World Pipelines July 2022

®

Volume 22 Number 7 - July 2022

TCII HiRes Caliper A Step Up in Your Toolkit

The leading innovator supplying cutting-edge integrity solutions. Together we can ensure sustainable decision-making. Our combination of advanced inspection systems and expert consultants delivers a comprehensive understanding of asset safety, lifetime, and performance.

Comprehensive Asset Integrity Management

www.rosen-group.com

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CONTENTS WORLD PIPELINES | VOLUME 22 | NUMBER 7 | JULY 2022 03. Editor's comment

35. Embracing ultra-high-resolution

James Lavender, North America Business Development Manager, ENTEGRA, USA.

05. Pipeline news

Updates on new oil and gas pipelines, new US crude lines and gas storage in Europe.

PIPELINE EQUIPMENT 40. Making a stand

Ken Pilidis, Proline Pipe Equipment, Canada.

REGIONAL REPORT 8. Scaling up production

COVER STORY 44. A step up

As many jurisdictions suffer as a result of the Ukraine war, Latin America is experiencing some inadvertent benefits, Gordon Cope writes.

Calvin Silver and Scott Hansen, GeoCorr, USA.

As many jurisdictions suffer as a result of the Ukraine war, Latin America is experiencing some inadvertent benefits, Gordon Cope writes.

T

he Ukraine war is having a multitude of disastrous effects around the world.

The consequences for South America, however, are different; as the EU, the US and other jurisdictions abandon Russian imports of natural gas, crude and refined products, producing nations south of the border have the opportunity to pick up the slack.

Calvin Silver and Scott Hansen, GeoCorr, USA, explain the results from a push for ‘smarter’ caliper technology by industry-leading transmission companies that propelled the steps to better data.

Venezuela

G

Venezuela has been the pariah of Latin America for several decades, following the rise of Hugo Chavez and the continuation of his regime under Nicolas Maduro. Production in the world’s largest crude reserves has fallen from over 3 million bpd in 2005 to approximately 500 000 bpd in 2020. But that may be about to change.

For the last several years, the US has imposed tough sanctions on Venezuela in an attempt to topple the Maduro regime. The moves drove the country into the arms of China and Russia, which worked to help dodge the sanctions.

After Russia invaded the Ukraine, the Biden administration announced it would ban the import of Russian oil, about 1 million bpd. Subsequently, the White House made overtures to Venezuela. While most USGC refineries are configured to use heavy crude and would benefit from a resumption of Venezuelan imports, the move is also seen as an attempt to drive a wedge between Russia’s and Venezuela’s geopolitical alliance.

Steps to ease sanctions should have a positive impact on Venezuela’s oil and gas sector. Thanks to mismanagement of the economy and corruption, the infrastructure is in decrepit condition, with breakdowns and leaks from pipelines and storage facilities fouling the land and surrounding international waters. Estimates for repairing the entire sector’s infrastructure exceed US$200 billion.

eometry inspections continue to lead the way when initiating your baseline integrity assessments. While thousands of runs are conducted over the global market, evolving technology continues to drive this industry forward. While we become smarter at earlier stages within the pipeline’s life, this helps protect these assets, address anomalies, and improve integrity decision-making.

GeoCorr’s new TCII HiRes Caliper with IMU is a step up in your tool kit, whether at pre-commissioning of a pipeline or for geohazard and dent strain assessments on in-service lines.

System design and architecture

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DECARBONISATION 13. A surge in solutions for decarbonisation

Rachel Schelble, Head of Corporate Carbon Management and Infrastructure, Wood Mackenzie, USA.

15. Pathways to decarbonisation

Janka O’Brien, Director of Sustainability, MEA, Emerson Automation Solutions, UAE.

Tackling the new high-resolution market, the TCII HiRes caliper system was designed to accommodate two caliper arms per dia. in. (Figure 1). Every tool diameter, 3 in. through 56 in. would see this new standard. The inline inspection system would serve to meet the rugged expectations of new construction applications, while setting a new standard with sensitivity and detection by employing this new caliper sensor technology.

The digital sensor technology has reduced the signalto-noise ratio by a factor of 10, and widened the sensor’s usable range to 100% of the available mechanical travel. This has allowed for exceptional sizing accuracy and increased confidence in low percentage features within the 0 - 2% OD range. In conjunction with the geometry sensor technology, the odometer system can be linearly sampled at user-selected

1 - 4 mm based on application requirements. With resolution more than doubling on direct wall caliper sensors, and the linear sampling more than doubling as well, confidence levels and accuracies are at an all-time high.

With these expanded capabilities, the TCII has been tackling a wide range of applications: ) Early detection and identification of anomalies and mechanical damage occurring during construction. ) Dent strain analysis where better data capture on geometry/

caliper data provides a more accurate evaluation of your ASME B31.8 strain results and anomaly shape. ) Dual and multi-diameter applications – previous Dual Dia.

Technology had sensor limitations. A compromise was typically given to the larger diameter pipe with regards to sensor measurement, coverage, and accuracy. Major improvements to measurement linearity throughout both pipe diameters have been achieved in dual-diameter applications with up to a 6 in. difference in pipeline OD. Proof of concept work was executed through 2020 with in-house development and testing split between GeoCorr’s production headquarters and engineering team. During system validation, extensive calibration procedures were carried out along with in-pipe testing. Using the high-resolution digital

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FLOW 50. Keeping up with demand Jesse Yoder, PhD, Flow Research, USA.

PIPELINE STEELS 53. Repurposing, re-using, recycling

Nick McNally, Commercial Director, Decom Engineering Ltd, UK.

PIGGING FOCUS 18. Pigging in the cloud Jason Farqué, CDI, USA.

29. Grounded in safety

Neil McKnight, Senior Business Development Manager, T.D. Williamson, UK.

31. A clean sweep

Barry Ritchie, International Pipeline Products t/a iNPIPE PRODUCTS™, UK.

®

Volume 22 Number 7 - July 2022

GeoCorr's latest advancements have led to the engineering and deployment of this innovative TCII HiRes Caliper technology. The drive for development allows detectability down to 0.25 mm, also improving linear and circumferential resolution using the latest in microchip technology. This ‘smarter’ pig meets the most stringent new construction specifications set by industry-leading transmission companies. www.geocorr.com

A Step Up in Your Toolkit

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U

K Prime Minister Boris Johnson is facing criticism for a willingness to break international law in a bid to protect the British steel industry.

He has signalled that controls on steel imports that were due to expire in late June could be retained. Speaking at the G7 summit in Germany in late June, he said that keeping the import controls on foreign steel would protect British producers, who are already under pressure from rising energy prices. “We need British steel to be provided with much SENIOR EDITOR Elizabeth Corner cheaper energy,” Johnson said. “But until we elizabeth.corner@palladianpublications.com can fix that, I think it is reasonable for UK steel to have the same protections that absolutely every other European steel economy does.”1 The Prime Minister is expected to announce that existing tariffs on Chinese steel will be maintained, even if this breaches trade obligations.

Lord Geidt, Johnson’s ethics adviser, resigned in mid-June, allegedly in part over Johnson’s openness to breaking international law in this instance, which he viewed as a deliberate and purposeful breach of the ministerial code.

Following the resignation of Lord Geidt (formal title: Independent Advisor on Ministers’ Interests), David Gauke, the former Conservative justice secretary tweeted: “So much for Brexit being about ‘free trade’ as the PM loses his ethics adviser because of a desire to break WTO rules in order to put illegal tariffs on steel.”2 Let’s break that down a bit: the limits on steel imports being considered were first introduced by the European Union (EU) in 2018, in response to tariffs imposed by the Trump administration in the US. These controls were mirrored by the UK after it left the EU (Brexit).

The restrictions add a tariff to steel imports once a certain quota has been reached, and are known as ‘steel safeguards’ because they protect the domestic market from an influx of cheap steel from overseas. The controls are currently in place for 15 categories of steel. Controls protecting 10 of those categories have already been extended to 2024, but import limits on five categories are set to expire on 30 June 2022.

In a letter responding to Lord Geidt’s resignation, the Prime Minister said he had sought advice on the use of tariffs for “protecting a crucial industry”, which “might be seen to conflict with our obligations under the WTO”.3 Johnson appeared to suggest in his letter that overruling the UK’s Trade Remedies Authority (TRA) could conflict with the UK’s WTO obligations – essentially a form of international law.

Set up under post-Brexit reforms to advise on trade policy, the TRA had told the government in June 2021 that nine out of 19 tariffs the government had imposed on steel imports could be removed because there was no evidence that British producers were being hurt by cheap foreign imports. It said tariffs on steel plates used by ship builders and tin used in cans, as well as barbed wire and steel rods for reinforcing concrete, could be scrapped. It said the taxes could be extended on other products, including metalliccoated sheets, railway material, and large welded tubes used for energy pipelines.

For more on pipeline steels, turn to p. 53, where Decom Engineering considers the status of the global steel sector and argues for repurposing, re-using and recycling of steel oil and gas infrastructure.

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2.

3.

www.bbc.co.uk/news/business-61944665 twitter.com/DavidGauke www.theguardian.com/politics/2022/jun/16/boris-johnson-says-ethics-adviser-resigned-over-steel-tariffs-row

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WORLD NEWS

Wood Mackenzie: Russia supply reduction via Nord Stream poses risks to gas storage refill in Europe Russia reducing flows via Nord Stream, outages at Freeport and French nuclear downgrades have sent the European natural gas market into an upward spiral with more volatility still to come.

And while summer consumption will be covered, analysts at Wood Mackenzie, a Verisk business, say storage refill is at risk unless additional demand and supply measures are taken.

Kateryna Filippenko, Principal Analyst, Global Gas Research for Wood Mackenzie said: “The uncertainty is high. Freeport and French nuclear downgrades offer some degree of predictability, but Gazprom’s supply into Europe is the biggest unknown. If Gazprom restarts flows via Nord Stream at full capacity, although we believe this is unlikely, and Russian flows are at contracted levels, Europe would theoretically still be able to refill the storage to the 80% target by 1 November – even with Freeport outages and nuclear downgrades.”

But if Nord Stream continues flows at 45% capacity, or if it stops altogether, Europe will only be able to refill storage partially – to 69% and 60% respectively, which is considerably

lower than the five-year range for European gas storage.

“If Gazprom continues restricting flows, in both cases storage will runout throughout winter unless other demand or supply measures are taken, or Gazprom sends additional gas via available booked capacity via Ukraine, although we believe this is very unlikely,” Filippenko said.

In Europe, additional demand measures could include further energy saving measures and fuel switching. From the supply side, measures could consist of increasing production at Groningen in the Netherlands, and additional Norwegian and Algerian gas – although their impact will be limited.

High prices resulting from the restrictions will inevitably lead to a reduction of Asian gas demand, freeing up some LNG for Europe – although limited regas capacity in continental northwest Europe will limit upside, something the industry has already observed in recent months. Any Nord Stream reductions will increase prices further, inevitably leading to more demand reduction in both Asia and Europe.

GlobalData: India to lead upcoming transmission pipeline length additions India is expected to lead in terms of global trunk/transmission pipeline length additions for planned and announced projects, contributing around 20% of the global planned and announced pipeline additions by 2026, according to GlobalData, a data and analytics company.

GlobalData’s latest report, ‘Oil and Gas Pipelines Length and Capacity and Capital Expenditure (CapEx) Forecast by Region, Countries and Companies including details of New Build and Expansion (Announcements and Cancellations) Projects, 2022 - 2026’, reveals that India is set to have a planned pipeline length of 23 839 km, and an announced pipeline length of 5095 km by 2026.

Sudarshini Ennelli, Oil and Gas Analyst at GlobalData, comments: “Kandla–Gorakhpur is the largest upcoming pipeline project in India, with a length of 2809 km. Expected to start operations in 2024, the pipeline project would serve LPG bottling facilities in the states of Gujarat, Madhya Pradesh, and

Uttar Pradesh to meet rising demand for the commodity.”

China ranks second globally in terms of transmission pipeline length additions, with a planned and announced pipeline length of 17 810 km by 2026. The Xinjiang– Guangdong–Zhejiang SNG gas pipeline is the longest upcoming pipeline project during 2022 to 2026, with a proposed length of 8972 km. Expected to start operations in 2026, the pipeline will help China meet its ever-growing demand for natural gas.

Ennelli concludes: “The US stands third globally with a planned and announced trunk pipeline length of 12 305 km by 2026. The Seahorse oil pipeline is the longest upcoming pipeline in the country, and is slated to begin operations in 2026. The 1127 km length pipeline would run from Cushing, Oklahoma, to a refinery in St. James, Louisiana. It would also supply crude oil to a liquid storage terminal planned near the Mississippi river for exports to international markets.”

EIA database: Two new US crude oil pipeline projects have been completed this year As of 3 June 2022, pipeline companies completed two crude oil pipeline projects in the US, according to the EIA’s recently updated Liquids Pipeline Projects Database.

No new hydrocarbon gas liquids or petroleum product pipeline projects were completed in the first five months of 2022.

