, they remain half the levels of the period 2015 - 2020.

“Europe is already experiencing a ‘quasi-curtailment’ of Russia gas flows,” says Michael Stoppard, Chief Strategist, Global Gas, IHS Markit. “The result is a European gas import picture that is starkly different from a year ago. One where LNG imports have ramped up to fill the gap.”

LNG imports to Europe increased considerably in January 2022 supplying higher volumes (34% of total supply) than Russian pipeline supply, which fell to 17% of supply, the report says. LNG imports from the US rose to a new record of 245 m3/d, accounting for the largest share of LNG by far.

Average total LNG imports in January were 490 m3/d, with the upward trend in LNG imports continuing into February. LNG imports for the first three days of February have averaged 605 m3/d, with 3 February reaching 710 m3/d.

Aramco closes gas pipeline deal with global investor consortium Saudi Arabian Oil Company (Aramco) and an international investor consortium, led by affiliates of BlackRock and Hassana, have announced the successful closing of the lease and leaseback deal previously announced on 6 December 2021. The consortium has acquired a 49% stake in Aramco Gas Pipelines Company, a subsidiary of Aramco, for US$15.5 billion. The consortium comprises leading institutional investors including, amongst others, Keppel Infrastructure Trust, Silk Road Fund, and China Merchants Capital.

As part of the transaction, first announced in December 2021, Aramco Gas Pipelines Company and Aramco entered into a 20 year lease and leaseback arrangement in connection with Aramco’s gas pipeline network. Under this arrangement, Aramco Gas Pipelines Company will receive a tariff payable

by Aramco for the specified gas products that flow through

the network, backed by minimum commitments on throughput. Aramco retains a 51% majority stake in Aramco Gas Pipeline Company, and also retains full ownership and operational control of the gas pipeline network. The transaction does not impose any restrictions on Aramco’s production volumes.

The announcement follows the closing of a US$12.4 billion infrastructure transaction in connection with Aramco’s stabilised crude oil pipeline network in June 2021.

Concurrent with closing of this transaction, Aramco has also signed a memorandum of understanding with BlackRock, to explore joint opportunities in future energy transition projects related to low carbon energy infrastructure. The MoU reinforces the relationship with BlackRock, enhancing opportunities for possible future collaborations.

MARCH 2022 / World Pipelines

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CONTRACT NEWS EVENTS DIARY 2 - 5 May 2022

Offshore Technology Conference Houston, USA https://2022.otcnet.org/

2 - 6 May 2022 PLCAC

Maui, USA https://pipeline.ca/

10 - 12 May 2022

Canada Gas & LNG Exhibition & Conference Vancouver, Canada https://canadagaslng.com/

23 - 27 May 2022

World Gas Conference Daegu, South Korea https://www.wgc2022.org/

7 - 9 June 2022

Global Energy Show Calgary, Canada https://www.globalenergyshow.com/

5 - 8 September 2022 Gastech

Milan, Italy https://www.gastechevent.com/

19 - 23 September 2022 IPLOCA

Prague, Czech Republic https://www.iploca.com/events/annualconvention/2022-convention/

24 - 30 October 2022 bauma

Munich, Germany https://bauma.de/en/

31 October - 3 November 2022 ADIPEC

Abu Dhabi, UAE https://www.adipec.com/

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World Pipelines / MARCH 2022

DESFA awards the contract for 163 km of West Macedonia pipeline in Greece to Corinth Pipeworks West Macedonia pipeline will be the first high-pressure transmission gas pipeline in Greece, certified to transport up to 100% hydrogen and one of the first in Europe. It is part of the European Hydrogen Backbone, Europe’s hydrogen infrastructure needed to achieve its climate and energy objectives.

In compliance with specification ASME B31.12 Option B, Corinth Pipeworks & DESFA cooperation provides a technically and economically feasible solution for the safe transportation of hydrogen at high pressures through large diameter/high strength steel pipelines. Thus, pipes produced today and installed in the current gas network can cover the energy mix of tomorrow.

The contract awarded to Corinth Pipeworks, from DESFA, the Hellenic Gas Transmission System Operator, relates to the development of a natural gas pipeline covering the Greece’s northern region of West Macedonia and paving the way for

Global oil and gas contracts activity improved in 4Q21: GlobalData In 4Q21, the oil and gas industry saw an increase of 77% in overall contract value, however, there has been a decrease of 14% in the number of contracts, according to GlobalData.

Pritam Kad, Oil and Gas Analyst at GlobalData, comments: “Notable contracts that made significant contributions in terms of value include Saudi Aramco’s 16 contracts, with a combined worth of US$10 billion for the subsurface and engineering, procurement, and construction (EPC) works for the development of the Jafurah shale gas field in Saudi Arabia.

Moreover, rising crude oil prices and improved margins helped to gain further momentum for contracts activity.”.

GlobalData’s latest report, ‘Q4 2021 Global Oil & Gas Industry Contracts Review’, reports that although the number of contracts declined from 1608 in 3Q21 to 1383 in 4Q21, overall contract value increased substantially from US$34.32 billion in 3Q21 to US$60.84 billion in 4Q21.

Other notable contracts include Yinson Holdings’ subsidiaries two contracts with Petrobras for the Integrado Parque das Baleias FPSO vessel and ADNOC Drilling’s five year drilling services agreement worth US$3.8 billion with ADNOC Onshore.

the country’s gas grid development. It comprises of 163 km coated steel pipes (97km of LSAW in. and 66 km of ERW 14 in. and 10 in.). Corinth Pipeworks’ proposal was evaluated as being the most advantageous for DESFA. The entire quantity of hydrogen certified pipes will be manufactured in Corinth Pipeworks’ plant in Thisvi, Greece.

Deliveries are planned to start by 2H22 and conclude by 1H23.

“With hydrogen playing an important role in the energy transition, we trust the expertise and valuable experience of Corinth Pipeworks for the flagship project of the West Macedonia pipeline that will pave the way for cleaner energy sources with significant benefits for the environment, local communities and the national economy”, commented Ioannis Chomatas, Asset Development Division Director of DESFA.

THE MIDSTREAM UPDATE •

FERC establishes hearing in proceeding on proposed Rover pipeline penalty

•

UK’s underwater industry set to grow to £45 billion

•

Equinor extends agreements with Norwegian suppliers

•

Weatherford and LYTT join forces to deliver digital boost for energy assets

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As the economy transitions toward net-zero emissions, Gordon Cope discusses the impact the pandemic has had on the North American oil industry, and why ‘cleaner’ hydrogen pipelines may be a wise investment.

N

orth America relies on millions of miles of pipelines to deliver fossil fuels in a timely and cost-efficient manner. A raft of challenges, from the COVID-19 hangover to regulatory and environmental demands, are putting unprecedented pressure on the sector, however.

Canada Thanks to over 160 billion bbl of bitumen in the oilsands, Canada’s crude production and exports continue to climb. As of December 2021, it shipped slightly over 4 million bpd to the US (a record), but this also represents the current capacity of pipelines heading south. IHS Market projects oil sands production to rise a further 1 million bpd by 2030, placing a significant squeeze on infrastructure.

Several potential solutions are in the offing. For the last several years, Enbridge’s 760 000 bpd Line 3, which runs from Alberta to Minnesota, has been operating at half capacity due to advanced age. The refurbishment has been under attack as environmentalists protested its

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potential damage to watersheds and indigenous lands.

After numerous court challenges were defeated, work was completed in late 2021, adding 380 000 bpd capacity.

In addition, the CAN$21.4 billion expansion of the 300 000 bpd Trans Mountain pipeline, which runs from Alberta to tidewater at Burnaby, British Columbia, is 45% complete. It will add 590 000 bpd of export capacity when the twinned line opens in 2023. Operators were forced to temporarily shut down the line in November, 2021, when torrential rains inundated the Lower Mainland region. The line was eventually restarted a month later, but not before refineries in the area ran out of crude and suspended operations.

The Montney shale in northeast British Columbia and northwest Alberta holds over 400 trillion ft³ of fluids-rich gas. Production exceeds 5 billion ft³/d, creating 169 000 bpd of natural gas liquids (NGLs) that is overwhelming current capacity. In August 2021, Keyera Corp finally began construction of its Key Access Pipeline System (KAPS) from northwestern Alberta to the Edmonton region. The 300 mile system, consisting of a 16 in. line for condensate and a 12 in. line for NGLs, is expected to be completed in 2023. The line had originally been slated for completion in 2022, but was delayed by COVID-19.

Also in August 2021, Brookfield Infrastructure Partners took over Inter Pipeline Ltd. with a CAN$8.6 billion offer to majority shareholders. The Toronto-based company initiated a hostile takeover bid in early 2021, having identified undervalued assets, including a crude pipeline network in Western Canada and the Heartland Petrochemical Complex under construction near Edmonton.

United States Crude production in the US suffered significantly from COVID, dropping from an all-time high of 13 million bpd in 2019 to 11 million bpd in 2020. Although production has been recovering, pipeline over-capacity has been a persistent headache. According to Wood Mackenzie, pipeline utilisation rates for crude pipelines in the US stood at 50% in late 2021; that compares to 60 - 70% utilisation rate prior to COVID-19.

Not all lines are suffering; in order to maintain flows, many midstream companies offered discounts. The Gray Oak Pipeline, for instance, has a 94% utilisation rate; its owner, Phillips 66, is offering uncommitted tariff rates below US$2.97/bbl, compared to US$4/bbl for competitors.

Shale oil is also making a recovery as crude prices rise above US$90. Permian crude production exceeded 5 million bpd in February, 2022, as rig counts rose and completion crews headed back to work. (To put that in context, if it were an OPEC member, the Permian basin would be the second highest producer, exceeded only by Saudi Arabia). The resurgence of production is expected to significantly ease low capacity rates in regional crude pipelines, bolstering midstream bottom lines.

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World Pipelines / MARCH 2022

In late 2021, Plains All American’s reconfigured Capline pipeline entered service. Originally built in 1967 to move imported crude north from Louisiana to the Patoka, Illinois hub, it eventually became a white elephant as domestic sources were developed. Now, the 1017 km, 40 in. pipeline has been reversed in order to deliver 200 000 bpd to the Gulf Coast.

The reversal has already had a direct impact on Canada’s exports from the US Gulf, which hit an alltime high of 266 000 bpd in December, 2021. Up until 2020, exports to countries other than the US had been hampered by a lack of tidewater terminals, rarely exceeding 70 000 bpd. Operators in the oilsands can now use Capline to access VLCCs in the Louisiana Offshore Oil Port (LOOP). With Venezuelan exports down dramatically and Mexico’s exports in doubt, India, China and other parts of Asia are seeking out Canadian heavy crude for their refineries.

Natural gas is also making a comeback. After suffering low prices through much of 2020 and early 2021, gas surged in late 2021 to finish the year at US$4.70/MMBtu. S&P Global Platts Analytics reported that Permian gas production, which stood at 13 billion ft³/d in late 2020, is expected to surpass 14 billion ft³/d in early 2022.

Much of that gas is heading south to Mexico. The country consumes over 8 billion ft3/d, but domestic gas production has been lagging. As CFE, Mexico’s national utility company, converts production from bunker-fuel, natural gas consumption is expected to rise significantly.

There are 20 gas lines in service crossing between the US and Mexico, with a total capacity of over 11 billion ft³/d. The Permian basin has seen several major lines come on-stream; Kinder Morgan’s Permian Highway Pipeline came online in early 2021, moving up to 2.1 billion ft³/d from the Waha hub in West Texas to the Gulf Coast, and Whitewater’s Aqua Blanca began operations in early 2021, transporting 1.8 billion ft³/d to the Waha hub. In November 2021, the 1.35 billion ft³/d Double E gas pipeline, a JV between Summit Midstream and ExxonMobil’s XTO Energy, entered service. The 135 mile line will accept gas from seven processing plants in New Mexico and Texas and deliver it to the Waha Hub, where it will have connectivity to East Texas and the Mexican border.

