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CONTENTS WORLD PIPELINES | AMERICAS 2026

03. Editor's comment 05. Pipeline news

REPAIR

37. Uninterrupted energy supply

Contract news and updates on Americas pipeline projects, by region, over the last six months.

Pushpendra Tomar, Principle Pipeline Integrity Engineer, T.D. Williamson.

FORECASTS

12. Unlocking Latin America's natural gas potential

Simon Ellis, Senior Policy and Analysis Advisor, International Gas Union (IGU).

18. Pipelines in the Americas: foundations for energy security Colin M. Frazier, API.

Pushpendra Tomar, Principle Pipeline Integrity Engineer, T.D. Williamson, explains the role of compression sleeve repairs in ensuring a reliable supply or energy.

ata centres accounted for 4.4% of total US electricity in 2023 and are projected to consume 6.7 - 12% by 2028, with total demand increasing from 58 TWh in 2014 to 176 TWh in 2023 and expected to reach 325 - 580 TWh by 2028. Globally, electricity

PAGE

PIGGING

43. Improving through automation

Jeff Lehr, Vice President of Product Innovation and Execution, WeldFit. INTEGRITY Colin M. Frazier API, discussing the ever-changing energy security landscape in the Americas

49. Into the unknown

Tim Mally, Director, Pipeline Integrity, Henkel.

he global energy landscape is evolving rapidly, shaped by rising demand, shifting market dynamics and the need to build systems that are not only efficient, but safe and resilient. That resilience is especially urgent today, as geopolitical tensions and market volatility continue to underscore the importance of energy security. Indeed, in our globally connected economy, disruptions to energy supply can reverberate quickly across markets and borders, making reliable access a strategic necessity. It is against this backdrop that pipeline systems across the Americas are playing an increasingly important role in global

PAGE 19

25. Keeping pace with the next phase of North American gas operations

David Gross and Anna Ignatova, ION Commodities, and Jay Bhatty, NatGasHub.com 31. The pipeline POV Gianluca Colonnelli, Senior SURF Manager, KBR.

53. Restoring ageing pipeline coatings

Edwin Welles, MBA, Vice President of Viscotaq, and founder and inventor of Viscotaq Coating Technologies, Denso Inc.

57. Enhancing confidence in pipeline integrity Kerry Cole, AMPP.

MIDSTREAM FOCUS

61. An investment in the future of midstream Andrew Topliffe, IMI Process Automation.

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IF YOU CAN’T BLAST, BRISTLE BLAST! Copyright© Palladian Publications Ltd 2026. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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EDITOR’S COMMENT CONTACT INFORMATION MANAGING EDITOR

James Little

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ASSISTANT EDITOR

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HEAD OF EVENTS

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Palladian Publications Ltd, 15 South Street, Farnham, Surrey, GU9 7QU, UK Tel: +44 (0) 1252 718 999 Website: www.worldpipelines.com Email: enquiries@worldpipelines.com Annual subscription £60 UK including postage/£75 overseas (postage airmail). Special two year discounted rate: £96 UK including postage/£120 overseas (postage airmail). Claims for non receipt of issues must be made within three months of publication of the issue or they will not be honoured without charge. Applicable only to USA & Canada: World Pipelines (ISSN No: 1472-7390, USPS No: 020-988) is published monthly by Palladian Publications Ltd, GBR and distributed in the USA by Asendia USA, 701C Ashland Avenue, Folcroft, PA 19032. Periodicals postage paid at Philadelphia, PA & additional mailing offices. POSTMASTER: send address changes to World Pipelines, 701C Ashland Avenue, Folcroft, PA 19032.

his year, the USA, Mexico and Canada welcomed the world for the FIFA World Cup. The 2026 tournament was the first World Cup since 2002 to be hosted by multiple nations (in 2002 it was held in Korea and Japan). Football stadiums from Vancouver to Houston to Mexico City saw world-class footballing action; host cities took legions of transplanted fans under their wings; and we all appreciated the star power of (choose your favourite): Mbappe, Bellingham, Haaland, Yamal, Messi, and Oyarzabal. Away from the stadiums, the wider Americas SENIOR EDITOR Elizabeth Corner elizabeth.corner@palladianpublications.com region is also playing host to an extraordinary period of energy infrastructure investment. According to BNamericas, Latin America has more than 1200 oil and gas projects in development, planning or construction, representing almost US$650 billion of investment.1 Brazil is home to 676 projects, followed by Colombia (120), Mexico (113), Argentina (109) and Trinidad and Tobago (38). Midstream accounts for around US$250 billion across 150 projects, highlighting the central role that pipelines, LNG terminals, and gas processing infrastructure continue to play. North America tells a similar story: continued LNG export growth, rising electricity demand and increasing natural gas production are driving discussions around the capacity of existing infrastructure and the investment needed to expand it over the coming decades. Industry forecasts suggest that substantial investment will be required over the coming decades to expand gathering systems, transmission pipelines and associated infrastructure. The projected US$1 trillion to US$1.4 trillion in midstream investment across North America is driven by growing global demand for US LNG and the unprecedented electricity needs of AI data centres.2 To meet these multi-decade requirements, midstream corporations and MLPs are forecasting an expansion of up to 70 billion ft3/d in transmission capacity. Energy trade across the Americas is also becoming increasingly interconnected. US LNG exports to Latin America recently reached their highest level in more than three years, with Brazil emerging as the largest destination, highlighting the growing role of regional gas trade in balancing supply and demand across the continent.3 These developments are reflected throughout this special Americas issue of World Pipelines. Simon Ellis from the International Gas Union explores Latin America’s natural gas potential (p.12). Colin M. Frazier from API considers the role of pipelines in supporting energy security across the continent (p.18). David Gross and Anna Ignatova of ION Commodities, with Jay Bhatty of NatGasHub.com, explore how digital connectivity is helping operators keep pace with growing gas demand, tighter pipeline capacity, and faster-moving markets (p.25). From there, our contributors examine the technologies helping operators keep pace with growing demand, with case studies detailing projects and potential in the Permian and Bakken basins, Brazil, Texas, Virginia, Mexico, Canada, and Southern California. Each region faces different political, regulatory and commercial realities, but the challenge of ensuring energy can move safely, efficiently and reliably is shared across the Americas. As the articles in this issue demonstrate, meeting that challenge depends upon the industry’s ability to build, maintain and optimise the infrastructure that connects supply with demand, even as demand patterns and geopolitical priorities continue to evolve. 1. 2. 3.

https://www.bnamericas.com/en/analysis/latin-americas-us600bn-oil-and-gas-project-pipeline https://etfdb.com/energy-infrastructure-content-hub/midstream-the-trillion-dollar-investment-opportunity/ https://www.spglobal.com/energy/en/news-research/latest-news/lng/070326-us-lng-exports-to-latin-america-surge-tothree-year-high

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NORTH AMERICA NEWS PHMSA announces 11 grant funding opportunities for pipeline and transportation safety The US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) announced in May a US$22 032 987 investment into pipeline and hazardous materials safety programmes. That includes funding to support safety awareness, training, research, and other activities to help communities avoid or respond to hazardous materials-related transportation incidents. The investment will go towards, training first responders, safety education programmes for communities, developing new pipeline

safety technologies, and supporting States, tribes, and local government partners. “Under President Trump and Secretary Duffy, we are ensuring the safety of the communities our pipeline and hazmat transportation networks run through,” said PHMSA Administrator Paul Roberti. “This investment will support first responders as well as help raise awareness at the local level so everyone is on the same page about how to reduce risk and what to do in case of an incident where you live or work.”

Trump’s Transportation Secretary Sean P. Duffy announces record fine against pipeline operator for violating pipeline safety regulations In January, US Department of Transportation Secretary Sean P. Duffy and Pipeline and Hazardous Materials Safety (PHMSA) Administrator Paul Roberti announced the largest civil penalty ever proposed in a pipeline safety enforcement action. The enforcement action, brought against Panther Operating Co., LLC, includes a US$9 622 054 proposed civil penalty for alleged violations that occurred in connection with a November 2023 failure of the Main Pass Oil Gathering (MPOG) pipeline system. The failure released 1.1 million gal. of crude oil into the Gulf of Mexico. “Safety drives everything we do,” said US Transportation Secretary Sean P. Duffy. “We are sending a clear signal: when companies fail to abide by the rules, we won’t hesitate to act decisively. We’ll continue to enforce the law to ensure the safety and efficiency of our energy infrastructure.” PHMSA’s investigation identified multiple probable violations of its hazardous liquid pipeline safety regulations related to

integrity management and operations and maintenance requirements, including those specific to leak detection, emergency response, and the protection of high consequence areas. Details of each probable violation can be found in the Notice of Probable Violation PHMSA issued to Panther last week. “PHMSA’s focus on safety and holding operators accountable when they fail to comply with federal safety regulations will never change,” said PHMSA Administrator Paul Roberti. “It is important for pipeline operators to remain vigilant in their operations to prevent these types of failures or there will be serious consequences.” The enforcement action also includes a proposed compliance order that would require the company to take certain actions to ensure compliance with federal pipeline safety regulations. As part of the order, Panther will be required to evaluate and develop a plan that works to protect the MPOG pipeline system against future unanticipated external loads caused by geotechnical and geological hazards.

STATS Group expands North American manufacturing with major Texas investment STATS Group (STATS) announced in May a major expansion of its North American operations with the opening of a new manufacturing facility in Rosenberg, Texas. STATS is a leading provider of pipeline isolation and intervention services, enabling safe and efficient maintenance and repair of onshore, topsides and subsea pipeline infrastructure. The 80 000 ft3 facility will manufacture a range of pipeline fittings, including hot tap and line stop components, enabling STATS to deliver a fully integrated service offering to customers across North America. Its existing office in Houston, Texas, will support the new facility, which marks STATS’ first dedicated manufacturing capability in the United States and represents the largest single capital project in the company’s history. The expansion is a direct response to increasing demand from operators for shorter lead times, and products manufactured locally in the US. STATS Group Manufacturing Director US, Brandon Glover, said: “The investment reflects customer demand for greater responsiveness and the quality that comes from skilled

craftsmanship. The new facility will streamline STATS’ end-to-end service offering, providing greater control over manufacturing quality and output.” STATS expects that its US-based manufacturing capabilities will significantly enhance the products and services it provides to customers across North America. As a market leader in the supply of pressurised pipeline isolation, hot tapping and plugging services to the global energy industry, STATS is well positioned to meet its clients’ evolving needs. The new manufacturing facility will include a fully modernised machine shop capable of producing pipeline fittings and component custom-designed to support STATS’ proprietary hot-tap and line-stop equipment – significantly reducing production lead times and improving service quality. The expansion represents an important step in STATS’ ongoing global growth strategy. Increasing manufacturing capabilities in the US and aligns with the company’s long-standing approach of investing in infrastructure and workforce in local markets, enabling STATS to be more responsive to client needs while strengthening scalability.

AMERICAS 2026 / World Pipelines

IN BRIEF USA

CO2 pipelines to benefit from PipeSense’s new leak detection system. Successfully designing, implementing, and testing a new dynamic pressure analysis-based leak detection system, PipeSense proved the capability of the technology on a South Texas pipeline transporting dense phase and supercritical carbon dioxide (sCO2) at approximately 2000 psi.

MEXICO

Bodycote has announced plans to open a new facility in Apodaca, in the Monterrey metropolitan area, expanding its capacity to support customers across Mexico and the southern US.

USA

Shelli Myers of WhiteWater Midstream, LLC has been elected to a two-year term as chair of the Texas Pipeline Association (TPA), the US’s largest state trade association representing intrastate pipeline operators. Myers is the first woman in the organisation’s 42 year history to serve in this leadership role.

VENEZUELA

The removal of Nicolás Maduro from Venezuela’s presidency and his transfer to US custody created near-term downside risk for oil prices while presenting longerterm uncertainties for upstream investment, according to analysis from Wood Mackenzie.

USA

Natural gas pipeline projects completed in the US in 2025 increased capacity by approximately 6.3 billion ft3/d.

USA

Europe is deepening its dependence on LNG from the US, which will supply two-thirds of the continent’s imports of the fuel in 2026, according to new research from the Institute for Energy Economics and Financial Analysis (IEEFA).

6 World Pipelines / AMERICAS 2026

NORTH AMERICA NEWS AMPP releases first energy industry report highlighting corrosion, workforce, and technology trends shaping pipeline integrity The Association for Materials Protection and Performance (AMPP), the leading global authority in materials protection and performance, has released its first Industry Report for the energy sector: US Pipeline Industry 2026: Leading Failures, New Technologies, and Future Outlook. This publication also launches AMPP’s new energy-focused report series, created to give industry professionals clear, data-driven insight into infrastructure risks and practical steps for addressing them. Using publicly available data from the US Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), along with input from experienced industry professionals, the report examines the root causes of pipeline incidents. It identifies corrosion as a major, but avoidable, factor and outlines the additional challenges posed by aging assets, workforce shifts, and the introduction of new energy systems. Sponsored by Sherwin-Williams, the report also explores how the pipeline industry is evolving.

It looks at the growing use of digital tools and inspection technologies, and the expansion of H2 and CO2 pipelines. These developments are increasing the need for skilled personnel, consistent standards, and practical approaches to protecting and operating pipelines safely. The report draws on contributions from AMPP technical experts and industry partners, including specialists in engineering, inspection, and asset integrity. It incorporates insights on regulatory trends, workforce development, emerging technologies, and proven corrosion mitigation strategies. As the first publication in AMPP’s new energy Industry Report series, the report reflects AMPP’s commitment to serving as a trusted resource for the global corrosion and materials protection community. Future reports will address additional sectors and emerging infrastructure challenges, support industry collaboration and advance safety, sustainability, and asset performance worldwide.