The completed crude oil pipeline projects are: )) Energy Transfer Ted Collins Pipeline, a 275 000 bpd pipeline that transports crude oil along the Gulf Coast from the Nederland terminal to the Houston Ship Channel, which are both in Texas. )) Energy Transfer Cushing South Phase II, a 55 000 bpd

expansion of the Cushing South project. The Cushing South project includes three existing Energy Transfer

pipelines, and a reversal and interconnection with the Centurion pipeline that transports crude oil from terminals in Platteville, Colorado, and Cushing, Oklahoma, to Energy Transfer’s terminal in Nederland, Texas. Phase I was completed in 2Q21.

The EIA’s Liquids Pipeline Projects Database compiles information on more than 250 future, ongoing, and past liquids pipeline projects in the US. The database dates back to 2010, and it contains a number of details on expanded, reversed, converted, and new pipeline projects.

Two announced projects and two under-construction projects are scheduled to come online later this year. As of June 2022, an additional 13 projects have been permanently cancelled, and 2 projects have been put on temporary hold. The current status is unknown for five projects.

JULY 2022 / World Pipelines

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CONTRACT NEWS EVENTS DIARY 5 - 8 September 2022 Gastech

Milan, Italy www.gastechevent.com

19 - 23 September 2022

IPLOCA 2022 annual convention Prague, Czech Republic www.iploca.com/events/annualconvention/2022-convention

22 - 23 September 2022

Subsea Pipeline Technology Congress 2022 (SPT 2022) London, UK www.sptcongress.com

27 - 29 September 2022 IPE 2022

Calgary, Canada internationalpipelineexposition.com

19 - 20 October 2022

Hydrogen Technology Expo Bremen, Germany www.hydrogen-worldexpo.com

24 - 30 October 2022 bauma

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

31 October - 3 November 2022 ADIPEC

Abu Dhabi, UAE www.adipec.com

16 November 2022

Global Hydrogen Conference 2022 VIRTUAL www.globalhydrogenreview.com/ghc22/

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World Pipelines / JULY 2022

Orbital Sidekick wins Energy Transfer Permian Basin contract Orbital Sidekick (OSK) has been selected by Dallas-based Energy Transfer to monitor its assets in the Permian Basin through satellite technology. Energy Transfer selected OSK to monitor its Permian Basin assets as part of its Partnership-wide pipeline integrity programmes.

OSK’s satellite technology enables earlier detection and prevention of leaks along pipeline ROW, using hyperspectral data analysis to drive broad improvements in community safety, environmental performance, and overall operating efficiency.

“Energy Transfer’s selection of Orbital Sidekick is a testament to our asset monitoring solution addressing a real and emerging market need,” Daniel Katz, CEO and Co-Founder of OSK, said. “Operators at Energy Transfer are able to assess the integrity of its pipelines daily, for a

Craig International wins major contract with INEOS FPS Aberdeen-headquartered Craig International has secured a major contract with INEOS FPS, potentially valued at over £20 million.

Following a competitive tender, the global energy procurement specialist has been awarded a five year contract (with two year options) to deliver consolidated procurement services to INEOS FPS. This includes the supply of maintenance, repair and operations equipment for its Grangemouth base which operates the Forties Pipeline System.

Craig International will service the contract from its Aberdeen headquarters using its bespoke digital platforms: ebuy and ecobuy.

These innovative digital platforms provide cost and efficiency savings through the streamlining of electronic processes and the ability to source globally and supply locally. This is backed-up by an advanced ecobuy platform to help customers reduce their carbon footprint.

Jill MacDonald, Joint Managing Director of Craig International, said: “We are thrilled to welcome INEOS FPS to our extensive portfolio of companies supporting the North Sea’s offshore energy industry, after a rigorous and competitive tendering process.

“Our e-commerce and approach to sustainability were major factors in this contract award. As the industry ramps up efforts to support global net-zero targets, there is a growing recognition that procurement plays a crucial part in reducing carbon emissions.”

reasonable price point and in a more sustainable fashion.” Further, Peter Weaver, OSK’s Vice President of Business Development, said “Energy Transfer is an ideal partner to stretch our capabilities to meet the next level of industry demands.”

Upon deployment of OSK’s GHOSt constellation, beginning late 2022/early 2023, OSK will offer frequent monitoring of pipeline assets to the global oil and gas industry through its SIGMA Platform. OSK’s technology will help the industry meet its compliance and regulatory obligations, as well as help transition towards more sustainable operations.

Energy Transfer is one of the largest energy infrastructure companies in North America, with more than 120 000 miles of pipeline. OSK is the first company to commercially deploy hyperspectral sensors in space.

THE MIDSTREAM UPDATE •

Phillips 66 publishes 2022 sustainability report

•

TUBACEX secures largest ever award

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EN Engineering collaborates with G2-IS’ GIS Services

•

Wood announces the appointment of new CEO

•

ExxonMobil on Biden’s letter to oil industry

•

TC Energy showcases ESG initiatives

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T

he Ukraine war is having a multitude of disastrous effects around the world.

The consequences for South America, however, are different; as the EU, the US and other jurisdictions abandon Russian imports of natural gas, crude and refined products, producing nations south of the border have the opportunity to pick up the slack.

Venezuela Venezuela has been the pariah of Latin America for several decades, following the rise of Hugo Chavez and the continuation of his regime under Nicolas Maduro. Production in the world’s largest crude reserves has fallen from over 3 million bpd in 2005 to approximately 500 000 bpd in 2020. But that may be about to change.

For the last several years, the US has imposed tough sanctions on Venezuela in an attempt to topple the Maduro regime. The moves drove the country into the arms of China and Russia, which worked to help dodge the sanctions.

After Russia invaded the Ukraine, the Biden administration announced it would ban the import of Russian oil, about 1 million bpd. Subsequently, the White House made overtures to Venezuela. While most USGC refineries are configured to use heavy crude and would benefit from a resumption of Venezuelan imports, the move is also seen as an attempt to drive a wedge between Russia’s and Venezuela’s geopolitical alliance.

Steps to ease sanctions should have a positive impact on Venezuela’s oil and gas sector. Thanks to mismanagement of the economy and corruption, the infrastructure is in decrepit condition, with breakdowns and leaks from pipelines and storage facilities fouling the land and surrounding international waters. Estimates for repairing the entire sector’s infrastructure exceed US$200 billion.

8

As many jurisdictions suffer as a result of the Ukraine war, Latin America is experiencing some inadvertent benefits, Gordon Cope writes.

9

Chevron, the only western oil company still operating in Venezuela, is lobbying Washington to increase its allowed scope of activities. Investment in pipelines and other decaying assets may prove an unexpected boon.

Guyana In April 2022, ExxonMobil announced new discoveries in its Stabroek Block in offshore Guyana, boosting reserves to 11 billion boe. Currently, the company and its partners are producing 130 000 bpd at its Liza Destiny FPSO vessel, and scaling up production at its Liza Phase II FPSO, with a capacity of 220 000 bpd. Two other projects, the Payara (220 000 bpd), and Yellowtail (250 000 bpd), are under construction. In all, a total of 10 projects are planned.

While FPSOs obviate the need for crude pipelines, longer-term plans may include natural gas infrastructure.

The 11 billion boe reserve estimates include approximately 20% in the form of natural gas. The Guyanese government has announced plans for a natural gas power plant near the capital of Georgetown; at least 100 km of offshore lines would be needed to bring the gas ashore.

The light, sweet crude being pumped makes it relatively easy to create high-quality fuels in European refineries; ExxonMobil estimates that Guyana’s output could hit 1.2 million bpd by 2027, helping displace Russian imports.

Brazil Brazil has been going through profound changes over the last several years, as legislation to both reduce Petrobras’s monopoly control and to liberalise the oil and gas sector has resulted in major shifts in all aspects of its energy infrastructure.

First and foremost is the growth of presalt offshore crude output. Brazil currently produces approximately 3 million bpd, with 97% of that originating offshore. While Petrobras accounts for the majority of all production, international partners are gaining ground due to the promotion of independent operations and joint venture projects. In early 2022, Petrobras signed agreements to share production at the major offshore fields of Atapu and Sepia with TotalEnergies, Qatar Petroleum, Petronas and Shell, among others.

Brazil relies heavily on hydropower for domestic electricity needs, but recurrent drought has reduced reservoirs to critical levels. Brazil produces 4.7 billion ft3/d of natural gas, with 3.3 billion ft3/d coming from presalt fields. About 2.1 billion ft3/d of the latter is reinjected, however, making it difficult to meet domestic energy needs.

President, Jair Bolsonaro enacted the New Gas Market in 2021, scheduled for implementation in 2022. The initiative is designed to unlock Brazil’s offshore gas potential and open access to the country’s three main transportation networks operated by TAG, NTS and TBG; extensive expansion of gas infrastructure will be necessary to achieve long term goals of increasing volumes and decreasing prices.

Delivering offshore gas to the mainland is key.

Federal agencies have mapped out a total of 11 gas lines

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World Pipelines / JULY 2022

to connect various offshore fields to onshore facilities.

One of the projects involves a JV between Equinor and Repsol Sinopec to co-develop the BM-C-33 presalt field, located 200 km offshore of Rio de Janeiro state. The gas/condensate field will be produced using an FPSO with a capacity of up to 125 000 bpd of crude and 500 million ft3/d of gas. The former will be exported via carriers, while the latter will be processed and integrated into the onshore gas transmission network that emanates from the Petrobras TECAB site at Cabiúnas. If all goes to plan, marketable natural gas production is expected to increase to 6.1 billion ft3/d by 2025.

As for the impact of the Ukraine war, the US has been in discussions with Brazil to help stabilise the international market; the Energy Ministry expects exports to rise from 1 million bpd in 2021 to as much as 1.2 million bpd in 2022, as crude output expands by an estimated 300 000 bpd over the course of the year. Multi-billion dollar plans are also underway to expand export terminals and related infrastructure.

Mexico Much of recent oil and gas related news coverage in Mexico has been focused on the efforts of populist President, Lopez Obrador (AMLO) to re-nationalise the energy sector by suspending lease auctions, building new refineries, reducing crude exports and prioritising statechampion Pemex over international companies.

But that obscures the fact that the largest expansion of its natural gas pipeline network has been occurring over the last decade. As CFE (the state electricity utility) switches aging power plants from bunker fuel to natural gas, a major transmission network has been growing to allow gas from the US Gulf coast states to flow south.

According to the EIA, US exports to Mexico averaged 6 billion ft3/d in 2021, and are growing at a rate of 12% annually. There is currently over 11 billion ft3/d of export capacity; the latest addition has been the Whistler pipeline, which added 2 billion ft3/d between the Permian Basin and the Agua Dulce hub in southern Texas, that serves trans-border transmission lines.

Once it reaches the border, major lines carry the gas south to urban regions. Mexico-based Fermaca recently completed the final leg of its 5 billion ft3/d Wahalajara pipeline network stretching from Waha, Texas to Guadalajara.

And much remains to be done; CFE and TC Energy are planning to extend the country’s natural gas network to the Yucatan peninsula. A new offshore pipeline will be built from the Tuxpan terminal in the state of Veracruz to connect to the Mayakan pipeline system in the states of Campeche and Tabasco.

Several headwinds threaten to slow domestic growth, however. AMLO has introduced constitutional reform legislation that would cap foreign ownership in the electricity sector, restricting investment.

Environmental and Indigenous concerns, as well as stalled negotiations with CFE, continue to delay projects; TC

Energy has repeatedly postponed the completion of its 886 million ft3/d Tula-Villa de Reyes natural gas pipeline.

One positive development has been the rise of LNG. Sempra Energy’s Energía Costa Azul (ECA) LNG in Baja California, is located just south of the US border.

A former LNG import site, it is already connected to existing pipelines. The 2.5 million tpy train, scheduled for completion in 2024, will use an estimated 370 million ft3/d. The Mexico Pacific Limited (MPL) project is located south of ECA on the Sea of Cortez in Sonora State. The plan is to build three trains totalling 14.1 million tpy. Cargoes are likely to go to Asia, offsetting demand pressures to Europe.

The high crude prices associated with the turmoil surrounding the Ukraine war are unlikely to abate soon, and are having an impact on highly-indebted Pemex. In 1Q22, the state firm saw profits rise to US$6 billion, the highest in at least 18 years.

Argentina Paradoxically, producers in Argentina cannot take advantage of surging commodity prices. Government controls cap the price of crude at US$60/bbl, roughly half of international prices, in order to protect domestic consumers.

That hasn’t stopped them from rapidly expanding production. The unconventional Vaca Muerta formation in Neuquen province contains up to 16 billion bbls of recoverable crude and over 300 trillion ft3 of gas.

With only 10% of the reserves under production, the play already produces 910 million ft3/d of natural gas and 136 000 bpd of crude. Analysts estimate that unconventional resources could help double Argentina’s output to 1 million bpd by 2026, increasing exports from current levels of 100 000 bpd to over 500 000 bpd.