Challenges For the last several years, pipelines have been kicked around like political footballs. On his first day in the White House, President Biden cancelled TC Energy’s Keystone XL pipeline, a 2000 km express line designed to deliver 830 000 bpd of Alberta crude to the USGC. Over the course of 12 years, the proposed line had already been cancelled by the Obama administration and reinstated by the President Trump.

In November 2021, TC Energy Corporation formally filed a trade appeal under provisions of the North American Free Trade Agreement (NAFTA), seeking US$15 billion in damages. “The US decision to revoke the permit was

unfair and inequitable,” TC Energy said in its filing, blaming the US for putting Keystone XL on a 13 year ‘regulatory roller coaster’. While NAFTA has been superseded by the new US-Mexico-Canada Agreement, arbitration is still temporarily grandfathered for some legacy investments.

The dispute will be heard before a three-member panel, one appointed by TC Energy, a second by the US and a third by agreement of both parties. The tribunal has the authority to award damages for lost profits and costs incurred.

Crude exporters in Canada face further pipeline complications. Enbridge Line 5 transports 540 000 bpd from Canada through Michigan to Ontario and Quebec.

Enbridge has been doing extensive upgrades to the system to ensure safe operation. In late 2020, however, Michigan Governor Witmer ordered Line 5 to shut down operations by 13 May 2021, due to the potential for spills where it passes under the Straits of Mackinac in the Great Lakes. As an international pipeline between Canada and the US, Line 5 is governed by the 1977 Transit Pipelines Treaty, which contains provisions guaranteeing uninterrupted transit of light crude oil and natural gas liquids between the two countries. In October 2021, the federal government of Canada invoked Article Six of the treaty to instigate bilateral negotiations with the US federal government.

The invocation of the treaty (which has never been used before), will oblige the Biden Administration to become involved in the dispute.

Sunoco’s Mariner East project is designed to collect natural gas liquids from the Marcellus shale formation in Pennsylvania and ship them to a tidewater terminal south of Philadelphia. The project consists of three pipelines carrying ethane, propane and butane, primarily used in the production of plastics. The project has been plagued by spills and infractions since construction began in 2017; Pennsylvania’s Department of Environmental Protection (DEP) has levied US$20 million in fines and numerous criminal charges. DEP finally halted construction in August 2020, after up to 28 000 gallons of drilling mud fluid was spilled into March Creek Lake State Park. Sunoco, which is now considering converting part of the system to refined products (such as gasoline, diesel and jet fuel), received permission from DEP to resume construction in late 2021. It now expects to finish the project in early 2022, two years after the initial completion date.

Methane leaks from gas facilities are a serious problem.

The University of Arizona’s carbon mapper research initiative and the Environmental Defense Fund (EDF) conducted a three year survey in the Permian basin using drones equipped with methane-detecting sensors. They found that a small number of ‘super-emitting’ facilities, comprising just one tenth of 1% of energy infrastructure, emitted 100 000 tonnes of leaked methane annually. Because methane is a much stronger greenhouse gas (GHG) than CO2, the amount represents the equivalent emissions of half a million cars. In addition to well pads, compressor stations and processing plants, gathering pipelines were a significant contributor, accounting for 20% of emissions.

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World Pipelines / MARCH 2022

“The fact that some facilities are persistently leaking methane for years without detection or repair highlights the urgent need for comprehensive and transparent methane monitoring,” said Riley Duren, Chief Executive Officer for Carbon Mapper and Research Scientist at the University of Arizona. Under the Biden administration, the Environmental Protection Agency (EPA) is working with state regulator New Mexico Environment Department (NMED) to finalise rules governing regular monitoring of most natural gas sites in the Permian. In addition, the EPA is proposing federal rules that will require operators in all jurisdictions to track down and aggressively eliminate methane leaks.

The future The International Energy Agency (IEA) identifies ‘green’ hydrogen as one of the most significant innovation opportunities to reach its target of reducing CO2 emissions to net zero by 2050. Their assertion is based on the fact that hydrogen is an energy-dense molecule that can replace oil and gas in many applications, but does not emit CO2 when consumed.

North America already produces significant amounts of hydrogen; the US alone makes an estimated 10 million tpy.

Almost all is ‘grey’ hydrogen, made from natural gas as both feedstock and energy source. Green hydrogen is produced entirely by renewable electricity, such as solar or wind power, which powers an electrolyser that splits water into hydrogen and oxygen.

In early 2021, the Biden administration issued an executive order mandating net-zero carbon emissions for the American economy no later than 2050. The US Department of Energy (DOE) noted that “clean hydrogen is a form of renewable energy that – if made cheaper and easier to produce – can have a major role in supporting President Biden’s commitment to tackling the climate crisis.”

The DOE and other federal agencies have set aside several billion dollars for research and development, with the goal of reducing the cost of clean hydrogen from US$5/kg to US$1/kg by 2030.

Because hydrogen causes standard pipeline steel to become brittle, dedicated networks are necessary to transport it. Over 1000 miles already exists in the Gulf Coast refinery region of Texas and Louisiana, but tens of thousands of new-build miles will be needed as hydrogen expands beyond refinery use into transportation, utilities and heating fuel.

In conclusion, opponents of fossil fuels in North America have waged an increasingly-successful battle by delaying or canceling pipelines. Both production and demand for fossil fuels is expected to persist for the next decade, however, and crude and gas pipelines will remain the most efficient, cost-effective, and safest means of transportation. In the longer term, as the economy transitions toward net-zero emissions, new hydrogen pipelines will create a significant investment opportunity for midstream companies.

Colin Scott PhD, PEng, Product Manager – Crack Management (IE), OneBridge Solutions, Canada, demonstrates how to uncover patterns in seemingly unrelated data.

T

he oil and gas pipeline industry, like many other industries in the world today, is undergoing a digital transformation. Pens and paper are increasingly being replaced with tablets and advanced computing, driven by artificial intelligence (AI) and development of machine learning (ML) algorithms that extract knowledge from big data. People today are able to connect online, working less often in big city offices and more often from their home offices. OneBridge Solutions, and its Cognitive Integrity Management (CIM) Software as a Service (SaaS) platform, is a leader in this new

work model. OneBridge is helping pipeline operators streamline their business through the use of advanced data management, analytics and AI/ML to operate their business processes more efficiently and their pipelines more safely.

“We view digital transformation as a combination of three factors – data, analytics and network – the foundation of the CIM architecture,” said Tim Edward, OneBridge President. “CIM is a sophisticated data-hub which stores information and data that pipeline companies need to manage their assets. ML algorithms automate the ingestion of various data sets (e.g. ILI, NDT and environmental

13

set is very useful on its own.

It allows integrity engineers to perform failure pressure calculations and select the most severe flaws on the pipeline for dig and repair, or some other form of mitigation.

A common second data set for most operators Figure 1. Run over run comparison based on aligned data in a 3D graphical visualisation. would be non-destructive evaluation (NDE) flaw depth data) which are then aligned to enable analytics and measurements provided by field technicians. The ILI and uncover patterns that are not otherwise determinable. field NDE data sets would be compiled to construct a This approach to data management is highly advantageous trending (or ‘unity’) plot. This comparison provides the to traditional methodologies where information is kept in analysts with information on the quality of the ILI tool run. disparate databases without easy capability to determine The calculated statistics of tool bias and precision provide cause and effect.” a third data set from the first two. The snowball grows It’s easy to take data for granted. Obviously, the more larger and integrity engineers can then adjust their dig and data we have, the more analysis we can perform. And repair programmes with new insight. compiling a network of data describing all aspects of a Operators and their analysts would then typically wait pipeline, inspections, operations, and geography, has clear for the next scheduled inspection. The new ILI flaw depth advantages. But what we’re learning more and more at measurements would be compared to the previous ILI OneBridge, is that compilation and alignment of various depth measurements. The flaw-to-flaw depth comparison data types compounds our understanding of the pipeline would allow for an estimate of a flaw specific growth rate, and its condition. It’s a snowball effect. This is something a derivative, and very useful, data set. The flaw growth that can only be exploited with strong data ingestion and rates would be used to estimate remaining lives and adjust alignment algorithms. reinspection intervals, if warranted.

On the surface, two integrity data sets would likely At this point, OneBridge would use CIM to perform an be considered twice as useful as one data set. But if additional analysis that is not feasible to many operators those two data sets are somehow related, we can infer due to time, resource, or software limitations. The new ILI a third ‘comparison’ data set (A-B) from the first two. depth measurements would be compared to the previous Adding another integrity data set would allow for three field NDE data. This is only possible if defects remain in comparison data sets (A-B, B-C, A-C), and so on. At this the pipeline because of a previous decision to recoat or point, some data scientists might offer a ‘combinations sleeve, and we assume there is no further flaw growth. and permutations’-type analysis and use factorial This comparison allows CIM to perform pre-trending of mathematics to determine the total number of data sets the new ILI tool run. So, more statistics can be inferred and comparisons possible. This allows a compounding without the costs of a full dig programme. Operators will of our understanding of pipeline condition. But a closer likely perform some validation work using a partial dig look shows us there are even more data sets that can programme. This represents a significant efficiency gain for be inferred, because we can also use our comparison the operator. data sets in combination. What makes this effect even The next scheduled inspection provides a third set of more powerful is that we can expand this learning across ILI flaw depth measurements. These can be pre-trended different tools, vendors and operators industry wide. using both the first (full) and second (partial) field NDE data OneSoft President & COO, Brandon Taylor added, sets, which have already provided two sets of statistics “OneBridge has over 100 000 miles of piggable pipe under describing the quality of those tool runs. The third ILI depth subscription with our customers ingesting ILI, Hydro, NDE, measurements allow for a multiple ILI flaw-to-flaw-to-flaw pipe property data from connected GIS systems, and comparison and more information on flaw specific growth. cathodic protection (CP) survey, etc. on a daily basis. We If the flaws are corrosion or stress corrosion cracking (SCC) plan to roll out corrosion management and probabilistic and a linear growth rate is assumed, the data may indicate risk management functionality this year, which will increase corrosion dormancy, consistency, or even acceleration. If this snowball effect dramatically. We are very excited to the flaws are cracks and fatigue growth is assumed, the data be a leader in the digital transformation that is occurring can be used to fit a non-linear equation and infer a Paris within the industry.”

Law exponent from the data. If operational pressure cycling Let’s look at an example: consider a standard inline data can be analysed, a Paris Law coefficient can be inferred. inspection (ILI) programme commissioned by a transmission Each data set builds on the existing knowledge, and the pipeline operator. The vendor report provides a listing snowball grows larger. of depth measurements for all flaws identified on the In some scenarios, the data comparisons can be pipeline (as well as many other properties). This first data combined for further study. The ILI and field NDE data

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World Pipelines / MARCH 2022

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comparisons help us understand the depth sizing error (bias and precision) of each of the ILI tool runs. The flawto-flaw (or more) depth comparisons allow us to estimate flaw growth rates. These two ‘inferred’ data sets allow us to calculate probabilistic flaw growth rates for both corrosion and cracks. This can provide either more or less confidence in our data, but will certainly provide a more defendable rationale for our decisions.

