The energy transition and climate targets have created a pressing need to scale technologies to decarbonise hard-to-abate sectors, many of which require low-carbon gases as well as greater electrification.
To reach the targets of the Paris Agreement, DNV, an international accredited registrar and classification society headquartered in Norway, forecasts that hydrogen will need to meet around 15% of world energy demand by 2050. This will necessitate a significant buildout of infrastructure to enable a hydrogen economy, much of it repurposed from natural gas infrastructure.
The cost to repurpose pipelines is expected to be just 10–35% of new construction costs. This potential saving will lead to more than 50% of hydrogen pipelines globally being repurposed from natural gas pipelines, rising to as high as 80% in some regions that have significant existing natural gas infrastructure.
As demand for repurposing natural gas pipelines grows, companies operating in the sector require guidance to help them get started. For example, as a pipeline operator looking to transform energy systems for hydrogen, or a government decision-maker or regulator, where do you start in your efforts to repurpose natural gas networks? What are the vital factors you need to assess? And what standards should guide your evaluation?
Standards and R&D
Assessing existing natural gas transmission pipelines for hydrogen transport requires a set of reliable and adequate guidelines. Industrial users, such as producers of ammonia, have transported the gas in pipelines for decades, but in limited use cases. Standards are not yet fully developed for its transportation more widely in gas infrastructure and in repurposed pipelines.
R&D and joint industry projects play an essential role in closing knowledge gaps to develop standards and recommended practices needed for safe and efficient repurposing of pipelines for the gas as an essential enabler of a hydrogen economy.
Existing pipeline infrastructure has been designed for transporting natural gas. Industry standards govern the construction and operation of natural gas pipelines (see Fig.1), along with local regulations. However, the codes in place provide limited guidance on the design and use of hydrogen in existing pipelines. The commonly cited design practices for hydrogen pipelines are based on the ASME B31.12 standard. However, some ASME requirements are likely to be conservative as they are based on sour service (containing hydrogen sulphide) design guidance.
These requirements are then challenging to achieve for existing natural gas transmission pipelines. Some of the constraints, such as weld hardness, are even more conservative than those found in sour service guidelines such as NACE MR0175/ISO 15156.
However, the possible negative effects of hydrogen on pipeline materials, especially long term, should not be underestimated, especially considering there is limited experience of managing hydrogen pipelines. The repurposing process must be aligned so that it ensures safe transportation of the gas in the future.
During the repurposing process, all aspects related to change of fluid should be carefully evaluated, considering the local regulatory regime. This requires deep technical knowledge and an understanding of gas networks.
For repurposing assessments, it is essential to know the gaps in standards and guidelines and understand where it will be necessary to follow a more bespoke repurposing evaluation process based on hydrogen engineering knowledge and a design review.
It is the gas network operators, together with governments and regulators, that initiate decisions to gauge the possibility of repurposing pipeline systems for hydrogen. Many operators have started assessing which of their pipelines could be converted to service the gas, and where new pipelines need to be built.
They must ensure the repurposing is safe, feasible and cost-effective. However, prior to undertaking this process they should identify where, when and what gas quantity demand there will be for hydrogen transport across their networks.
A solid regulatory framework is also essential. Up to now, no specific legislation has been implemented for widescale hydrogen transportation in pipelines, meaning existing regulations for natural gas are used for hydrogen projects.
Governments can also assist network operators in their evaluations by setting national strategies outlining the sectors expected to utilise the gas and making clear the pricing models to be used for its transportation and supply. This will allow operators to better plan the conversion of existing assets.
Before a natural gas pipeline is filled with hydrogen, the challenges and impact of the gas must be understood and accounted for. Hydrogen use in long-distance pipelines, for example, has been relatively limited to date, and such new uses could lead to new and unknown failure modes.