The growth in production has led to a need for more pipeline infrastructure. Currently, Neuquen province is served by the 260 000 Oldelval pipeline, which connects Neuquen to Puerto Rosales in Buenos Aires province. The operator has announced plans to spend US$500 million to almost double capacity to 500 000 bpd. The 100 000 bpd Otasa pipeline, which runs 400 km from Neuquen province to a 116 000 bpd refinery in Chile, is currently mothballed, but plans are underway to recommission it by late 2022.

Shell Argentina is building a 120 000 bpd crude line between Neuquen and Rio Negro province, scheduled to enter service at the end of 2022.

As for natural gas, the extended drought in Brazil has placed severe constraints on its hydropower capacity, motivating the country to investigate continental sourcing with Argentina. The latter government has announced plans to build a 1.5 billion ft3/d line from Neuquen province to Brazil; the first stage is expected to come online in 2023.

High LNG prices have also spurred Latin America’s industry leaders to discuss Greenfield projects. Pan American Energy has proposed a US$15 billion facility to supply Argentinian LNG to countries looking to reduce

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supplies from Russia. Pipeline operator TGS said it has plans to supply feedstock to the project.

Colombia Prospects for Colombia’s oil and gas sector are looking up. After several adversarial years (including COVID-19, insurgents and mass protests in oil-producing regions), investment in the sector is expected to climb from a low of US$2 billion in 2020 to US$4.4 billion in 2022. In March 2022, Baker Hughes reported that 31 rigs were actively exploring in the country, up from half that two years ago.

Although Colombia’s heavy sour crudes are discounted by refineries seeking lighter alternatives, buoyant commodity prices are proving a boon to a country that relies on crude exports to earn approximately 20% of government revenues.

Much still needs to be done. Colombia’s crude reserves remain stuck at 1.8 billion bbl, enough to keep production of 750 000 bpd going for another six years.

Attacks on crude infrastructure, including the 210 000 bpd Caño Limón-Coveñas oil pipeline running from the Colombia-Venezuela border to Colombia’s Caribbean port of Coveñas, continue to plague exports. In June 2022, Gustavo Petro was elected president; during his campaign, he vowed to stop issuing oil exploration licenses, and gradually phase the sector out.

Hydrogen The world currently produces around 75 million tpy of hydrogen, primarily using the steam-methane reforming process, where high-temperature steam is used to strip hydrogen from natural gas. The International Energy Agency (IEA), estimates that greenhouse gas emissions associated with the production amounted to roughly 830 million tpy of CO2e; many jurisdictions, including the EU, have announced plans to increase green hydrogen production through the use of renewable energy and electrolysis, which emits no CO2.

The invasion of the Ukraine has super-charged those plans. Countries such as Germany, which relies heavily on Russian gas, are keen to accelerate the development of alternative fuel sources. The EU recently announced a €300 million hydrogen funding package aimed at reducing the dependence on Russian gas, by ramping up the current target of 3 million short t by 2030 to 15 million t. While the potential for Latin America to produce CO2-free hydrogen is huge, so far, only a few projects have been announced; Australian firm Enegix plans to take advantage of northeast Brazil’s abundant wind and sunshine by constructing a 600 000 tpy green hydrogen plant in Ceará state.

In conclusion, while the Ukraine conflict has created inadvertent benefits to South America’s oil and gas sector, many challenges remain. Jurisdictions will need to deal with domestic issues (such as regulatory regimes, fiscal incentives and corruption), in order to beneficially develop the continent’s vast natural resources. Regardless, the potential for new transportation infrastructure in Brazil, Argentina and Guyana over the next decade remains huge.

Rachel Schelble, Head of Corporate Carbon Management and Infrastructure, Wood Mackenzie, USA, discusses the ways in which midstream operators can fuel the energy transition.

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he midstream oil and gas sector is doing more than just transporting CO2 from A to B in the race to decarbonise. The industry is at the forefront of developing new value chains and evaluating novel business models as they facilitate the shift to new low-carbon energy sources. They are testing the limits of their pipelines for CO2 transportation, developing new pipelines to decarbonise the US Midwest, and driving innovative solutions for CO2 extraction and storage. They are doing this all while balancing fiscal discipline and sustainable investment principles in a nascent new business with no tried-and-true returns.

Midstream early movers in decarbonisation Companies with existing CO2 transportation and processing infrastructure – like Occidental Petroleum, Denbury, and Kinder Morgan – are natural early movers in the race to decarbonise. Oxy stores up to 20 million tpy of CO2, with over 2500 miles of CO2 pipelines, 13 CO2 recovery plants and more than 6000 CO2 injection wells across 34 Permian Basin EOR projects. Oxy is progressing technology to extract CO2 directly from the air, a process known as direct air capture (DAC), with its first plant operational in the Permian Basin in 2024.

Kinder Morgan is the largest transporter of CO2 in North America, shipping up to 1.5 billion ft3/d of CO2.

Its 1500 mile pipeline system in New Mexico and Texas is connected to natural CO2 sources at McElmo Dome, Doe Run and Bravo Dome, which have consistently provided CO2 for Permian Basin enhanced oil recovery (EOR) projects, previously for conventional fields, but now also for unconventional resources. Kinder Morgan’s CO2 business has consistently generated positive returns, and it is evaluating carbon capture, utilisation and storage (CCUS) opportunities along its entire infrastructure footprint.

Denbury has over 1300 miles of CO2 pipelines, and a strategically important CO2 infrastructure footprint in the US Gulf Coast. It has executed agreements for over

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7 million tpy of CO2 for transportation and storage, and are working to repurpose water injection wells for CO2 injection into the subsurface. Denbury has pipeline expansion projects planned for 2023 that will grow their CCUS business into the future.

New CO2 pipeline projects

The economics supporting the CO2 value chain are at an early stage. Tax incentives like the 45Q tax credit in the US are encouraging some companies to build new CO2 transportation infrastructure. The 45Q tax credit provides US$35 - US$50/t of CO2 to companies that build infrastructure to capture CO2 and store it in the subsurface. There are three planned pipelines that will connect CO2 emissions from industrial plants in the Midwest to subsurface geological storage.

Summit Carbon Solutions is developing the Midwest Carbon Express CO2 pipeline that will span over 2000 miles across Iowa, Minnesota, Nebraska, North Dakota, and South Dakota with an estimated cost of US$4.5 billion. The pipeline aims to collect 10 million tpy of CO2 from 31 industrial CO2 sources and store the CO2 subsurface in North Dakota. 2022 will be a pivotal year for Midwest Carbon Express as it works to get permits approved for the project. Recent investors include Continental Resources and Tiger Infrastructure Partners.

Blackrock and Valero partnered with Navigator Energy Services in 2021 to build the 1200-mile Heartland Greenway CO2 pipeline, which is estimated to cost US$3 billion. Open season commitments on the pipeline were sufficient for the project to reach Final Investment Decision (FID) approval in 2021.

Additional Midwest industrial facilities continue to sign up for transportation on the pipeline which will transport up to 15 tpy of CO2. Construction will begin in 2024 along approved routes, and the pipeline will be fully operational in 2025.

Less details have been released regarding the collaborative pipeline project being designed by Archer Daniel Midlands (ADM) and Wolf Carbon Solutions. The 350 mile pipeline will be dedicated to ADM’s industrial CO2 waste and is planned to have a capacity of up to 12 million tpy of CO2. CO2 will be transported for subsurface sequestration in Illinois.

The limits of repurposing infrastructure and the power of partnerships Repurposing existing infrastructure is an obvious opportunity for midstream operators. CO2 must be transported in a super critical phase, which can place limitations on the types of infrastructure that can be re-purposed. This constraint requires CO2 pipeline pressures to be in the range of 1200 - 2200 psi.

Crude pipelines are designed for pressures that generally range from 600 to 1000 psi, which makes them less than ideal candidates for CO2. Natural gas pipelines are generally designed for pressures between 500 and 1400 psi, which leaves more opportunity for converting these pipelines for CO2 transportation.

Naturally, there will be a cost associated with re-purposing midstream infrastructure, and without a price for carbon, it will be a challenge for midstream operators to build confidence in the investment case. Converting natural gas pipelines for CO2 transportation may be possible in some cases, but the

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trade-off is that natural gas sales generate revenue, while CO2 sales do not, unless the CO2 is being used for EOR. It may be that creative partnerships between upstream and midstream companies help to crystallize the value proposition.

The midstream sector provides much needed transportation expertise to an upstream oil and gas industry trying to decarbonise.

Enlink Midstream and Talos announced a Memorandum of Understanding (MoU) in February 2022 to jointly develop the River Bend carbon capture and sequestration (CCS) project in Louisiana’s Mississippi River Corridor. The project will leverage Enlink’s Midstream expertise and existing pipeline infrastructure to provide decarbonisation solutions for industrial CO2 emitters in Louisiana, with subsurface storage at the River Bend CCS facility. Enlink plans to repurpose natural gas pipeline infrastructure to facilitate the project, which is already signing up CO2 shippers.

In September 2021, Enterprise Product Partners announced plans to partner with Chevron New Energies on CCUS opportunities for joint development in the US Midcontinent and Gulf Coast. The partnership started with a six month evaluation phase looking at opportunities for collaboration. Enterprise has an extensive midstream pipeline and storage network, which combined with Chevron’s subsurface knowledge, is poised to deliver new and innovative decarbonisation solutions.

In Canada, Enbridge has partnered with Lehigh Cement to progress CO2 storage solutions in Alberta. At Lehigh’s Edmonton plant, it is working to develop full-scale CCUS solutions for the cement industry. Captured emissions will be transported and stored in the subsurface by Enbridge, with a goal of capturing up to 780 000 tpy of CO2. The project could be in service as early as 2025.

Carbon sequestration economics and carbon offsets As companies work to tackle the economics of CCS, they are testing every lever that they may have available. The 45Q tax credit is one option available to companies, but the evolving carbon markets offer another potential economic pathway. New methodologies for carbon sequestration have recently been approved for carbon offsets. Both Verra and the Gold Standard have approved methodologies for CO2 sequestration in concrete building materials. Updated methodology to support offsets for CCUS projects that store CO2 in oil and gas reservoirs was approved by the American Carbon Registry in September 2021.

Final thoughts The midstream oil and gas industry can provide infrastructure solutions that will enable the energy transition. The economics of the nascent CO2 value chain are still largely untested. But early indications show that there is enough incentive for the midstream to act. Tax incentives like the 45Q tax credit, the carbon markets, and creative partnerships with the upstream are catalysing an entrepreneurial mindset amongst midstream operators. Making the connections between the different parts of the CO2 value chain will propel the industry to surge ahead with solutions for decarbonisation well into the future.

Janka O’Brien, Director of Sustainability, MEA, Emerson Automation Solutions, UAE, considers opportunities to store, transport and distribute hydrogen.

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he oil and gas industry are going through a massive transformation towards sustainability and decarbonisation. While we see several initiatives at play towards more sustainable operational practices by operators and oil and gas end users, there continues to be much to do in order to meet net-zero targets.

Even with the emergence of newer energy sources such as solar and wind, there is consensus that the molecule form of energy is here to stay – we are transitioning from coal to oil to natural gas as the primary drivers of global energy, and are approaching the beginning of a new wave of energy through emerging value chains such as hydrogen.

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The emissions problem As operators look for opportunities to progress their sustainability journeys – the focus shifts to oil and gas pipelines. Much of traditional emissions measurement and reduction focus has been around the operating plant, yet oil and gas pipelines have one of the highest methane emissions profiles across the value chain – not just with oil pipelines, but also with gas pipelines. This is an interesting situation, as gas is broadly seen as a ‘cleaner’ fossil fuel and a transition fuel as the world shifts to net-zero. In fact, across the natural gas value chain, pipeline transport is a key source of emissions, especially for older pipelines and networks. To add context and scale to this problem – it is estimated that the global length of oil and gas pipelines transportation networks is approximately 1.8 million km long, enough to circle the earth 30 times over.

Roadmap towards emissions reduction First and foremost, pipeline operators must have quantified emissions reductions targets; according to a DNV survey that was conducted across global pipeline operators, as many as 63% have quantified goals around reducing emissions by at least 50% by 2050.

From here, an operational roadmap towards emissions reduction can begin with the low hanging fruit: Fugitive emissions and leaks through flanges, valves and packaging material. Regular inspection, maintenance and upgradation of packing material to minimise leaks are key routes to reducing emissions.

Many gas pipelines still utilise gas operated valves, which vent gas to the atmosphere. There are several ways to address this; these valve operators can be upgraded to reduce bleed, modified to operate on instrument air (via volume tanks) or to return gas back into the pipelines or to electric actuators altogether. This reduces emissions on a per-use basis and can make a sizeable dent on emissions over the lifetime of the pipeline.

Similarly, optimal leak detection systems across transmission pipelines also holds promise of reducing greenhouse gas emissions, particularly in the case of gas pipelines, through early identification that can prompt remedial approaches. There are several technology approaches to leak detection that range from real-time detection, periodic surveys to computational and real-time model-based systems that can be deployed.