Impact of expanding data capture At OneBridge, we also recognise the enormous value of some ‘keystone’ data sets. Although this is under the early stages of consideration and analysis at OneBridge, we recognise that these data sets can be used in multiple ways and, in some cases, can provide significant value to different aspects of pipeline integrity. One example of this is soils data, which can provide substantial benefit to corrosion, cracking, and deformation analyses. The soils’ electrical conductivity and drainage can indicate a pipeline’s susceptibility to external corrosion. It is important in designing and optimising cathodic protection systems. Soil types with specific salt contents are known to influence stress corrosion cracking susceptibility. Soils’ mechanical properties affect their constraint against land movement and susceptibility to global bending strains.

In the case of soils, it is not just the properties in the immediate area of a given corrosion flaw or bending strain that is important, but the patterns of soils properties between pipeline and rectifier or along the length of a pipeline in a geotechnically unstable area. Alignment of the soil properties with multiple data sets becomes increasingly important to integrity analyses, and this is where CIM relies on its core strength of data alignment.

Another keystone data set of interest is pressure cycling data. Pressure cycling data is typically used to construct pressure cycle histograms that are used for fatigue crack growth analyses. This helps analysts understand how defects are growing during operation, and when they might become a serious threat to the pipeline.

The primary concern is usually long seam cracks, but we can also consider the role of pressure cycling in the growth of girth weld cracks or circumferential SCC. Here we need to rely on our keystone soils data to understand if the pipeline constrained or unconstrained and susceptible to local deformation. In the case of circumferential SCC, the soils conductivity and salt content become important. We can also review our pressure cycling data to determine our internal corrosion susceptibility, as it helps us understand if and when sediment might accumulate in the pipeline. The more we study different aspects of integrity management, the more we recognise the importance of data compilation and appreciate CIM’s ability to align various data sets effortlessly.

Data management does not come without its challenges. “Operators are often challenged by imperfect or incomplete historical data sets, and tasked with maintaining the integrity of assets that might have been put into service many decades ago before digital records were even a possibility,” says OneBridge CTO Jordan Dubuc, responsible for the development team that builds the CIM platform. “Cognitive Integrity Management aims to help operators make the most of the data they already have, aligning linear and spatial data sets while accommodating inconsistencies or uncertainty, identifying areas where we might find gaps or discrepancies and ultimately delivering greater confidence in integrity decision-making.”

Data avalanche transforms?

I learned many years ago to line up every data set against every other data set I had. Most of the time you find no correlations, but sometimes you find some real surprises that help you understand the challenge of the day. If two data sets have no known reason to be correlated, but they are, then what are we missing in our understanding of the problem? If two data sets should be correlated but aren’t, where does the problem lie? Each comparison helps us learn a little bit more.

At OneBridge, we’re always looking for new and better ways to analyse our users’ data. Much of this relies on data alignment and a willingness to try unusual combinations. We never know what might work until we try it. And the more data we can compile and align, the more we understand our pipeline condition, the better our integrity decisions become.

So, let’s all think about the data avalanche we’re facing and how the industry can work together to build snowballs.

As Alexander Pope wrote, “a little learning is a dangerous thing… but, more advanced, behold with strange surprise new distant scenes of endless Figure 2. ILI flaw depth versus NDE flaw depth measurements across multiple data sets. science rise!”

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World Pipelines / MARCH 2022

T

he energy transition is picking up momentum.

Major energy producers are looking for ways to diversify into greener energy sources. This requires significant investment in infrastructure and innovation, and suppliers who can move quickly to provide the technological solutions that will help their customers remain relevant.

As part of its focus on the renewable and green energy sectors, Russian steelmaker Severstal is developing a range of innovative large diameter pipe products for hydrogen transportation, and the company intends to launch sales in Europe in the not-so-distant future.

Vitaly Lipin, Head of Technical Sales at Severstal’s pipe-producing unit, gives us his insight into this new strategic direction for the business.

World Pipelines sits down with Vitaly Lipin, Severstal, Russia, to discuss the role hydrogen pipelines play in the transition to renewable energy sources.

When do you expect to deliver Severstal’s first hydrogen pipes to the market?

After two years of product development, we are expecting to be ready to supply the first products – pipes for hydrogen

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We are also making sure we comply with new international standards for hydrogen products that are currently being developed. We took part in the joint industry project (JIP), teaming up with several market leaders with the goal of developing the best design and material solution for hydrogen pipelines.

Is Severstal looking for partners to support this initiative?

Figure 1. Vitaly Lipin, Head of Technical Sales at Severstal’s pipeproducing unit.

transportation and steel plates for these pipes – at the end of 2022 or the beginning of 2023. We believe that Severstal will be one of the first companies globally to produce LDP for hydrogen.

By that time, we expect to have completed all of our research and testing. Our products undergo extensive testing to make sure that they meet the quality requirements and technical specifications for hydrogen production and transportation. We are currently testing some very specific properties of the materials we’ll use to manufacture hydrogen pipes with our specialist R&D partner in Italy.

You already produce pipes for natural gas pipelines. How are pipes for hydrogen different?

The characteristics of hydrogen are very different to natural gas (methane) that’s usually transported via largediameter pipes. The transportation of hydrogen can lead to degradation of the pipes’ mechanical properties (welds seams and base metal), which may potentially cause either dangerous leaks or lead to pipelines wearing out quickly.

Preventing these risks is hugely challenging. While the technological stages of constructing pipes for natural gas and pipes for hydrogen are basically the same – steel casting and slab production, then rolling and pipe production – we have to work out the proper chemical composition and microstructure of the steel. Then, we have to adjust the specific technological parameters of the steel rolling process, and the welding material and welding regimes for pipe production.

It is critical to ensure the highest quality at every stage.

That means the best raw materials, control and testing during every step. Severstal is able to manage this quality control throughout the production process due to the fact that we are a vertically integrated company. We have a skilled team of highly qualified engineers and production staff that ensure we deliver our cutting-edge products with the highest level of precision.

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World Pipelines / MARCH 2022

We are in contact with several potential hydrogen transportation companies both in Russia and abroad, whose projects are still at the pre-feasibility study stage. We are very keen to participate in the first phase of a hydrogen project. When you start at an early stage you are better positioned to offer the best solutions and improvements that will eventually benefit the entire industry.

Severstal has extensive experience of developing new products to meet the future needs of our customers, often through R&D partnerships with customers and start-ups.

We are very excited to develop solutions for hydrogen production and hydrogen transportation, and we are looking for partnerships with customers, R&D partners, and producers of similar products, since we believe that the exchange of experience can be very useful in achieving the best solutions.

Natural gas pipelines often run several thousand miles, requiring very large volumes of steel pipes. How will hydrogen pipelines compare – are they likely to be long or short distance and how will this affect demand for volumes?

The hydrogen market is still evolving, and there are two different schools of thought on this issue.

The first states that there is no need to transport hydrogen over long distances. This argument is based on the view that transporting hydrogen will be more costly than transporting natural gas, while the materials used for building hydrogen pipelines are also expected to be more expensive. As the industry also has limited experience of operating transportation systems for hydrogen or hydrogencontaining mixes it would be logical in this case to build hydrogen production capacities in close proximity to where the hydrogen will be consumed. On this basis, hydrogen pipelines would not be lengthy at all.

The second school of thought is that the transportation of hydrogen and hydrogen-containing mixes (hydrogen mixed with natural gas) will actually follow a similar model to regular natural gas transportations. That means there’s potential for many kilometres of hydrogen transportation pipeline made from specially selected materials. Major hydrogen pipeline networks would negate the need for building multiple local capacities for hydrogen production next to their consumer bases. Hydrogen production could then be focused in certain zones and the gas transported to its points of consumption.

There is no final clarity yet on how the market will evolve, with different approaches being trialled in different

regions. For example, the Netherlands is developing its own hydrogen transportation system based on its existing natural gas transportation system. Once certain upgrades to the pipelines have been completed, the existing gastransportation system will be used to transport pure hydrogen or hydrogen-containing mixes. Minor upgrades to the pipe network would be required such as linking up the pipelines to new production capacities and consumers, but these would only account for 30% of the entire pipeline length, while 70% of transportation will run through existing pipelines.

So far, a lack of experience and a lack of regulatory framework makes it hard to project the requirements for building and maintaining such transportation systems. The JIP was created with the ambition of creating workable regulations.

With large diameter pipes for natural gas, you’ve historically focused on supplying domestic pipeline projects and only recently started export sales. When developing pipes for hydrogen, is Severstal expecting to sell more on export or in the Russian market?

These things can’t be directly compared. With natural gas pipes, demand from our Russian clients historically absorbed all of our production. It was only last year that we significantly increased exports of pipes, which became 20% of our pipe sales. Hydrogen pipes are totally different.

- ics w -Nectron Ele

As one of the first movers launching these products, we will be evaluating the market opportunities globally from a very strong vantage point.

The fact is that the energy transition has become a reality, we are gradually moving to global industry decarbonisation. I am confident that in the nearest future we will have a large number of customers with many projects that require our hydrogen pipe products. We expect large scale demand to come first from Europe, then from Asia. Eventually, I expect we will see demand from all over the world.

Large-scale demand from the EU will come from a number of hydrogen transportation projects at different stages of implementation. Russia has some pilot hydrogen projects, but these are very local, running over short distances. So far there are no major projects that would consume large volumes of hydrogen pipes in Russia.

According to the European Hydrogen Backbone strategy, 11 600 km of hydrogen pipelines will be operational by 2030, which may expand further to 39 700 km by 2040. As part of this 39 700 km of infrastructure, construction of 12 450 km of new pipelines is planned. Severstal is looking to be among the first to support energy market players with hydrogen transportation solutions.

Severstal is also investing into hydrogen production itself. In February, the company bought a stake in Canadian start-up Ekona Power that develops technology to produce low-carbon hydrogen.

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Adam Murray, Vice President, Performance Products, WeldFit, USA, discusses how to safely and efficiently eliminate nearly all emissions associated with voluntary flaring and venting.

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he world has fired another volley in the fight against climate change, and this time the target is methane.

While carbon dioxide emissions continue to be enemy number one, methane was squarely in the crosshairs at the November 2021 Glasgow climate summit. Methane has more than 80 times the warming power of CO2 over the first two decades after it reaches the atmosphere, according to environmental defense fund research, so it’s not surprising that the need to reduce methane emissions would eventually emerge from CO2’s shadows. In Glasgow, more than 100 countries signed the global methane pledge, a US-led initiative aimed at cutting methane emissions by 30% within nine years, in large part by tightening regulations related to methane leaks from oil and gas operations.

While these requirements may be new, the industry’s interest in capping involuntary methane emissions isn’t. Methane intensity in US energy production dropped 17% between 1990 - 2019, while oil and natural gas production rose 66% and 96%, respectively.

Still, there’s plenty of room for improvement. Driven by their own ESG commitments as well as public and investor sentiment, midstream operators are among those working the hardest to meet methane reduction targets.

And though it may seem counterintuitive, many even welcome the new rules, says Eric Heinle, WeldFit President of pigging and performance products.

“Midstream operators with a large footprint realise that every reduction they make can have a meaningful impact both on

Figure 1. Emissions recovery/distribution pipeline replacement, 8 in. natural gas pipeline, 5.5 miles, 250 PSIG, Abilene, Texas, 2021.

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the environment and the safety of people living near pipeline operations,” he said. “Companies see the new rules as a catalyst for service providers to bring methane-capturing technology to market as quickly as possible.”

The industry won’t have to wait long. In fact, in the US, at least, there’s really no wait at all. Gas recapture solutions that safely and efficiently eliminate nearly 100% of methane emissions associated with voluntary flaring or venting are already in use on American natural gas pipelines.

