Q1) How do you see the level of interest in hydrogen and CO₂ pipeline development differ across global regions?
Tony Alfano: We see regional appetite for hydrogen and CO₂ infrastructure varying significantly across regions based on existing energy systems, policy frameworks, and industrial needs. Europe leads in hydrogen pipeline planning, driven by aggressive decarbonization targets and regulatory support. The EU’s hydrogen strategy has catalysed projects like the European Hydrogen Backbone, while countries such as the Netherlands and Norway are advancing CO₂ transport networks to support carbon capture and storage initiatives.
North America, on the other hand, shows strong interest in CO₂ pipelines, particularly in regions with enhanced oil recovery operations and geological storage potential. The U.S. already operates one of the largest CO₂ pipeline networks in the world (by length and transported volume), and recent policy incentives are accelerating expansion. Hydrogen interest is growing but remains more focused on industrial hubs and specific corridors.
In the Middle East and Asia-Pacific, we see that hydrogen development is heavily oriented toward large‑scale production for export and industrial applications. Although some Asia-Pacific countries are also building substantial domestic hydrogen demand in sectors such as power, transport, and heavy industry, key economies like Japan, South Korea, China, and Australia are now central drivers of global hydrogen demand growth and are developing both import value chains and domestic end‑use markets.
In other words, the key differentiator across regions isn’t just ambition but rather the ability to align infrastructure development with policy certainty, funding mechanisms, and anchor demand.
Q2) What lessons can be learned from early CO2 and hydrogen network projects to accelerate future CO₂ and hydrogen infrastructure development?
Timothy Illson: The two key lessons learned from early trial projects are (a) the need to follow a defined framework for repurposing existing infrastructure, and (b) that managing public perception is as important as the technical aspects of the project. DNV has service specifications (DNV-SE-0657) and white papers discussing the process for repurposing pipelines for hydrogen and CO2, which can be used as the basis for operators to develop their own localised process. Experience in the UK, Netherlands and France has shown that project success critically depends on an effective public information and consultation strategy to combat misinformation and gain public trust in the safety of the process and competence of the operators involved.
Q3) What modifications or replacements are necessary for valves, seals, compressors, and metering stations to ensure long-term integrity and prevent fugitive emissions in an H2 pipeline environment?
Timothy Illson: The modifications required depend on the equipment already installed. The industry has developed protocols for assessing hydrogen readiness of pipeline equipment; these were used in projects such as H21, HyReady and HyDeploy to assess the requirement for modification or replacement. It is generally helpful to maintain items such as valves and replace seals to minimise fugitive emissions before conversion to hydrogen. Industry research has shown that if equipment is gas-tight in natural gas, it will also be leak-free in hydrogen. Thus, the main activity required is to ensure the equipment is maintained to prevent leaks before conversion.
Q4) How can existing gas infrastructure be adapted for new low-carbon fuels in regions where hydrogen is not yet viable?
Timothy Illson: In regions where large volumes of hydrogen are not yet available, an alternative is to increase biomethane production. Biomethane can be readily transported in existing gas networks and, in most cases, is compatible with appliances and industrial burners. The adaptation required is to establish a consistent biomethane quality standard for network entry, along with standardised designs for entry units to encourage commercial biomethane production. Countries such as Denmark and France have demonstrated strong progress in encouraging the use of biomethane, along with hydrogen when available.
Q5) What are the biggest cybersecurity challenges facing increasingly digitalized and automated pipeline networks today?
Tony Alfano: The convergence of operational technology and information technology has created vulnerabilities that didn’t exist when pipeline systems operated on isolated networks. Legacy equipment was not designed with current cybersecurity risks in mind, yet many systems remain in service and now connect to broader digital networks for remote monitoring and control.
Supply chain security poses an escalating concern. Pipeline operators increasingly rely on software, sensors, and control systems from multiple vendors, each representing a potential vulnerability. Recent incidents have demonstrated why investing in software solutions that maintain rigorous security standards is crucial and why operators must carefully vet every component in their digital ecosystem.
The skills gap compounds these technical challenges. Our industry survey (Pipeline Insights 2025) shows that 46% of pipeline operators struggle to find people with the required digital and data skills, including specialised cybersecurity expertise needed to protect both IT and operational technology environments. This talent shortage creates risk, as effective cybersecurity requires professionals who understand both pipeline operations and evolving threat landscapes.
The response from the industry reflects the severity of these challenges. Our survey shows 62% of pipeline organisations are planning to increase cybersecurity investments, with this focus particularly pronounced in North America (69%) and Asia-Pacific (65%)—regions that have experienced high-profile attacks and face heightened geopolitical tensions affecting energy security. As digital transformation accelerates, cybersecurity has evolved from an IT concern to a fundamental operational imperative.
Q6) What specific materials science challenges and mitigation strategies are necessary to prevent hydrogen embrittlement and fatigue crack growth when repurposing high-strength steel natural gas pipelines for 100% hydrogen service?