Finally, vapour recovery systems can be utilised to recover light hydrocarbons or gases from liquids that are removed by pigging operations. Gases rich in hydrocarbons tend to condense liquids in gathering systems upstream of gas gathering and processing plants. These pipelines are periodically pigged, and condensate is removed and moved to a lowpressure storage tank. The liquids during recovery flash and vent light hydrocarbon gases from the storage tanks – vapour recovery systems can both reduce emissions, but also improve pipeline throughput.

A broader look at energy use As pipeline operations build momentum around the use of operational technology to reduce emissions, operators must

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take a holistic view of the energy use of the entire pipeline.

Good examples of these are compressors and pumping systems, which are key equipment that ensure the efficient functioning of the pipeline. The right asset performance and condition monitoring programme can help compressors and pumps run most efficiently, and therefore consume the lowest energy to operate.

Hydrogen: the transformative opportunity Hydrogen is a very versatile fuel that has a variety of use cases, from transportation to heating to long-term energy storage and can serve as an energy vector to other green chemicals such as ammonia and methanol. The global opportunity for green hydrogen is expected to be worth US$11 trillion by 2050, according to Goldman Sachs.

Despite the opportunity, one of the key barriers to success lies in the lack of dedicated infrastructure to store, transport and distribute hydrogen. Building new transport infrastructure depends on detailed planning and approvals which are both time and cost sensitive.

Here, existing gas pipeline networks are now being seen as a potential substitute to building new hydrogen pipeline infrastructure. In order to repurpose existing pipeline infrastructure, it needs to be re-assessed for readiness and there would be potential modifications the existing pipeline design. For example, compressor requirements for hydrogen transport will be quite different to traditional gas transport.

Similarly, some metal pipes can degrade when they are exposed to hydrogen over long periods, particularly with hydrogen in high concentrations and at high pressures. This effect is highly dependant on the type of steel and must be assessed on a case-by-case basis. Emerson has non-intrusive corrosion sensors that can be deployed to test the integrity of existing gas pipeline networks while transporting hydrogen.

Another opportunity that is relatively quick to deploy and is seeing large traction globally, is the blending of hydrogen with existing natural gas to create a blend with relatively high calorific value but a smaller emissions footprint when compared to pure natural gas. Several countries in the EU allow for between 2 - 6% of hydrogen to be blended with natural gas. Emerson is working with customers to provide fully integrated solutions that help in the blending of hydrogen into existing natural gas transmission networks. These consist of gas chromatographs to measure the purity of the hydrogen being blended, Coriolis meters to measure the quantity of the hydrogen being injected, and Fisher control valves to carefully tune the hydrogen blend.

Conclusion There are several approaches to sustainability and decarbonisation across existing transmission pipelines: from solutions that help reduce emissions to transformative opportunities such as hydrogen transport and hydrogen blending, Emerson is working with customers to take incremental steps towards emissions reduction and sustainability, and navigate the transition towards a future hydrogen economy.

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Jason Farqué, CDI, USA, explores capabilities and value proposition for the cloud-based virtualisation of pigging operations.

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ipeline pigging projects are streamlined and made more transparent at all phases and to all stakeholders with cloud-based virtualisation and mapping of pigging operations.

Cloud-based software platforms which send and receive data and images from ground-based AGMs, signalers, tracking equipment, and personnel can provide near real-time pig positions and status during pigging operations.

Pipeline pigging operations created in such online platforms have a high degree of reusability – permanently capturing man-hour investments in all aspects of the survey and run process providing strong ROI. Safety is enhanced as the number of personnel required to be present on a pipeline is reduced. Pig passage events are automatically transmitted to the cloud 24 hours a day, and pigging activity can be monitored and commented on from anywhere.

Managers can coordinate and monitor multiple jobs simultaneously, further reducing the number of man-hours consumed by a single run. Safety is increased as stakeholders can receive instant notification of changes to a project as well as potentially hazardous developments such as inclement weather, nearby lightning strikes, heat/cold/UV alerts, and more.

Run virtualisation and recording provide unique techniques unavailable to traditional pigging operations. For example: should a pig become stuck, operators have the unique ability to ‘rewind’

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a run’s state to the precise moment when pressures spiked, getting a snapshot of the pipeline at that instant.

Permanent database storage of completed runs allows for easy reference to previous work and provides for rapid comparisons of multiple runs year-over-year and can lead operators to identify developing problems on their lines.

Introduction In 2020, Control Devices, Inc. (CDI) began the development of a comprehensive cloud-based web service that provides pipeline pig tracking project management, scheduling, tracking, and reporting services. This system, GlobalTrack™,

has at its core the ability to monitor and simulate the movements of up to three tools at any one time within a pipeline, as well as to provide project stakeholders with near-real-time access to all of this information during a run.

These basic pig tracking, run simulation, and monitoring functions are further enhanced by a wide range of capabilities that bring the entire workflow from the initial pipeline survey to post-inspection reporting into a single centralised repository.

The consolidation of this large workflow, coupled with pig passage detection equipment that provides swift and automatic updates of passage events via satellite and cellular networks, has several benefits to be explored.

The internet of things and pig tracking

Figure 1. CDI’s satellite-equipped AGM.

Over the last few years, communication technologies such as cellular networks and satellite transceivers have allowed for the creation of remote tracking and locating equipment that can broadcast detection events through the internet.

Unfortunately, the cost of owning and operating these systems, coupled with the remoteness of many pipelines and implicit lack of infrastructure along them, has meant that their use was confined to projects where both the infrastructure allowed, and the costs could be justified.

The rise of the internet of things (IoT) and its need for tiny devices to transmit and receive small amounts of data to end users, has created an enormous market for lowpower internet-connected systems. As major electronic firms have entered the IoT market with everything from thermostats to automobiles, the number of connected devices has risen to many billions.

The large IoT market has raised the market cap of, and created significant increased competition among, the satellite and cellular communications companies.

Figure 2. Global internet connected IoT devices (in billions) projected through 2025.

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ability to visually track any number of pigs simultaneously, while at your desk performing other work, is a powerful tool.

2) Risk management and safety It has become increasingly difficult to justify the expense of, and risk to, non-essential personnel on work sites – especially in the post-COVID world. Pulling much of the task of pig tracking into the cloud means fewer people on the pipeline, resulting in a savings of both time and risk.

Figure 3. CDI GlobalTrack™ showing passed pipeline (green), pig location (red).

3) Globally distributed talent pools Having live pig tracking in the cloud allows companies to pull the best talent from virtually anywhere in the world. No longer are companies constrained to hiring personnel that can be physically onsite – the work can come to them.

Pig tracking, primarily aboveground marking for intelligent inspection tools, has unique logistical challenges. Cloud-based pig tracking provides a number of tools that a tracking contractor or pipeline operator can mix and match to streamline their work and to help further mitigate risk.

Real-time tracking of a project from anywhere With the use of a standard web browser, users with proper credentials can see a project’s progress from anywhere in the world. This means that managers and field personnel alike share a real-time view of any number of runs in progress. Pigs’ movement through a pipeline and their projected locations, as well as points that have successfully reported a passage time, are all viewable in a generic web browser.

Figure 4. Storing images of tools, AGM locations, etc. in the cloud permanently attaches them to the run and ensures they are available for references indefinitely.

These market forces have lowered the pricing of wireless communications systems significantly, directly benefiting pipeline pig tracking systems.

Advantages of tracking in the cloud There are many compelling reasons to bring the process of tracking pipeline pigs into the cloud. The strongest of them are: 1) Time savings Upper management and the integrity managers of a pipeline have a high demand of their time during peak inspection seasons. It is not always practical to be onsite for routine launches and receives. While text groups and phone calls can keep management informed, having the

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Centralised data storage Data generated through the survey of and tracking on a pipeline is captured into a central repository and saved indefinitely. Cloud services can be used as references to gauge the performance of pigs and tracking services runover-run and year-over year.

Photographs, site sketches and notes pertaining to the work on the line can be entered into and captured by

GlobalTrack. Notes can be attached to individual tracking points and might hold information such as a gate code, landowner’s telephone number, etc. Photographs of the condition of tools pre and post-run can also be quickly and permanently recorded as part of the job as seen in Figure 4.

Virtualised tool tracking By building upon the massive capabilities of Google Maps and Google Street View, it is possible to project a pipeline route along with the location of launchers, receivers and AGM points in the browser window, allowing for true virtual pig tracking.

From one’s office, Google Street View allows for realtime tracking of the tool along the ground as though you were there. In Figure 6, we see a valve site in the extreme background with a blue AGM icon illustrating the location of the AGM device. In the foreground, we see a grey line representing the pipeline and a red dot which indicates the location in real-time of the pig within the line.

As the simulation moves the tool along the pipeline, the red dot is shown moving at its proper speed.

Figure 5. Remote asset performance monitoring.

Time spent developing a survey and project with a cloud-based system can be re-used any number of times, thus capturing those costly man-hours.

Centralised information

Inventory and asset management

A cloud-based approach to pipeline AGM and tracking work allows for much or all of the information regarding a project to be stored in, and managed by, the software.

Since the information is stored in the cloud, it is broadly accessible anywhere in the world to individuals with proper credentials.

Inventory of any kind of pipeline pigging tools can be managed by the software. Having tool inventory in a cloud-based service means that scheduling of tools, their refurbishment status, and all aspects of the tool itself can be viewed by anyone anywhere, provided they have the proper credentials.

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Further, allocating assets to projects with a cloudbased system means that the software can ensure that equipment is not required to be on different jobs at the same time, and technicians can flag devices in an equipment pool as unavailable for use when they are being refurbished or repaired.

To further reduce and help manage risk, cloud-based pig tracking systems can track the location of assets, such as equipment and vehicles on the line. Should equipment become lost or stolen, it’s location can be retrieved and viewed on the map.

Internet connected devices can have many parameters of their performance monitored from remote. Their internal temperature, humidity, battery level, and GPS location can be known. This information can be used in a variety of ways to troubleshoot and generally monitor the performance of these devices.

Personnel monitoring The movements of tracking crews on a pipeline are extremely important. For tracking crews, it is extremely useful to know, without texting or calling on the phone, the location of other members of a team. This knowledge increases their safety and situational awareness.

Cloud-based systems can retrieve the GPS location of in-field users and display them on the map in real-time.

Weather forecasting and alerts

Figure 6. Real-time street view from within CDI GlobalTrack of an AGM’s location (background, blue dot), pipeline route (grey), pig’s real-time location (foreground, red).

Since a project’s start-date is known to the system, weather forecasting allows cloud-based tracking services to present relevant information about upcoming inclement weather.

Forecasting can be useful to caution field personnel that the environment is particularly hot or cold. For example, automated text messages and emails can advise that the temperature is going to be below freezing or that the ultraviolet light index for a run date is going to be harsh.

CDI GlobalTrack, for instance, has the ability to see lightning strikes with 5 min. resolution anywhere in the world. Should lightning strike near the pipeline all stakeholders,

Figure 7. CDI provided remote tracking services to this pipeline through difficult mountainous terrain.

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including those in their offices, can receive a text message that they should exercise caution.

These types of automated notifications regarding the changing conditions on a pipeline provide decision-makers with useful and actionable data.

A case study of the benefits of remote cloud-based tracking A European pipeline operator approached CDI with a problem. They were seeking a way to track pigs over extremely mountainous terrain with real-time Figure 8. GlobalTrack UI showing an inspection run in progress with radar weather information. feedback of their tool’s location 24 hours a day.

For this project, the operator was faced with a two day intelligent inspection run which required four tracking teams working in 12 hour shifts. The terrain was extremely mountainous with very poor access and with little to no communications; the safety of tracking teams working in those conditions, and in the dark of night presented a serious safety problem.

CDI provided remote cloud-based pig tracking of satellite-equipped AGM units, which allowed for the number of teams to be cut in half, and for all the equipment to be preset and placed during daylight hours in the days before the tool run.

Real-time cloud-based pig tracking meant that the operator was able to monitor the progress of the inspection tool – from the launcher to the receiver – from the safety of their offices.

Figure 9. The author’s location displayed in Broken Arrow, Oklahoma.

Stakeholders for this project were spread throughout both Europe and North America.

Once the run was complete, the operator was able to generate a full report before the AGM units were Conclusion even retrieved, and the deployed devices were retrieved at Tracking pigs from one’s office has long been an his leisure. unattainable dream for many of CDI’s customers.

In this case, the operator was not only able to reduce Technological advancements and the falling prices of his overall cost by cutting the staff required to track the communications systems have finally made this dream a tools in half, but satellite feedback from the AGMs also reality. allowed the position of the tool to be known by all of A full-featured cloud-based pig tracking system the stakeholders at all times, rather than only when the not only makes this possible, but also allows for costtracking teams were within cellular range. savings and risk reduction to be achieved. Automated Because the inspection tool would have been out of communications and passage detections further reduce communication for several hours at three mountainous the possibility of human error, increasing overall job points along the pipeline, the continuous and automated satisfaction of owner/operators. tracking provided by the satellite equipped AGMs and As the benefits of cloud-based pig tracking software cloud-service yielded a reduction in the overall stress level become more widely known and realised, CDI expects that of everyone involved. This is difficult to quantify. the use of such systems will become the norm.