Venting in public Service providers have supported the industry’s efforts to reduce greenhouse gas (GHG) emissions for decades. New and better ways to detect leaks, capture and sequester carbon, and seize fugitive vapours are being introduced all the time.

Many of these technologies are aimed at mitigating the large-scale releases that attract the most attention. But it’s impossible to ignore the fact that methane emissions are a part of everyday life for energy companies. Thousands of tons of CO2 equivalent (CO2e) methane are released during routine operations. Before a technician opens a pig launcher at a natural gas processing facility, or a contractor removes and replaces a section of pipeline isolated by a hot tapping crew, the product must first be removed from the pressurised system.

It’s not uncommon for the gas to be flared or vented, directly

Figure 2. Emissions recovery/transmission pipeline maintenance, 30 in. natural gas pipeline, 7.6 miles, 585 PSIG, Ogden, Iowa, 2021.

Figure 3. Emissions recovery/gathering pipeline tie-in, 8 in. natural gas pipeline, 2.5 miles, 135 PSIG, Carlsbad, New Mexico, 2021.

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World Pipelines / MARCH 2022

releasing methane and other greenhouse gases (GHG) into the atmosphere.

The total time needed for venting depends on a number of variables, but it’s rarely a quick, open-and-shut activity. Even an operation as simple as replacing a filter could require 10 min. of venting first. And while that might result in the release of just a small amount of methane, given how often filters are replaced it all adds up. On the other hand, isolating a large transmission pipeline for maintenance might occur infrequently, but the venting process can take days, with the associated methane emissions easily running into the hundreds or thousands of tons.

Venting isn’t just risky to the environment, of course; it’s also a personnel safety hazard. Opening a valve by hand or with a tool puts the technician in close proximity to the pressurised pipeline contents, which is inherently dangerous.

And it’s no secret that the sound of a high-pressure valve opening is disruptive to anyone living or working nearby and has even been known to attract unwanted attention. In fact, one producer said every time his company vented a section of isolated pipeline near a highway in New Mexico, it would attract protestors.

Fast and efficient One way to reduce the emissions from venting and flaring is to eliminate venting and flaring altogether. But since we’re not there yet, gas recapture systems provide a safe and efficient alternative that can achieve methane reductions of nearly 100%.

Generally speaking, these systems remove natural gas associated with blowdowns during common pipeline operations then return it to the pipeline for use. The concept may sound simple, but the reality is often far from it.

Many systems can’t recover gas at a constant rate from start to finish, meaning either speed or recovery rates are sacrificed.

To overcome these challenges, Houston-based WeldFit engineered and recently introduced a gas recovery system employing patent-pending technology to ensure a constant transfer rate. This makes gas recapture fast and efficient and brings ESG goals well into reach. In fact, environmental audits verify that WeldFit’s ReCAP™ Emissions Recovery System reduces methane emissions by up to 99.99% compared to venting or flaring.

The three-step ReCAP process recovers methane during pipeline depressurisation operations, recompresses it, then discharges into an adjacent pressurised system. The ReCAP technician makes just two connections, turns the system on, and the automated system does all the work. There’s little to no operator involvement.

What truly sets ReCAP apart from other systems, though, is its patent-pending XR technology. XR allows pipeline owners to safely recover gas and control the transfer of methane into the live pipeline at a constant rate, no matter the pressure differential, from 1440 - 0 psig. Competitive products struggle with either low pressures or high pressures, which slows down their performance and adds to the burden of downtime.

“The feedback we’re getting from our customers is ReCAP is faster than anything they’ve seen,” Heinle said.

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dioxide equivalent (CO2e) stayed in the pipeline instead of being released into the air.

Damage control

Figure 4. Complete depressurisation of pipeline to zero PSIG, emissions recovery/gathering pipeline tie-in, 8 in. natural gas pipeline, 2.5 miles, 135 PSIG, Carlsbad, New Mexico, 2021.

While those projects were scheduled in advance, everyone knows that in the oil and gas industry, unplanned incidents are inevitable.

The question isn’t whether an event will occur, but when – and how fast crews can be onsite to respond.

When a Dallas, Texas based utility company experienced a leak on one of their pipeline systems, before they could launch an emergency repair, they first had to quickly transfer gas from an isolated section of 20 in. pipeline.

The location of the leak made depressurisation more complicated. The section traversed a heavily populated residential and commercial area near Interstate 635, which makes a partial loop around the metroplex and carries 230 000 cars per day.

“We were tying into a valve station that was literally next to a neighbourhood,” Heinle explained. “The operator could have opened the valve to vent it but everyone in the neighbourhood would have heard it and smelled it and wondered what they were breathing – or more importantly, what their kids and pets were breathing.”

Instead, less than 24 hours after the utility had contacted them, the ReCAP team had arrived from Houston, prepared the site and completed the transfer project so repair crews could begin their work. Using ReCAP kept nearly 195 000 ft3 of natural gas in the pipeline, or 88 metric t of CO2e, and protected the environment in the process.

A significant victory

Figure 5. Reletative frequency-to-magnitude of voluntary venting or flaring events associated with common pipeline operations.

For example, in strictly regulated New Mexico – where new rules passed in March 2021 prohibit routine venting and flaring at new and existing wells — it took the ReCAP system only about 90 min. to depressurise a 2 mile section of 8 in. midstream pipeline to 0 psig prior to the onsite contractor commencing a tie-in. This level of efficiency is critical when there are construction personnel ready to go and high-day-rate equipment waiting in the wings.

“Our customers are willing to recover emissions responsibly, but they don’t want it to take longer than it should because that just adds unnecessary cost to the project,” Heinle said. “In our experience, the ReCAP solution is significantly faster than anything else out there. We’re able to allow our customers to achieve their reduction targets in the most efficient way possible.”

If trimming downtime were the only concern, ReCAP’s speed would be impressive enough. But the true test of its performance is how effective it is at keeping methane emissions from entering the atmosphere. In nearly every case, ReCAP’s emissions reduction levels exceed 99.97% when compared to venting; and on some of WeldFit’s larger projects, methane totaling 3700 metric t of carbon

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World Pipelines / MARCH 2022

Housed in a skid-mounted, weatherproof, sound-attenuated enclosure, ReCAP technology is unobtrusive and quiet, meaning there’s little risk of it drawing the kinds of crowds venting and flaring does. Even when it was used in a busy Dallas neighbourhood, there were no curious onlookers.

But it’s a different story for customers’ engineers and project managers, who are interested in watching the process from connection to completion. They’re really intrigued by what ReCAP can do and “how we get it done in a timely manner,” said Branden Allen, ReCAP Field Services Manager.

Obviously, moving natural gas in a pipeline isn’t new to them, Allen said. However, they don’t necessarily know what to expect from a gas recapture process, or how much incremental savings occur from ReCAP’s ability to depressurise the pipeline to zero.

“For example, they’re very surprised and pleased that ReCAP is able to get the pipeline decompressed efficiently, as well as to get the pressures down to zero so there’s nothing left in the pipeline,” he added. “We’ve had jobs where the project manager expected us to recover 80% and had their equipment lined up to come out and blow down the rest of the pipeline, but it didn’t take long for us to get that last 20% out of the system.”

Of course, as standards change, they may find that an 80% target is no longer acceptable.

“We’re helping customers who are trying to eliminate voluntary emissions get as close to zero as possible,” Heinle said.

The battle against emissions may not be over - but by taking direct aim at methane, ReCAP represents a significant victory in the overall war against climate change.

Savannah Adkins-Heron, Terramac, USA, explores the use of rubber tracked carriers on pipelines.

P

ipeline construction is not for the weak. Like the crews, the equipment needed to meet pipeline demand must be powerful and efficient. When equipment meets those requirements and offers versatility and reliability in the field, that’s the golden ticket. Low ground pressure and good traction are essential for traversing the expansive terrain variation on challenging pipeline right-of-ways (ROWs). Terramac rubber-tracked crawler carriers possess each of these elements making them an adaptable equipment solution for tackling pipeline projects.

Traditionally, wheeled trucks and steel-track carriers have been the go-to equipment option for many pipeline applications, but contractors discovered that productivity can suffer when these heavy-duty haulers get stuck in wet and muddy terrain. Terramac rubber track crawler carriers are specifically designed for operating on steep grades and working angles where standard trucks and wheeled vehicles can’t. Loaded, they exert minimal ground pressure between 5.3 – 8.3 psi which allows for greater weight distribution and flotation to traverse poor ground conditions. Furthermore, when compared to traditional equipment, the smaller footprint of Terramac carriers creates less soil disturbance and need for remedial repair work which helps protect project budgets.

Support equipment and the interchangeability of attachments has also become an incentive for utilising crawler carriers on pipeline projects. Terramac’s are multi-purpose in that they are built with a frame that easily accommodates a variety of specialised pipeline equipment. Anything that can be seen on the back of a truck can be outfitted onto one of Terramac’s carrier models. With carrier sizes ranging between 6 - 14 t there is an equipment combination suitable for every step of the pipeline.

Clearing Clearing vegetation along the pipeline ROW creates a path for the pipeline and establishes the ROW for transporting materials and equipment during the construction process. Customising Terramac carriers with cranes helps to accomplish this task with more flexibility while maneuvering in and out of densely thick terrains and provides the strength and dexterity to lift, drag, and haul brush.

Potholing Identifying existing utility lines before trenching and laying pipe is done though potholing, and Terramac equips track units with a variety of vacuum excavation products. One partner, Vacuum X-Traction Products, offers a variety of vacuum excavation systems for precisely this. Terramac’s RT6 carrier with VXS-240-4 is a small and compact version that applies 2400 CFM’s and has a 4 yd waste tank making it agile on pipeline right of way. The RT14 carrier with VXS-500-6 is large and durable

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allowing it to utilise 5200 CFM’s with a 6 yd waste tank for potholing in more dense ground conditions. Regardless of size, the vacuum excavator paired with a crawler carrier improves the potholing process by providing contractors a safer, faster and more cost-efficient exposure of the pipelines.

“Crawler carriers are widely used for potholing along the pipeline for their nimble movement on all terrain types. They simply don’t get stuck like wheeled semi-trucks that were previously used,” says Chris Holomon, Enviro Services.

Hauling and transport Figure 1. The Terramac RT14 crawler carrier with flatbed lays mats on a pipeline ROW.

Figure 2. Hauling large sandbags up steep terrain requires a Terramac RT9 crawler carrier to get the job done.

Material transport is easily accomplished with Terramac carriers due to their lighter footprint and incredibly powerful hydraulic system. Rubber track carriers offer a variety of bed styles to accommodate items such as sandbags, dirt, mats and more which are typically transported between access points along the ROW. Rock beds and convertible beds are ideal for moving various types of materials whereas flatbeds lead the way on pipeline projects by hauling mats in preparation for heavier equipment to come through.

“Over 35 years ago we used to haul material along the ROW with sleds pulled by dozers. Sometimes two pieces of heavy equipment needed to be used,” explains DJ Craven, Vice President of Pipeline Systems Inc. “Crawler carriers allow us to combine these tasks but at a lesser cost because they can be operated by one trained crew member. This results in our crews being much more self-sufficient.”

More recently Terramac expanded their pipeline offerings by building a Terramac RT9 with Hiab X-CLX 058 crane attachment.

This is a loader crane that provides a lifting capacity of 5.0 metric t and an outreach ranging from 5.3 m to 11.3 m for lifting and loading heavy stationary equipment along the ROW as well as to hold heating units and weld shacks in place while crew work. The unit features jacks for increased stability and safety and a standard dump bed for multi-purpose functionality.

360˚ rotation is another feature available on Terramac track trucks that helps improve efficiency and cost savings on pipelines.