Charps approved as hydrotesting service provider in California Pipeline infrastructure contractor Charps LLC (Charps) is now eligible to provide hydrostatic testing services in California after being confirmed as a state-approved service provider. Verified by the California Department of Forestry and Fire Protection (CalFire), Charps has been designated as an Approved Hydrostatic Testing Company. To meet state requirements, Charps had to demonstrate that it possesses the in-house expertise and resources for pipeline integrity testing, made possible by its pressure testing service range, which includes hydrostatic test planning and execution. Supplying construction, maintenance, integrity,

and emergency response services across North America, Charps had decades of experience, project records, and customer testimonials to leverage when working with CalFire throughout the application process. California’s pipeline safety standards are stricter than elsewhere in the country, meaning the list of approved vendors is limited and specialised. With the addition of Charps to this list, pipeline operators in California now have access to turnkey hydrostatic testing services enhanced by real-time monitoring, leak detection, and digital reporting, provided through subsidiary company, PipeSense.

MOU agreement a step forward to support growth and advance the proposed Pathways CCS Project A trilateral MOU has been entered into by the federal and provincial governments and Oil Sands Alliance member companies to support Canada’s ambition to become a global energy superpower. The MOU contemplates a series of regulatory reforms and fiscal measures needed to accelerate oilsands production growth and get products to new markets, including via the proposed West Coast Oil Pipeline. It also signals a continued commitment to supporting a more resilient, competitive, and sustainable Canadian oilsands sector. Advancing the proposed Pathways Project as

outlined in the MOU is subject to execution of definitive agreements and regulatory approvals. When operational, the Pathways Project will have the capacity to safely transport and store approximately 6 million tpy of captured CO2 by the mid-2030s from multiple oilsands facilities to a hub in the Cold Lake area for permanent underground storage. The Alliance will also work toward the objective of additional reductions in subsequent years which may be achieved by leveraging the Pathways Project, deployment of other emission reduction technologies, or projects deploying improved production practices.

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LATIN AMERICA NEWS IGU, ARPEL, and OLACDE launch landmark report on Latin America and Caribbean gas On 3 June 2026, the International Gas Union (IGU) together with the Association of Oil, Gas, and Renewable Energy Companies of Latin America and the Caribbean (ARPEL), and the Latin American Energy Organisation (OLACDE) launched a landmark report, Opportunities for the Development of Gas in Latin America and the Caribbean, highlighting the region’s potential to become a leading force in global energy markets while advancing its own energy evolution and socio-economic development. The report identifies major opportunities for Latin America and

the Caribbean to strengthen their energy security, reduce their energy poverty and support the wider global energy evolution, while highlighting how responsible development of the region’s vast gas resources could unlock economic growth, regional integration and lower-emission energy systems. While Latin America and the Caribbean possess abundant conventional and unconventional gas resources, including major shale formations, offshore discoveries, and significant undeveloped reserves, the region currently accounts for only approximately 5% of global natural gas production.

The US’s first US$500 million sale of Venezuelan crude marks a strategic reset in hemispheric energy relations as Latin America and the Caribbean enter a critical investment moment. When the US completed its first sale of Venezuelan oil, the US$500 million transaction reopened a geopolitical channel that had been largely dormant for years, signalling that energy pragmatism is once again shaping Washington’s approach to the Western Hemisphere. Carried out under a new US-Venezuela arrangement that allows sanctioned crude to be marketed with proceeds held in US-controlled accounts, the sale marks a tangible shift in how Washington is balancing political pressure with supply security. For Latin America and the Caribbean, the implications extend well beyond Venezuela. The resumption of Venezuelan crude sales has the potential to stabilise regional oil flows and support refinery economics in the US Gulf Coast, where heavy crude processing capacity remains significant. For Caribbean refineries and energy importers, greater availability of regional crude could reduce reliance on longer-haul imports from the Middle East or West Africa, lowering transportation costs and improving supply reliability for refineries and power producers. For island economies that remain heavily dependent on imported fuels, even incremental improvements in logistics, pricing and supply predictability can translate into meaningful fiscal and energy-security gains. Over time, this can support local employment, government revenues, and more resilient energy systems in markets that have historically paid a premium for fuel imports.

The shift also reflects Washington’s broader effort to reassert economic influence across Latin America at a moment of intensifying global competition. US President Donald Trump has publicly floated figures of up to US$100 billion in potential US investment in Latin American energy and infrastructure should engagement deepen – a figure that is more political signal than firm commitment, but nonetheless indicative of how central energy has become to US regional strategy. Even a fraction of that capital, if realised, would be transformative for upstream rehabilitation, midstream infrastructure and downstream modernisation across the hemisphere. For regional governments and energy companies, this moment presents both opportunity and urgency. Venezuela’s partial reintegration could unlock billions of dollars in deferred investment to rehabilitate aging fields, pipelines and export infrastructure. Neighbouring producers and service hubs also stand to benefit from increased regional throughput and collaboration. Guyana and Suriname are already attracting multi-billion-dollar upstream commitments, while Trinidad and Tobago continues to position itself as a gas processing and LNG anchor for the Caribbean. The US sale of Venezuelan oil may be only the first cargo in a longer process, but it is already a marker of change. For Latin America and the Caribbean, the question is no longer whether global attention is returning – it is how effectively the region positions itself to capture it.

THE MIDSTREAM UPDATE: WORLDPIPELINES.COM

• Baker Hughes to supply three gas compression units for major

natural gas pipeline in Argentina • Sallyport announces investment in Submar, a Louisiana-based

pipeline erosion remediation business. • CRC Evans secured US$37 million in new global contracts in

January 2026, marking a record month for the company

• AMPP marks five years united, showcasing progress and the

future of materials protection • Orbital Eye expands into North American market, appoints

Marc Fleck as General Manager North America • Trump’s Transportation Department streamlines inspections of

pipeline systems to enhance safety

• Texas Internal Pipe Coating launches expanded website to

• Kinder Morgan to acquire Monument Pipeline a natural gas

streamline customer access to technical data and support

pipeline system serving Houston and nearby markets

8 World Pipelines / AMERICAS 2026

SOUTH AMERICA NEWS EVENTS DIARY

Oceaneering secures Petrobras contract for ROV services offshore Brazil

14 - 17 September 2026

Oceaneering International, Inc. announced that its Brazilian subsidiary, Marine Production Systems do Brasil LTDA (MPS), has won a contract from Petróleo Brasileiro S.A. (Petrobras) to deliver ROV services offshore Brazil. The award follows a competitive tender process. The contract term is four years and operations are expected to begin in 2027. Oceaneering will supply two work class ROVs and specialised tooling packages in addition to carrying out monitoring and positioning support operations offshore Brazil. The ROV systems will be deployed from AKOFS Offshore’s subsea engineering support vessel (SESV) Aker Wayfarer,

Gastech Exhibition and Conference Bangkok, Thailand https://gastechevent.com/

15 - 16 September 2026 Subsea Pipeline Technology Congress (SPT 2026) London, UK https://sptcongress.com/

21 - 24 September 2026 ROG.E 2026 Rio de Janeiro, Brazil https://roge.energy/en

22 - 24 September 2026 International Pipeline Conference and Expo 2026 Calgary, Canada https://www.ipceyyc.com/

28 September - 2 October 2026 IPLOCA Convention Athens, Greece https://www.iploca.com/events/annualconvention/

20 - 22 September

which Petrobras has contracted for intervention, installation, and abandonment support scopes. The project will be executed by Oceaneering’s local team in Brazil. Oceaneering has supported Petrobras’ subsea engineering campaigns for more than a decade. With nearly three decades of presence in Brazil, Oceaneering – through MPS – operates multiple facilities, including a centre for ROV, Survey, Subsea Intervention Tooling, and Engineered Solutions and an Onshore Remote Operations Center in Macaé, along with an umbilical manufacturing plant in Niterói.

EnerMech awarded Saipem contract for Whiptail subsea pre-commissioning project offshore Guyana EnerMech has been awarded a subsea precommissioning services contract by Saipem for the Whiptail Development, located approximately 200 miles offshore Guyana in the Stabroek Block operated by ExxonMobil Guyana. This award marks EnerMech’s first project on the Whiptail field and builds on its proven track record supporting subsea pre-commissioning campaigns offshore Guyana, including Liza Phase 2, Payara, Yellowtail, and Uaru fields. Under the new contract, the integrated technical solutions specialist will deliver a full suite of activities, including flooding, cleaning, and hydrotesting of subsea risers and flowlines.

Umbilical post-load out, transit and lay monitoring from the offshore construction vessel. Dynamic umbilical lay monitoring and postinstallation testing from the FPSO unit. To meet the growing demand for offshore energy services in the region, EnerMech is establishing a new facility in Georgetown and executing a phased equipment acquisition strategy, including the addition of remote flooding units (RFUs) and subsea test pumps (STPs). These investments will support future projects and enable faster, more efficient mobilisation of equipment locally.

Hydrogen Technology World Expo

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Hamburg, Germany

PipeSense, the provider of pipeline leak detection and monitoring technologies, has announced the expansion of its services to support pipeline operations in South America following an exclusive agent agreement. Partnering with Chile-based FastPack, PipeSense will now have direct access to deliver its advanced solutions to the Chilean and Peruvian oil, gas, utilities, and mining markets. As an established provider of transportation, fluid handling, and asset integrity solutions to heavy industries, including mining and energy, FastPack provides US-based PipeSense with immense potential to establish itself in a new continental market for the first time. Strengthening both parties, this new agreement means that FastPack now has access to a catalogue of leak detection, pig tracking, and hydrotesting technologies that have covered oil,

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21 - 22 October 2026 UKOPA Conference & Exhibition Silverstone, UK https://ukopa.co.uk/event/ukopas-30th-birthdaycelebration/

02 - 05 November 2026 ADIPEC 2026 Abu Dhabi, United Arab Emirates https://bit.ly/4s9yXms

10 World Pipelines / AMERICAS 2026

refined product, natural gas, and water pipelines in North America since PipeSense entered the market in late 2023. The partnership follows receipt of an initial contract in which PipeSense will provide its PipeGuard leak detection system to a project in Peru in early 2026, supporting one of the region’s largest producers of metals and precious minerals. This marks the first time that PipeSense will deliver its expertise outside of North America, and the first time it has supported mining operations anywhere. Already a leader in the US market thanks to its rapidly growing reputation over the past two years, heading into 2026, PipeSense is targeting inter-continental investment and growth to replicate its success further afield. Endorsement in South America follows a similar agency agreement for PipeSense to distribute solutions in Canada.

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Simon Ellis, Senior Policy and Analysis Advisor, International Gas Union (IGU), considers a strategic imperative for energy security, development, and the energy evolution in Latin America.

s governments seek to balance energy security, economic development and decarbonisation, Latin America and the Caribbean possess a largely untapped advantage: abundant natural gas resources capable of transforming their regional prosperity while supporting a pragmatic energy evolution. Latin America and the Caribbean stand at a defining moment in their energy history as the region possesses many of the ingredients needed to become one of the world’s most important energy growth stories: abundant natural resources, growing economies, expanding energy demand and increasing potential to play a larger role in the global energy markets. Yet, one of its greatest strategic advantages remains significantly underdeveloped, and that is natural gas. Across Latin America and the Caribbean, vast natural gas resources remain largely untapped despite their potential to strengthen energy security, support economic growth, reduce energy poverty and contribute to emissions reductions. At a time when policymakers are seeking practical solutions to complex energy challenges, the opportunity presented by gas deserves renewed attention. The International Gas Union (IGU), together with ARPEL and OLACDE, recently examined this opportunity in depth through our report, ‘Opportunities for the Development of Gas in Latin America and the Caribbean’ and its findings are compelling as

they point to a region that possesses extraordinary potential, but which must act decisively if it is to realise the full benefits of its natural resource endowment. The message is clear: developing the region’s natural gas resources is not simply an energy opportunity but a strategic development opportunity.

A region rich in potential Few regions in the world can match the diversity and scale of natural gas resources found across Latin America and the Caribbean. From Argentina’s world-class Vaca Muerta formation and Brazil’s prolific pre-salt basins to the significant reserves of Venezuela, Peru, Bolivia, and Trinidad and Tobago, alongside emerging opportunities in Guyana and Suriname, the region possesses a resource base capable of supporting domestic growth while contributing to global energy security for decades to come. Yet despite this abundance, Latin America and the Caribbean account for only a small share of the global natural gas production. Even more concerning is the fact that that share has declined in recent years. This gap between geological potential and actual production should concern policymakers, investors and industry leaders alike, as it reflects challenges that are not

geological in nature. Rather, they stem from regulatory uncertainty, insufficient infrastructure, fragmented markets and difficulties in attracting the long-term investment needed to unlock large-scale resource development. The consequence is that a region with immense natural gas resources has yet to fully capture the economic, social and strategic benefits these can deliver. At a time when energy security has returned to the forefront of global policy discussions, this represents an opportunity that should not be overlooked.

Energy security and economic resilience Recent years, let alone the recent months, have demonstrated that energy security cannot be taken for granted. Latin America and the Caribbean have a unique opportunity to respond to this challenge from a position of strength. Geopolitical tensions, supply disruptions and increasingly volatile weather patterns have exposed vulnerabilities in energy systems around the world. Governments are recognising the importance of diversification, resilience and reliability in ways not seen for many years. Unlike many energy-producing regions, Latin America is largely insulated from major geopolitical conflicts and strategic chokepoints that can disrupt energy flows. Combined with its substantial resource base, this provides a strong foundation for attracting investment and building long-term energy partnerships. Developing domestic gas resources can help countries reduce exposure to volatile international energy markets, improve trade balances and strengthen macroeconomic stability. At the same time, gas development generates investment, creates employment and stimulates economic activity across the entire value chain, from exploration and production through to transmission, distribution and end-use industries. These benefits extend well beyond the energy sector as affordable and reliable energy is fundamental to industrial competitiveness, economic diversification and sustainable development. For many countries across the region, a greater availability of gas can support manufacturing, petrochemicals, fertilizer production and other industries that create jobs and strengthen the region’s national economies. In this sense, gas is not merely a fuel. It is an enabler of development.

