Special Focus: H₂ Mobility, Transportation and Infrastructure

J. SUTHERLAND, Baker Hughes, Calgary, Canada

As global industry targets carbon emissions reductions, the envisaged use of hydrogen (H₂) as a primary energy medium is underway. Like other energy sources, H₂ must be generated, stored, transported and finally consumed.  

Pipelines are a highly cost-effective method of transportation, and existing pipeline infrastructures are being assessed for their suitability to transport H₂ around the globe, blended within natural gas transport or as pure H₂.

The nature of natural H₂ itself as an energy medium brings new considerations in its handling throughout its lifecycle. Using pipelines as a primary means to transport H₂ directly infers alternative and additional requirements for public safety and pipeline integrity beyond the natural gas hydrocarbon infrastructures of the last 80 yr.  

There is anticipation that governmental and industry groups will convert and utilize substantial portions of the existing hydrocarbon infrastructure for H₂.  

Pipeline integrity principles and knowledge in the conversion of service and ongoing maintenance may be directly applied in many cases, while others may be adopted with some specific validation. These principles include threat management practices and known techniques for detection, mitigation and prioritization, leading to the mitigation (or removal) of a threat.  

Such practices also include forecasting of pipeline integrity in the future, namely through methods for time-dependent flaw growth and remaining life predictions. A primary method in quantitatively assessing current and forecasting future pipeline integrity states is inline inspection (ILI). 

This article is outlined in terms of pipeline integrity, threat management practices and the use of ILI within some stated presumptions for the mass-transport of H₂ in pipelines.  

H₂ lifecycle in energy infrastructures. Traditionally, H₂ production has been for industrial purposes and consumption, including the fundamental production of modern chemicals and metals widely used by society.

H₂-based infrastructure for energy presumes to displace hydrocarbon fuels as a primary distributed source (FIG. 1).

 

 

H₂ does not abundantly occur naturally and must be generated through electrolysis or chemical processes such as methane reforming.

Globally, each nation and region have generated strategies for clean energy and the role of H₂. Each nation broadly considers H₂ generation capacity, its role in distribution and usage in the context of current energy sources and availability. Each strategy also highlights the need for significant investments in the transition.  

The U.S. Department of Energy (DOE) has created a strategic program and roadmap for the generation, distribution and use of H₂ as a primary energy source.  

It presumes growth of H₂ production through assumed future capacities of H₂ generation through “green” renewables, “blue” reforming and other phased means. It also addresses and presumes a role for carbon capture, which requires its own pipeline network for carbon dioxide (CO₂) capture and sequestration. Most prominently, the DOE highlights the need for social acceptance and broad infrastructure investments (FIG. 2).  

 

 

Australia released its initial H₂ strategy in 2019, followed by an updated version in 2024. The country's strategy looks at both energy interests and options of energy infrastructure.

Canada’s H₂ strategy was published in December 2020 and was developed by its Department of Natural Resources. While it addresses similar optics of national energy interests and requirements, it focuses on transition opportunities based in existing production industries and energy sectors.

Europe has outlined goals for the energy transition, summarized as the EU Hydrogen Backbone.¹ The infrastructure of this backbone includes the reuse and conversion of Europe’s widespread natural gas infrastructure of transportation pipelines and distribution networks. It also outlines means for H₂ storage including repurposing existing natural salt caverns used for hydrocarbons, as well as the reinjection of carbon byproducts back into depleted hydrocarbon fields (e.g., under the North Sea).

Depending on the approach and scale adopted in H₂ generation and usage, a new parallel role has also emerged for carbon capture, where carbon emissions byproducts (CO and CO₂) are captured at points of emissions vs. being released. Captured byproducts will also require their own infrastructure of transport and sequestration, and pipelines are expected to play a role.^2,3,4,5

Carbon capture is required to produce blue H₂ because methane reforming produces carbon byproducts that must be captured. In addition, in any scenarios where emissions from current electrical power generation have carbon byproducts, the CO₂ must be transported from combustion to final sequestration. 

A color spectrum has been adopted to describe the different methods used to produce H₂ (FIG. 3).