The Terramac RT7R and RT14R models are supplied with upper frames that rotate allowing materials to be offloaded at any angle or on the go. Units will dump materials directly into the trench when padding the pipeline as well. The amount of time an operator saves by being able to drive in, dump, and drive straight out adds up quickly when you factor in how many loads are being hauled daily. Furthermore, rotating track trucks keep operators in a face-forward position for added safety.

Personnel transport

Figure 3. Rotating functionality enables the Terramac RT14R to haul and dump materials while traversing terrain.

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World Pipelines / MARCH 2022

Rubber tracked carriers outfitted with 10 man or 25 man personnel carriers make the transport of crew members to and from a jobsite a safe, easy, and efficient task. Personnel carriers are utilised throughout the entire pipeline project – from the clearing crews to the final reclamation crews – for their ability to transport the maximum number of workers with one vehicle while minimising trips over rough, soft, and steep ground conditions.

“One personnel carrier can take up to 25 crew members plus all of their tools and meals safely out to the jobsite and back,” says Eric Rice, Product Analyst. “No need for multiple vehicles that get in the way or get stuck trying to get through. The cabins can also

be enclosed and equipped with heaters to protect crews from the worksite elements, which makes a big difference.”

Pipeline stringing Transporting pipe along the ROW requires utmost strength and attention to detail. Crawler carriers equipped with a specialised

fifth wheel attachment simplify the pipeline stringing process by pulling the stringing trailer. These specialised carrier units allow the stringing crew to efficiently string the pipe from end-to-end along the ROW, eliminating the need for using heavy haulers that cause soil damage or get stuck in adverse ground conditions while in transit.

Pipe welding and coating

Figure 4. The Terramac RT9 crawler carrier hauls a crew, tools and the days supplies to a remote pipeline location.

Crawler carriers are often used as all terrain welding systems.

After the stringing and bending are complete, the pipe sections are aligned and need to be welded together. The Terramac RT9 with tac welder unit has become highly useful on pipeline jobsites for its ability to deliver power for up to four welders at one time while also providing the shaded canopy necessary for crew to perfect welds. Terramac’s RT6 model offers a similar set up using a custom designed weld decks built to securely fit on the existing flatbed so contractors can easily swap between the two attachments as needed. In addition, crawler carriers can be equipped with sandblasting rigs, air compressors and sandblast pots to make cleaning and coating a simple process for maintaining a pipeline over time. These specialised carrier units allow crews to sandblast the welds and remove any of the initial coating that could have been damaged during the welding process.

Reclamation

Figure 5. A compressor on tracks easily moves up and down the ROW as needed to provide services for multiple stages.

Figure 6. The Terramac’s RT9 crawler carrier versatility increases when paired with welding equipment.

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Protecting the environment throughout a pipeline project is extremely important. Restoring the disturbed land to its native state is typically the final stage in a pipeline construction project which requires specialised restoration equipment such as hydroseeding units. When these units are mounted Terramac’s low ground pressure track trucks the process becomes very easy and cost-effective.

“After the pipeline construction is complete, we use the Terramac RT14 to haul and replace the topsoil along the ROW and then follow up with the RT14 with hydroseeding unit to seed, fertilise, and mulch the land in one simple process,” says Roger Zacher, Co-Owner at Absolute Reclamation Services.

Other support equipment mounted to crawler carriers for the reclamation stage include straw blowers, bark blowers and water tanks which provide refills to the hydroseeding equipment.

Crawler carriers are also utilised for the installation, maintenance and removal of erosion and sedimentation (E&S) control devices along the ROW. “Due to the flotation from the units’ rubber tracks, we are able to safely maintain the E&S devices with minimal environmental damage and disturbance to the soil. Once we achieve 70% growth on the ROW, we can go back in and remove all the E&S devices,” says Zacher. “At this stage, landowners may also want the wood chips removed from their fields and pastures located along the ROW. We utilise the crawler carrier to haul all of that material back out, so the crews finish the job with little evidence they were ever there working.”

While Terramac specialises in manufacturing one type of equipment, the rubber tracked crawler carrier, that one machine produces unlimited solutions for pipeline contractors conquering the most challenging projects presented on the ROW.

Despite being quicker and cheaper than well point drilling, many UK contractors ignore horizontal dewatering, Christopher Pett, Commercial Director, Mastenbroek, UK, believes things are about to change.

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stablished in 1977, Mastenbroek has carved out an enviable reputation for designing and manufacturing a range of self-propelled trenchers that are deployed in construction and pipeline projects, agricultural drainage, subsea cable laying.

The company, which is based in Boston, Lincolnshire, UK, designed its first deep trencher at the request of Heerschap Drainage Netherlands in 1983, which had various projects which necessitated the water table to be lowered below the capabilities of their regular drainage trenchers.

Unlike its competitors, which were opting to convert drainage trenchers into deep trenchers, Mastenbroek decided to design a new machine from the ground up, so to speak.

The solution – the Mastenbroek range of deep trenchers have proven popular both in

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Figure 1. Mastenbroek model 70/80 installing horizontal dewatering in Belgium.

the Netherlands, the UK and across Europe, especially in Benelux and Germany where high water tables in alluvial soils are common. The combination of soil type and high water tables can make it almost impossible to excavate an open trench as the soil simply collapses into the channel.

There are some situations where well point drilling is the preferable option, particularly when the water table needs to be lowered more than 6 m beneath the surface.

However, above 6 m Mastenbroek believes horizontal dewatering is the best approach.

“We believe that the process we have pioneered offers the optimal solution to dewatering,” says Christopher Pett, Commercial Director at Mastenbroek. “With well point drilling, contractors need to bore holes every 5 - 6 m and install surface pipes to remove the ground water, which restricts the movement of plant and machinery around the job site. Not only is this approach time consuming, but it is also more expensive than horizontal dewatering.”

A different approach The Mastenbroek approach uses its range topping model 70/80 deep trencher to install perforated pipe to a controlled depth and grade at up to 8.5 m below the surface. A surface pump connected to the pipe is used to extract the water for offsite storage or dispersal. By incorporating a hopper into the 70/80, sand or gravel filtrate can be simultaneously installed into the channel over the dewatering pipe.

Speed Mastenbroek believes that many hundreds of metres of pipe can be laid each day when the 70/80 is deployed in optimal conditions. By incorporating three multi-coil pipe reels and a working platform on the machine, operators can easily connect pipe coils without delaying the trenching process.

Figure 2. Popes Hightown using a Mastenbroek trencher in Macclesfield, Cheshire, UK.

Figure 3. Mastenbroek has developed a vertical digging mechanism.

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World Pipelines / MARCH 2022

Robustness As well as speed, Mastenbroek’s engineers have invested considerable time developing a robust and accurate digging mechanism.

As noted earlier, some manufacturers opted to convert drainage trenchers into deeper trenchers. This is inherently weaker than Mastenbroek’s approach and has been known to pull the pipe installation chute away from the digging mechanism when working in challenging conditions.

Mastenbroek’s approach utilises a vertical digging mechanism powered by a Hägglunds hydrostatic drive motor, with a vertical sliding mast to automatically control the trench depth and grade.

The Hägglunds hydrostatic drive motor was first used in rock and subsea trenchers and was incorporated into Mastenbroek’s deep trenchers in 2010.

Its digging chain has step-less adjustable speed so it can cut through various soil conditions. A 2.7 m hydraulic cylinder extension in the digging boom, combined with the 3.4 m vertical mast movement, enables the trench depth to be adjustable from minimum 2.4 m to maximum 8.5 m.

Positioning

The contractor’s view As a contractor, Popes Hightown Limited is regularly asked to install drainage schemes and provide dewatering services for pipeline installations, road construction and housing developments.

In the 1990s, Colin Pope and his team attempted horizontal dewatering with an extended boom and box, which they found to be quicker and cheaper than previous methods. However, the approach stressed out both the machine and the team, with frequent breakdowns costing Pope Hightown a substantial amount.

“In 1998, we decided to invest in a purposemade Mastenbroek dewatering machine which goes from 2 - 6 m and ticked all the boxes for us,” says Colin. “Since then, horizontal dewatering has become a method we use with complete confidence, although uptake of horizontal dewatering does seem slow in the UK. “We have found horizontal dewatering to be ideally suited for many road construction contracts and housing developments. As well as being very cost-effective, the technique offers the advantage of having room for works to continue after installation, as overground pipework was at a minimum as the machine’s design gives us the option of offsetting the pumps required.

“In all honesty, horizontal dewatering isn’t ideally suited for rocky conditions, but for a 200 m section where there is variation in soil types – clay, sand or peat – it is very good.

“With horizontal dewatering, you have a continuous pipe through all areas with a permeable backfill which catches the pockets of water, which is then pumped away.

“In our view and experience, horizontal dewatering is the way forward for so many pipelines and construction projects in general.”

Popes Hightown Established over 50 years ago, Popes Hightown Ltd is a family-owned business based in Hightown, Merseyside, UK. The company is unique because it offers specialist horizontal dewatering services alongside the design and installation of drainage schemes for agricultural and construction projects. As well as drainage solutions, Popes Hightown has undertaken several major gas, water and oil pipeline installations.

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When operating, the digging mechanism must be vertical.

Any movement fore or aft, left or right, can place immense pressure on the mechanism and lead to catastrophic failure. Mastenbroek has overcome this by developing hydraulic cylinders to create a gimble to ensure the digging mechanism remains vertical. The verticality of the trenching mechanism is automatically maintained according to machine pitch and roll with a side tilt correction of 10˚ each side of vertical. The entire trenching mechanism will slew 12˚ each side of centre to allow curved trenching and to enable the machine to reach dewatering pumps outside the working strip.

Accuracy As well as the gimble, Mastenbroek has also refined the accuracy of its 70/80 machine. The use of lasers to control and maintain the correct trench depth and gradient in undulating topography has been deployed for some time.

In the last five years, though, GPS has been pioneered in dewatering, providing more flexibility with machine control and survey and design.

Collaboration Mastenbroek has a close working relationship with Trimble®, the hardware and services technology company which has led the way in developing GPS-based solutions for agriculture and construction companies. In 2010, the two companies worked in partnership to develop a GPS system for agricultural drainage trenchers.

Another recent enhancement to the 70/80 is the presence of Volvo EU stage five emission engines, which feature a highly advanced exhaust after-treatment system, based on SCR technology, uncooled EGR and a diesel particulate filter.

For working in confined areas, Mastenbroek has given the operator the ability to retract the cabin, undercarriage and pipe reels, and the 70/80’s heavy-duty, oscillating undercarriage provides excellent traction on undulating surfaces and low ground bearing pressure soils.

“Adding the stage five engines to our 70/80 not only improves its performance and efficiency, but it also reduces its emission levels which is something our customers have welcomed. Like every machine we manufacture, we have listened to our customer base, taken their feedback into account, and included it in every machine we produce.

“Unlike some other manufacturers, all of our horizontal dewatering trenchers are bespoke to the contractors’ needs. This means they receive a machine that offers optimal performance as it has been designed for that specific contractor and its unique work methods.

“Our customers operating in Benelux and northern Europe have really bought into our approach, and we are starting to see UK contractors realise the benefits of deploying bespoke horizontal dewatering trenchers,” concludes Christopher.

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ultipass welds used in oil and gas pipeline construction are critical since weld failure can be catastrophic.

In addition to being subject to stringent quality requirements, pipeline construction is often completed in challenging environments. Due to tight project timelines and the need to ensure proper penetration between weld passes, operators and helpers typically must grind and clean the welds while they are still hot.

All these factors make proper weld preparation and interpass cleaning crucial to the success of the overall process.