Supporting a practical energy evolution

Figure 1. Gas pipeline (image created using AI) - credit: Arpel.

Figure 2. Gas production site - credit: Tecpetrol.

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Discussions about the future of energy often present a false choice between energy security and emissions reduction. Successful energy pathways require both. This is particularly true in Latin America and the Caribbean, where countries must simultaneously address economic development priorities, expand energy access and reduce emissions: natural gas can play an important role in achieving these objectives. The region has made significant progress in renewable energy deployment, particularly in wind and solar power. These investments should continue as renewable energy will, undoubtedly, play an increasingly important role in future energy systems. However, renewables alone cannot guarantee reliability. As electricity systems incorporate larger shares of variable generation, flexibility becomes increasingly important. This challenge is further amplified by the growing impact of climate variability on hydropower resources which have, historically, been a cornerstone of electricity generation across much of the region. Recent experience has demonstrated this reality. Periods of drought have reduced hydroelectric generation in several countries, requiring alternative sources of dispatchable power

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to maintain electricity supply. Natural gas has repeatedly proven capable of providing this flexibility. Rather than competing with renewable energy, gas can complement it, as it has constantly done so. gas-fired generation provides the reliability needed to support larger shares of wind and solar while helping maintain affordability and system stability. This is not a theoretical proposition. It is a practical solution already being deployed across many energy systems around the world.

Delivering immediate emissions reductions The role of gas in reducing emissions is sometimes overlooked. Yet, in many parts of Latin America and the Caribbean, substantial opportunities remain to lower emissions by replacing more carbon-intensive fuels. Several countries continue to rely heavily on fuel oil, diesel and other petroleum products for power generation. Replacing these fuels with natural gas can deliver immediate reductions in greenhouse gas emissions while also improving local air quality and reducing energy costs.

Figure 3. LNG tanker leaving port - credit: Stock photo.

The benefits of gas extend far beyond electricity generation: heavy-duty transport and maritime shipping remain among the most challenging sectors to decarbonise. While alternative fuels continue to develop, many of these technologies remain in the early stages of commercial deployment. For these, and others, natural gas offers a commercially available solution today. Compressed natural gas and liquefied natural gas can reduce emissions, compared with conventional fuels, while providing a pathway towards lower-emission energy systems. Importantly, the gas infrastructure developed today can also support the integration of future low-emission gases such as biomethane and hydrogen. This creates a valuable bridge between present-day energy needs and longer-term decarbonisation objectives.

The opportunity for regional integration Perhaps one of the most exciting opportunities identified in our Report is the potential for deeper regional integration. South America already possesses a substantial network of cross-border gas infrastructure. Over several decades, pipelines have been constructed connecting major markets across the Southern Cone and much of this infrastructure is currently underutilised. Historically, limited gas availability constrained regional trade, but that reality is changing. The development of Argentina’s Vaca Muerta resources has the potential to transform the regional energy dynamics. With vast unconventional natural gas reserves and growing production, Argentina is increasingly positioned to become a major supplier to neighbouring markets, and the benefits of greater integration would be shared widely. Brazil could access additional competitive supplies to support industrial growth and energy diversification, Chile could reduce its reliance on more expensive imported LNG, Uruguay could lower its domestic energy costs, Bolivia could strengthen its energy supply security while maximising the value of existing infrastructure, and Argentina could expand its natural gas exports, reduce its imports and generate significant foreign exchange earnings. In an era when regional cooperation is increasingly important, energy integration represents one of the most tangible opportunities to strengthen the economic ties and improve resilience across Latin America.

A growing role in global LNG markets

Figure 4. Fortín de Piedra production site, Vaca Muerta - credit: Tecpetrol.

16 World Pipelines / AMERICAS 2026

The opportunity presented by the Latin American gas resources extends beyond its regional markets as the global demand for LNG continues to grow as countries seek reliable and diversified sources of energy supply. This is precisely why Latin America and the Caribbean are well positioned to participate in this expanding market. Countries including Argentina, Trinidad and Tobago, Peru, Guyana, and Suriname possess significant opportunities to monetise their resources through LNG exports. Emerging technologies, including floating LNG solutions, are creating additional pathways to commercialise offshore resources that may otherwise remain undeveloped.

At a time when many importing nations are reassessing their energy supply strategies, this region has an opportunity to establish itself as a trusted and competitive supplier. But, capturing that opportunity will require investment, infrastructure and long-term policy stability – notwithstanding this, the potential rewards are substantial.

Reducing energy poverty and expanding opportunity Ultimately, every country’s/region’s/economic or multilateral block’s energy policy must be judged by its impact on people’s lives. Across Latin America and the Caribbean, millions of citizens continue to face some form of energy poverty. Many households still lack access to affordable, reliable and modern energy services. Expanding their access to gas can help address this challenge. Affordable energy improves living standards, supports economic opportunity and contributes to social inclusion. It enables businesses to grow, communities to prosper and families to enjoy better quality of life. Evidence from across the region demonstrates that improved access to modern energy services can deliver measurable and considerable social benefits while supporting broader development objectives. This is why energy pathways must be people-centred and, as evidenced, gas can play an important role in ensuring that no one is left behind.

Turning potential into progress The opportunity facing Latin America and the Caribbean is extraordinary as the resources exist, the infrastructure foundation already exists, the demand exists and the economic rationale is increasingly clear. What remains is the collective commitment to turn this region’s energy growth potential into progress. Its governments can help by providing stable and predictable regulatory frameworks that the financial community and capital markets require to provide them with the confidence that longterm projects will be supported by consistent policies and transparent institutions. Financial institutions and development partners also have an important role to play in supporting strategic investments that advance energy security, economic development and emissions reduction. As the world is entering a new phase of energy development, one shaped by the need for security, affordability, sustainability and resilience, regional cooperation must be strengthened to unlock cross-border opportunities and maximise the value of shared infrastructure. Latin America and the Caribbean have an opportunity not simply to participate in that future, but to help shape it. Natural gas is not the sole answer to the region’s energy challenges but, undoubtedly, it is one of the most important levers available. The time has come to use it.

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Colin M. Frazier, API, discusses the ever-changing energy security landscape in the Americas.

energy supply. Their growing importance reflects a basic reality: as energy demand rises and markets seek reliable supply, the need for production growth, expanded export capacity and deeper cross-border energy connections become more important. In that environment, pipelines remain essential

infrastructure, providing the safest means of transporting oil, natural gas and related products from production centres to processing facilities, export terminals and end markets, supported by standards and safety frameworks such as those developed by the American Petroleum Institute (API).

North America: the transport imperative

Figure 1. Proportion of US LNG exports that went to the EU in 2024.

This reality is perhaps most prominent in North America, which has expanded its role in oil and natural gas production and exports. But its resource abundance only attains value when matched with the infrastructure that gathers, transports, and delivers it safely and efficiently. Consider the case of LNG. The US serves as a major LNG supplier to Europe (see chart in Figure 1), helping the region diversify its energy sources and strengthen energy security. That export growth depends on the pipeline networks that move natural gas from producing regions to processing and export facilities. But that alone is not enough. Even the most efficient infrastructure network combined with resource abundance requires a predictable and durable regulatory environment. When permitting reviews lack clear processes or enforceable deadlines, critical projects are left in limbo, and infrastructure cannot keep pace with market opportunities. For continued success in scaling North American oil and gas industry capabilities, certainty is the essential prerequisite for converting infrastructure investment into energy security for the region.

South, Central, and Latin America: investments fuel export growth

Figure 2. Field inspection and monitoring help support safe and reliable pipeline operations.

Figure 3. Control room personnel monitor pipeline systems and operating conditions in real time.

20 World Pipelines / AMERICAS 2026

This need for a predictable path to development continues to emerge across South, Central, and Latin America, where rising production increases the importance of pipeline and midstream infrastructure, including cross-border natural gas integration. Indeed, Brazil, Argentina, and Guyana are all expected to reach record production levels in 2027. That is, if the systems needed to move that supply can keep pace with opportunity, as infrastructure constraints remain a persistent bottleneck to scaling regional and international supply. In Argentina’s Vaca Muerta, where oil production reached about 600 000 bpd in 2025, the Vaca Muerta Oil Sur project has secured US$2 billion in financing for a 550 000 bpd pipeline and related storage infrastructure. This investment is part of a broader effort to strengthen the country’s exports and reduce its dependence on imported gas. As a result, Argentina’s energy trade surplus could reach as much as US$10 billion in 2026, according to Reuters. Brazil’s gas market highlights a related issue. While building infrastructure is important, so too is creating a market framework that allows it to function effectively. Recent tariff revisions approved by Brazil’s regulator ANP help clarify capacity-contracting rules and establish a more stable pricing mechanism, giving operators and shippers greater predictability. Additionally, ongoing efforts to enhance regulatory clarity are intended to support private and international investment. Together, these reforms can help improve how natural gas is moved across the country’s midstream system, brought to market, and connected with cross-border flows.

This shift is taking shape in an evolving gas relationship between Argentina, Bolivia, and Brazil, where regional interconnections can improve supply reliability and create more options for balancing energy across markets. In Bolivia, for example, efforts to update energy regulations are aimed

A framework for Pipeline Safety Management API RP 1173 describes 10 essential elements for the comprehensive and systematic management of safety-related activities for energy pipeline operations and explains how these elements can be used as part of a repeatable and consistent approach to help ensure safe pipeline operations. ) Leadership and management commitment. ) Stakeholder engagement. ) Risk management. ) Operational controls. ) Incident investigation, evaluation, and lessons learned. ) Safety assurance. ) Management review and continuous improvement. ) Emergency preparedness and response. ) Competence, awareness, and training. ) Documentation and record keeping.

Figure 4. Pipeline networks connect production, processing, and end markets across an integrated energy system.

Figure 5. Storage and terminal infrastructure support the efficient movement of energy to market.

22 World Pipelines / AMERICAS 2026

at creating clearer rules and regulatory certainty, which could help attract investment. This could help revive cross-border energy partnerships, improving access across the region.

API standards for emerging technologies As regional markets integrate and as new technologies are being brought to scale, the role of pipeline infrastructure is expanding beyond conventional fuels. Across the Americas, pipelines are increasingly being considered part of the systems needed to support emerging technologies as the oil and gas industry continues to mitigate emissions and drive toward a lower carbon future. As interest in carbon capture, utilisation, and storage (CCUS) continues to grow, so does attention to the infrastructure needed to move CO2 securely and uninterrupted between capture sites and long-term storage locations. Reflecting this rising interest, API published API Recommended Practice 1192 (RP 1192), Transportation of Carbon Dioxide by Pipeline, providing industry guidance for the safe and reliable transport of CO2. The document addresses technical considerations that differ from those associated with oil and natural gas service. These considerations are critical because CO2 behaves differently from other substances commonly transported in pipelines. As a result, RP 1192 focuses on three primary guidance areas: dispersion modelling, which helps operators estimate the potentially affected area of a CO2 release; equations of state, which inform design and operating decisions by estimating how CO2 behaves under different pressures, temperatures and mixtures; and fracture control, which helps reduce the risk that a crack would form or continue to spread. And as pipeline applications continue to evolve, frameworks like RP 1192 will need to evolve, as well. That evolution will also extend to hydrogen, where API revisions to API Spec 5L, Line Pipe, and API Spec 6D, Specifications for Pipeline and Piping Valves, documents for pipelines and piping valves, address the specific requirements of hydrogen service. As with all API standards, these will all be reviewed and potentially updated on a five year cadence as technologies and operational methodologies mature.

The importance of safety systems As pipeline infrastructure expands in both scale and application, its enduring value depends on modernised regulations and safety frameworks that help operators identify risk, strengthen decision-making and continuously improve performance. That need becomes even more important as pipeline systems take on greater strategic significance across the Americas, connecting supply chains and diversifying products transported. To that end, API and pipeline operators, working in partnership with the US Pipeline and Hazardous Materials Safety Administration (PHMSA), state pipeline regulators and pipeline safety advocacy groups, developed API Recommended Practice 1173 (API RP 1173), Pipeline Safety Management Systems. The document helps pipeline operators implement a safety management system to systematically manage pipeline safety risks and continuously

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measure progress to improve overall safety performance. It is designed to be scalable and flexible for companies of different sizes and at different stages of implementation, while reinforcing the role of safety culture across the organisation. API RP 1173 outlines 10 essential elements for the systematic management of safety-related activities in pipeline operations, including leadership and management commitment, stakeholder engagement, risk management and operational controls (for the complete list, see the sidebar). These elements provide a structured approach for helping operators strengthen safety performance over time. The document serves as the framework for API’s Pipeline Safety Management System (PSMS) programmes.