The role of transmission pipelines will continue to evolve, as a means of interim storage as pipeline networks are redirected depending on new generation sources, consumption needs and roles in carbon capture. Hydrocarbon reservoirs are not expected to be the same as future H₂ generation locations.⁶ 

As the generation of H₂ scales up, initial methods considered include the blending of H₂ with natural gas during transport within pipelines.^1,5 It is recommended today to treat H₂ blends as a conversion of service of a pipeline, including an assessment of threats that the presence of H₂ brings.^6,7,8,9 Fundamental considerations in a conversion of service include:

• Line pipe materials and assessments for compatibility  
• Weld materials and assessments for compatibility 
• Compressor stations and components  
• Valves 
• Gaskets (at flanges or other joining points)  
• Potential threat populations from prior history and integrity programs  
• Pipe routing (reclassification of class location due to population and pipeline surroundings)  
• Preparation, testing and drying to ensure the water present is removed. 

In lower H₂ gas concentrations within a primarily natural gas fluid, studies have highlighted minor operational differences. In high concentrations, including the 100% H₂ case, the thermal content of H₂ gas and the compressibility has inferred higher pressures, and higher flow speeds will be required to meet the same energy flow of current natural gas pipeline delivery.^10,11,12 

New pressure levels and operational practices will evolve in accordance with safety considerations. Evolving standards like those established by the American Society of Mechanical Engineers (ASME) recommend assuming higher class locations for H₂ pipelines and specific integrity management processes to consider, such as H₂ embrittlement (in both line pipe, welds and other components).⁷ 

Some initiatives have started to investigate H₂ transport and storage in alternative forms (e.g., ammonia). A small amount of ammonia pipelines exists today but have unique hazards (e.g., high corrosivity, toxicity) and are not considered in this article.

Pipeline integrity. Stress concentration should be expected in blended H₂ pipelines. Stress concentration may be considered a classical physical flaw, but also may be generalized to any localized region where a change in its mechanical or metallurgical properties has occurred.

With H₂ transportation, the inclusion of threats for areas with atypical compositional or metallurgical properties may need to be considered, although they are not considered active threats with current hydrocarbon pipeline integrity practices; for example, an arc burn, produced by accidental contact with a welding electrode, or a grinding burn, produced by excessive force on a grinding wheel during maintenance. They may also include more distinctive conditions, such as manufacturing impurities (e.g., inclusions, laminations) in the line pipe, which are sites for H₂ permeation and concentration.

It should be assumed that there are existing threats in the pipeline that are unknown until quantified and calibrated through various means (typically from ILI, but also pressure testing or direct assessment/examination modeling).

With geometric time-dependent flaws, conventional integrity practices would confer a “critical flaw” size that is deemed potentially hazardous in the near- to medium-term.^9,10,11 This approach is applicable for time-dependent threats, but cracking will take the focus here. Critical flaw sizes may be determined for given line pipe by establishing a safe pressure target, setting properties assumptions of the strength of materials and using expected operating conditions.

With these criteria and by working through the relevant failure assessment methodology, a flaw can be categorized into an equivalent flaw size as “critical.” Therefore, it is assumed that definitions and conditions for tolerable flaw criteria will also achieve consensus amongst stakeholders, while likely being more stringent than today.

Due to H₂ embrittlement, the presumption of additional conservatism over equivalent hydrocarbon pipelines, such as for crack and time-dependent features in the near term, would lead to smaller critical flaw sizes and related acceptability levels (if any) of remaining flaws. This, combined with the potential accelerated growth rates of time-dependent flaws, presents a need for early detection, preferably for the smallest features through regular monitoring activities.

Growth modeling of a flaw—assuming simultaneous crack initiation and growth parallel to the flaw—becomes a tangible scenario. This would include not only corrosion, cracking, deformation and combinations of these, but it would also include external forces (changing over time) coincidental with conventional, time-dependent flaws and for regions of alternate material properties.

Susceptibility and confirmation. The impact of introducing H₂ into carbon-steel pipelines is being investigated extensively to establish practical and effective operational conditions and criteria. Understanding a pipeline’s susceptibility to H₂-induced effects should come from conversion-of-service activities or within fundamental design activities, where a threat/risk model for a given pipeline would be established.⁶

The conditions for susceptibility will be based on the threats addressed in natural gas pipeline practices and experiences. This includes known damage mechanisms, such as cracking, corrosion, mechanical damage, deformation and external forces.