Tony Alfano: The primary challenge isn’t simply whether hydrogen causes embrittlement; it’s understanding and managing the specific failure mechanisms under actual operating conditions. Hydrogen embrittlement manifests differently depending on steel grade, strength level, and operating conditions. High-strength steels show increased susceptibility, with welds and heat-affected zones presenting elevated risk due to different microstructures and residual stresses.
The question, therefore, is whether existing crack-like defects will grow to critical size during the pipeline’s design life under hydrogen service. Pressure cycling accelerates this risk, as fatigue crack growth rates in hydrogen can be up to 10 times higher than in air under cyclic loading. Atomic hydrogen generated at actively growing fatigue cracks contributes to this acceleration, particularly when fluctuations exceed threshold stress intensity values. Material assessment must move beyond static testing to fracture mechanics analysis under representative hydrogen environments and loading conditions.
A risk-based approach is essential because not all pipelines face the same risk profile. Operators should develop fatigue risk matrices combining current integrity data, material properties, and planned operating scenarios to determine which assets can be safely repurposed, which require operational restrictions, and which need replacement. Mitigation strategies should be proportional to risk: low-risk pipelines may only need enhanced inspection for crack-like defects, medium-risk assets might require pressure cycling controls or lower maximum allowable operating pressure (often significantly below natural gas service, per ASME B31.12 design factors), while high-risk pipelines may need significant derating or replacement.
The key insight is that many pipelines could operate safely with appropriate risk management, moving from rigid compliance to integrity-driven decision-making that balances safety, operational flexibility, and economic viability.
Q7) What types of internal polymeric or metallic coatings are showing the most promise for mitigating hydrogen embrittlement and corrosion in repurposed steel pipelines for hydrogen service?
Timothy Illson: Research is underway to determine if polymeric or metallic coatings can be used to mitigate hydrogen embrittlement effects. Small-scale studies indicate that polymeric coatings can reduce the amount of hydrogen at the steel surface, but the significance for embrittlement is unclear at present. Experimental PVA-based coatings are more effective hydrogen barriers but are not generally commercially available. For metallic coatings, Tungsten is effective but impractical, some alloys of zinc, nickel and cadmium also show good barrier properties but need further development. The primary issue, however, is the difficulty in applying an internal coating to an existing pipeline and ensuring complete coverage rather than the barrier properties of the coating.
Q8) How must digital models be adapted to accurately monitor and predict the behavior of hydrogen in repurposed or new pipelines?
Tony Alfano: It is true that pipeline models built for natural gas require adaptations for hydrogen service. Hydrogen’s lower density, higher diffusivity, and different compressibility factor demand adjustments to the underlying flow equations and equations of state. Simply substituting hydrogen properties into existing natural gas models could produce misleading results, particularly during transient conditions. Advanced modeling platforms like DNV’s Synergi Gas and Synergi Pipeline Simulator, support multi-component gas analysis for hydrogen blends up to 100%, incorporating proper thermal modeling for heat transfer and temperature profiles. Component tracking functionality enables monitoring of gas composition changes across the entire system, which is essential for managing blend ratios and energy content variations.
Beyond hydraulics, the integrity and risk modeling challenge is where hydrogen truly demands a different approach. For hydrogen, digital models must integrate operational patterns with material degradation mechanisms as hydrogen-assisted fatigue and embrittlement. That means your digital model needs to track historical pressure cycling, correlate loading patterns with fatigue crack growth rates, and predict where integrity risks will emerge over time. Pipeline Integrity and Risk Management software should enable scenario analysis, risk quantification, and predictive modeling based on inspection and operational data. These tools should help you answer questions such as: What happens if we increase hydrogen concentration to 30%? How does that change pressure cycling frequency? What is the impact on fatigue life for specific pipeline segments?
The operators getting this right are those who recognise that hydrogen isn’t just a different molecule to transport—it requires integrated digital models that combine hydraulic analysis with integrity management to ensure both safe operations and long-term asset viability.
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The Experts
Tony Alfano, Executive Vice President, DNV Pipeline Product Line
Tony Alfano leads the Pipeline Product Line at DNV Digital Solution, bringing decades of experience in helping clients navigate complex safety and reliability challenges. As a trusted advisor, he combines deep industry knowledge with innovative approaches to optimise risk strategies for pipeline networks and facilities worldwide. A recognized thought leader, Tony has authored international publications and frequently speaks at industry workshops. His passion for integrating science and technology drives DNV’s development of cutting-edge solutions, significantly enhancing pipeline safety for clients across the globe.
Tim Illson, Principal Integrity Specialist – Hydrogen and Carbon Transport, DNV
Tim Illson has worked in industrial corrosion control for more than
35 years and is presently involved in consultancy for a wide range of hydrogen and CCUS activities, and renewables infrastructure. Specific areas of technical expertise include pipeline repurposing studies (H2/CO2), corrosion control and materials selection for hydrogen and CO2 pipelines, test programme development for validating hydrogen materials, corrosion of wind turbine structures, cathodic protection of monopile interiors, and offshore and onshore coating systems.