Through implementation tools and the API Third-Party PSMS Assessment Programme, PSMS gives operators and contractors (two separate programmes) who work on pipelines a standardised, objective way to evaluate the maturity of their systems and identify opportunities for improvement. Its goal is to move companies beyond safety compliance alone and toward a more disciplined approach to safety culture and performance. These programmes are not based on regulation, as safety management systems are considered the voluntary industry standard for managing safety all over the world – represented in all segments of industry. It is a collaborative approach that is central to API’s standards and safety work. For more than a century, API has developed more than 800 standards, working through a consensus-based process that brings together technical experts from across the industry and around the world. And in the pipeline space, that work includes frameworks such as API RP 1173 and PSMS, which help operators strengthen safety performance as pipeline infrastructure continues to evolve. These and other standards and programmes reflect a growing emphasis n Lightweight, one-piece ergonomic design provides comfortable all-day use around shared technical expectations n One wand covers the entire voltage range from 0.5 to 30 kV across global energy markets. As n Up to 16 hours of battery life—powerful Li-ion batteries fit neatly within the operators, manufacturers, regulators, compact wand handle eliminating the need for a separate battery box and other key industry stakeholders n Built-in Certified Voltmeter and Voltage Calculator feature work to modernise infrastructure, n Industry standard connectors and adaptors provide compatibility with strengthen supply chains and integrate nearly all existing electrodes new technologies, API standards and programmes help provide a common technical foundation that drives safety as a foundational principle.

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As the global energy landscape continues to evolve, shaped by uncertainty and change, one reality remains constant: connecting energy supply to the markets that depend on it requires safe, reliable pipeline infrastructure. Across the Americas, that foundation is becoming increasingly resilient. And more important than ever to the global energy landscape.

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Colin Frazier is the Senior Director of Safety Programmes at API. He has worked in the oil and gas industry for 15+ years, with expertise in safety and environmental policy, programming, and data.

David Gross and Anna Ignatova, ION Commodities, and Jay Bhatty, NatGasHub.com, explain why the ability to move data is becoming as important as the ability to move gas across North America’s pipeline network.

orth America is in the middle of what many now call a renaissance, even a golden age, for natural gas. Demand is rising, the customer base is broadening, and gas is being asked to do more across the energy system than ever before. But abundance brings its own pressure. The central question is shifting from whether there is enough gas in the market to whether it can be moved

through existing pipelines quickly, accurately and efficiently enough to keep up with a market that changes by the hour. That shift reflects a fundamental change in who is buying gas. For decades, demand came predominantly from residential and commercial users and power generators. That picture has widened considerably. Since the middle of the last decade, LNG exports have created a major new source of demand and tied North American supply far more directly to international prices, global demand and geopolitical events – now one of the clearest structural forces reshaping the continent’s gas balance. Power generation remains a major and growing call on gas, and a new, power-intensive form of demand is emerging alongside it. Data centres, driven by AI computing, add load distinct from residential, commercial, and industrial consumption and from LNG: it is tied to domestic power infrastructure, grid availability and the pace of computing growth. Where the grid is constrained, operators increasingly look to dedicated or on-site generation, pulling demand closer to those facilities. Coal-to-gas switching adds another pull, with gas the most readily available substitute, reinforcing the need for reliable gas flows. All of this means that more kinds of customers are competing for flows through the same network – this is a commercial opportunity, but also a new operational challenge.

A network under strain Rising demand falls, first and foremost, on the physical pipeline network, but that network is not growing nearly as fast as the demand placed on it. New interstate pipelines remain difficult, slow and contentious to build. While some capacity is being added, particularly intrastate, participants must make better use of the infrastructure that already exists. Pipelines that once carried spare or underutilised capacity are now running closer to full. As they do, constraints, cuts, and capacity limitations become far more commercially significant, and firms can no longer assume capacity will be available whenever an opportunity arises. With limited new builds, the secondary market for trading and re-leasing capacity is likely to grow – something close to an Airbnb for pipeline space, where shippers resell what they hold to whoever values it most. Like prime real estate, that space is finite and likely to become more expensive, putting upward pressure on tariffs as owners charge more for capacity on peak summer and winter days. Price risk, geopolitics, and shifting demand all feed into planning and execution, and plans once stable over longer periods are now exposed to intraday change. Pipeline execution – timely, accurate nominations and scheduling – is becoming central to how firms manage volatility, capacity and performance, because small timing gaps or mismatches quickly turn into imbalance exposure, delivery risk or a missed market. None of this is abstract. In January 2025, ANR Pipeline declared force majeure after an unexpected equipment failure, cutting northbound capacity at several locations by around 300 million ft3/d and warning shippers that already-

26 World Pipelines / AMERICAS 2026

scheduled volumes would be cut for that day’s evening cycle. This is exactly the kind of event that squeezes teams against fixed-cycle deadlines: positions must be reworked and resubmitted in a narrow, high-pressure window, and any clerical delay incurs a direct cost. Other days bring different but equally demanding problems. On 13 June 2026, Northern Natural Gas was experiencing numerous capacity constraints across its system simultaneously – dozens of separate constrained paths and allocation points, alongside an open force majeure in one area. Schedulers were forced to juggle bulletin board screens, spreadsheets, and their trading and risk system across all of them. This cumulative manual overload can mean simply reacting too late or booking against quantities already out of date.

The gap between trading and execution The trouble is that many firms still manage nominations and scheduling through manual, spreadsheet-heavy processes. Those workflows were workable when the market moved more slowly, and capacity was less constrained; they are increasingly inadequate when speed, accuracy and intraday visibility are what matter. In a typical workflow, the same information is entered two or three times: a scheduler plans in a spreadsheet, keys it into one or more pipeline websites or electronic bulletin boards, then enters it again into an internal CTRM/ETRM system. When a constraint, cut, or schedule change lands, each system must be updated by hand. Every manual handoff is a point where information can drift out of step, where updates may not reach trading, risk, credit or back-office teams quickly enough, and where teams work from different versions of the truth. The consequences are familiar: imbalance risk, missed opportunities, inaccurate positions and avoidable cost. Much as travellers once had to visit several websites to assemble a single trip before Booking.com, schedulers must move across multiple pipelines, routes, counterparties and time periods to complete what is, in effect, one process, now with far greater complexity and far less margin for delay. The problem is not a lack of expertise, but that these teams are being asked to run a faster, more constrained market through processes that demand too much manual duplication.

Connecting pipeline workflows with CTRMs A good solution must address these specific problems: less re-keying, a more unified workflow, scheduling and nomination data that flows back into the CTRM/ETRM environment quickly, and greater speed, accuracy, and consistency. This is the gap ION and NatGasHub.com are working to close. NatGasHub.com provides connectivity to 300+ pipelines across North America; ION provides the CTRM/ETRM environment in which trades, positions, risk and commercial data are managed. Together, they link commercial decisions to physical execution. Rather than moving from spreadsheet to pipeline bulletin board to trading system, firms can connect the CTRM/ETRM environment directly to pipeline workflows: nominations

and scheduling become less manual, routine pipeline communication can be automated, updates flow back into the system of record more quickly, and operational data becomes visible to the teams that need it. This connectivity also changes the purpose of a CTRM/ETRM system. Historically, these platforms were treated mainly as systems of record; that is no longer enough. They must become operational decision-making environments that link commercial intent, physical execution, risk, credit, and back-office processes. The commodity is gas, but the data attached to it are increasingly valuable in their own right. Firms must move both the molecules and the data so that operational reality is reflected in their commercial and risk views. Spreadsheets won’t disappear – they will keep a role at many firms – but the goal is to remove the most repetitive, time-sensitive and error-prone handoffs. The payoff is faster nominations and scheduling, fewer duplicate entries, lower risk of manual error, faster updates when cuts or constraints occur, and more consistent data across desks. This also unlocks scale: as more gas moves through existing infrastructure, firms cannot keep adding manual effort in proportion to complexity but need workflows that absorb greater volume without a matching rise in burden – making automation a source of resilience as much as efficiency. More broadly, focusing on cleaner, more standardised data will help teams break out of data silos, allowing each member direct access to current pipeline information rather than depending on a colleague for the latest position.

The data foundation for AI That cleaner data foundation matters far beyond today’s workflows, because it is the precondition for doing AI well. AI will transform how firms analyse, optimise and manage gas operations, speeding up the analysis of market, operational and risk data, helping teams spot patterns and manage exceptions, and increasing in importance as markets become more intraday. But it depends on the foundations above: firms cannot use AI effectively if key data is trapped in spreadsheets, pipeline portals, and disconnected systems, or if nominations, schedules, positions, and constraints are not standardised and up to date. ‘Bad data in, bad data out’ remains the central challenge. AI does not reduce the need for accurate operational data; it raises the stakes, amplifying incomplete, late or inconsistent data rather than fixing it. As large language models commoditise, the differentiator will increasingly be the quality of the data a firm can feed them. CTRM/ETRM and pipeline workflow systems will be critical because they standardise, cleanse and structure it. The firms best placed to use AI will be those that have already connected their trading, scheduling, pipeline and risk workflows.

Benefits across the desk, and the business The payoff is felt across the organisation. Traders see whether commercial decisions have actually been executed physically, and respond faster to intraday change. Schedulers spend far less time on duplicate entry – a real opportunity

cost recovered – and more on exceptions, constraints and higher-value judgement. Risk teams gain more current visibility into positions and an independent data feed direct from each pipeline, easing their reliance on traders to confirm what is flowing. Credit teams work from more timely, consistent data; back-office teams face fewer breaks between trade capture, scheduling and settlement; and management gains a clearer view of how activity is executed and where bottlenecks lie. Better connectivity improves the flow of information across the business, which is how operational automation becomes commercial performance.

Collaboration over duplication Nominating, scheduling and communicating with pipelines accurately is something every shipper must do, but it is rarely where firms compete; the commercial edge comes from trading and market decisions, not from the mechanics of execution. That makes it an odd thing for each firm to reinvent in isolation. And in a market this interconnected – where shippers, pipelines and counterparties all rely on the same timely information – smoother, better-connected workflows lift efficiency across the market as a whole, not only inside any one company. Firms could build these tools themselves, but it would be slow and costly, with the full capital and maintenance burden falling on them rather than shared across an industry. Effective automation also demands deep knowledge of trading, scheduling, nominations, and constraints. Collaboration can help tackle a shared problem faster than firms could alone, reducing operational friction, improving data flow across the gas value chain, and enabling the necessary scalability for the next phase of market growth.

Keeping pace North American gas is entering a more demanding operating environment. LNG, power, data centres, geopolitical risk and pipeline constraints are all adding volatility and complexity, and existing networks will have to carry greater volumes and more complex flows. As capacity tightens, firms will need to operate faster and more accurately than disconnected systems and manual workflows allow, moving towards more connected, automated and data-rich operating models, with pipeline execution integrated far more closely into trading, risk and operational decisions. Technology will not remove market volatility or pipeline constraints. What it can do is help firms manage them: scaling operations, reducing errors, improving visibility and responding faster when conditions change. In a market defined by higher volumes, tighter capacity and faster movement, speed, accuracy and data quality have become strategic capabilities, not back-office details. The firms that build them now will be best placed for the next phase of North American gas. Increasingly, moving data accurately and quickly matters as much as moving the gas itself – and connected pipeline execution is not simply a technology upgrade, but a foundation for resilience in a more volatile, capacity-constrained market.

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Gianluca Colonnelli, Senior SURF Manager, KBR, considers how the Americas market is seen from a pipeline view.

ecent developments across the Americas have brought energy pipeline infrastructure back into focus, particularly as offshore projects become more technically demanding and regional supply routes attract renewed attention. The Americas cannot be treated as one pipeline market; a project in the

Gulf of Mexico deals with different challenges than in Guyana, Brazil, or Venezuela.

Mature basins In the Gulf of Mexico, where there is vast offshore infrastructure built over decades, operators favour subsea

tiebacks to existing hosts. Operators have also found it a natural habitat for developing technologies and innovation. Recent developments such as Chevron Anchor and Beacon Shenandoah are part of a new generation of high-pressure offshore projects requiring 20 000 systems, a step forward from the 15 000 already considered demanding from an equipment and materials perspective. These drive wall thicknesses often above 1.5 in. in relatively small diameter pipelines.

Anchor and Shenandoah are new host developments, but where high-pressure fields are tied back to existing hosts, operators need high-integrity pressure protection systems (HIPPS) to manage pressure safely. HIPPS is widely used in the North Sea but remains relatively new in the Gulf of Mexico. Offshore Brazil remains one of the most important markets in the world. Its deeper offshore fields and CO2-rich production have driven the selection of short flexible lines, with suppliers expanding capacity to support the market. This also means that the Brazil market favours FPSO activities. The flexible riser part of the system has its own lifecycle challenge due to fatigue damage coupled with CO2 strength reduction, which means that inspection, replacement and decommissioning have become an integral part of the scope. The Caribbean has also long supplied gas to the region and continues to attract investment with Venezuela adding another dimension.

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Figure 1. KBR’s ASTEP I.S. platform uses a normally unattended platform.

Venezuela has significant existing onshore infrastructure. Much of it is ageing and has not necessarily been maintained to the standard needed for a rapid restart but it is certainly a region that is expected to be focused on. Colombia may also become part of this wider picture if recent gas discoveries move forward. The Mexican side of the Gulf is also seeing renewed interest. Woodside’s Trion development, for example, is bringing deepwater activity into a part of the region that has historically been dominated by shallow-water projects; other shallow water opportunities are also under consideration but require political stability and support. Elsewhere, Guyana, and Suriname are developing rapidly while building the infrastructure needed to support long-term offshore activity. Although the producing FPSOs and those under construction tend to attract the most attention, the pipeline scope is substantial, with around 1000 km of pipelines expected to be laid by 2030, including 200 km of pipeline-to-shore infrastructure to support gas monetisation. Each region has its own history, challenges and operating environment. That is why it is difficult to talk about pipelines in the Americas in broad terms.

LNG and alternative fuels Figure 2. A new generation of 20 000 high-pressure offshore projects is driving wall thicknesses above 1.5 in. in relatively small diameter pipelines.