Knowing the common mistakes to avoid and which abrasive products can help get the work done is important to maintaining quality and staying on production timelines.

Pipeline welding challenges As mentioned above, the sometimes-difficult environment and stringent quality and timeline demands of pipeline welding introduce challenges into weld preparation and cleaning.

In midstream pipeline construction, full-length pipe is often laid out in the right-of-way (ROW) already bevelled. The pipe gang preps the pipe by cleaning the rust and pits off of this bevel.

They then face the land to a nickel thickness and tack weld the

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Figure 1. For grinding the root pass, look for a product, like Weiler® Tiger pipeline grinding wheels, that is balanced to reduce chatter and provide better control to stay in the weld groove.

Figure 2. Using the right products for the job and following best practices in weld prep and interpass cleaning can help operators avoid failed X-rays or other inspections and produce high-quality welds.

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World Pipelines / MARCH 2022

two ends of pipe together, leaving an 1/8 in. gap between the 37˚ bevels on each end of the pipe. The first pass, called the root pass or bead pass, is the most critical because it creates the foundation for the remaining passes to be added on top of that bead. The welder or helper grinds the root pass with a 1/8 in. grinding wheel to create a ‘U’ in preparation for the hot pass.

After the root pass, the second pass (the hot pass) helps ensure full penetration of the weld. The hot pass must be completed quickly after the root pass to avoid the pipe temperature falling below allowable levels. This means grinding the root pass on a hot weld before laying down the hot pass. If the pipe diameter is larger than 12 in., two welders and two helpers work simultaneously to quickly lay and grind the root and hot pass and ensure there is no distortion during the welding process.

The hot pass and all subsequent passes – the number of passes depends on pipe diameter and wall thickness – are typically cleaned with a knot wire brush known as a stringer bead brush. These products remove inclusions or impurities that rise to the surface of the weld without removing base material.

If inclusions aren’t removed, they can cause a weld to fail X-ray inspection later – resulting in costly repairs or rework.

One challenge in multipass welding, especially during root pass grinding, is the space constraint involved in the v-groove.

It’s important to choose abrasive products designed to fit deep into the bevel so there is no accidental grinding of the pipe sidewall, which could cause potential rework or failures.

In addition, because the root pass is ground while it is still hot, operators may be grinding a weld that is up to 500˚F (260˚C). The hot weld will cause some grinding wheels to glaze over. When a product glazes, the wheel is not removing material effectively from the root pass. This can cause operators to push harder on the wheel or to chip the edge of the wheel in an attempt to get it to grind better.

However, chipping the wheel is an unsafe practice that can result in the wheel breaking apart at high speeds. To avoid this, look for a wheel specifically designed to grind hot welds without glazing.

Chatter is another challenge during pipeline root grinding. A wheel that has a lot of chatter and vibration can cause the operator’s arm or hand to become numb over time, which creates an ergonomic issue. Too much chatter can also cause the wheel to bounce out of the

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Oil and gas industry trends Demand has fallen in some parts of the oil and gas sector, which makes it even more important to complete jobs as efficiently as possible and to use products that enhance productivity.

The industry also faces challenges related to costs and finding qualified welders for pipeline construction and repair.

But even as the industry changes and demand ebbs and flows, the need for energy remains. There are several areas of future growth and opportunities for the sector.

With globalisation, growing regional economies bring a need for greater energy capacity in areas that didn’t have as much demand previously. As a result, more pipelines are being built in developing areas like North Africa.

In addition, clean energy is on everyone’s radar. Pipelines are being constructed in many regions to carry things other than oil, including liquefied natural gas and methane fuel.

These trends make it essential to have effective weld grinding and cleaning methods.

bevel, and the operator may accidentally scar the pipe.

This can require costly repair.

Avoid these five common mistakes Addressing some common mistakes in pipeline weld preparation and interpass cleaning can help improve efficiency and safety — and produce better results.

1. Improper cleaning The more preparation done upfront in the process, the fewer problems an operator will face when it’s time for weld inspection. If the weld cleaning and preparation aren’t done correctly, it can result in weld inclusions or even costly weld failure. Ensure that all the pits and rust are removed from the pipe bevels just prior to the pipe being set and tacked for prep of the root pass.

2. Using the wrong product At the start of the day, welders and welders’ helpers often get a bucket of products before they head to the ROW. If they aren’t provided with the right products for the job, they will attempt to make them work due to their distance from the yard. However, using tools and products that aren’t designed for the job introduces safety risks and can result in poor weld quality. Be aware that not all 1/8 in. thick wheels are the same. Some wheels are designed only to be used vertically, while other products are designed to be used for grinding as well. Make sure to look at the manufacturer’s recommendations and never use a wheel designed only for vertical use to face the land or transition pipe.

3. Too much pressure When using a wire brush for interpass weld cleaning, too much pressure can cause problems. Pushing too hard will bend the wires of the brush so that the sides – rather than the wire tips – are hitting the weld. This reduces cleaning power and efficiency and also increases the likelihood of long wire breakage. Let the brush do the work to make sure the ends are striking the weld to remove inclusions.

4. Poor product storage For abrasive products, proper storage and handling are critical to performance and product life. Store the products in a clean, dry place overnight and avoid laying them on the ground in snow, mud or puddles. While pipeline welding is rarely done in perfect conditions, keeping the products out of dirt, mud and water goes a long way toward optimising results. Often, welders mount the grinding wheel and products on their rigs so they can hang them up when they’re not in use.

5. Not using the tool guard For safe use of a grinding wheel, the tool guard should always be in place. If an operator feels the guard gets in the way when grinding or cleaning tight spaces, look for a floating guard that can be easily adjusted.

Figure 3. When using a wire brush for interpass weld cleaning, too much pressure can cause problems. Let the brush do the work to make sure the ends are striking the weld to remove inclusions.

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Products for pipeline weld cleaning From flap discs and grinding wheels to wire brushes, there are a range of abrasive products available for pipeline weld prep and interpass cleaning. One product will not cover

the needs for all the necessary steps in the process, so it’s important to choose the right product for each job.

For grinding the root pass, look for a grinding wheel that is balanced to reduce chatter and provide better control to stay in the weld groove. Weiler® Tiger pipeline grinding wheels are designed specifically for pipeline notching and grinding, so they can be used for facing the land and transitioning, as well as grinding the root pass. These wheels are also designed to break down and grind hot welds, which eliminates glazing. They deliver bite right out of the box, so operators won’t feel the need to chip the wheel to improve performance.

Weiler Abrasives visited several ROW jobsites and worked directly with contractors to develop the Tiger pipeline grinding wheels to ensure the products meet pipeline needs.

Because they are specifically designed to grind hot welds without glazing and to deliver immediate bite, the wheels optimise performance and efficiency in pipeline welding.

Tiger aluminum-backed flap discs are another product typically used during weld repair and bevel grinding. These products have less flex for more control and are good for grinding pits and rust from pipe bevels without rounding the edge. They can also be used to smooth out welds during repair work in tight spaces.

For cleaning the hot pass and any subsequent passes, a variety of wire brushes can be used to do the job. Weiler stringer bead brushes – the industry standard – are designed to fit into the base of the V-groove and be aggressive enough to remove inclusions on the first pass.

Encapsulated brushes provide increased aggression in tight spaces and eliminate wire breakage. Filler pass brushes can be used to clean filler and cap passes since they have a wider footprint to clean larger surface areas toward the top of the V-groove.

Weiler Abrasives also offers Dually stringer bead brushes, which have a hex nut on each side of the wheel that allows operators to easily remove the brush from a right-angle grinder and flip it. The design provides adequate tool clearance so there is no need to remove the tool guard to flip the wheel. This allows operators to take advantage of the natural self-sharpening feature by wearing the brush tips in the opposite direction to increase cleaning speed.

No matter which product is chosen for the job, be sure to follow best practices for safe and efficient use. Pay attention to these factors and think ‘SPOT’: )) Speed and size: make sure the product fits the tool and has an rpm rating that meets or exceeds the tool rpm rating.

)) Pressure: to get the most efficient and safe performance,

use proper pressure and don’t push too hard. )) Orientation: the angle to the workpiece at which an

abrasive is used plays a role in safe operation. Different tools may require different orientations, so the proper angle can vary. )) Time: don’t dwell or grind in one area too long, which can

result in grinding through the weld.

Putting it all together Using the right products for the job and following best practices in weld prep and interpass cleaning can help operators avoid failed x-rays or other inspections and produce high-quality welds in these challenging environments.

It can also help keep projects on time and on budget by introducing efficiencies and preventing downtime and costs for rework.

Andreas Thieme, Dillinger, Germany, focuses on increased safety for natural gas pipelines, through attention to local hard zones on pipes.

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ocal hard zones, also called hard spots, are small areas on the surface of steel plates only a few tenths of a millimeter in thickness. Formed in pipes transporting sour natural gas, they are held responsible for sudden stress corrosion cracking in the through thickness direction. In order to reliably detect and eliminate these local hard zones during plate production, Dillinger, Europe’s leading heavy plate manufacturer, developed a special eddy-current testing system. This method has now been recognised by several oil and gas companies. First projects have begun, using pipes made of D-TECT branded steel tested for local hard zones on a large scale.

Big changes in technology with niches for adapted ‘old’ technologies With what we know about global warming, the world must move energy generation from the old carbon economy towards new technologies that have less environmental impact. But this can’t be done by flipping a switch. It’s a long process, with a slow conversion from old to new, requiring bridge technologies that can secure a significant reduction in CO2 emissions. One of these bridging

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Figure 1. In order to detect and eliminate local hard zones reliably already during plate production, Dillinger developed a special eddy current testing system.

corrosion problems can be caused by the transported medium. In the worst case, it would exhibit acid sour gas characteristics that can cause various types of cracking inside the pipe wall or on the surface. This forces the designer to specify challenging mechanical, technological and corrosion properties at the material selection stage. Materials need to have special toughness at low temperatures, distinctive crack-stop behaviour and special corrosion resistance, to be adjusted evenly throughout the entire production. The design of pipelines is done with the best knowledge and belief of all parties involved: life, environment and invested capital have to be protected for the duration of the operation of the pipeline, which can last several decades. New insights are gained by analysing the operational life of pipelines and, usually, this knowledge comes in small steps of development. However, when unknown damage mechanisms cause larger failures, it can force the whole supply chain to develop and introduce new technologies on a short time basis, to solve the issue.

Fatal stress corrosion cracking as a challenge A fatal failure of a pipeline in 2014 in Asia can be cited as an example: in presence of H2S as a promotor for the absorption of hydrogen in the steel, stress on the pipe and susceptible areas on the surface, a very severe sour gas attack occurred in a new, as yet unknown, form. This sour gas attack led to sulphide stress cracking (SSC) through the wall of the pipes that did not allow Figure 2. Dillinger, together with an industrial partner specialised in NDT, developed a testing continuing operation. These cracks are method on basis of eddy current (EC) that is able to detect small hardness differences on the assumed to be related to very thin plate surface. local hard zones on the surface of the pipes. Since this case became known technologies is natural gas. The supply of this less harmful about, all manufacturers of plates for natural gas pipelines have combustible has to be secured, of course in the most efficient dealt more or less intensively with the phenomenon that is way. There is only one reasonable solution: transport in occurring on high tech steel plates for sour service, produced pipelines. by thermomechanical rolling and accelerated cooling (TM+ACC).

In the meantime, local hard zones have been well investigated.

Pipes for the transport of oil and gas It became clear that the formation of these zones is generally Although a pipe does not look very spectacular, it has a lot to related to several steps in the production process for these type accomplish. Pipelines transport natural gas at high pressures, of plates. often through inhospitable areas such as cold arctic tundra, hot These local hard zones have four characteristics: desert or seismically active areas. They are often laid offshore )) Their hardness is well above the hardness level of the base in deepwater or at low temperatures. Besides mechanical loads, material.