JULY 2022 / World Pipelines

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Neil McKnight, Senior Business Development Manager, T.D. Williamson, UK, discusses pigging in the hydrogen take-off.

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overnments and policy makers are increasingly turning to hydrogen to counter the twin challenges of carbon emission reduction and energy security. Plans for hydrogen-carrying pipeline networks are being expedited and expanded. It’s clear, however, that repurposing existing gas lines must form a significant portion of this effort, as much as 60% in the case of Europe. As such, hydrogen will be increasingly present in pipelines in the coming decades.

In anticipation, the industry has focused on finding ways to protect pipeline infrastructure from degradation associated with hydrogen exposure, including embrittlement of commonly used pipe materials. But we have to be equally committed to safeguarding the people working onsite, including those who execute pigging operations.

Hydrogen risks Pigging delivers the diagnostic and remediation solutions to keep pipeline networks healthy. As pipelines are converted from methane to hydrogen, any legacy flow assurance and integrity issues not completely rectified will be carried forward. In these instances, pigging with hydrogen present in the line will be necessary.

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In any pigging operation, launching and receiving pigs is the most safety-critical aspect, requiring breaking of containment and introducing the potential for volatile gas mixtures to form. The properties of hydrogen exacerbate these risks. Compared to methane, hydrogen has a significantly larger flammability range, far lower ignition energy and is difficult to contain, with a propensity to find leak paths. Hydrogen’s lower calorific value means that to

deliver equivalent energy, pipelines will need to be operated at higher pressures and flowrates.

Competence and controls How do we begin to mitigate hydrogen risks for safe pigging operations? Optimised worksite and equipment design, an informed and educated workforce and robust operational controls are a sound foundation. ) Personnel must have the opportunity to understand the hazards of working with hydrogen and receive written plans regarding the operation, management and maintenance of the worksite. )) Proper ventilation and the elimination of ignition

sources are priorities. It’s also important to consider neighboring activities as potential sources of ignition or impact. )) Before attempting any insertion or retrieval of pigs,

critical valves must be fit for purpose and validated as not bypassing. The same level of verification should apply before mobilising any temporary equipment.

Figure 1. The strongest defences begin with design.

)) Once a pig is moving through the line, hydrogen’s low

density and compressibility make it more difficult to control tool velocity and can exaggerate speed excursions. This must be carefully managed to ensure they reach the receiver in a controlled manner. )) Debris that is displaced intentionally by cleaning tools

or unintentionally during inspection or isolation can create additional hazards. Pyrophoric black powder can auto-ignite in the presence of air when the pig trap closure is opened, and high volumes of debris in the receiver can result in undetected trapped pressure. )) It is standard practice in methane lines to purge Figure 2. Pigging plays a central role in pipeline integrity management and optimising throughput.

launchers and receivers with inert gases to displace volatile gas mixtures. Hydrogen increases the window of possibility for an explosive atmosphere to be present and the effectiveness of this process must be confirmed. Additional diligence is needed due to hydrogen’s volatility when displacing and venting.

Recompression or controlled flaring is required.

Safety equals success

Figure 3. Launching and receiving is the most safety critical aspect of any pigging operation.

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We are entering an era of rapid expansion of hydrogen into pipeline networks. Currently, if hydrogen is in a pipeline it will be operated by industrial gas specialists with suitable expertise and planning of operations.

However, as we see a democratisation of hydrogen into our broader gas networks, exposure will become part of our pigging crews’ regular work. It is paramount that this transition achieves its necessary goals without critical incidents involving frontline workers. As an industry we need to share knowledge, plan appropriately and educate our operational teams.

Barry Ritchie, International Pipeline Products t/a iNPIPE PRODUCTS™, UK, presents a product intelligence and cost saving solution to pigging.

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n pipeline transportation, pigging is the practice of using pipeline inspection gauges, gadgets or devices generally referred to as pigs or scrapers. These practices include, but are not limited to, pipeline cleaning, maintenance and inspection operations without stopping the flow of the product within the pipeline.

These operations include cleaning and inspecting the pipeline. This is accomplished by inserting the pig into a ‘pig launcher’ (or ‘launching station’) – an oversized section in the pipeline, reducing to the normal diameter. The launching station is then closed and the pressure-driven flow of the product in the pipeline is used to push the pig along the pipe until it reaches the receiving trap – the ‘pig catcher’ (or ‘receiving station’).

Pig refurbishment The pig refurbishment process receipts pigging tools from the pipeline operator post-run to conduct a full overhaul service, comprising of tool cleaning, stripping, inspection, performance assessment, spares replacement, refurbishment, testing and recertification. The pigging tools are thereafter ready to be re-utilised for another cleaning run in operational condition, and configured to the optimal engineered solution for pipeline maintenance. The inspection data and reports are

logged within the online management system. Each person has a personalised log in which improves visibility of the pigging tool fleet and current condition, whilst also providing the option to remotely access the data via a mobile phone or tablet app.

This pig refurbishment service has helped customers make significant savings on pigging costs, whilst also receiving the required engineering expertise to optimise their pigging operations.

Pig performance assessment Pig performance assessments are based on data gathered during operational pigging and refurbishment records. An assessment of the pig condition, run performance and pipeline data is conducted to ensure the pig design and bypass configuration selected was successful, and future designs are the optimal solution for cleaning performance and flow assurance in current pipeline conditions.

Engineering support services Pig design studies In addition to the pig performance assessments discussed above, iNPIPE PRODUCTS™ frequently carry out pig design

31

studies to provide suitable designs for long term condition maintenance or pre-inspection pigging campaigns. For pipelines which have not been previously pigged, these studies typically include confirmation of the basis of design, and a review of all key pipeline parameters and features, followed by development of concept pig designs for client review. If required, the study may also include an assessment of suitable bypass configurations. These may be documented in a technical report, including a summary of the design considerations, CAD models of the pigs in key pipeline features, recommendations for any factory acceptance testing, and concept test rig designs.

For pipelines which have an existing pig fleet, the design report will discuss the advantages and disadvantages of

changing the pig designs, and will highlight any recommended changes to the pig configuration based on the current or expected pipeline operating parameters.

Pigging strategy documents iNPIPE PRODUCTS develops pigging strategy documents for pre-inspection cleaning campaigns, routine maintenance pigging, and remediation of pipelines where regular pigging has stopped. Where necessary, these strategies will follow a progressive approach, including decision trees which can be used to assist in pig selection. The pigging strategy will also identify data which should be collected from each pig run and may include sample data sheets.

Operational pigging procedures From the pigging strategy document, any required work scopes and operational procedures can be developed.

For pipelines with permanently installed pigging facilities which are not frequently used, iNPIPE PRODUCTS will often recommend that the existing pig trap operating procedure is reviewed before the pigging campaign begins, to ensure the trap is fully operable and no changes are required to the procedures. Where there is a requirement to use temporary pigging equipment, including pump spreads, additional chemical injection or water crossed over from platform process to boost flow rates, iNPIPE PRODUCTS can generate a revised operational procedure as required, including stepped procedures for installation, pressure test, flushing and disconnection of the equipment.

Pipeline intelligence services Pig fleet management for routine maintenance cleaning provides a platform for the development of a project specific pigging programme, such as pre inline inspection (ILI) or decommissioning. Utilising the experience gained and the confidence from the pig refurbishment process, a pigging programme can easily be developed with minimised risk and, in addition, be validated by the available pipeline intelligence products.

Pipeline intelligence services Pipeline calipering A pipeline pigging-based inspection tool developed primarily to measure pipeline parameters such as ovality, dents, features, misalignment and buckling. Mainly utilised for the pre-commissioning of pipelines, the process is necessary to ensure that a pipeline can safely transport products when in operation. This process examines several factors of a pipeline, including integrity.

Debris mapping

Figure 1. iNPIPE PRODUCTS™ 28 in. Black Powder Cleaning pig complete with memory wire brush assemblies.

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World Pipelines / JULY 2022

Using unique sensor and data logging technology, a debris mapping tool records the location and quantity of debris in a pipeline to allow a pipeline operator to safely and cost effectively manage internal cleanliness by optimising pipeline cleaning. This tool is mainly used for pre-ILI, or periodically as part of a flow assurance strategy.

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Figure 2. Light weight, high-tensile aluminium bodied scrapers designed for 242 km gas pipeline with black powder debris.

Figure 3. iNPIPE PRODUCTS 36 in. magnetic cup pig with lightweight aluminium body.

pigs. Based on the clients shared pigging reports, the previously selected tools (provided by others) had experienced excessive wear to the 4 to 7 o’clock position and brushes.

The client was obviously concerned with the level of wear and therefore limited cleaning efficiency of the tools. iNPIPE PRODUCTS developed a high tensile, lightweight tool with a unique disc package incorporating variable bypass, jetting heads, memory wire brush heads.

Based on assessment of the disc wear, by the client, it was confirmed that the tools had travelled in a centralised plane, with no ‘nose-diving’. Black powder is known to be highly abrasive and a growing concern for clients globally. iNPIPE PRODUCTS unique design and manufacturing capabilities enables the company to develop designs based on asset specific requirements and clients KPI’s to improve both asset integrity and product throughput.

Working on a similar brief, iNPIPE PRODUCTS was approached by one of Europe’s biggest oil and gas producers, who required assistance with a pigging programme to systematically remove condensate and black powder from a 36 in. line.

The purpose of the bespoke design was to control the amount of condensate and black powder removal at any one time; too much brought out by the pigging run could have resulted in receiving problems, and health and safety handling/disposal issues, for example.

Following the technical review of the client project requirements, iNPIPE PRODUCTS designed, engineered and supplied 36 in. magnetic cup pigs with lightweight aluminium bodies, which ensured progressive and controlled pigging. Similar pigging issues with differing client considerations can alter designs and pigging concepts dramatically.

Pig fleet management key beneficiaries

Camera vision

Customer

Utilised mostly in water filled pipelines, the camera vision provides video evidence that the caliper and debris mapping tools assessments are verified in a live system.

))

Cost savings on project management.

))

Information available via internet or mobile app.

Environmental data logger

))

Detailed reports and certification available.

The environmental data logger is designed for installation within pigs, and registers changes in pressure and temperature of the pigging medium, overloads and shocks arising from the movement of the pig through the pipeline, as well as recording pressure changes across the pig.

Contractor ))

Additional data received to analyse run effectiveness.

))

Streamline pig fleet to reduce customer costs.

Case studies

))

Progressive cleaning programme: FEED, manufacturing and testing

Optimise pigging tool capabilities against current pipeline conditions.

Pipeline asset

iNPIPE PRODUCTS was approached to provide a design and manufacture a solution that removes black powder.

Upon review of the details and discussion with the client, it was established that they had previously run standard

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World Pipelines / JULY 2022

))

Information available when out of office via internet or mobile app.

))

Detailed reports and certification available.

James Lavender, North America Business Development Manager, ENTEGRA, USA, discusses ultra-high-resolution ILI and the detection, identification and sizing of seam-weld corrosion.

A

s new technological frontiers have expanded, so has the technology within the pipeline industry. The phone you hold in your hand is more powerful than most computers of the early 2000s. The same is true for the technologies behind axial magnetic flux leakage (MFL) inline inspection (ILI) technology.

Many misperceptions still exist about the ability of MFL to deliver – particularly with regard to seam detection as well

as POD, POI and sizing of seam-weld corrosion – but in truth, the capabilities of MFL, and the ability to extract nuanced data from it, have grown exponentially beyond what was previously thought possible. This includes the all-important area of seam-weld assessment.

Driving this rapid improvement? The advent of ultrahigh-resolution (UHR) technologies backed by human-based insight, vision and analysis which are able to extract more

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knowledge from the data itself. The ability of operators to see more and know more about their pipelines allows them to address these anomalies accordingly and keep their assets running safely.

The problem: seam-weld assessment As operators know, metal loss that interacts with a pipe’s long seam can pose imminent integrity threats. Especially considering that this is one of the most consequential areas of a pipe while remaining among the most difficult to accurately assess.

Differentiating metal loss as coincidental or preferential to the seam allows the pipeline operator to more efficiently prioritise their dig programme. Unfortunately, there is a myriad of variables such as different seam types, the age of the pipe, manufacturing methods, construction and welding processes, and other factors impacting an accurate assessment of this area.

With so many factors impacting an accurate, efficient MFL inspection of seam-welded pipe, it is easy to see why misperceptions of MFL performance remain, even to this day.

Prior to UHR technology, axial MFL was limited to detection of volumetric anomalies with widths 10 mm or greater and, therefore, axial narrow irregularities required a much larger width for detection. The traditional train of thought was that the axial magnetic field had reached its technical limit of performance. It was once believed that sensor density and overall performance could not overcome the perceived shortcomings of axial MFL. Today’s axial UHR MFL has advanced well beyond the limitations encountered by past technologies. UHR is not only capable of detecting the seam, but goes beyond, identifying different types of seam welds.