If susceptibility for H₂ embrittlement is treated simply as a “Yes” or “No” for a given location, then the following procedures apply:

• If no, operators may presume no immediate concern but should engage in longer-term monitoring activities to ensure some level of detection is initiated in the future. The scope and threat conditions may be expanded.
• If yes, then operators may presume a given baseline for the pipeline state and an assumed accelerated pace of deterioration for damage mechanisms. Then, integrity planning would factor into an immediate response and mitigation with lower acceptability thresholds. 

Susceptibility considerations must include monitoring water (aqueous H₂), which is considered a primary factor in steel permeation and embrittlement.^7,11 

An assumption is that the presence of any stress concentrator areas will be immediately addressed, given presumed higher safety protocols and a lower acceptable tolerance for any potentially dangerous anomalies. In context, such practices and tolerability have similarities in integrity management for sour service and specialty service pipelines.

For “low” count populations of potential flaws, immediate remediation programs to address all reported threats are practical and cost-effective for risk mitigation.

For “high” count populations of potential flaws, additional means of assessments and validation are required to establish criticality and hazards within a risk mitigation prioritization framework, which may still involve remediation of all reported threats.¹³

Quantification and location. Monitoring activities are presumed to include practices such as those from current natural gas practices and procedures. Distinct among those is the use of ILI as a foundational and quantitative dataset across threat types.^6,7 In previous work, guidance was provided as recommended elements for a reliable assessment based on ILI inspection, including those for future forecasting and remaining life prediction.¹⁴ With some adaptation to terminologies used here, these were:

• A reliable measurement performance for detecting, discriminating and sizing flaws and potential stress concentrators. 
• An excavation program with accurate field and laboratory direct observation to evaluate threat types, calibrate risk/susceptibility models, catalog characterization of flaws in the pipeline and determine ILI tool predictive performance. This process includes updates to operator practices and threat modeling and provides reliable data feedback to the ILI vendor for improvements—particularly for non-conventional flaws and conditions. 

Comprehensive flaw assessment methodologies—particularly fracture mechanics-based methods with representative material properties data—should be used to prioritize excavations and predict future lifecycle/re-inspection intervals.

Cracking. Practices for crack management threats were initiated for liquid lines, where pressure cycling and material fatigue are prominent. This quickly evolved to gas pipelines, with external cracking mechanisms formally classified as stress corrosion cracking (SCC), independent of internal pipeline products.

The Center for European Policy Analysis (CEPA) and the American Petroleum Institute (API) 1176 address multiple forms of cracking that have factored H₂ into different cracking formation mechanisms.^11,15 It is presumed that flexure stress (fatigue) is present in the presence of initiators or impurities in the line pipe material (or weld) as a H₂ concentrator site, which leads to cracking.

A fundamental point is the notion of the crack feature as a material “discontinuity,” especially with a population of those features present in the pipeline as “growing discontinuities.” With this point in mind, see FIG. 4 for a crack growth lifecycle. Modeling of cracking growth presumes a multi-stage “bathtub,” as stated initially by Perkins and adopted by CEPA and API.^11,15

For external cracking and initiation, SCC stage timing remains as it does for hydrocarbon pipelines. For H₂ influences as the internal source, it is (conservatively) assumed that acceleration through the stages will occur compared to hydrocarbon influences, as H₂ may permeate within the material (as line pipe or weld) from the inside to the outside.

In comparison, SCC (external) conditions for Stage 1 are typically mediated through corrosion control practices. However, crack initiation may still occur.

In Stage 2, crack growth is “mechanically driven” and assumed in the presence of H₂ embrittlement. Key conditions include stress-dependent loading interactions and frequency, where the crack is growing at its fastest rate. Growth mechanism modeling may factor in the localized stress state at a crack tip.

By Stage 3, rapid crack growth of sizable cracks occurs, and failure is imminent. Remediation and integrity management measures are expected to be taken prior to reaching this stage.