32 World Pipelines / AMERICAS 2026

The global LNG market is expanding, and the Americas is no exception. LNG, FLNG and

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FSRU projects are all being studied and developed across the region, and each depends on pipeline infrastructure in some form. Cryogenic LNG systems are significantly more complex than pipelines carrying processed natural gas in gaseous form, but the pipeline network is still what connects the import, export, regasification or receiving facility into the wider energy system. KBR is working on several LNG projects, one of these is the JERA Longboard LNG project in Hawaii, which includes an import terminal connected to an FSRU by a short shallow water pipeline. It is fascinating to see how reducing the carbon footprint can be combined with providing cheaper electricity to serve the public via the Hawaii Gas pipeline system. The pipeline itself may be only one part of the capital cost, but it can determine whether the wider system operates safely, efficiently and with enough flexibility for future needs. The Longboard project also gives an insight into how much work is required before construction begins. JERA Americas has just started the FERC pre-filing process, and even at this early stage, engineering work is already underway including detailed installation assessments. One interesting assessment we are carrying out is looking at how the same infrastructure could potentially support alternative, lower-carbon fuels in the future. Adapting a pipeline for a different product can sound straightforward, but it still needs proper validation. In some cases, the checks may be relatively high level, particularly where an existing gas export line is being used for dry gas, or to support an LNG or FLNG development. The main questions are usually around integrity, internal corrosion and external corrosion. If those are under control, and the new product is compatible with the original design, reuse may be relatively straightforward. The same may be true for some refined or renewable fuels. An older oil line could potentially be repurposed for a product such as SAF or another processed fuel,

provided the pipeline is in sound condition and the new product does not create a more aggressive operating environment. CO2, hydrogen and ammonia bring different challenges. CO2 transport, whether for CCUS or enhanced recovery, can introduce corrosion risks, particularly when the stream contains impurities such as water, hydrogen sulfide, oxygen, nitrogen or trace hydrocarbons. Dense-phase CO2 pipelines also need to be designed carefully for fracture control, as running ductile fractures can propagate along the line if the material is not suitable. Even small traces of hydrogen can reduce the toughness of modern seam-weld steels, increasing the risk of rapid fracture propagation. Hydrogen and ammonia can affect material strength and lead to embrittlement. A pipeline that is perfectly acceptable for one product may need to be derated for another. In some cases, that derating could make the pipeline unsuitable for its new duty, with implications for welding, material selection and whether the line can be reused at all. There is also a wider system question. A gas pipeline that is technically capable of carrying hydrogen may still not deliver the same amount of energy equivalent to the end user, because hydrogen has a lower volumetric energy density than natural gas. The line may work from a materials perspective, but still not provide enough energy for the facility it is supposed to supply. That could mean additional pipelines and/or facilities or a different solution altogether.

Strategic front-end evaluations

These assessments need to be performed during the early phases of the project cycle, ahead and in support of the final investment decision. This is where concept and pre-FEED work comes in. The early phase is where solutions can be tested, new and alternative ideas can be evaluated and technology thought of. This is where solutions such as KBR’s ASTEP I.S. can become relevant. Designed to support long-distance subsea tiebacks to existing host platforms up to 100 km away, it uses a normally unattended platform to provide a functional approach to power generation, chemical injection and subsea control to overcome flow assurance challenges. The same study approach is relevant to brownfield and life extension integrity assessments. All pipeline systems require long-term maintenance. Pipelines are usually designed for a defined service life, often 20 - 30 years, but once they are operating, they must be monitored like any other asset. This is particularly relevant in regions like Venezuela, where much of the onshore infrastructure is older and may have been idle or under-maintained for long periods. Venezuela’s heavy, sour crude, often with Figure 3. KBR’s ASTEP I.S. platform is designed to support long-distance subsea tiebacks to existing host platforms up to 100 km away. high sulfur content, can also place greater

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demands on the system. If a pipeline has not been properly maintained, restart may involve much more than simply opening a valve. The cost of recovery can be far higher than the cost of maintaining integrity in the first place.

Taking a systems-based view These are only a few examples of how pipeline activity reflects wider market trends; many other active and emerging regions, including Argentina, the Falklands, Canada and the Permian Basin, are also driving infrastructure development. The technical demands are rising in mature basins. New markets are developing faster than their infrastructure. Legacy regions may reopen, but with assets that need careful assessment. New energy products are changing the assumptions that older pipelines were designed around. Pipelines will remain central to energy development across the Americas. They will support offshore oil and gas production, LNG import and export, domestic gas networks, future low-carbon fuels and, potentially, wider CO2, ammonia, and hydrogen systems. It is easy to see a pipeline as simply a line between two points, after all, that is how it appears on P&IDs. The reality is that as the interface to all the other facilities, the pipeline design takes care of all these interfaces, and, as in any system, the interfaces are critical.

It is also true that the pipeline challenge in the Americas is bigger than the pipeline itself, as projects become more technically demanding and more regionally varied, success will depend on taking a systems-based approach. For operators, this means that pipelines should not be treated as isolated assets. They need to be developed together with the infrastructure they connect to, the conditions they will operate under, and the future demands likely to be placed on them.

About the author Gianluca Colonnelli is Senior SURF Manager at KBR with over 25 years of experience in the Energy industry; he has worked in small- and large-scale concept, FEED, and EPCI projects located in Europe, Africa, and the Americas.

About KBR KBR deliver science, technology, and engineering solutions to governments and companies around the world. They employ approximately 36 000 people worldwide with operations in over 28 countries. KBR is proud to work with its customers across the globe to provide technology, value-added services, and longterm operations and maintenance services to ensure consistent delivery with predictable results.

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Pushpendra Tomar, Principle Pipeline Integrity Engineer, T.D. Williamson, explains the role of compression sleeve repairs in ensuring a reliable supply or energy.

consumption for data centres is set to more than double to approximately 945 TWh by 2030, driven largely by AI workloads. As a result, uninterrupted energy delivery often reliant on pipeline infrastructure has become a critical operational requirement. Traditional repair methods typically require shutdowns, such as pipe replacement, or prolonged pressure reductions associated with welded repairs and in-service welding. The Type C compression repair provides a practical, permanent repair solution without service interruption. Installed without welding to the carrier pipe and typically requiring minimal pressure reduction, these systems reduce operational risk while reinforcing the pipeline through load sharing and induced compression. This mechanism mitigates defect growth, including crack-like features, supporting longterm integrity.

As reliable fuel supply becomes essential for high-demand digital infrastructure, increased adoption of repair methods such as Type C compression repair may be necessary to enable resilient pipeline operations without interrupting delivery.

Factors for growth in energy demand AI workloads require high-density computing clusters powered by advanced processors, which consume significantly more energy than traditional servers. Cooling demand is increasing proportionally, as AI infrastructure generates higher heat loads, requiring energyintensive thermal management systems. Hyperscale data centres are expanding rapidly, with new facilities often requiring dedicated or co-located power infrastructure. In practical terms, this shift represents a structural change in the US energy system. Growth rates for data centre electricity demand have accelerated from approximately 7% annually (2014 - 2018) to 18% annually (2018 - 2023), with projections of 13 - 27% annual growth through 2028.

Implications for energy supply infrastructure

Figure 1. Compression sleeve/PETROSLEEVE® repair system.

The implications of this demand growth extend beyond the power grid. In many regions, particularly in major data centre hubs such as Texas and Virginia, AI-driven load growth is beginning to outpace available generation and transmission capacity, creating operational and planning challenges for utilities and infrastructure operators. This has led to several emerging trends: ) Increased reliance on natural gas-fired generation to provide flexible, dispatchable power for data centres. ) Deployment of on-site or behind-the-meter generation, often gas-based, to ensure reliability and avoid grid constraints. ) Heightened focus on energy security and continuity, particularly for critical digital infrastructure where outages can have immediate economic and operational consequences. ) In this context, pipelines play a critical enabling role by delivering the natural gas and liquid fuels required to support both grid-scale generation and distributed energy systems.

Limitations of traditional pipeline repair approaches

Figure 2. PETROSLEEVE being placed on pipeline for repair.

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Historically, pipeline repair strategies have relied on methods such as cut-out and replacement or welded sleeve installation (e.g., Type B sleeves). While effective, these approaches introduce operational and integrity risks that are increasingly difficult to justify in environments where uninterrupted supply is essential. ) Cut-out and replacement typically require pipeline depressuriation and shutdown, leading to production losses and increased operational complexity. ) Welded repairs, including full-encirclement or pressurecontaining sleeves, necessitate in-service welding, which introduces risks such as burn-through, hydrogen-assisted cracking, and heat-affected zone degradation.

) These constraints are amplified when operating conditions

involve high-strength steels, thin-wall pipelines, or locations where welding procedures are difficult to execute safely. As defect detection technologies improve particularly for crack-like features such as stress corrosion cracking (SCC) or circumferential cracking operators are increasingly required to repair a broader range of defects without major impacts to product supply.

PETROSLEEVE® or Type C compression repair: concept and mechanism T.D. Williamson (TDW’s) PETROSLEEVE or Type C compression repair system represents a fundamentally different approach compared to traditional welded repairs. Classified as a metallic repair method within industry practice, these systems work through induced compressive stress and load sharing. The repair system is a two-part metallic sleeve installed around the pipe without welding to the carrier pipe. The repair mechanism can be described through two primary effects:

Load sharing and reinforcement It creates a strong mechanical interference with the carrier pipe and provides structural support by sharing hoop stresses with the carrier pipe, thereby adding additional strength, and reducing the stress intensity experienced at the defect.

Induced compression at the defect location The installation process places the defect in the repair region into a compressive stress state, which counteracts the tensile stresses responsible for crack initiation and propagation. While compression sleeves are effective for blunt defects such as corrosion, that require bulging restraint, their induced

compressive stresses are particularly beneficial for crack-like defects. Compression reduces the effective stress intensity at the crack tip by limiting crack opening and altering the local stress field. Experimental studies and numerical analyses have shown that tight-fit or compression-based sleeves can reduce stress intensity factors and maintain crack closure, thereby slowing or arresting crack propagation under operating loads. In practice, once installed, the sleeve maintains continuous compression on the pipeline and can prevent further defect growth while restoring structural integrity.

Operational advantages: maintaining service continuity A key advantage of the PETROSLEEVE repair is its ability to be installed without interrupting pipeline operations. Unlike cut-out or welded repairs, these systems: ) Require no welding to the carrier pipe, eliminating welding-related risks and qualification requirements. ) Can typically be installed with minimal or no pressure reduction, depending on operating conditions and installation parameters. ) Allow the pipeline to remain in service throughout installation, preserving throughput and avoiding supply disruptions. ) These characteristics directly support operational continuity, which is increasingly critical in high-demand energy systems. In addition, the absence of welding reduces exposure to risks associated with material properties (e.g., high carbon equivalent steels) and field conditions, while also simplifying execution logistics and reducing installation time.

Application scope and integrity considerations Type C compression repair systems have been applied to a wide range of defect types, including: ) External corrosion and wall loss. ) Crack-like defects (including SCC and circumferential cracking). ) Dents, gouges, and mechanical damage. ) Manufacturing or construction-related defects. Field experience and documented performance over several decades indicate that compression sleeves can provide permanent, code-compliant repair solutions, provided that appropriate engineering design and installation controls are applied.

Supporting resilient energy infrastructure

Figure 3. PETROSLEEVE being installed under designed parameters.

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As electricity demand continues to increase driven by digitaliation, electrification, and AI, the resilience of energy supply systems becomes a critical concern. Pipelines play a central role in delivering fuels required for power generation, industrial processes, and backup energy systems supporting data centres. In this context, repair technologies that support continuous operation, reduced installation risk, and

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long-term defect mitigation will play an increasingly important role in maintaining system reliability. The PETROSLEEVE repair systems align with these requirements by providing a non-intrusive, permanent repair option capable of restoring integrity without interrupting service. Their ability to mitigate crack growth through induced compression offers a distinct advantage in addressing emerging threat profiles associated with modern inspection and monitoring technologies.

Case study To maintain gas flow and pipeline integrity, an operator in the US was required to address multiple stress corrosion cracking (SCC) and double submerged arc weld (DSAW) defects. These defects were distributed across 13 locations on a 36 in. diameter pipeline operating at approximately 820 psig. Based on defect characteristics and pipe geometry, conventional repair methods, such as welded Type B sleeves, were expected to require an extended repair duration, potentially up to five weeks, due to installation complexity and associated operational constraints. The operator elected to install 22 PETROSLEEVE compression sleeves. This approach allowed the repair programme to be completed in four days. The selected method also avoided additional pressure restrictions and associated operational impacts, including potential throughput losses.

Conclusion The evolving energy landscape, characterised by rapid growth in AI-driven demand and critical infrastructure reliance, requires pipeline operators to adopt repair strategies that prioritie both integrity and continuity of supply. Traditional repair approaches, while effective, often necessitate operational disruptions or introduce additional risks. As the need for uninterrupted energy delivery continues to intensify, the adoption of proven, non-intrusive repair technologies such as PETROSLEEVE may become an essential component of modern pipeline integrity management programmes.

About the author Pushpendra Tomar is a Principal Pipeline Integrity Engineer at T.D. Williamson with over 16 years of experience supporting global pipeline integrity and repair programmes. His background combines engineering analysis with hands-on field execution, including direct involvement in repairs and supervision under active operating conditions. His expertise spans in-line inspection, integrity consulting, repair programme development, advanced field services, and metallurgical investigations. He has worked with Applus RTD, Kiefner and Associates, and Dynamic Risk, bringing a practical, operator-focused perspective while actively contributing to IPC, PRCI, and ASME.