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The system detects areas of diameters 20 mm and above by using physical characteristics of the different structures in comparison to the base metal. These show with a certain threshold the hardness increase versus that of the base. These indicated areas can be repaired with light grinding. The eddy current device, currently in operation in both of the Dillinger plate mills in Germany and in France, tests plates inline the production without any interruption of the flow. It enables Dillinger heavy plate mills to check 100% of the surface of the plates on both sides for the occurrence of these local hard zones. Orders in large quantities, as is typical for pipeline projects, are able to be processed. All plates tested on the appearance of local hard zones are marked with the brand name D-TECT (Dillinger - Totally Eddy Current Tested).

Stakeholders are convinced Figure 3. Eddy current testing (ECT) is a well-known and proven testing method used in steel production.

)) With a thickness of a few tenths of a mm, these hard zones

are very thin. )) Their occurrence over the plates is irregular and rare. )) Research showed that they cannot be prevented completely.

Conventional hardness testing methods are not able to detect these zones on the plates, as they have lateral dimensions of only a few centimetres and are distributed on plates with a rolled length of up to 40 m.

Problem solving for current sour service pipeline projects After defining the harmful phenomenon of local hard zones, most oil and gas majors no longer allowed the use of TM+ACC material for the transport of sour natural gas. However, due to its advantages in terms of mechanical/technological properties, and its efficiency, it is still a first choice for both production and processing. Therefore, every attempt had to be made to regain confidence in this type of material, and to find a technical solution to solve this issue for the whole industry.

The solution: inline inspection for local hard zones As it is clear that local hard zones cannot be avoided completely, a method to find them on the plates in a largescale production had to be developed. In order to achieve this, Dillinger – together with an industrial partner specialised in NDT – developed a testing method on basis of eddy current (EC) that is able to detect small hardness differences on the plate surface. Eddy current testing (ECT) is a wellknown and proven testing method that has been used in steel production, for example to detect cracks on hot wide strip materials. In co-operation with Dillinger, plant engineers and research institutes, the system was adapted in such a way that differences in hardness on the surface were detectable.

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Since there are currently no standards or specifications that deal with this subject, it was necessary to approve the testing method in the production of heavy plates. Most importantly, the testing and final approval of the method and the installation had to be done in partnership with the end customers, the oil and gas majors. Together with them, a test programme on the basis on the Dillinger ECT procedure was established. The sensitivity of the system and the probability of detection (POD) were demonstrated. This approach for verifying new test methods is described in DNV.RP-F118 and in mathematical models. Test plates with different kinds and sizes of artificial and natural local hard zones, covering the known different material structures responsible for hardness variations, were driven through the EC device. On the one side, the detectable minimum size of these areas was checked depending on size and thickness of the hard layer. On the other hand, the repeatability of the test was determined. At the end of the test, it could be proven that the system could find hardened areas in sizes of 15 mm in diameter and above, having the same thickness of 100 µm as the natural ones.

Further, it was shown in multiple successive tests that the reproducibility was very high. As the artificial hard zones were circular and significantly smaller than those occurring naturally in combination with the high reproducibility, it can be stated that the system fulfills the task to detect local hard zones in the plate production safely.

Both the POD of the eddy current test device and test procedure were approved by several oil and gas companies.

Dillinger will be the first supplier for upcoming complex sour gas projects, especially in the Middle East. Through its subsidiary Europipe, 160 000 t of plate for the Qatargas NFPS project will now be supplied exclusively by Dillinger from Germany and its identically equipped sister plant in Dunkirk, France. As a special highlight, owing to the current restrictions on travel, the inspection of the plate production can be performed remotely with the Dillinger myE-Service.

This system allows following up all relevant production steps directly and inspection of all the material testing on a web based platform.

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Stephen Petit, on behalf of Zetec, details how the latest NDT technologies deliver more accurate pipeline inspections without requiring the removal of coatings.

I

nspecting pipelines for material thickness, defects, and weld integrity is one of the most challenging – and common – types of non-destructive testing (NDT) applications in the oil and gas industry. NDT techniques range from simple manual and visual tests to sophisticated technologies that detect and measure surface and sub-surface flaws, porosity, variations in metallurgical structure, corrosion, and a range of other discontinuities in exposed pipelines without having to damage or destroy materials.

While NDT inspections can help pipeline owners ‘see’ what’s going on with their assets, coatings can complicate the process.

For instance, penetrant testing (PT) is a common way to detect surface-breaking flaws such as fatigue and stress-corrosion cracks in metal and other non-porous materials. It involves applying coloured liquid penetrant to the surface and allowing capillary action to draw it into open cracks. The liquid becomes visible under ultraviolet light or by the contrasting color of the dye being used, indicating the presence of defects to the technician.

In a localised area, PT can be affordable and simple to use. However, the process requires chemicals and

extensive surface preparation, including the removal of coatings before the penetrant can be applied.

Magnetic particle testing (MT) has similar advantages and disadvantages. With MT, very fine ferromagnetic particles are applied to the material and are drawn into any surface-breaking defects using magnetic fields. MT is only effective on ferrous metals and determining crack depth is particularly challenging. One common practice is to successively buff or grind the cracks until they disappear and then measure the depth of the grind or the remaining wall thickness – at best, it’s a messy and imprecise technique.

Because PT and MT both require a clean, bare metal surface, the time and effort required to remove coatings and field-apply them after the test can erode the simplicity and cost-effectiveness of these techniques, especially when the work surface is large or complex.

Digital revolution In lieu of PT and MT, eddy current and ultrasonic testing instruments, software, and probes can capture and analyse cracks, corrosion, changes in thickness or metallurgical structure, and other defects while leaving protective coatings intact.

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Eddy current testing is a widely used technology that can detect surface and subsurface defects in conductive materials. In simple terms, when the technician places a probe or coil to a metal surface, it applies an electromagnetic field which swirls through the material in loops, like eddies in a river. Any defects will alter the flow of electrons; these distortions are captured and analysed by an eddy current instrument and displayed for the technician to review.

Figure 1. TOPAZ64 pipe weld.

Under comparable conditions and with a skilled technician, single-coil eddy current testing and PT will produce comparable pass/fail-type results. However, the newest generation of handheld eddy current instruments, such as the Zetec MIZ-21C, dramatically increase the test speed, accuracy, and repeatability, especially on long weld runs and large inspection areas. These instruments have the processing power, software, and battery life to perform inspections virtually anywhere.

An eddy current tool with a C-scan display can present a digital ‘big picture’ and help inspectors find more defects in less time, and the industry’s more advanced instruments can conduct dual-frequency testing, digital conductivity testing, and non-conductive coating thickness measurement.

Eddy current array (ECA) takes eddy current testing a step further. ECA probes like the Zetec Surf-X flexible array probe family have multiple coils in one assembly, positioned at longitudinal, transverse, or off-axis orientations and firing at coordinated times. Technicians can capture more information in a single pass than conventional, single-coil probes and significantly increase their inspection speeds.

Eddy current testing has the added benefit of generating electronic inspection records for advanced analysis and reporting, a significant advantage over penetrant testing, magnetic particle testing, and other manual techniques.

Eddy current results can be saved, shared, stored, processed, and compared at any time.

Indeed, with the right surface array probe, software, and handheld eddy current instrument, an operator can set up an inspection quickly, conduct a test, see results instantly on a C-scan display, and dramatically increase the speed, accuracy, and repeatability of the inspection.

One practical consideration for eddy current testing is that the excitation coils need to be close to the material for accurate flaw detection and signal quality. Probe suppliers now offer flexible probes that allow the coils to stay nominally perpendicular to the material’s surface. In the case of a coated or painted non-ferromagnetic weld, for example, a flexible surface array probe can encapsulate the weld bead, transition zone, and heat-affected zones in a single pass without extensive surface preparation.

Understanding ultrasonics

Figure 2. Zetec’s TOPAZ64 gives technicians access to multiple data analysis techniques.

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World Pipelines / MARCH 2022

Ultrasonic testing (UT) uses high-frequency sound energy to indicate flaws both on and beneath a coated or non-coated metal surface. Ultrasonic waves enter the material at precise intervals and a set angle, and when a wave encounters a defect, some of that energy is reflected back and generates an echo. The time it takes for that energy to reflect back to the probe is calculated and analysed by a test instrument and presented instantaneously as a graphic on a screen for the technician to interpret.

A conventional or standard UT probe is capable of generating and receiving a single ultrasonic beam. Phasedarray UT systems use probes with multiple elements (typically from 16 - 64) that are excited by an instrument in a highly controlled manner, using a specific delay law and, after reception, the contribution of each element

is summed to produce one A-Scan. A phased-array UT instrument can produce a focused beam of ultrasound that can also have different steering angles. This can simplify and improve the inspection of complex geometries and dissimilar materials, which are challenging to test because of the varying acoustic properties the technician will encounter.

The computing power of the latest phased-array UT instruments, including Zetec’s TOPAZ64, gives technicians access to data analysis techniques – and inspection opportunities – that once seemed out of reach. One of these is full matrix capture (FMC), a data acquisition strategy that leverages phased array UT to capture every possible transmit-receive combination for a given ultrasonic phased array transducer. It can increase the reliability of inspections and reduce the need for costly and time-consuming re-scans.

The important thing to remember is that with phased array UT, a single pulse and single reception produce a single A-scan. With FMC, each array element in a probe is sequentially used as a single emitter while all array elements are used as receivers. By capturing and storing A-scan signals from every transmitter-receiver pair in the array, it’s possible to generate UT imaging for any given focal law/ beam (aperture, refracted/skew angles, focusing position) and to apply the latest post-processing algorithms today or as they improve in the future. The set of FMC data can be processed multiple times to produce different results, using different reconstruction parameters.

One example involves the total focusing method (TFM), an advanced processing algorithm that uses FMCcollected data to generate a frame of pixels where each pixel is computed using a dedicated focused focal law. This results in one focal point per pixel; in theory, every pixel is perfectly focused. With the right combination of hardware and software, like the TOPAZ64 with UltraVision, FMC and TFM together are a powerful tool for processing and reconstructing data for defect characterisation.

Array probes come in a variety of shapes, sizes, frequencies and the number of elements. A 1D linear array probe is the most common type of array for straight beam and angle beam inspections. Think of it as a long transducer that’s capable of generating and receiving a single ultrasonic beam. 2D matrix array probes have elements along two directions. This enables the rapid acquisition of data and the ability to perform a complete volumetric inspection which is ideal for weld inspections or mapping wall thickness to detect corrosion.

Probe alignment is critical to a proper UT inspection, and curved geometry, long seams, irregular surfaces, dissimilar metals, and crowded work environments add to the challenge. Handheld scanners like the Zetec NDT Sweeper with side-by-side encoded wheels and 2D array probes make it easy for technicians to monitor probe position and orientation as they inspect curved surfaces like pipelines.

Any gaps in coverage show up on the instrument’s colour display in near real-time, so technicians can feel confident they’re covering an area completely and with

Figure 3. Surf-X probe on weld.

Figure 4. NDT sweeper pipe.

a high probability of detection. Advanced scanners and crawlers have magnetic wheels, motors, and can even map elbow aspects of a pipe using a flexible array probe.

Materials, welding techniques, and coatings may evolve but fatigue cracks and corrosion will continue to be threats to pipeline reliability. A better understanding of NDT testing techniques can provide next-level insight into the integrity of your assets, the quality of your inspections, and help you make informed decisions about maintenance and uptime.

