Typically, the inner vessel material used is 304 SS and the outer vessel is a combination of 304 SS and carbon steel depending on location. 316 SS or 316L material can be used, but due to higher cost and lower strength, are typically only used for higher purity systems. Nearly all tanks manufactured today use various forms of vacuum jacketed multilayer insulation for best performance. Older tanks frequently used vacuum jacketed perlite as an insulation method.

It’s not clear if “mobile” in the question refers to vehicle fuel tanks, or vessels used for transportation of hazardous materials. 

1. If it’s a Type 4 vessel for transportation of hazardous materials, it will be built to a special permit that details the inspection requirements. Special permits vary but they are generally consistent on a 5-year requalification period, which also includes a visual inspection by an inspector certified to CGA C-6.2 at that interval. 
2. Since C-6.4 is mentioned, the question might pertain to vehicle fuel tanks. The C-6.4 document  recommends 36 months or less, but there are inconsistent requirements. The tank standard (ANSI/CSA HGV 2) originally required for a visual inspection every 36,000 miles or 3 years, whichever comes first, but the latest version states that the inspection is to be specified by the container manufacturer. There is an annex in HGV 2 that calls CGA C-6.4 or ISO 19078 to be used, although the ISO standard does not yet include hydrogen in its scope and is for CNG tanks only. Commercial vehicles such as trucks, buses and trailers also required an annual U.S. Department of Transportation (DOT) inspection to ensure that it complies with the Federal Motor Carrier Safety Regulations. This is a comprehensive check but does not have specific requirements for vehicle fuel tank inspection.
    

Regarding the concept of introducing hydrogen gas into natural gas pipelines, this is indeed a hot topic and there are recent quantitative treatments of fatigue crack growth driven by pressure cycling and potentially accelerated by hydrogen.  Some analysis has shown that it can be acceptable to operate natural gas pipelines with a hydrogen blend.  However, this is highly dependent upon the pressure and wall stress.  Whereas low pressure distribution lines with low wall stress are more amenable, the higher pressures and wall stresses of major transportation pipelines may not be.  Deep cyclic stresses that might occur from using pipelines as storage  may also create additional issues since hydrogen can accelerate fatigue crack growth, especially for systems where both hydrogen and deep cycles were not anticipated in the original design.  Individual pipelines likely need to be evaluated based on their design and there is likely to be no single answer for this question of pipeline storage. 

    
For industrial propane tanks, the Panel needs more information about structural materials and their properties (including welds). All propane tanks are not built from the same materials or with the same construction techniques, so these tanks likely need to be evaluated on a case-by-case basis. Propane tanks are often built with techniques that leave potential internal features that are susceptible to the initiation of crack growth. In addition, and depending on the application, it’s likely that the cyclic pressure service will be significantly different for a tank in hydrogen service, particularly one that might be cycled deeply on a daily (or more frequent) basis. From the perspective of the low-pressure storage options, while it is tempting to repurpose old LPG vessels for hydrogen service, the Panel cautions against it due to the potential for hydrogen embrittlement in the steel/weld material. Also, a challenge with newer propane tank designs is that they are moving to thinner walls and higher strength steel, which is notably less resistant to embrittlement than older vessels, so counterintuitively, newer tanks might be less amenable to hydrogen than older tanks.   

Another concern for vessels in hydrogen service is the amount of non-circularity, or “peaking” of the longitudinal welds.  This is not as much of a concern for propane so is likely not to be part of a standard design specification. This manufacturing issue can have a severe effect on cyclic life and is well understood when designing and building high cyclic hydrogen vessels, but not propane. Besides the issue described above for the tank itself, there are similar potential embrittlement issues for PRVs, instrumentation, and other accessories on these tanks. Many incidents have been due to component failures in these accessories. 
In conclusion, propane vessels were not designed for H2 cyclic service. Almost by definition, the reason people want to use them is for storage. and that is likely to be over a wide pressure range. Fracture mechanics should be applied to all cyclic H2 service vessels, especially if they start from another service. Propane tank designs vary and unless a tank is specifically intended for H2, there is no guarantee of what might be used terms of materials and construction techniques.
 

It is possible to store large quantities of gaseous hydrogen above ground, but it will likely require a large footprint due to its relatively low density even at high pressure. Also, if the quantity equals or exceeds 10,000 lb., the facility will need to comply with OSHA 1910.119 process safety management requirements if located in the US. Similar regulations exist in Europe and Asia that increase the regulatory requirements as storage exceeds about 5 tons. Codes such as NFPA 2 aren’t intended to provide full guidance for large facilities and  systematic hazard and risk analysis should be completed to ensure safety. A large storage facility would have to be sited and permitted using methods and risk analysis as typically would be done for a large plant. The technology for gaseous storage is fairly well established and well proven from previous and smaller installations. The same types of tanks, from fully metallic to fully composite construction, would be selected and used based on the operating parameters and economics. Individual tanks may be larger, but large amounts of non-cavern storage are likely to consist of large arrays of multiple vessels due to manufacturing and transportation limitations. The key aspects for large storage systems are as follows: 