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Jeff Lehr, Vice President of Product Innovation and Execution, WeldFit, describes improving the economics and safety of high-frequency pigging programmes through automation.

or operators managing liquids-rich natural gas pipelines, pigging is not optional. It is a critical operational requirement that helps maintain flow efficiency, maximise throughput, control liquid accumulation, and protect downstream processing facilities.

Figure 1. Installed in the field, the SureLaunch® system helps operators reduce operational complexity while maintaining pipeline integrity.

In many liquids-rich gathering and transmission systems, frequent pigging is essential to maintain performance. However, traditional pigging programmes often require significant labour resources, repeated travel to remote locations, frequent launcher access, and increased exposure to safety and environmental risks. As operators continue to face workforce constraints, rising operating costs, increasing environmental scrutiny, and pressure to improve asset performance, many are reexamining how pigging programmes are executed. Automation is emerging as a practical solution that enables operators to maintain or increase pigging frequency while reducing the operational burden traditionally associated with these programmes. A project completed for a Bakken-region midstream operator demonstrates how automation can fundamentally change the economics, safety profile, and efficiency of a high-frequency pigging operation.

The challenge of high-frequency pigging

Figure 2. Designed for frequent pigging applications, SureLaunch streamlines operations while reducing manual intervention in the field.

Many liquids-rich natural gas systems rely on regular pigging to manage condensate and liquid accumulation. As liquids build within the pipeline, flow efficiency can decline, pressure losses can increase, and downstream facilities may experience operational disruptions. In certain systems, operators may need to pig multiple times per day to maintain desired operating conditions. While technically effective, these programmes often create significant logistical challenges. A midstream operator in western North Dakota faced precisely this situation. The operator maintained a 36 mile, 20 in. natural gas pipeline connecting a gathering system to a processing facility. Due to the volume of liquids present in the system, the pipeline required pigging six times per day. The pigging programme relied on a conventional single-pig launcher that required personnel to travel to the site, load a pig, and repeat the process multiple times daily. The result was a labour-intensive operation requiring extensive travel, dedicated personnel, and significant operating expense. Compounding the challenge was the location itself. The pipeline traversed a remote area of the Bakken region where severe winter weather, snow, ice, and limited road access can create hazardous driving conditions for several months each year. While the operator successfully maintained the required pigging frequency, the cost and risk associated with doing so were substantial.

Rethinking the pigging process Figure 3. Lower safety risks, transportation costs and field installation costs-while freeing up crew members for other duties.

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Historically, operators have focused on optimising pigging frequency, pig selection, and receiver operations. Less attention has been paid to the pig launching process itself.

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Every launch event typically requires personnel, transportation, equipment preparation, launcher opening and closing, and associated safety procedures. For systems requiring multiple launches per day, these activities consume a considerable amount of labour and operational resources. Automated multi-pig launching systems offer an alternative approach. Rather than loading and launching a single pig before repeating the process for every subsequent launch, a multi-pig launcher can store multiple pigs and deploy them automatically at predetermined intervals. By reducing the frequency of human intervention, operators can maintain aggressive pigging schedules while significantly reducing the labour and travel associated with the programme. According to Brandon Hostutler, Pigging Service Line Manager at WeldFit, the value of automation extends beyond simply reducing labour requirements.

“Most operators initially focus on the number of launches they need to perform,” Hostutler explained. “What often gets overlooked is everything that surrounds those launches – the travel, the scheduling, the launcher openings, the exposure to weather conditions, and the time that skilled personnel spend performing repetitive tasks instead of higher-value work. There is also a maintenance component that isn’t always obvious. Reducing launcher interactions means fewer valve cycles, less wear on critical components, and lower maintenance costs over the life of the system.” The SureLaunch® automated multi-pig launching system was developed specifically to address these challenges. Unlike gravity-dependent systems, the horisontal design uses an electric drive mechanism to deploy seven to ten cleaning pigs automatically under a wide range of flow conditions while minimising manual intervention. This approach allows operators to maintain consistent pigging schedules while significantly reducing launcher interaction and associated operational activities.

Quantifying the benefits

Figure 4. As pipeline operators face increasing demands for throughput and reliability, automated pigging is becoming a critical tool for maintaining system performance.

Figure 5. As pipeline systems extend into increasingly remote regions, operators are seeking ways to minimise travel requirements while maintaining reliable operations.

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The North Dakota operator elected to replace its traditional pigging process with an automated multi-pig launching system. While the technical concept was straightforward, the results were substantial. The most immediate benefit was a reduction in personnel travel requirements. Previously, technicians were required to make multiple trips associated with pig loading and launch activities throughout the day. With automation, pigs could be loaded once and launched automatically according to the desired schedule. As a result, daily drive time associated with pigging operations was reduced from approximately six hours to two hours. This represented a reduction of roughly 360 miles of daily driving exposure. The impact on labour utilisation was equally significant. Analysis of the operation showed a 61% reduction in man-hours associated with daily pigging activities and an 83% reduction in pig loading and unloading events. Technician utilisation costs dropped dramatically, freeing personnel to focus on other operational priorities rather than repetitive pigging tasks. Reduced launcher interaction also delivered equipment-level benefits. By loading multiple pigs at once and automating deployment, the operator reduced valve cycling and associated wear, helping lower maintenance requirements and extend valve service life.

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Most importantly, the operator achieved meaningful financial results. The project generated more than US$1.7 million in first-year operating expense savings and is projected to deliver annual savings exceeding US$2.4 million during subsequent years of operation. For many operators evaluating automation projects, these economic outcomes can fundamentally change the business case.

By reducing the frequency of launcher access, automated systems can help operators reduce piggingrelated emissions while maintaining operational objectives. The reduction in vehicle travel further contributes to lower overall environmental impact. For organisations pursuing emissions reduction initiatives, pigging automation can provide an operationally practical means of supporting broader environmental goals while simultaneously reducing costs.

Safety beyond the jobsite

The workforce challenge

While labour savings often drive initial interest in automation, safety improvements frequently become equally compelling. Remote pipeline locations create inherent transportation risks. In many regions, driving to and from launcher sites represents one of the largest safety exposures associated with pigging operations. Reducing the number of required site visits directly reduces vehicle exposure, particularly in challenging operating environments. In the Bakken application, where winter conditions can make road travel hazardous, minimising unnecessary trips created a meaningful reduction in operational risk. Hostutler notes that reducing launcher interaction is also an important consideration. “Every time personnel interact with a launcher, there is a process that must be executed safely and correctly,” he said. “Automation reduces the number of times crews have to perform those activities, which naturally reduces exposure while helping improve consistency.” Remote connectivity can further enhance operational efficiency. WeldFit’s OnSite™ functionality provides visibility into launcher status and launch activity while enabling remote technical support. In applications such as the Bakken project, this capability can improve troubleshooting and reduce unnecessary travel to launcher locations. Hostutler noted, “Remote access allows operators to stay connected to the system while giving our support team the ability to help diagnose issues and provide assistance without waiting for someone to travel to the site. For remote assets, that can be a significant operational advantage.” For operators focused on safety performance, reducing both transportation exposure and manual launcher interaction can produce measurable benefits.

Workforce availability is another factor driving interest in automation. As operators continue to face staffing and retention challenges, many are looking for ways to deploy skilled personnel more effectively. Automated pigging systems do not eliminate the need for qualified personnel. Rather, they allow those individuals to spend less time performing repetitive launch activities and more time addressing maintenance, optimisation, inspection, and reliability initiatives that create greater value for the organisation. As pipeline systems become more sophisticated and operational expectations continue to rise, maximising the effectiveness of available personnel will become increasingly important.

Environmental considerations Environmental performance is increasingly becoming part of the decision-making process for pipeline operators. Traditional pigging operations often require repeated opening and closing of launcher closures. Each event can contribute to emissions associated with depressurisation and venting activities.

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The future of pigging operations The Bakken project illustrates a broader trend occurring throughout the pipeline industry. Historically, pigging programmes have been evaluated primarily through a technical lens focused on launch frequency, pig selection, and liquid management. Today, operators are beginning to evaluate pigging programmes through a wider operational lens that includes labour efficiency, workforce utilisation, safety performance, environmental impact, and total lifecycle cost. Automation enables operators to improve performance across all these dimensions simultaneously. For systems requiring frequent pigging, the opportunity can be particularly compelling. Maintaining aggressive pigging schedules no longer requires the same level of personnel commitment, travel, and operational disruption that has traditionally been accepted as part of doing business. As a result, automated multi-pig launching systems are becoming an increasingly important tool for operators seeking to improve efficiency while maintaining operational excellence. The North Dakota operator’s experience demonstrates what is possible when automation is applied to one of the industry’s most routine – but resource-intensive – activities. In this case, the outcome was more than improved pigging efficiency. It was a safer, more productive, and significantly more economical approach to pipeline operations.

Tim Mally, Director, Pipeline Integrity, Henkel, suggests that composite research is pushing the envelope for remediating complex pipeline integrity threats.

long time ago, in a galaxy nearby, composite repairs for pipeline defects were an unknown commodity, barely a twinkle in an inventor’s eye. In the 1980s and 1990s, a few innovators had ideas that would change

the landscape of pipeline integrity for decades to come, of which pipeline operators are still reaping the benefits. One inventor observed a few phenomena that would ignite a passion for a new solution for pipeline integrity. The first was the use of composites by NASA to help astronauts land on the moon. The second was the use of composite

Figure 1. Clock Spring installed in the GRI field validation programme in the 1990s.

Figure 2. Pipes buried and cyclically fatigued for the PRCI 10-year long-term buried study.

wrapped aluminum cylinders that helped reduce weight for compressed air tanks for firefighters entering burning buildings, increasing safety and stamina of these courageous first responders. The third was the transition of compressed natural gas cylinders to becoming lighter weight and increased impact safety using aluminum cylinders again being reinforced with composites. Looking upon these space age technology upgrades, this inventor decided that the same could be done for long distance transmission pipelines. After originally inventing the Clock Spring® as a crack arrestor for propagating fractures in a pipeline rupture event in the 1980s, the Gas Research Institute helped to steer the rigid fibreglass, polyester and methyl-methacrylate materials toward use as an anomaly reinforcement for pipeline defects. This composite is still being used to repair high pressure pipelines today. Another inventor began as a periodontist and avid boater who happened to be part of a team that helped to lead the charge on pioneering dental implants. Utilising composites in dentistry, this innovator began to explore the application of composites to boating and industrial applications in the 1980s. The difference for this pioneer was that the fibreglass materials were flexible as opposed to rigid, and were saturated with a polyurethane resin, allowing water to be the source of the cure. Many iterations and years later his son applied the same technology to pipeline repairs, where Syntho-Glass® XT was born and is still being used to repair and reinforce piping systems and steel structures today. A third inventor came from a background as a chemist who specialised in the formulation of liquid epoxies for use as a liner for man-holes and water/wastewater pipes in the late 1990s. One particular concrete water pipe had leaks coming into the pipe from the outside in, and he began to search for a solution to this problem. Adding a flexible and high-strength carbon fibre to his epoxy mixture allowed the pipe to prevent future water ingress and added structural reinforcement, and voila, DiamondWrap® was created. The high strength of the carbon fibre had many benefits that eventually led to further developments for modern-day pipeline repairs and technology advancement. These three composite systems have helped to pave the way for repair technology to advance to the modern state that it is in today. But what was the path it took to get here? Along the way, the technology has had to undergo rigorous testing and validation, detailed engineering analysis, and field application trial and error to become the sleek, buttoned up repair solution that pipeline operators trust implicitly. Continue along as the path is revealed, including all of the bumps and bruises that were accumulated to become a robust and trusted pipeline integrity remediation tool.

Innovation timeline

Figure 3. Failure outside of the metal loss repair after 10 years of cyclic fatigue at approximately 4000 psi.

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Once the Clock Spring was identified as a potential permanent repair option for pipeline anomalies, the Gas Research Institute began a 10-year testing programme to validate its use as such. Through grueling tests studying the essential variables critical to long-term composite performance on pipelines, the GRI eventually drew the conclusion that there were certain anomaly types and sizes

that could be reinforced with these materials, namely metal loss and dents of specific dimensions. Following the validation of this new repair solution, the real task that followed was to not only convince pipeline operators that the material could permanently restore serviceability of a corroded or dented pipeline, but also to entice the regulators to follow. Based on the validation testing and engineering analysis that were achieved in the GRI programme, among others, North American regulators would follow suit in the late 1990s and early 2000s to provide guidance and regulation for pipeline operators to evaluate alternative repair methods as potential permanent repairs. With the tail wind of regulatory guidance and completed testing and engineering validation, composite repairs could now enter the pipeline integrity market as a viable permanent repair solution. With the Clock Spring repair pioneering pipeline integrity, the other inventors previously mentioned followed suit into the market, and began to invest in validating the wet layup fibreglass and carbon fibre technologies at hand. Organisations such as the Gas Technology Institute (formerly the GRI) and the Pipeline Research Council International (PRCI) began to participate in composite repair validation efforts. In the 2000s, the GTI and PRCI worked to put these wet layup composite repairs through the wringer, including testing long-term adhesion, compatibility with cathodic protection, and long-term and cyclic performance on metal loss and dents. One particular programme was the long-term buried study initiated by PRCI. Composite repair manufacturers could choose to participate for 3 or 10 years, and would reinforce 40%, 60%, and 75% deep metal loss defects. Through years of cyclic fatigue in a buried environment under cathodic protection, a new sample would be pulled every year or so and subjected to a burst test. This test programme began to make believers out of doubters, as many composites demonstrated strong performance when the right materials and engineering design were selected for the anomaly at hand.

and other seam weld anomalies in a low-frequency electric resistance welded (LF-ERW) pipeline, Atlas engineers pioneered new approaches to reinforcing cracks and crack-like defects. Whereas composites would never be considered for cracks before 2015, now, all of a sudden, they became a viable repair method for types and sizes of cracks and seam weld defects in the right situation. Backed by well over 150 individual tests, Atlas began to lead the industry in crack-like defect reinforcement. Atlas engineers combined this in-depth research with advanced fracture mechanics expertise to expand the engineering basis for deploying composite repairs on cracks and crack-like defects in operating pipelines. Atlas engineers combined the significant amount of research with an advanced understanding of fracture mechanics to help advance

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the engineering analysis supporting the composite repair deployment to crack repairs in the field. In present day, an increasing amount of operators are adopting composite repairs as a robust reinforcement for these crack-like defects.