It also can detect, identify, and size anomalies on those welds to allow operators to address them accordingly and keep their assets running safely, smoothly and cost effectively.

The solution: ultra-high-resolution There is not an industry standard for what constitutes UHR which has led to the term being overused and, in some applications, mis-used.

To begin with, true UHR MFL tools contain a higher number – and concentration – of primary axial sensors. True UHR technology also boasts a larger number of secondary sensors like ID/OD. Finally, the UHR MFL/Cal combo tool includes an array of caliper sensors so dense and sensitive, it can map the surface of the ID wall (Figure 1). This gives the UHR platform an incredible POD and POI on all aspects of anomalies detectable by MFL technologies – and some previously considered virtually impossible to detect.

State-of-the-art electronics are also distinguishing factors in determining whether or not a platform in question is truly UHR. True UHR collects data in a manner never before seen, delivering extremely high sampling rates and allowing for the collection of two to three times the amount of sampling data vs traditional Axial MFL. Innovation in design and engineering is also a key differentiator. It’s not all sensors and electronics, but also the mechanics of the tools themselves. New-generation UHR tools not only have more dense sensor arrays and higher-speed data sampling, but are also shorter, lighter and more collapsible. Their design and fabrication physically reduce chattering in the line, which in return reduces the vibration and noise on the sensors, allowing for a smooth, comprehensive – and accurate – collection of UHR data.

Knowledge vs wisdom There is an old adage: “knowledge is knowing that a tomato is a fruit, but wisdom is knowing not to put tomato in a fruit salad.” So, too, with trying to understand the difference true UHR technology backed by human-experience based analysis can make to an ILI.

Figure 1. Correlating features across multiple datasets: note on this image how the primary and secondary sensors map the presence of scale in the line. You can clearly see how the UHR caliper sensors do a great job supporting and adding data to map the scale in the line.

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World Pipelines / JULY 2022

An innovative, true UHR AMFL system delivers the knowledge, but that is just the beginning. A unique DA system is a must have. It provides nuanced assessments and recommendations – wisdom – based on that knowledge.

That is why automation alone and black box DA assessment cannot replace human experience-based insight and deduction.

The proof is in performance The journey to seam assessment begins with the seam type.

For most, seam assessment means to look for anomalies on or around the seam, but it is more than that. It’s not just about anomalies, but also about defining the type of seams in question. Knowing if you have an ERW, flash welded, DSAW and any other type of seam can provide valuable information about a pipeline operator’s assets. For example, seam types are often used in materials identification and records matching.

Another important aspect of seam assessment is the clock position within the pipe. A key part of construction, this must be offset to provide another layer of defence for the pipeline integrity, and it is also a common tool used to confirm location on dig verifications.

As shown in Figure 2, true axial UHR technology can easily detect both seam and clock position. Also, it can recognise the manufacturing differences between ERW and DSAW, where DSAW has enough nuance to be classified as such.

The UHR advantage Many MFL technologies have a much wider sensor spacing and struggle not only with seam detection but also with Figure 2. Detecting the seam across pipe types: while the correctly identifying the location of ML on the seam and/or difference between ERW, flash welded and DSAW can be subtle, adjacent to it. A more-dense, UHR sensor array allows for a UHR and expert data analysis can help to identify differences on seams such as those shown. Lap welded is a notable exception clear detection and distinction of the seam location and the because of lack of volume in this manufacturing method. anomalies that surround, cross or otherwise interact with the seam.

Combining this UHR technology with Table 1. POD and POI for seam types a human-experience based DA process, as Probability of detection Probability of identification mentioned, allows for the classification of these (POD) (POI) anomalies according to their true interaction – or Pipe type Yes No Maybe No Maybe Yes lack thereof – with the seam. Similar to what an LF ERW • • AI process or algorithm would do in this case, the first distinction would be ‘if’ yes/no and if HR ERW • • yes, ‘how’.

Once the distinction has been made ‘if’ Flash welded • • the anomaly indeed interacts with the seam DSAW or not, the next step is to define the ‘how’.

• • For this step, the analyst must truly define and Spiral • distinguish if these anomalies are metal loss • crossing or interacting closely with the seam, or SSAW • • if it is traveling axially on the seam, and indeed preferential/selective metal loss.

Lap welded • • While these classifications might not create a big change on the repair approach, they are a key Key: factor for the future integrity programme of the Yes: POD > 90% Yes: POI > 90% Maybe: 50% ≤ POD ≤ 90% Maybe: 50% ≤ POI ≤ 90% pipeline and one that must be considered. This No: POD < 50% No: POI < 50% process requires a nuanced application of analysis

JULY 2022 / World Pipelines

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Table 2. POD and POI for anomalies on seam Probability of detection (POD) Feature type

Yes POD > 90%

No POD < 50%

Probability of identification (POI)

Maybe 50% ≤ POD ≤ 90%

Yes POI > 90%

No POI < 50%

Maybe 50% ≤ POI ≤ 90%

Metal loss Corrosion Corrosion cluster

• •

• • •

HIC

Arc burn Grinding Gouge/scratch

• •

•

SCC

• • •

• • • •

Axial crack

• •

Circumferential crack

•

Manufacturing anomaly Mill anomaly

•

Void Inclusion Blister Sliver Lap

• •

Lamination

•

• • • • •

• • • • • •

•

Spalling

Pipe deformations Dent Dent with metal loss Ovality Buckle Wrinkle Ripple

• • • • • •

• • • • • •

Weld indication

•

Lack of fusion Lack of penetration

•

Spiral weld crack Undercut

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World Pipelines / JULY 2022

• •

Seam weld crack Slag (excess material)

• •

•

• • •

• •

that can only be achieved through humanexperience based DA. As shown in Figure 3, data confirms the characteristics that allow DA experts to classify metal loss on the seam as preferential where it is recognised as such.

As stated previously, the proof is in performance. Tables 1 and 2 show the current POD/POI for seam types and anomalies, which true UHR technology can detect and identify.

Figure 3. Classifying the orientation of metal loss on the long seam.

Conclusion UHR has paved the way for advancement in seam anomalies detection with the use of Axial MFL technology. What was once considered impossible – true pinhole detection, hard spots, material identification and more – is now all possible with a proven system combining the latest UHR technology with humanexperience based DA. What started as a single channel technology with paper ribbons for data collection, evolved into multichannel and analogue data collection, the first combo tool, high-resolution MFL and now, into UHR MFL. Today, we, as an industry, are busting paradigms on axial MFL technologies with true UHR and the systems it empowers. The only way to know the limit is to push to the limit. That’s what UHR is allowing operators to accomplish.

Applying the latest technology and human-based insight, vision and analysis to solve realworld-problems; putting that knowledge to work; rinsing and repeating: that is the ENTEGRA approach to UHR ILI and seam-weld assessment. It is something that has evolved – from a technical perspective, an engineering perspective, and a people perspective – since before ENTEGRA’s founding in 2016 by the same team of engineers, operators, analysts, and field professionals who first commercialised the MFL/Combo tool more than two decades ago.

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Plastic pipe stands ensure pipeline workers prioritise safety, suggests Ken Pilidis, Proline Pipe Equipment, Canada.

T

he Proline Pipe Equipment yellow plastic stackable pipe stands, or pipe cones, have been a huge success since their inception by Proline over 25 years ago.

The 2 - 8 in. plastic pipe stands handle pipe of various wall thicknesses from 2 - 8 in., the 8 - 12 in. will handle pipe from 8 - to 12 in., and so on. Proline has also designed a star-shaped pipe stand that will accommodate a 12 - 24 in. pipe. Proline’s stand capacity increases as the pipe diameter gets bigger, to match increase in the increased weight. However, just because you’ve invented something to speed up right-of-way placement of the pipe for welding, coating, repair, storage etc., doesn’t mean that you

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should stop innovating. With that in mind, Proline came out with another version of the popular stackable plastic pipe stands. With our yellow pipe stands being a big hit, we decided to go further with a version for hotter ambient temperatures.

They say that imitation is the sincerest form of flattery. While travelling around the country visiting customers, our salesmen saw other plastic pipe stands in the field that looked like they’d seen better days. They were coloured stands; some were black, some were orange, and they seemed to sag under the heat of the sun and weight of the pipe. This can be a concern, especially if someone is lying under the pipe welding. With this

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Figure 1. 36 in. pipe being supported on the 12 - 36 in. Proline High Temperature (HT) pipe stand.

predicament in mind, we wondered if Proline could make something better. What we came up with was a new high temperature (HT) stand. More resin was added so the stands were thicker and would have greater strength in hot conditions. However, the weight increase was negligible. It was decided that if these stands were going to be made to withstand hotter climates, then Proline would do something about the colour too. We decided to make them white, since that colour does not attract the heat as much as other stands or pipe cones; they were a huge success in the tropics and countries that sustain heat all year.

In 2019, seeing bigger inch pipelines being built, and contractors asking for something bigger than 24 in., Proline decided to upgrade the size of one stand. With 24 in. the largest plastic pipe stand Proline had, it was decided to investigate moving to a larger size. One stipulation was that we wanted the new size to be the same price as the 24 in. stand, and just as safe. After some designing and a few samples made to test, we moved forward.

Why and how we made these stands Figure 2. 11 HT 12 - 36 in. plastic pipe stands hold up 36 in. pipe in Australia. 20 stands can fit on a pallet in a container.

Figure 3. Pallets of the new 12 - 36 in. HT stands ready for export to Arizona, USA.

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World Pipelines / JULY 2022

We wanted a new plastic pipe stand to have the same versatility of the regular stands, and something that wouldn’t sag as easily in high heat environments under ideal conditions.

That new stand is the 12 - 36 in. This pipe stand can hold 12 - 36 in. pipe of various wall thicknesses. When designing this stand, Proline engineers gave it a ‘star’ shape which contributes to its strength. These stands were tested on a third-party press until they failed due to extreme pressure; increments of 5000 lb (2268 kg) were applied at different intervals.

When the weight reached 65 000 lb (29 480 kg) the stand was inspected, and there was no change. So, we subjected the pipe stand to more pressure and brought the weight up to 70 000 lb. Still no change. At 75 000 lb there was a slight wave, but the stand endured, so we went to 80 000 lb and a few more waves appeared. We added 10 000 lb more, and at 90 000 lb the stand lost its shape. The weight was removed and after 5 minutes of discussing what we had just witnessed, we noticed that with the weight removed, the stand returned to its original shape. That was unexpected, so it was decided to try adding the weight again on the damaged stand to see when it would fail. At 50 000 lb (22 680 kg) we couldn’t believe that it was holding the weight after being crushed; this was the stand that had been crushed not 10 minutes earlier. We made it up to 65 000 lb (29 480 kg) on the damaged stand, before the waves returned.

We didn’t test just one stand, but multiple stands and the results were the same. The results of the tests were taken and the stand was rated with a 5:1 safe working load capacity. After the tests, we rated each 12 - 36 in. pipe stand a safe working capacity of 13 000 lb (5897 kg).

One 40 ft joint (12 m) of 36 in. pipe with a standard wall thickness (0.375 in.) weighs 142.68 lb/ft x 40 ft = 5707.2 lb. (2589 kg). Schedule 40 pipe (0.750 in. wall) will weigh 282.35 lb/ft x 40 = 11 294 lb (5123 kg). This is still in the safety range of one stand, and usually two stands hold up one pipe joint.

These stands can be set in the bed of a truck as they are stackable. While driving the right-of-way, one worker hands the pipe stand to a worker walking along side, and he places it on the ground. From each stand dropped off, the labourers are saving about 5 - 7 min. vs building each skid. Dropping off fumigated and heat-treated wood and requiring someone to build skids, is no longer required for pipe in the range of these pipe stands.

Storage of the stands are also made easy as they are stackable and can nest on top of each other. For example, the 2 – 8 in. stands can store 100 pipe stands on one 42 x 42 in. (107 x 107 cm) pallet and be ready for the next job.

Applications and success stories With the added resin and the white color, these stands are just what was needed for the southern US, Latin America, the Caribbean, Africa, Australia, or anywhere where ambient temperatures could exceed 37°C or 98°F. In Canada, where these stands are made, we are starting to see 42˚C (108˚F) summer temperatures; last year, British Columbia saw 49.5˚C (121˚F). We have been asked, what happens if the temperature exceeds 45˚C (113˚F)? If you have two pipe stands holding up a pipe in 45˚C+ temperatures, what do you do? The answer is simple; just add a third pipe stand. One on each end and one in the middle. This is especially recommended if you have black coating, and the pipe has been lying out in the sun for a few days.

Add another stand for insurance; if you can’t hold your hand on the pipe for 5 seconds, you should add an extra pipe stand and monitor the situation.

In 2017, 400 of the 8 - 12 in. HT White stands were shipped to Australia on a trial basis to fill a 40 ft container that was only three quarters full, and used on various pipeline projects across the continent. The feedback that we received was phenomenal; the company that supplied our stands received emails from end users asking why these weren’t promoted before. Since they were first introduced down under,

several 40 ft sea containers have been filled to the rafters with all three sizes (2- 8 in., 8 - 12 in. and the new 12 - 36 in.) and shipped to keep up with demand.