H₂ has always been a factor in SCC susceptibility, particularly for aqueous H₂. Still, with SCC, it presumes direct contact with the pipe's external surface with the presence of water. Crack threats are categorized broadly within environmental cracking (including H₂-induced cracking), fatigue cracking and SCC. API outlines an inclusive list of conditions (all must be present) for H₂ effects to be applicable. These are poor coating state, water presence (internal or external), high cathodic protection (CP) potentials, known high hardness material values and higher observed crack growth.¹¹

Cracking definitions have typically been based on the formation mechanism of the cracking, which evolved out of the susceptibility model for monitoring conditions. However, the physical embodiment of the crack itself factors into the (fracture mechanics) assessment for integrity.^16,17,18

Recent efforts in the transition to H₂ pipelines have focused on the threat of cracking due to the potential embrittlement of the material caused by H₂. Comprehensive fracture mechanics methods consider pipeline material properties, with material toughness being a primary factor for and influence on the sensitivity of results and the determination of severity and risk.

One study, looking specifically at the EU gas transmission network, concluded that around 70% of European pipelines are API 5L Gr. B, X46 or X52—steel grades that are expected to be compatible with H₂ transport without modification.¹⁶ 

However, findings by Sandia National Laboratories, on behalf of the U.S. DOE, reported that the deterioration of fracture resistance in pipeline steel is unrelated to the concentration of the H₂ blend in the pipeline. At a given pressure, the proportion of fracture resistance lost at 1% H₂ blend was the same for 100% H₂.¹⁷ 

Conditions can initiate cracking at any time during a pipeline's operating life; therefore, susceptibility assessment and active monitoring have been recommended practices.

Editor’s note: This article was first published at the 36th Pipeline Pigging and Integrity Management Conference, February 2024. Organized by Clarion Technical Conferences. Used with permission. This article was also published in the June 2024 issue of our sister publication, Pipeline & Gas Journal. 

LITERATURE CITED 

¹ European Union, “The European Hydrogen Backbone (EHB) initiative,” online: https://ehb.eu/ 

² UK Government, “The ten point plan for a green industrial revolution,” November 2020, online: https://www.gov.uk/government/publications/the-ten-point-plan-for-a-green-industrial-revolution 

³ NaturalHy consortium, “Preparing for the hydrogen economy by using the existing natural gas system as a catalyst,” 2009. 

⁴ EU Hydrogen Alliance, “Hydrogen,” online: https://energy.ec.europa.eu/topics/energy-systems-integration/hydrogen_en  

⁵ EU Commission, “A hydrogen strategy for a climate-neutral Europe,” August 2020.  

⁶ Huising, O. J. C. and A. H. M. Krom, “H2 in an existing natural gas pipeline,” 2020. 

⁷ ASME, “Hydrogen piping and pipelines,” online: https://www.asme.org/codes-standards/find-codes-standards/b31-12-hydrogen-piping-pipelines 

⁸ European Industrial Gases Association, “Hydrogen pipeline systems,” 2014. 

⁹ ASME, “Managing system integrity of gas pipelines,” 2020. 

¹⁰ API, “Fitness for service,” 2021.  

¹¹ API, “Recommended practice for assessment and management of cracking in pipelines, 2021.  

¹² Ramboll, G. A., “Hydrogen as energy carrier—Comparison with gas and electricity,” 2021. 

¹³ Adianto, R., J. Skow and J. Sutherland, “The benefits of accurate ILI performance on pipeline integrity programs for axial crack and metal loss corrosion threats,” 2016. 

¹⁴ Slaughter, M., K. Spencer, S. J. Dawson and P. Senf, “Comparison of multiple crack detection in-line inspection data to assess crack growth,” 2011.  

¹⁵ Canadian Energy Pipeline Association, “Stress corrosion cracking recommended practices,” 2015.  

¹⁶ Pluvinage, G., “Mechanical properties of a wide range of pipe steels under influence of pure hydrogen or hydrogen blended with natural gas,” 2021.  

¹⁷ Sandia National Laboratories, et al., Ronevich, J. and C. S. Marchi, “Hydrogen blending into natural gas,” Sandia National Laboratories, 2019. 

¹⁸ Tappert, S. and L. Lamborn, “Leveraging ILI crack profiles,” 2023.