This success initiated an acceleration in research efforts, which have greatly expanded the validation of composites repairs for more complex anomalies, including stress corrosion cracking (SCC), circumferential stress corrosion cracking (C-SCC), girth welds, wrinkle bends, hard spots, external loading, geohazards, MAOP reconfirmation, and more. As inline inspection (ILI) tools have improved, so has the visibility of pipeline defects that were not seen or quantified in Integrity Management Programmes (IMP) before. With the visibility of these new threats, the validation and research in composites has given pipeline operators more tools to address them.

Putting the research to work

Figure 4. Over 150 data points have been achieved for the Atlas carbon fibre composite repair system on crack and crack-like defects.

Oftentimes, research can go unused or it can take years or decades to deploy to field utilisation. Contrary to that point, the recent research on composite repairs has been able to be deployed relatively quickly. One instance of the research getting put to work quickly occurred when an operator discovered a lack of penetration on their girth welds in areas susceptible to landslides. The pipeline operator needed a landslide to be able to hit a defective girth weld and not have the pipeline rupture. The Atlas engineering team was able to quickly develop a composite reinforcement solution for the girth weld that significantly stiffened the girth weld in the axial direction to prevent a failure in the girth weld. A four-point bend test confirmed that the composite reinforcement was able to transfer the failure from a rupture in the girth weld to a buckle in the pristine pipe. The composite was deployed to the field within one month from the original request, and the operator was able to reinforce dozens of girth welds to protect the pipeline from rupture against the landslide threat, making the pipeline and the surrounding communities safer.

Where do we go from here?

Figure 5. A defective girth weld reinforced against landslide threats.

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Composites are a fantastic tool to remediate pipeline integrity threats, but now the question becomes: what’s next? Now that there are hundreds of thousands of these repairs in the ground, and some for over three decades, pipeline operators and composite repair manufacturers have been working to understand the longevity of these repairs. While a properly validated, designed, and installed composite repair can be a fantastic and streamlined tool, the long-term monitoring of these repairs has now come under study. Questions such as installation quality, installation pressure, and long-term performance are being asked of composite manufacturers, and rightly so. However, coming from such humble beginnings, composite repair engineers and innovators will surely rise to the task, providing both installation quality and monitoring developments that will help to ensure these repairs can not only last a long time, but can be monitored over that time as well. Are there other developments beyond these in store? With composite technology also being used to help airplanes safely transport humanity from one continent to another, it’s safe to say, the sky is truly the limit.

Edwin Welles, MBA, Vice President of Viscotaq, and founder and inventor of Viscotaq Coating Technologies, Denso Inc., highlights a successful pipeline rehabilitation project in Mexico that restored ageing coatings and delivered over 14 years of corrosion protection performance.

ipeline rehabilitation projects often become most challenging when operators are dealing with aging legacy coating systems that were never designed with modern repair compatibility in mind. In these situations, the goal is not simply to cover a damaged area. The real objective is to restore long-term coating performance in a way that integrates with the existing system, supports

corrosion control, and avoids introducing new weaknesses at the transition between the original coating and the repair

material. That was the challenge facing a pipeline rehabilitation programme in Mexico, where aged bitumen and coal tarcoated pipelines required a practical and durable long-term repair solution.

A rehabilitation strategy built for compatibility For this project, Denso’s ViscoWrap HT and Viscotaq PE Outerwrap were selected to rehabilitate aged sections of existing line pipe coating. The rehabilitation work began in October 2011 and addressed pipelines coated with older bitumen and coal tar enamel, both of which are well known throughout the industry as difficult substrates for coating repair. These legacy coatings can present significant compatibility challenges, particularly when the owner needs a field-applied repair system that will bond securely, create a reliable tie-in to the existing coatings, and continue performing over the long term in real operating conditions.

Figure 1. The Viscotaq system was easily installed over Project Details difficult pipeline legacy coatings with SP2 surface preparation.

Why long-term performance was critical The project called for more than a temporary repair. The owner needed a rehabilitation approach that could be applied efficiently in the field, work across multiple pipeline sizes and operating conditions, and restore the overall effectiveness of the coating system. Just as importantly, the repair had to support the proper function of the existing cathodic protection system, which depends on sound coating performance to operate efficiently. When coatings deteriorate, the burden on cathodic protection increases. Restoring coating continuity and integrity is therefore critical not only from a mechanical standpoint, but also from a corrosion prevention perspective.

Surface preparation and the real-world difficulty of legacy coating repairs

Figure 2. Following rehabilitation, the cathodic protection system was able to function normally again.

One of the most notable aspects of this project was the required surface preparation. The rehabilitation was completed using SP2 surface preparation, a condition that makes successful repair over aged coal tar coatings especially significant. Anyone involved in rehabilitation of legacy external pipeline coatings understands that coal tar and bitumen systems can be difficult to tie into successfully. Achieving long-term adhesion and continuity on such surfaces requires a repair material capable of conforming to the substrate and maintaining intimate contact without creating a vulnerable interface.

Creating a seamless transition

Figure 3. The ViscoWrap HT shows strong adhesion to any of existing pipeline coatings.

54 World Pipelines / AMERICAS 2026

That need for compatibility was central to the product selection. ViscoWrap HT was chosen because of its ability to conform to and integrate with existing coating systems through Van der Waals bonding principles. In practical terms, this enabled the repair material to tie into the original coating and create a seamless, monolithic transition between the rehabilitation area and the existing line coatings. For projects involving aged coal tar and bitumen coatings, that type of transition is especially important. A repair may appear acceptable on the day it is installed, but if it cannot maintain a continuous and durable bond over time, the repaired area may

become the next failure point. In this case, the selected system was able to address that concern directly.

across multiple regions, temperatures and circumstances while still delivering consistent performance.

A large-scale rehabilitation programme across Mexico

Visible adhesion and seamless tie-in performance

The full rehabilitation programme was carried out over a period of two years and included 12 in., 16 in., and 24 in. O.D. product pipelines. Operating temperatures ranged from 86°F to 140°F (30°C - 60°C), demonstrating that the system needed to perform under a broad range of service conditions. During the initial two-year programme, more than 1 000 000 ft2 (100 000 m2) of the Viscotaq coating system were applied across Mexico. The installation work was completed in a wide range of field environments, climates, and jobsite conditions, further demonstrating the practicality of the system for large-scale rehabilitation programmes rather than isolated repair work.

Another important aspect of the project was the visible quality of the tie-in and adhesion to the existing coating. Project imagery documented strong adhesion of ViscoWrap HT to the prepared coal tar coating, as well as the smooth transition from the repair area into the original line coating. This was not simply a surface-level observation. The seamless interface between the old and new materials was a critical indicator that the rehabilitation system was functioning as intended. In legacy coating rehabilitation, the tie-in zone is often the area most vulnerable to disbondment, edge lifting, or premature failure. The fact that the repair material integrated cleanly with the aged coating was therefore one of the most meaningful signs of long-term success.

More than a trial: proven at real-world scale

Restoring coating integrity and cathodic protection performance

This scale matters. Many case studies focus on a single repair location or a limited trial section. In contrast, this project demonstrated the application of the system across a broad operating footprint and over an extended period of time. That gives the results added credibility because performance was not limited to one set of site conditions. Instead, the rehabilitation programme showed that the selected solution could be deployed repeatedly

The performance benefits extended beyond the repaired coating area itself. According to the project results, the rehabilitation work significantly improved the overall performance of the pipeline coating system, allowing the existing rectifiers and cathodic protection system to function normally again. This is a major outcome in any corrosioncontrol programme. A high-performing coating and a well-

Navigating the world of pipeline pigging In this episode of the World Pipelines Podcast, Elizabeth Corner is joined by Diane Cordell, Executive Secretary of the Pigging Products and Services Association (PPSA), together with PPSA President Neil MacKay and Vice President Mark Elliott. The conversation explores the role of the PPSA in supporting pipeline operators around the world, from connecting them with specialist expertise to promoting knowledge sharing, collaboration and safety across the pipeline pigging industry.

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functioning cathodic protection system are meant to work together. When the coating is compromised, cathodic protection becomes less efficient and system demands can increase. By restoring the integrity of the coating system, the repairs helped reestablish the intended balance between passive and active corrosion protection.

Inspection results that reinforced the success of the project Long-term performance is where rehabilitation systems ultimately prove their value, and this project offers a particularly strong record in that regard. Since the original application in October 2011, the rehabilitation system has remained in service for more than 14 years and is now approaching 15 years of performance. That kind of field history carries weight, especially when dealing with older coating systems that can be difficult to rehabilitate successfully. In many cases, short-term installation success is easy to document. True long-term performance is much harder to demonstrate. Here, the long service life is supported by inspection history as well. During the initial two-year inspection, the repaired Viscotaq coating was reported to be in excellent shape. In addition, during the subsequent five year recurring integrity inspections of the pipelines, no issues were present. This means the project did not simply meet shortterm application expectations; it continued to validate itself under ongoing operating and inspection conditions. For asset owners and engineers, that kind of multi-year performance history is often the most persuasive proof point of all.

What this project means for owners of ageing pipeline assets The broader importance of this project is that it demonstrates a practical path forward for operators dealing with difficult legacy coatings. Rehabilitating aging coal tar and bitumen systems is rarely straightforward. Full coating replacement may be costly, disruptive, or impractical. At the same time, not every repair material is capable of providing the compatibility, adhesion, and continuity required for long-term success. In this case, ViscoWrap HT and Viscotaq PE Outerwrap provided a solution that addressed those challenges directly: compatibility with existing coatings, application under field conditions, support for corrosion control performance, and a long-term record in service.

A proven approach to pipeline rehabilitation For pipeline owners facing similar issues, the project offers a useful example of what an effective rehabilitation strategy looks like. The repair system was not chosen simply because it could cover damaged areas. It was selected because it could restore coating performance in a way that respected the realities of existing infrastructure: legacy materials, challenging surface preparation, varied field conditions, and the need to maintain long-term corrosion protection. More than a decade later, the service record shows that this approach was justified. In the end, the Mexico rehabilitation programme stands as a strong case for targeted, compatible repair over wholesale replacement when the right technology is used. By combining ViscoWrap HT with Viscotaq PE Outerwrap, the project team was able to rehabilitate difficult legacy coating systems, restore coating continuity, support normal cathodic protection function, and achieve long-term field performance that continues to hold up after more than 14 years in service. For operators managing aging pipeline assets, that is exactly the kind of proven result that matters most.

About the author Edwin Welles, MBA, is Vice President of Viscotaq and founder and inventor of Viscotaq Coating Technologies, bringing more than 25 years of coatings industry expertise and serving as an SME for organisations including AWWA, AMPP, and ISO.

About the company

Figure 4. Fully rehabilitated section of pipeline coating area using the Viscotaq HT and outerwrap system.

56 World Pipelines / AMERICAS 2026

Denso Inc. is a leading manufacturer of corrosion-prevention products and systems for the energy industry. With operations in North America, Denso provides proven solutions designed to protect critical assets in demanding service environments. Denso, Inc. provides its customers with technical expertise, field-proven products, and longterm corrosion prevention systems.

Kerry Cole, AMPP, explains how contactless magnetic inspection complements inline inspection, using a Canadian crude oil case study.

n line inspection (ILI) is the king of pipeline integrity assessment, but even the most capable monarchs rely on trusted advisors. Pipeline operators have long relied on ILI to identify corrosion, cracks, and other threats to integrity. Yet many pipelines remain difficult – or impossible – to inspect using conventional tools. As a result, operators often turn to alternative assessment methods to evaluate non-piggable assets and support integrity decisions. One technology gaining attention in that role is contactless magnetic inspection technology (CMIT), which uses aboveground magnetic sensing to identify potential anomalies in buried pipelines. “For piggable pipelines, inline inspection remains the benchmark,” said Chukwuma C. Onuoha, Ph.D., President and CEO of Canchuks Corrosion Inc. in Edmonton, Alberta, Canada. “In fact, it is widely considered the king of integrity assessment tools.”

Figure 1. Aerial view of excavation locations.

Rather than replacing ILI, Onuoha said CMIT is designed to complement existing integrity programmes. “Magnetic inspection can serve as a complementary technology, enhancing performance and improving overall confidence in integrity assessments,” he said. Onuoha and his colleagues presented their paper, “Field Validation Case Study: Applying Contactless Magnetic Inspection Technology (CMIT) to Assess Integrity of a 30 in. Crude Oil Pipeline,” at the Association for Materials Protection and Performance (AMPP) Alberta Conference 2026 in February. With more than 15 years of experience in pipeline corrosion and integrity management, Onuoha has spent much of his career applying direct assessment methodologies. That experience helped shape his interest in technologies that can strengthen integrity assessments on difficult-to-inspect pipelines.

The challenge of non-piggable pipelines

Figure 2. Excavation location 2 with a moderate anomaly.

Figure 3. CMIT field verification on exposed pipeline.

Figure 4. Field measurements verify CMIT corrosion indication.