1. Materials of construction:  Material science for hydrogen pressure vessels is well established and would mirror smaller storage systems. 
2. Fatigue:  Gaseous storage systems are likely to cycle deeply to increase utilization of the high capital cost of vessels. Deep cycles will typically lead to relatively short intervals between inspections based on fracture mechanics. 
3. A Mechanical Integrity program:  Given the large amount of stored energy, a mechanical integrity program will be very important. The cost of inspections could be high based on quantity and size of vessels. 
4. Minimization of impingement: Piping should be designed such that leaks don’t impinge on a neighboring tank. Impingement fires offer high risk of failure. Fire barriers or intumescent paint could be used at the base for protection. 
5. Relief systems:  Design of relief systems from a fire could be challenging, as well as designing a safe vent system and stack for what are likely to be very large relief devices. 
6. Permitting:  Large quantities of hydrogen need to meet additional regulatory requirements and height of vessels can lead to additional review depending on location. 
7. Foundations:  These will be large and expensive due to weight, height, and seismic considerations. 
8. Pressure: Higher pressure means lower volume required, smaller and/or fewer vessels, and smaller plot space. Lower pressure requires less compression equipment and less compression energy requires less compression.
9. Installation: One overlooked aspect of storage is the cost to transport and then install the vessels including freight, concrete, rigging, and piping. These costs must be added to the capital cost of the vessels. Storage vessels are expensive to ship   due to size and weight.
    

Hydrogen cylinders contain pure hydrogen unless they are specifically manufactured for and marked as a mixture. The purity grade is usually between 99.5% and 99.9999%. The balance is typically inert gases (such as nitrogen) with just ppm levels of other contaminants, but this can vary depending upon the production source. When emptied, the residual is still the same purity of hydrogen, just at lower pressure. If emptied to atmospheric pressure, there would still be one atmosphere of hydrogen within the container unless evacuated or purged to another gas. (See Properties section for related FAQs). Note that when a cylinder is reduced close to or at atmospheric pressure, it is very susceptible to air migration into the cylinder, especially if ambient temperature changes can create a slight negative pressure in the cylinder. Air should never be allowed into a hydrogen cylinder until it’s been properly purged with an inert gas such as nitrogen, helium or CO2.

This production rate of hydrogen of about 96 kg/h is quite significant, which depending upon the application might require a significant amount of storage. There will be a need to determine how many kg the project wants to store from this production rate in order to determine how much hydrogen ground storage is needed. Since the project is in Europe, look for pressure vessel manufacturers that offer PED approval for their vessels. 

There are many types of vessel construction other than Type 4 vessels for ground storage.  General vessel types also include Type 1 which are more traditional metallic vessels, Type 2 which are hoop wrapped, Type 3 which are fully wrapped with metallic liners, and Type 4 which are fully wrapped with non-metallic liners.
Selection between these types of vessels is highly dependent upon the design attributes (e.g., weight, service conditions, longevity, etc.), the nature of the process (pressure, temperature, cycles, etc.), and economics. The Panel is not in a position to endorse a particular type, brand or vendor. There are many vendors that can supply a variety of these types of vessels. It is important to develop a process specification for a vendor to quote since the application will have a significant effect on the economics of one type compared to another.

It is important to be aware of the local pressure vessel Codes within your jurisdiction. Virtually any manufacturer can help with that determination if requested but it’s also prudent to confirm with the local authority having jurisdiction. The manufacturer can also assist with the User Defined Specification for your service as well recommend   the storage pressure and number of vessels that might be optimized to store the quantity of hydrogen needed. Storage vessel cost may range from $500 up to $2000 per kg stored depending on the requirements selected. There are also many indirect costs related to storage such as relief devices, piping, freight, foundations, and installation that also must be considered as part of the overall assessment.
 

NFPA 2 has provisions for the use of LH2, and there are many existing fueling stations that store and use liquid hydrogen. One challenge for the use of LH2 in stations with small footprints is the code required separation distances from exposures. NPFA 2 has updated the separation distances with a risk informed approach in the 2023 edition.

Another possibility for public fuel stations would be to install the LH2 tank underground. Underground LH2 storage is permitted within NFPA 2 and requirements can be found in Section 8.3.2.3.1.7. It is certainly feasible to design and build a fuel station with an underground LH2 tank. 

It’s important to note that the NFPA definition of storage systems and resulting separation distance requirements are based on more than just the tank. The definition in NFPA 2 is an assembly of equipment that consists of, but is not limited to, storage containers, pressure regulators, pressure relief devices, vaporizers, liquid pumps, compressors, manifolds, and piping and that terminates at the source valve. The Hydrogen Tools portal (http://h2tools.org) has a variety of information, best practices, and lessons learned. 
 

These distances are based primarily on hydrogen piping releases and resultant vapor clouds and jet flames based on pipe diameter and pressure. It’s important to note that many facilities have issues such as confinement and congestion, so it may be applicable to apply contemporary engineering models to assess risk.

There is technically no upper limit for GH2 storage listed within the separation distance tables within Chapter 7 of NFPA 2. For LH2, there is a 75000-gallon upper limit for the LH2 storage separation distance tables within Chapter 8 for LH2. 
It’s important to note that many facilities have site specific issues such as large quantities, confinement, and congestion, so it may be applicable to apply contemporary engineering dispersion and radiation models to fully assess risk.
ISO TC 197 is actively developing LH2 tank standards based on recent research results in the European program described at http://preslhy.eu/. This process is usually slow because of the many nations involved and time inherently needed to reach the consensus required by the ISO standard development process.

This is an impossible question to answer without greater understanding of the quantities of hydrogen involved, the types of vessels involved, and the atmospheric conditions. Several companies offer software to model such releases. It’s important to note that there is a high probability of ignition either during the vessel rupture or from nearby ignition sources.