As a pipeline company in Australia just bought all the stock from our distributor, he has asked for another 40 ft container to be filled for the next voyage there. These stands, like their yellow brethren, are made from UV-stabilised high density polyethylene (HDPE) with an average life span of 6.5 yr, after which, can be recycled at the end of their lifecycle. Safety is our highest priority at Proline Pipe Equipment and our plastic pipe stands reflect this commitment. Is this something that could help you on your next pipeline job?

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Calvin Silver and Scott Hansen, GeoCorr, USA, explain the results from a push for ‘smarter’ caliper technology by industry-leading transmission companies that propelled the steps to better data.

G

eometry inspections continue to lead the way when initiating your baseline integrity assessments. While thousands of runs are conducted over the global market, evolving technology continues to drive this industry forward. While we become smarter at earlier stages within the pipeline’s life, this helps protect these assets, address anomalies, and improve integrity decision-making.

GeoCorr’s new TCII HiRes Caliper with IMU is a step up in your tool kit, whether at pre-commissioning of a pipeline or for geohazard and dent strain assessments on in-service lines.

System design and architecture Tackling the new high-resolution market, the TCII HiRes caliper system was designed to accommodate two caliper arms per dia. in. (Figure 1). Every tool diameter, 3 in. through 56 in. would see this new standard. The inline inspection system would serve to meet the rugged expectations of new construction applications, while setting a new standard with sensitivity and detection by employing this new caliper sensor technology.

The digital sensor technology has reduced the signalto-noise ratio by a factor of 10, and widened the sensor’s usable range to 100% of the available mechanical travel. This has allowed for exceptional sizing accuracy and increased confidence in low percentage features within the 0 - 2% OD range. In conjunction with the geometry sensor technology, the odometer system can be linearly sampled at user-selected

44

1 - 4 mm based on application requirements. With resolution more than doubling on direct wall caliper sensors, and the linear sampling more than doubling as well, confidence levels and accuracies are at an all-time high.

With these expanded capabilities, the TCII has been tackling a wide range of applications: ) Early detection and identification of anomalies and mechanical damage occurring during construction. ) Dent strain analysis where better data capture on geometry/

caliper data provides a more accurate evaluation of your ASME B31.8 strain results and anomaly shape. ) Dual and multi-diameter applications – previous Dual Dia.

Technology had sensor limitations. A compromise was typically given to the larger diameter pipe with regards to sensor measurement, coverage, and accuracy. Major improvements to measurement linearity throughout both pipe diameters have been achieved in dual-diameter applications with up to a 6 in. difference in pipeline OD. Proof of concept work was executed through 2020 with in-house development and testing split between GeoCorr’s production headquarters and engineering team. During system validation, extensive calibration procedures were carried out along with in-pipe testing. Using the high-resolution digital

45

sensors, multiple samples are taken during calibration for each point, resulting in clearer data acquisition and more accurate subsequent pipe measurement. Across the many arms and steps of the calibration graph, graphs present as nearly linear throughout the mechanical range (Figure 2).

The implications of this are twofold: )) Wide swings in diameter (whether due to extreme

restriction or multiple diameter pipelines) do not compromise the quality of the sensor reading. )) This then allows for quick benchmarking and validation

of calibrations where the effects of human error are greatly reduced because the easy recognition of invalid data points during infield calibrations or the standard tool preparation process.

Pipe-based measurements were performed for wall thickness calibrations. The high sensor density combined with the sensor has made a big impact on data analysis. This has allowed for a simpler interpretation of the slightest changes in internal diameter discrepancies and changes in wall thickness.

With the design intent of exceeding 1 mm of detection accuracy on wall thickness, validation has been performed on the sensors down to the finest calibration block with a thickness of 0.25 mm or just under 0.01 inches. This would be the equivalent of a 0.028% dent in a 36 in. pipe. Consistent measurement of the 0.25 mm calibration blocks was achieved for all arms with repetition and repeatability (Figure 6). These tests provided an observation of baseline sensor noise within the system, further demonstrating that electronic noise would not impact measurements as small as a quarter of a millimetre.

Being able to detect changes in the pipe wall with TCII HiRes Caliper at a thickness less than a credit card should provide smarter information to pipeline integrity decision-makers prioritising threats to their assets.

Figure 1. Rear view of GeoCorr’s 36 in. TCII HiRes Caliper Tool with 72 channels.

Figure 2. 36 in. Tool Calibration: each arm has an approximately flat profile across a full 30 cm of mechanical range.

46

World Pipelines / JULY 2022

A novel approach to high-resolution validation As of late 2021 in-field testing was completed on the TCII HiRes system by GeoCorr’s team that has been specialising in caliper inspections for over 16 years. Several inspections pushed through compressed air have been performed across 20 - 42 in. pipelines in the precommissioning phase. With a 100% first-run success rate during its deployment in multiple new construction applications, the TCII HiRes has yielded a few real-world observations.

Validation of in-run measurement at precommissioning has traditionally been performed based on the industry-standard dig specifications of 2% dents and 5% ovalities.

While some end users have endeavoured to excavate 1% features for both anomaly types,

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Figure 3. Dent A: Channel view of ~2.56 mm dent profile (0.28% against baseline) adjacent to spiral weld signature for comparison. Blue dotted lines denote dent baseline zone and the white arrow signifies the spiral weld.

Figure 4. Dent B: Channel view of ~3.29 mm dent profile (0.36% against baseline) adjacent to spiral weld signature for comparison. Blue dotted lines denote dent baseline zone and the white arrow signifies the spiral weld.

Figure 5. Dent C: Channel view of ~4.11 mm dent profile (0.45% against baseline) adjacent to spiral weld signature for comparison. Blue dotted lines denote dent baseline zone and the white arrow signifies the spiral weld.

48

World Pipelines / JULY 2022

finding ways to validate a high-resolution tool against very small features in-field has been challenging as they are not typically candidates for excavation or cut-out.

Sizing the height of a spiral weld for a 36 in. spiral welded pipe provided a consistent expression for the extent of the entire line, measuring 2 - 4 mm across all sensors and on all joints (Figure 7). While the sizing of the spiral weld is not a classical diagnostic of an effective ILI tool, it is extremely useful for proving the consistency of a high-resolution caliper.

‘Spiral weld reinforcement height’ is a parameter with an API-specified tolerance during manufacturing. The spec states the weld must be less than or equal to 4.76 mm for wall thicknesses greater than 0.500 inches. A standard-length joint of spiral weld pipe will allow each sensor on the tool to pass a spiral well 6 - 8 times. On a 3 mile line, this provides for over 2000 sensor verifications for each arm.

Identification of low percentage ID reductions (dents, debris, mill anomaly, etc.) in the spiral welded pipe allows for a comparison of the anomaly to the consistently milled and measured weld feature. Sizing anomalies adjacent to the weld signatures showcase the reliability of the TCII HiRes sensing technology, even while running in the particularly challenging new construction environment, while being pushed with compressed air in a low-pressure setting. Figures 3 - 5 present a collection of three different low percentage expressions near the previously mentioned spiral welds.

All three anomalies reside on the bottom of the pipe, so while these certainly resemble ID reductions, differentiating these anomalies as dent, debris, or mill defects is another task. They have been classified as dents for this study. The anomalies presented vary in magnitude and when compared to the spiral weld signature present as Dent A being smaller than the size of the weld, Dent B being similar in size, and Dent C being greater in size. Note that each of the figures has a baseline zone (blue dotted lines) of measurement adjacent to the feature which encompasses some vibration and provides an average ‘nominal’ reading for the anomaly.

Using the information previously gathered on the spiral weld features, the anomalies size appropriately, by comparison, suggesting valid readings for all the expressions. Note that the largest anomaly showcased here is 0.45% and 0.16 in. and is distinctly observed across two caliper channels on this 36 in. inspection.

Through inspections in ERW pipes, there have been other observations of low percentage anomalies across multiple caliper channels. There has also been detected expression of long seam welds, suggesting that identification of long seams caliper only technology is possible. Long seam expression is dependent on a few factors; both the manufacturing process, and run parameters seem to vary interpretation capabilities.

However, this case study highlights successful detection through the aided use of heat mapping software views traditionally used by MFL analysts, which assists in providing a clearer interpretation of the detection.

Evaluation and possibilities The potential of the GeoCorr’s TCII HiRes Caliper system provides elevated data quality and detection and

opportunities to further push forward with other technology to fulfil multiple integrity needs, whether it be IMU (for mapping, bend strain, or geohazard), debris mapping, as a more informative go-no-go, or as an aid of detection of small illegal taps or long seam.

This progress demonstrates a considerable step up in terms of data collection for a caliper technology, meeting the most stringent end user requirements under some of the toughest conditions. In-field testing has resulted in consistently verifying this specification while providing a high level of reliability which,

historically, has been challenging while deploying recently developed technology.

Acknowledgments The authors would like to thank their committed customers for continuing to acknowledge the importance of developing new standards to push the growth of pipeline technology, and the dedicated Engineering, Operations, Software, and Analysis personnel at GeoCorr for their contributions to these advancements.

Figure 6. The use of the 0.25 mm feeler gauge (compared to standard credit card on left) provides consistent measurement above baseline for all arms. Sensor noise does not impact baseline. Channel 14 with measurement inset in millimeters.

Figure 7. Heat map view (split with channel) of spiral welded pipe around girth weld #1120. The spiral weld consistently measures 2 - 4 mm across all channels. Upstream of the girth weld there is tool motion where the drive cup impacts the weld.

JULY 2022 / World Pipelines

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2022 will be a banner year for the flowmeter markets, suggests Jesse Yoder, PhD, Flow Research, USA.

T

he past several years have been an anomaly for the flowmeter business for multiple reasons. The COVID-19 pandemic disrupted demand for the products flowmeters are used to measure. Flow Research recently completed a study of the worldwide flowmeter market, including all flowmeter types. Our goal was to determine the impact of the COVID-19 pandemic on the flowmeter market as a whole, and to find out which types of flowmeters were most impacted by the pandemic. We published our findings in a new study called ‘Volume X: The World Market for Flowmeters, 8th Edition’. The study was published in January 2022.

The markets in 2020 The year 2020 was in many ways an anomaly, and virtually no industrial, commercial, or retail segments were unaffected by the pandemic. Many businesses were forced to close, travel slowed to a trickle in many cases, and demand for many products simply dried up. This especially applied to the energy industry. Demand for gasoline and jet fuel plummeted, as people curtailed both driving and flying. Due to the prevalence of the pandemic, many people worked from home. This had its own impact on travel, as Zoom calls replaced many in-person meetings. For most of 2020, business as we know it was dramatically altered or ceased to exist.

As we researched the flowmeter market, including all flowmeter types, we found that most, though not all, companies reported reduced revenues in 2020 when

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compared to 2019. While 2019 was not a stellar year, it was a much more ‘normal’ year than 2020. We also found that many companies expected to have revenues in 2021 that were close to their 2019 revenues. In the end, 2021 may have been a slightly weaker year than some expected, due in part to uncertainty caused by the emergence of the Omicron variant towards the end of 2021, and due to some re-emergence of the Delta variant in Europe as colder weather in the autumn drove people indoors. Even so, the determined efforts by the developed countries to vaccinate as much of their populations as possible made 2021 a much more viable year economically than 2020.

While the pandemic taught us once again how difficult the future is to predict, it is not controversial that energy demands will remain high, chemical plants will continue to operate, power plants will generate needed power, and water and wastewater treatment plants will produce clean water and treat wastewater.

Flowmeters are needed for all these applications, and with an expanding population in most countries, demand for flowmeters will increase. Which flowmeter markets can be expected to grow the fastest depends on the industries and applications.

The comprehensive new Flow Research study found that the worldwide flowmeter market totalled US$7.03 billion in 2019 and US$6.6 billion in 2020, with revenues forecast to reach a projected US$6.9 billion in 2021 and US$8.2 billion by 2024.

Coriolis and magnetic flowmeters are the revenue leaders in the flowmeter market, with Coriolis meters projected to take over the lead more strongly by 2024, due largely to growing demand in the oil and gas industry for more accurate custody transfer measurement. Coriolis flowmeters are the most accurate meters on the market today.

Coriolis, ultrasonic, and magnetic flowmeters lead the way Coriolis, magnetic, and ultrasonic flowmeters drive the total flowmeter market, and the decreased demand and supply of oil and gas during the pandemic significantly affected the Coriolis and ultrasonic markets. Going forward, however, the tightness in supply for both oil and natural gas could cause significant growth in these flowmeter markets.

Magnetic flowmeters are widely used in the water and wastewater industry, and are growing in demand as water shortages and climate change intensify the need to monitor water supplies and usage more closely. In fact, thanks to industry group standards that include using magnetic flowmeters for water utility measurement, these meters are now displacing positive displacement and turbine meters in some commercial and industrial applications. Magnetic flowmeters, which do not measure hydrocarbons, are used in the oil and gas industry and were also affected by the slump. These meters are used for hydraulic fracturing or ‘fracking’ applications, including measuring water injected into oil and gas wells and water flowing from them for capture, disposal, or recycling.