MARCH 2022 / World Pipelines

51

Julie Holmquist (USA), Khalil Abed (UAE) and Philip Horsford (Southeast Asia), Cortec Corporation, explain how volatile corrosion inhibitors quite literally fill significant gaps in the standard cathodic protection system.

C

athodic protection (CP) is well-established as the main method of soil-side corrosion mitigation on aboveground storage tanks (ASTs), according to API 651 and other standards. It is also commonly used to protect underground pipelines. However, it is well known that CP is only effective in areas where the structure to be protected is in direct contact with a conductive electrolyte.

Loss of such direct contact leaves gaps in the protection system of cased pipeline crossings and floor-to-soil interfaces on AST bottoms. CorroLogic® VpCI® Technology developed

by Cortec® Corporation, US, and distributed by regional providers such as Cortec Middle East and Cortec Southeast Asia, provides a practical complementary method of corrosion protection with significant potential for cost savings and greater asset integrity assurance for asset owners.

CP for ASTs and pipelines: its effectiveness and challenges CP is a very effective system under the right conditions.

For ASTs that have tank bottoms in direct contact with a conductive pad, CP can completely mitigate soil-side corrosion. However, the tank floor-to-soil interface is complex and often includes air gaps where the bottom plate has buckled or the sand has settled. Since the sand carries the CP charge, the presence of such gaps shields the CP current from reaching the metal surface. Another challenge is the

52

continuous increase in sand pad dryness over time, which reduces the amount of CP current needed to achieve the required level of polarisation at the interface of tank bottom plates. The presence of shielding material such as asphalt or oily or bituminous sand in the tank pad renders the CP system only partially effective.

Another challenge faced in CP protected tanks is the feasibility of retrofitting the existing CP system in the presence of a non-conductive release preventive layer such as highdensity Polyethylene (HDPE) liners. Retrofitting a defective CP system on an existing AST can be physically labour intensive, time-consuming, and costly, requiring the entire tank to be jacked up in order to access the area below. This may be done simultaneously with tank re-bottoming, which itself carries an expensive price tag in the millions of dollars.1 Both retrofitting and tank bottom replacement are best avoided, if possible, by more comprehensive protection in the first place that includes the complementary action of volatile corrosion inhibitors (VCI) such as CorroLogic VpCI. The inability to activate the CP system during construction of ASTs, which can take anywhere from several months to several years until the tank is commissioned, leaves the tank floor at risk of soil-side corrosion and eventually impacts the actual service life of the tank. This is an area where VCI can provide the necessary protection for the tank floor against soil-side corrosion until the CP system is commissioned.

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In cased pipeline crossings a section of pipeline passing underground is placed in a steel casing or sleeve to protect it against mechanical stresses from the road or railway above. It is also used to provide a means of removing and replacing the pipe section without the need for excavating the road. The use of a steel casing creates an annular space where cathodic protection cannot be used to provide protection for that section of the pipeline.

Benefits of VCI technology VCI Technology has been gaining increasing acceptance over the last two decades or so as a complementary corrosion prevention methodology to CP. In 2021, this culminated in the publication of the API TR 655 technical report, which provides details on utilising VCIs for protection of tank bottoms against soil-side corrosion.

Section 7 of this technical report highlights the synergistic effect between CP and VCI and the effect of VCI on soil resistivity, as well

Put Down Your Work Gloves.

as the possible considerations to be taken into account by owners and tank operators when both systems are combined.2 VCIs are marked by their ability to sublimate from solid to vapour form and diffuse through void spaces. They have an affinity to metal that allows them to adsorb onto surfaces such as tank bottoms and create a molecular layer of protection against soil-side corrosion. Cortec Corporation has tailored this technology for use in oil and gas industry applications under the name of CorroLogic.

CorroLogic VpCI is based on salts of amine carboxylates that present a low environmental impact and are designed specifically for application in difficult to reach voids underneath tank bottom floors or in pipeline casings. Because CorroLogic VpCI is able to diffuse through sand and space, it is ideal for complementing CP systems in areas of deficiency.

CorroLogic VpCI comes in several forms including CorroLogic Powder, CorroLogic Slurry, and CorroLogic VpCI Filler. The first two can be applied during any stage of an AST’s life: new, in-service, or out of service.

CorroLogic VpCI Filler is a version designed for injection into casings at pipeline crossings. For AST applications, CorroLogic application often includes four main system components: ) Vapour corrosion inhibitor products (i.e. CorroLogic Powder or CorroLogic Slurry depending on the application methodology).

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) Corrosion monitoring system to

monitor the corrosion before and after introduction of VCI material. ) A chime area seal system to close the gap

between the annular plates and the ring wall. ) Delivery and replenishment network

to apply and replenish the content of vapour corrosion inhibitors when needed, during the service life of the solution.

Thus, CorroLogic VpCI provides a lifetime solution by allowing for application, corrosion rate monitoring, and reapplication with minimal invasion on new or existing tanks.

Logical companions?

A logical approach to protecting against corrosion on AST bottoms and cased pipeline crossings would be to combine both CP and VCI technologies to achieve comprehensive protection. In areas where a tank floor is in direct contact with a conductive tank pad, CP will provide full protection. In areas where CP cannot reach (e.g., AST bottom air pockets, cased pipeline crossings), or when electricity is unavailable, CorroLogic VpCI offers protection.

As such, CorroLogic serves as an important backup to the standard approach. The question

Table 1. Corrosion rates on lab tanks with and without CP, pre- and post-VCI injection is, are both systems compatible since they both affect CP status Tag Corrosion Corrosion Percentage the electrochemistry of the tank floor? number rate pre-VCI rate post-VCI reduction Several studies have been conducted to answer (mpy) (mpy) this question. In a research work published at the TK-01 15.44 6.39 59% NACE International CORROSION 2016 Conference & OFF TK-02 10.73 0.91 92% Expo, six lab scale tanks were constructed to simulate TK-03 15.44 0.40 97% actual tank construction with an HDPE liner, ICCP (impressed current cathodic protection) system, and TK-04 2.52 0.29 88% ER (electrical resistance) probes. Three tanks had their ON TK-05 3.80 0.29 92% CP system turned off, and the other three tanks had TK-06 3.50 0.40 88% them turned on. The tanks with their CP system off showed an average corrosion rate of 13 mils per year (mpy) on ER probes, while tanks with CP on showed an average corrosion rate of 3 mpy on ER probes, demonstrating a clear benefit from the CP system. In the second phase of the research, all six tanks were injected with VpCI liquid. The corrosion rate of ER probes in non-CP tanks dropped to an average of 3 mpy. In CP tanks, ER probe corrosion fell to 0.3 mpy. The results indicated that maximum protection was achieved by combining both systems (see Table 1).3 Further study suggested that VCI chemistry can work as a cathodic polariser to reduce the amount of cathodic protection current required.4 However, a sequel study testing two other VCI chemistries found that one worked as a cathodic polariser.5 This underscores the importance of consulting with CorroLogic engineers to ensure the right VCI chemistry is chosen for best Figure 1. Aboveground pipelines are redirected underground results when pairing VCI with CP.

CorroLogic vs retrofit A recent CorroLogic installation shows how advantageous CorroLogic can be for protection of in-service ASTs. When a large oil company realised that one of their in-service tanks had an ageing CP system that might not provide sufficient corrosion protection, they evaluated different soil-side corrosion mitigation techniques, comparing CorroLogic VpCI with the option of retrofitting the CP system – in this case, a sacrificial system.

Retrofitting the tank with an equivalent CP system would have been technically challenging as it required horizontal directional drilling in straight lines under the tank while avoiding the remnants of the legacy system – not to mention navigating around the sump and any other buried facilities under the tank. While the CP engineer may have been able to design such a retrofit system, the contractor who would have installed the system highly doubted its feasibility.

In contrast, the CorroLogic system did not require extensive civil works and accordingly diminished the risk of interacting with other systems under the tank. This was a huge benefit to the client from a safety and quality perspective. Commercially, the Cortec system was found to be less than half the overall price of the CP retrofit system, although a single dose of CorroLogic was estimated to have half the design life (10 vs 15 yrs) of a CP retrofit. However, the CorroLogic system could be periodically monitored after installation and VpCI material added if needed to replenish the system after five, 10, or even 15 years. The cost of additional material represents only a fraction of the original total system cost, meaning over a 20 year time period, the CorroLogic system would still be more commercially viable compared to a CP retrofit, thus providing an excellent complement to CP at the end of its service life.

at road crossings and placed in casings to protect them from the weight of the road. CP is generally not viable here; however, CorroLogic® VpCI® Filler presents an exciting alternative protection option. Image courtesy of Cortec® Case History 628.

Figure 2. Illustration shows the complex tank floor-to-soil interface and where CP current loses contact with the tank floor and the role of VCI in supplementing CP performance. Image courtesy of Cortec Middle East.

Figure 3. Holes were drilled (and later sealed) to allow injection of VpCI in the form of CorroLogic Slurry. Image courtesy of Cortec Southeast Asia.

MARCH 2022 / World Pipelines

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Figure 4. Injection of CorroLogic Slurry beneath an in-service storage tank. Image courtesy of Cortec Southeast Asia.

The client opted for CorroLogic, injecting CorroLogic Slurry beneath the tank and installing a long-term corrosion monitoring system.6 At the end of a little more than one year, the overall corrosion rate had already dropped by 77%, from 1.85 mpy to 0.42 mpy, on average.7

Conclusion As can be seen, VCI quite literally fills significant gaps in the standard cathodic protection system. Because of its vapour phase action, VCI can protect voids where the CP current is not able to reach — whether in air pockets beneath the tank or in cased pipeline crossings where there is no electrolyte. CorroLogic can provide substantial cost savings as a workaround to avoid the challenges of CP retrofitting on existing tanks. It also has promising indications of potential synergy when used in conjunction with CP. Either way, VCI is an excellent and logical companion to CP for corrosion protection of AST bottoms and cased pipeline crossings.

References 1.

IFC 2.

SCAIP S.p.A.

Bound insert

Stark Solutions Weldfit Winn & Coales International World Pipelines

3.

29 OBC 7

4.

5.

IBC 6.

7.

AL GHAFRI, A., et. al., ‘Successful Implementation of a Corrosion Management Strategy

by Online Injection of Vapor Phase Corrosion Inhibitors to Extend Storage Tank Floor Life,” Paper No. 11428, CORROSION 2018 Conference & Expo, NACE International, Houston, TX. American Petroleum Institute, ‘Vapor Corrosion Inhibitors for Storage Tanks,’ API Technical Report 655, First Edition, April 2021, Washington, D.C. ABED, K., PANCHAL, P., GANDHI, A., ‘Evaluation of Impressed Current Cathodically Protected API 650 Tank Bottoms in the Presence of Vapor Phase Corrosion Inhibitor,’ Paper No. 7600, CORROSION 2016 Conference & Expo, NACE International, Houston, TX. PYNN, C.R. and ABED, K., ‘Compatibility & Interactions between Cathodic Protection and a Vapor Phase Corrosion Inhibitor,’ Paper No. 9232, CORROSION 2017 Conference & Expo, NACE International, Houston, TX. ABED, K.M. and PYNN, C.R., ‘A study on the Effect of Volatile Corrosion Inhibitors on Impressed Current Cathodic Protection,” Paper No. 11030, Corrosion 2018 Conference & Expo, NACE International, Houston, TX. Cortec® Corporation, ‘CorroLogic® for In-Service Aboveground Storage Tank,’ Case History 758, February 2022, Saint Paul, MN. Internal Cortec® Southeast Asia report, October 2021.

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