A harmonised process is needed to align operators on their repurposing projects to ensure safety as significantly greater amounts of hydrogen are transported, by a growing network of repurposed pipelines, over longer distances and across borders. Beyond this, operators also need to perform a rigorous assessment of the specific pipeline system before converting a pipeline for transporting the gas.
DNV has developed a process to guide operators in evaluating their pipelines for hydrogen. This process considers the current state of infrastructure, the anticipated operating conditions and the various damage mechanisms involved. It includes examples of some of the variables that may influence the appraisal.
Parameters for operations
To properly assess whether a pipeline system can be repurposed, operators need to define the content of hydrogen in the blend and the requirements for the pipeline material and compare this with existing natural gas code requirements. ASME B31.12 offers two options for determining design pressure: a prescriptive option (A) and a performance-based option (B). Each option has different material requirements (see Fig.2).
When designing a new pipeline, the material can be specified for hydrogen service to meet the ASME B31.12 requirements. For existing natural gas pipelines that have been in operation for years, it will be a challenge to meet all specifications, especially for the performance-based option (option B).
Typically, mid-strength steel such as X42 to X60 is used for natural gas transport for pipelines with a diameter of 16–36in. and pressures of 40–66 bar. Higher steel grades are used for large-scale transport at 66–94 bar, and it is these pipelines that are intended for dedicated hydrogen transport.
Prior to hydrogen transport, operators should perform a safety evaluation of the system, addressing the implications of the change from natural gas to hydrogen. The system should be evaluated based on the specific safety obligations for hydrogen pipelines.
As part of the safety calculations, operators should identify the requirement for modifications of the pipeline system, such as additional block valves, leak detection upgrades and updating ATEX zones. This should include an assessment of the suitability of components, and a change-out of valves and gaskets not suitable for hydrogen transport.
Integrity evaluations can also be performed based on material properties, historical operating condition and state of the infrastructure.
Asset integrity management of existing natural gas pipeline networks is a mature technical discipline, based on extensive operator experience as well as analytical, experimental and empirical data.
Yet, even with this experience, integrity management programmes are constantly developing and improving. Conversely, the industry has limited experience transporting hydrogen in pipelines not originally designed to such standards, and operators recognise the potential for the gas to exacerbate certain defects.
The maximum allowable pressure (MAOP) of a pipeline has a strong effect on its transport capacity and is an important step in the process. The MAOP can be determined by using option A (prescriptive) or B (performance-based) from standard ASME B31.12 (see Fig.2).
Option A limits the pressure up to 50% of that possible for natural gas, depending on the steel grade, which is not economically feasible in many cases. For this reason, gas operators are more interested in option B, which allows them to keep a higher MAOP.
When determining the MAOP, the pipeline condition should be considered. For old pipelines with defects, it is uncertain how remaining strength capacity should be assessed. The remaining strength of corroded pipelines for oil and gas operations has traditionally been reviewed using methods defined in standards such as ASME B31G or DNV-RP-F101.
The question is whether these methods are applicable for pipelines under high-pressure hydrogen environments without modifications or calibration. This is an area of research for DNV and international research institutes including the European Gas Research Group and the European Pipeline Research Group.
There may be certain defects that are acceptable under current integrity management criteria that will become critical due to the material property change in hydrogen containing environments. There are several defects that can contribute to reducing the fatigue life of a pipeline.
These include corrosion or metal loss, weld seam defects, stress corrosion cracking, dents, and dents in combination with gouges. The most significant defects in the case of hydrogen are crack-like defects, which reduce the fatigue life of pipelines performing under pressure fluctuations. An existing crack-like defect will have an impact on the MAOP and on the number and amplitude of cycles.
There are always existing defects in welds. Adding hydrogen into the pipeline network changes the operating environment, which may accelerate crack propagation or fatigue failures due to the existing defects, and thus adversely impacts pipeline integrity.