58 World Pipelines / AMERICAS 2026

While ILI remains the preferred method for evaluating pipeline condition, not every asset can accommodate an inspection tool. Older pipelines may lack launchers and receivers, while others contain diameter changes, tight bends, flow restrictions, or operational constraints that prevent successful pigging. As a result, operators often rely on direct assessment methods such as external corrosion direct assessment (ECDA), internal corrosion direct assessment (ICDA) and stress corrosion cracking direct assessment (SCCDA) to evaluate integrity threats. Although these approaches have proven effective for ECDA programmes, they typically require the interpretation of cathodic protection (CP) data, coating surveys, environmental conditions, and predictive models (where applicable) rather than direct measurements of the pipe wall itself. This can create uncertainty and increase the number of excavations required to confirm the presence of actual defects. Rather than travelling inside the pipeline, CMIT uses sensors positioned above ground along the right-of-way to detect subtle magnetic disturbances associated with metal loss, stress concentrations, deformation, and other anomalies. According to Onuoha, one of the technology’s most significant benefits is enhancement of pipeline safety by reducing operational disruption. Traditional integrity programmes often require excavations to confirm whether predicted threats are present. In urban areas, those excavations can be expensive, time-consuming, and disruptive to surrounding infrastructure. By providing another layer of information before a dig is initiated, CMIT may help operators refine excavation programmes and focus resources where they are most needed. In a recent field trial on a 30 in. crude oil pipeline in Canada, the technology was used as a screening tool ahead of a conventional ILI run. The results showed strong agreement between the two methods, suggesting CMIT could provide operators with a practical way to prioritise integrity assessments on difficult-to-inspect assets.

Prediction meets confirmation

Field validation

The authors position CMIT not as a replacement for To validate the technology, the operator excavated established integrity assessment methods, but as a two locations identified during a CMIT survey of a 1 complementary technology that can help validate their km section of 8 in. natural gas pipeline in Canada. The findings. Traditional programmes such as ECDA and SCCDA rely first indication, ranked as minor, proved to be a benign heavily on indirect indicators, including coating condition, CP weld-related feature with no measurable wall loss. The performance, and environmental factors, to identify areas that second indication, ranked as moderate, revealed coating may require excavation. disbondment and external corrosion with approximately CMIT adds a direct measurement component by detecting 25% metal loss. The findings suggest that CMIT was magnetic signatures associated with metal loss, stress able not only to detect anomalous locations but also concentrations, deformation, and other anomalies. According to differentiate between low-risk features and active to the authors, combining these approaches could improve corrosion requiring attention. excavation targeting, reduce unnecessary digs, and provide operators with greater confidence when assessing difficult-to-inspect pipelines. ECDA can detect conditions that could lead to external corrosion. SCCDA can establish where cracks are most likely to develop. CMIT can spot signs that the pipe has already changed. In most cases, none of these methods tells the whole story by itself. When used together, operators can move from educated guesses to more informed decisions. “When you combine the two, you effectively take ECDA to the next level,” Onuoha said. One way to view the relationship is through a medical analogy. If ECDA represents a patient’s medical history and SCCDA serves as a risk assessment, CMIT functions more like a diagnostic scan, providing direct evidence that can either confirm or challenge the conclusions drawn from other assessment methods. “It does not replace inline inspection; rather, it serves a different purpose,” Onuoha said. Although CMIT has existed in various forms for more than a decade, Onuoha said industry understanding of the technology has Figure 5. Aerial view of the pipeline location. improved significantly in recent years. Through pilot programmes, field trials, and validation studies, operators have gained a clearer understanding of both its strengths and limitations. That growing body of experience has helped increase confidence in how and where the technology can be applied most effectively. ECDA provides information on coating condition and CP performance, while SCCDA identifies areas susceptible to cracking. CMIT adds another layer by supplying aboveground evidence of potential metal loss, stress concentrations, and other anomalies. Together, the three approaches can help operators prioritise excavations, improve confidence in integrity decisions, and develop more comprehensive management strategies for unpiggable Figure 6. Integrated relationships of CMIT with ECDA and SSCDA. pipelines.

AMERICAS 2026 / World Pipelines

According to Onuoha, the case was particularly significant because the observations made during the CMIT survey aligned closely with both field excavations and other assessment methods. The case study provides evidence that CMIT can: ) Detect weld-related stress features. ) Detect external corrosion. ) Distinguish between low- and moderate-severity indications. ) Help prioritise excavation locations. ) Identify corrosion beneath disbonded coatings. ) Comparing results with MFL inspection A key test of CMIT’s capabilities came when a major North American operator compared the technology’s findings against a scheduled magnetic flux leakage (MFL) ILI on a 30 in. crude oil pipeline. MFL is a widely used inline inspection technology that identifies corrosion and metal loss by detecting disturbances in a magnetic field induced in the pipe wall. CMIT characterised the line as being in generally good condition, identifying only a single moderate stress-related indication and no evidence of significant corrosion or metal loss. When the MFL inspection was completed three months later, it reached the same conclusion. The strong correlation between the two assessments helped validate CMIT as a practical screening tool and encouraged the operator to expand its use on unpiggable assets and other difficult-toinspect pipeline systems.

The technology surveyed the 30 in. crude oil line and concluded: ) No significant metal loss. ) No reportable corrosion. ) No cracking. ) No major integrity threats. “The MFL results independently confirmed the findings from the magnetic inspection,” Onuoha said. “That direct alignment between the two methods provided strong validation of the technology’s reliability.” While the validation results were encouraging, the authors acknowledge that CMIT is not intended to replace ILI. Rather, it is positioned as a screening and prioritisation tool that can help direct integrity resources more efficiently. The case studies demonstrated successful identification of corrosion-related anomalies and agreement with MFL inspection findings, but they did not provide extensive validation of other claimed capabilities such as crack detection, SCC identification, or geohazard assessment. Additional field applications will likely be required to further establish performance across the full range of pipeline threats. “The future of this technology is likely to involve increased integration rather than replacement,” Onuoha said. “Its greatest value lies in enhancing existing integrity programmes by improving confidence, reliability, and safety outcomes.”

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Offshore manufacturing has been the story of the past three decades. Andrew Topliffe, IMI Process Automation, explains how IMI’s new site in Southern California is bucking that trend, giving midstream operators more immediate access to flow control expertise in a time of growing pressure.

t’s rare for the midstream sector to feature in mainstream news. This is partly down to its role as an intermediary between its upstream and downstream counterparts. Freely moving product is not a story because it poses no threat to the global energy system or economies that rely on it. There is little public interest in stable conditions.

As many will know, this has not been the case in the opening months of 2026. Major disruption and bottlenecks in key regions have put midstream issues front and centre, with regular reporting on the supply, flow and rising cost of hydrocarbons. It’s a situation that has also added pressure on other regions, such as North America, which accounts for the sector’s largest throughput, pipeline capacity and export volumes.1 Problems here have a major knock-on impact across the world, emphasising the need for greater reliability from existing infrastructure. Reaching this position remains challenging. In North America, many facilities are now several decades old and still rely on outdated flow-control systems. These systems are critical to keeping product moving efficiently, but they also require specialist expertise to upgrade effectively and minimise

the threat of unplanned downtime. Given the harsh service conditions common to midstream processes, operators left without access to the right support can quickly find themselves in a difficult position, not least in the current climate.

Place for problem solving Giving operators more immediate access to the right technologies and flow control expertise is one of the drivers behind IMI’s newly built facility in southern California. Based in Lake Forest, the 55 000 ft2 site extends more than six decades in the region, with a 200 strong team now working across engineering, manufacturing, quality assurance and R&D. The company can trace its roots back to Control Components Inc. in Irvine, California. This earlier business, which was acquired by IMI in 1981, supported midstream operators with challenging pressure, temperature and erosion-related problems. That mission continues today at the new facility but at a much larger and accelerated scale. “The new site in Lake Forest is really about problem solving,” says Sina Alikhani, Interim GM at IMI’s Lake Forest Facility. “By having all our constituent teams under one roof, we’re able to diagnose, design and deliver flow control solutions at a much quicker rate than before. This is important given the current state of the midstream market, where demand for high-performance aftermarket components is arguably greater than ever.”

Timely and strategic Figure 1. Based in Lake Forest, the new 55 000 ft2 site extends more than six decades in the region, with a 200 strong team now working across engineering, manufacturing, quality assurance and R&D.

Figure 2. The new site gives IMI’s team the environment and tools to deliver the critical engineering their customers depend on.

62 World Pipelines / AMERICAS 2026

Midstream accounts for a large percentage of IMI’s business in the region, although it’s the company’s work in critical service that served as the anchor for a new site. IMI’s nuclear control and isolation valves account for around 10 - 15% of total output in the region but were the deciding factor for investment in a greenfield development. “We have an established team working with nuclear facilities across the United States. Moving this production overseas was not feasible from a regulatory point of view. While this was the main driver behind Lake Forest, we also recognised the secondary benefits for our target sectors by keeping production onshore.” The secondary benefits Brian Metz, Director of Nuclear Programs describes are mainly time to market and access to knowledge. With more than 60 engineers under one roof, IMI can now work collaboratively with customers on flow control challenges – including full valve manufacturing, spares, refurbishment and retrofit upgrades – calling on expertise

in other departments when required. This integration is particularly important where the ability to move rapidly from design and production to field support is critical. “We know operational reliability is closely tied to speed of response,” says Sina Alikhani. “You can have the best design principles and materials, but the disadvantages soon begin to stack if you cannot deliver and install a solution in good time. Lake Forest closes that window, making critical components available in a shorter time.” Given the focus on cost and lead times, IMI’s decision to settle in Southern California makes good strategic sense. Recent disruption to global supply chains has highlighted the vulnerability of extended international manufacturing networks. Delays, constrained capacity and limited oversight have created challenges for operators, especially those reliant on complex cross-border production and delivery models. The response for many has been a return to the type of regional manufacturing capabilities offered by IMI at Lake Forest. “Establishing production closer to end markets reduces exposure from complex logistics, while also offering greater control over scheduling and output,” adds Sina Alikhani. “The ability to source, produce and deliver within the same region offers greater flexibility in managing both routine operations and unexpected demands.” From Lake Forest, the company can target most of western North America, including Canada, as well as major midstream and LNG export infrastructure around the Gulf of Mexico. There are also Pacific trade routes available, although Lake

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Forest and the company’s earlier sites have typically worked with companies in the Americas rather than overseas, with the latter being serviced by other IMI regional facilities.

Customer-centric thinking Retrofit projects have been a mainstay of IMI’s aftermarket support across the Americas. This is largely down to the state of infrastructure in the region, featuring a large volume of brownfield assets that are typically several decades old. With increasing output demand and stricter regulatory oversight, these sites are now being pushed beyond their original specification, requiring increasingly complex and invasive work to improve operation. “Rather than full system replacement, which is expensive and time-intensive, operators are opting for targeted upgrades as a way to extend performance and improve yields,” says Jonathan Davis, Director - Aftermarket Sales and Service. Upgrades and refurbishments have become a fast-growing segment of IMI’s business. In nuclear, retrofits and upgrades of major systems such as Feedwater and Main Steam Isolation help plants operate with greater safety while extending the operating life of the plant. In power, control system upgrades allow more precise process control avoiding issues with vibration and pipe cracking. Similarly, in petrochemical plants, major refurbishment projects ensure plant safety, reliability and profitable operation. New technologies are constantly learned and applied to extend the life of equipment. Technologies such as EroSolve,

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designed to prevent trim erosion through a combination of precise surface geometries, flow paths, hard facing, and specialty surface coatings, are multiplying the service life of critical equipment. As operating conditions change, or performance issues are detected with competitors’ equipment, IMI Engineers’ unique problem-solving skills demonstrate real value. IMI’s ability to apply Metal Additive Manufacturing technology allows it to retrofit competitor equipment to incorporate specialised DRAG™ Trim technology without cutting equipment out of line and without in-line machining. In turn, this allows implementation of the solution within the timeframe normally required to service the equipment. “Across the Americas, we’re seeing ageing brownfield assets being asked to do far more than they were ever designed for,” added Mr Alikhani. “For most operators, replacing entire systems simply isn’t feasible, either due to cost or timescale. This is why the conversation has shifted to targeted retrofit upgrades, and why IMI has been focused on the question of how we can extend the life and boost the performance of existing infrastructure. “Through the lens of this question, we have seen retrofit grow from a periphery service to a genuine engineering discipline. In our nuclear division, IMI is upgrading feedwater and main steam isolation systems to boost safety margins and extend plant life. In power, precision control mitigates the vibration and pipe-cracking issues that often reduce reliability and lead to downtime. Petrochemical refurbishment shares this same line of thinking. “What differentiates this work is the ability of the technology behind it. Erosolve makes a significant, tangible difference to the life of critical equipment, while our Metal Additive Manufacturing allows us to retrofit competitors’ equipment with our DRAG Trim technology. No cutting out of line, no in-line machining, all inside a regular service window. “At the end of the day, these benefits come back to the customer: maximum performance, minimum disruption.”

Elsewhere in the Americas IMI has served customers in the Houston region since the early 1990s, providing local support to the midstream market, as well as refineries and power producers. IMI’s latest investment in the region is a new, state of the art 60 000 ft2 service and manufacturing facility, which opened in June 2025. As the centre of excellence for the design and manufacturing of silencers and desuperheaters, this facility also acts as IMI’s main centre for field service and repairs. “At IMI, we’re proud to be driving innovation through our investment in the Americas”, said Mr Alikhani. “The Lake Forest and Houston sites showcase our commitment to excellence and support for the mid-stream market, allowing us to play an important role through the provision of aftermarket products and services.”

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Reference 1.

https://www.mordorintelligence.com/industry-reports/oil-and-gas-midstreammarket

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