The ultrasonic flowmeter market is projected to grow the fastest over the next three years. Ultrasonic flowmeters feature high accuracy, high reliability, high turndown ratios, long service life, low maintenance, relatively low cost, diagnostics, no moving parts, and redundancy. Both Coriolis and ultrasonic flowmeters have received industry association approvals for custody transfer of both gas and liquids, but, unlike Coriolis meters, ultrasonic flowmeters perform very well in the large line sizes often used in oil and gas pipelines.

The impact of oil prices on the flowmeter markets One reason for the downturn in the flowmeter market in 2020 was the drop in oil prices. Flowmeters are widely used in upstream oil production, in oil and gas refining, and in downstream distribution of oil and gas. In 2020, oil prices started off the year at above US$60/bbl. However, by April 2020, prices had declined to less than US$20/bbl. This prompted an emergency meeting

by OPEC to support prices by taking supply off the table. In a meeting on 12 April 2020, OPEC used multiple means to reduce supply by almost 20 million bpd. This had the desired effect, and

by July 2020, oil prices were above US$40/bbl.

As economies in the US and around the world began opening up, demand for petroleum products began coming back. At the same time, most OPEC and non-OPEC countries were abiding by the terms of the supply cuts that were part of the April agreement. This had a stabilising effect on the oil markets. After July 2020, prices continued to rise slowly through 2020, and in the beginning of 2021 prices reached the US$50/bbl range.

Oil prices in 2021 stayed above US$50/bbl until mid-February, when they reached US$60/bbl. Prices remained mostly between US$60 and US$65/bbl until early June, when they climbed to US$70/bbl. From that point on, prices stayed between US$65 and US$75/bbl until early October, when they reached US$80/bbl. For the rest of 2021, prices remained high, although they declined to under US$70/bbl in December 2021.

Oil prices in 2022 In January 2022, oil prices topped US$80/bbl on 11 January. Since that time, prices have climbed steadily, reaching US$123/bbl on 8 March.

Russia’s invasion of Ukraine on 24 February introduced many new uncertainties in the market. The most pronounced long-term result is a crimp in the world oil supply since some Russian oil has been taken off the market. In addition, supply chain shortages are disrupting manufacturing around the world and inflation is rampant.

This is not the kind of instability that anyone wants.

In the first week of June, the EU agreed to phase out a substantial portion of Russian oil imports by the end of the year.

This will further reduce the amount of oil available on the market.

During that same week, crude oil was trading at above US$115/bbl. In response to the action by the EU, Russia, which had already halted gas supplies to Bulgaria, Poland, and Finland, also cut off gas flow to some companies in Denmark and Finland. In the past, European countries have been heavily dependent on Russian oil and gas.

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Oil prices are fundamentally determined by supply and demand. With supply continuing to diminish, and demand for refined fuels increasing due to pent up demand from the pandemic, it is difficult to see how oil prices can go anywhere but up over the next six months. As for Europe’s dependence on natural gas, it is now beginning to turn to LNG to fill its natural gas needs. The problem with this solution is that there are not currently enough LNG terminals to meet Europe’s growing need.

The current supply and demand energy situation is likely to have these consequences: )) Increased drilling for oil and natural gas.

Figure 1. Crude oil prices from January 2014 to May 2022 (US$/bbl). Source: Energy Information Administration (EIA).

)) Greater reliance on LNG as a

source of gas supply. )) An acceleration in the search for

competitively priced renewable energy.

The dynamics for these consequences were in place before the war in Ukraine began on 24 February. However, the war has intensified the situation by reducing oil and gas supplies even as demand for refined fuels is rising.

Effect on the flowmeter markets Flowmeters are likely to have a banner year in 2022. Increased oil and gas production should especially benefit ultrasonic and turbine flowmeters. The greater need for downstream delivery of refined fuels will favour both Coriolis and positive displacement flowmeters.

Magnetic flowmeters will benefit both from increased fracking and from measuring produced water coming out of oil and gas wells. They will also benefit from additional investments in clean water and wastewater treatment plans, as water becomes scarcer and the need to measure it rises. Coriolis and magnetic flowmeters will be more widely used in chemical and food and beverage plants, especially for sanitary applications. This shows that energy needs are not the only reason why 2022 should be a banner year for flowmeter sales – the reasons span the entire process industries.

Figure 1. Decom Engineering’s C1-24 chopsaw on test trials at the National Hyberbaric Centre, Aberdeen.

Repurposing redundant oil and gas infrastructure could unlock millions of pounds of untapped revenue for energy firms, argues Nick McNally, Commercial Director, Decom Engineering Ltd, UK.

R

ising commodity costs, not least the price of steel, combined with soaring shipping and freight rates, alongside a global desire to reduce CO2 emissions, means no stone should be left unturned in finding ways to re-use and recycle steel.

Add in geopolitical disruptions in Europe and Russia’s invasion of Ukraine, resulting in sanctions on the world’s fourth largest steel producer, and disruption to 90% of Ukraine’s steel capacities (the world’s 8th largest producer) and it’s plain to see the energy sector which relies heavily on steel tubulars faces a challenging time.

Utility or oil and gas pipelines can be split into two main re-use or recycle categories – prime surplus pipe and decommissioned pipe – and if executed properly, both can release significant value to the asset owner. Looking at the decommissioned market first, the opportunity is immediate and on paper potentially massive.

Over the next 10 years, it is estimated that 7500 km of oil and gas pipelines in UK and Norwegian waters will require to be decommissioned, meaning if it can’t be repurposed in-situ, it must be removed from the seabed. However, this North Sea infrastructure is dwarfed by the 7.5 million t of steel and

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55 000 km of pipeline in the Asia-Pacific region which will become redundant in the next decade, ranging from India to Papua New Guinea, and China to Australia.

With energy transition and working towards a net-zero end-game placed front and centre in the boardroom of every oil and gas major, the focus has turned to repurposing as much redundant infrastructure as possible, and millions of pounds of government and private sector money is being invested in the research and development of potential solutions.

Innovative thinking and emerging technologies are making it increasingly realistic that North Sea oil and gas infrastructure, which has helped Figure 2. A section of cleaned pipe after being processed using Decom Engineering’s Pipeline keep UK lights on for half a century, Coating Removal machine. could be put to use in generating or storing green energies, including wind, hydrogen, carbon capture and storage (CCS), solar and tidal technologies.

Repurposing steel tubulars

Figure 3. Decom Engineering’s C1-24 chopsaw being tested on a ROVCON connector at the National Hyperbaric Centre, Aberdeen.

It seems ethically and economically sensible to make the most of that existing infrastructure to push forward on energy transition goals, but even with the sector’s best brains engaged in determining the optimal use for end-of-life pipelines, it’s estimated there will still be more than 500 000 t of pipelines which will have to be removed from the seabed.

Recycled properly, these assets could represent well over £250 million worth of steel – and a CO2e saving of more than 1 million t – that’s the equivalent of travelling 7.5 billion miles in an average car. According to research by John Lawrie Tubulars in January 2021, it was found that for every tonne of repurposed steel tubulars, there is a CO2e saving of 97.21% over new manufactured prime steel products.

Steel tubulars which can be safely removed from the seabed and brought ashore are perfectly suitable for reuse in a range of infrastructure projects, in particular in piling operations which are central to many large-scale construction and building projects.

Increasing the availability of steel tubulars for infrastructure needs would provide a huge boost to economic productivity, as these pipes will be available for lower prices, in a shorter lead time than factory produced pipe, and with a lower carbon footprint.

Cutting pipelines

Figure 4. Decom Engineering’s C1-24 chopsaw can be deployed on decommissiong projects – undergoing testing at the National Hyperbaric Centre, Aberdeen.

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World Pipelines / JULY 2022

There is a double benefit for oil and gas operators who opt to recover redundant kilometres of pipeline – it not only limits or reduces carbon emissions and aligns with net-zero ambitions, but also returns monetary value to asset owners from pipelines which have already served their original purpose for decades.

But to maximise recoverable value while limiting environmental impact, the steel pipelines have to be removed with minimal damage. It sounds straightforward – but it’s not.

One of the biggest challenges in the cutting of pipelines is the efficacy of subsea cutting apparatus and the ability to make multiple cuts on a single deployment. For example, if hydraulic shears are utilised then this results in the crimping of the pipe ends, making it more difficult to inspect, decontaminate and re-use or recycle the pipe.

Operators, or decommissioning specialists working on their behalf, will benefit from considering other cutting solutions which can make a fast, clean cut of the pipeline, that requires limited retooling, and can be operated by ROV, crane or excavator.

Decom Engineering’s range of subsea cold cutting saws have been successfully deployed across the globe on behalf of major operators engaged in decommissioning and are capable of clean cutting materials of between 2 - 24 in.

Recent tests on behalf of a client at the National Hyperbaric Centre in Aberdeen, showed our chop-saws are capable of operation at depths of up to 800 m, opening up huge possibilities on decommissioning projects in deeper waters.

The end result of any cutting workscope should be decommissioned pipe which is delivered in clean-cut sections, so that internal probing and testing for decontamination work can continue unobstructed. However, even if that is achieved, another barrier remains – the original pipe coating.

The materials, which for years have protected the pipe and its integrity in one of the world’s harshest weather environments, must be removed safely and cost effectively to render a

piece of almost-new pipe, which can be sold on for use in the construction sector.

Re-using surplus pipe While the decommissioning and re-use of redundant pipelines offers a positive financial and environmental outcome, there is a risk some pipe cannot be re-used but instead has to be scrapped, which leads in to what happens to prime surplus pipe.

Surplus pipe is pipe which has been previously purchased but unused – often the result of cancelled projects – the best example of which is the on-off US$9 billion Keystone XL pipeline extension, which now appears to have been put to bed indefinitely with President Joe Biden’s decision to revoke a key permit needed for the 1200 mile US section.

With a minimum of 48 000 t installed on Keystone, and an even greater amount sitting redundant in storage, it raises an urgent question as to how that pipe can be re-used and how the re-use possibilities can be increased by safely and efficiently removing the specific coating already present on the pipe.

Phil McKenna, Inside Climate News, highlighted important considerations in pipe re-use – the need to remove fusionbonded epoxy coating, which may have become degraded due to exposure to UV light for a prolonged period of time while being stored.

The Inside Climate News report warned that coating failures can lead to pipeline failures, citing an example when a steel pipeline ruptured and caused a large crude oil spillage. The report also identified a risk that degraded coatings on outdoor

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stored pipe could have local adverse health and environmental impacts.

These findings underline the financial and environmental need to remove coatings in a cost-efficient and scalable manner whilst safely capturing all waste products – an area in which Decom Engineering has extensive operational experience with its pipe coating removal (PCR) technologies.

Unfortunately, many existing coating removal processes are slow, costly, unsafe for operators, environmentally unfriendly, and of poor quality. Methods include excavator removal, water jets, lathes, or a reverse heating process, but all present a range of negative factors which, from a carbon emissions, cost or practicality aspect, should be avoided.

Also, the trend of transporting redundant pipe thousands of miles half-way across the world for disposal, makes no economic sense against a backdrop of surging freight prices, and this increases the carbon footprint of the pipe.

Restructuring the industry An alternative is provided by Decom’s PCR machines which can be mobilised anywhere in the world, so reducing the carbon footprint and transport costs involved in moving pipe to other locations for cleaning and repurposing.

Our environmentally-friendly cold method can be used to strip the tubulars of all coatings, achieving a clean pipe surface which can be NDT-tested prior to reuse in a range of infrastructure projects, preferably close to the point of refurbishment – a better option than simply stacking and storing piping on industrial sites, and which releases no value and incurs costs.

This dual approach to repurposing redundant oil and gas infrastructure could unlock potentially millions of pounds of untapped revenue for energy firms. Although new steel and scrap steel prices are volatile, analysis reveals that the long-term price (2000 - 2016) differential between the cost of UK structural steel and ‘scrap’ sectors is more than £300/t.

Even taking into account additional costs relative to recycling (deconstruction, testing, storage etc), re-using structural steel offers a significant profit opportunity for asset owners, not to mention cost and carbon savings for end users who opt for repurposed steel over ‘new’ structural steel.

The commercial rationale for buyers of steel pipe is based on a mixture of cost, regulatory and brand perception elements, but there is growing pressure on the construction industry to be more resource efficient, to reduce waste, and to lower embodied carbon impacts.

Increasingly, circular economy concepts are being promoted, particularly at EU level, with a roadmap developed to support a shift towards a resource efficient, low carbon European economy. What could be more circular - and more cost effective - than repurposing steel pipe which has done a fantastic job for up to 50 years, and putting it to work in new projects which will last at least another 50 years?

It is clear the energy industry needs to think creatively about what we do with the redundant oil and gas infrastructure which is not suited to being repurposed for emerging green energy production and storage technologies which will be rolled out in the next decade.

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