When considering the potential conversion of natural gas pipelines for hydrogen, operators need to evaluate the likelihood that expected pressure cycles will produce acceptable (very low) fatigue crack growth. They can then establish a threshold value for the pipelines. Based on the frequency of pressure cycles, the amount of time until a crack reaches its selected maximum depth can also be estimated.
Usually, it is assumed that repurposed hydrogen pipelines will be operated under similar conditions to natural gas in terms of pressure fluctuations. In practice, it could be different, and it will not always be possible to keep the fluctuation below the determined threshold value, and it can be expected that this will sometimes exceed the threshold value when transporting the gas. For this reason, it will not always be possible to control and limit the crack growth in repurposed pipelines.
To manage the fatigue risk for repurposed natural gas pipelines, operators can develop a fatigue risk matrix considering the crack growth per cycle and the number of cycles per given period (see Fig.3). The fatigue risk matrix should consider the current integrity of the pipeline and operating conditions, the determined threshold pressure value, and the new working conditions expected when transporting hydrogen.
The transport capacity of a transmission system will change if the gas composition is changed. The energy content of 1cm of hydrogen at pressures relevant for pipeline transportation is roughly one third of the energy content of 1cm of natural gas at equivalent pressure. This implies that, to transport an equal amount of energy, the velocity of pure hydrogen would need to be three times that of natural gas.
When converting an existing natural gas system to hydrogen, there are typically three scenarios:
- Equal maximum velocity: most conservative option, sticking to maximum design velocities.
- Equal pipeline capacity or equal pressure loss.
- Equal energy flow: the velocity of pure hydrogen would need to be three times that of natural gas.
Operators must calculate and evaluate these scenarios to determine which is most optimum considering all pipeline limitations. Fig.4 depicts the pipeline capacity for these three main scenarios.
Evaluation for conversion
When considering the conversion of an existing pipeline to hydrogen service, operators need to study the business case justifying the conversion. This includes factors such as the demand for energy capacity from end-users, supply availability, determination of an acceptable conversion cost compared with a newbuild option (or alternative transportation method), the consequences for end-users, the required pipeline life and the availability of state support or funding.
Based on the MAOP calculations and capacity assessment, operators should define optimal functional conditions, considering the pipeline condition and operating scenario. They should then compare the pipeline capacity with the requirements of the business case to determine if conversion is economically viable or if a modified strategy is required.
Operators should perform an analysis to identify gaps between the original design standard and current design specifications, as well as hydrogen specific guidelines and recommended practices. Where gaps are detected, they should propose mitigation measures. The mitigation measures should cover all stages of the pipeline integrity management system, with modification alternatives evaluated with respect to feasibility, safety and integrity.
The modification alternatives should then be reassessed through documenting the integrity status. Modification could also include material testing to better understand material properties.
As a result of the re-evaluation, operators should be well-positioned to determine the feasibility of repurposing pipelines and be aware of the mitigation actions they need to take. Independent assurance providers can play an essential role here. They can support and advise operators throughout the process, and can provide assurance to the assessment, such as by issuing an independent statement of pipeline feasibility for hydrogen repurposing.
Victoria Monsma is senior pipeline integrity specialist, energy systems, at DNV. She advises on different integrity and safety issues, performing verification of oil and gas transmission pipelines, carrying out safety and integrity assessments. Victoria is a subject matter expert in the field of reuse of existing natural gas network for transport of hydrogen and its blended mixtures.
Tim Illson is principal specialist, energy systems, at DNV and has worked in industrial corrosion control for more than 33 years. Illson’s specific areas of technical expertise include hydrogen effects on materials, specification of hydrogen test programmes to meet code requirements (ASME B31.12 and IGEM TD/1), corrosion in CO₂ transportation pipelines and subsurface equipment.
Afzal Hussain leads pipeline operations Northern Europe in energy systems at DNV. He has more than 20 years of experience in the oil and gas industry. Hussain has knowledge within materials and corrosion technology, and hands-on experience through failure analysis.
This article was previously published in Pipeline & Gas Journal.