Yes, these would be ignitable mixtures.  In this case, it does not appear complicated geometry is involved, so 1200 psig pipe should be more than adequate to protect against internal deflagration. The most likely scenario is a "backfire," similar to a car, where ignition occurs too soon and shoots out the open end of the pipe. Consider using an inline deflagration flash arrestor on the supply line to protect upstream piping and equipment. Also, make sure pipe welds, fittings, and instruments have a comparable rating. The pipe needs to withstand an over-pressure resulting from an ignition at the mixing point of H2-O2. This is the issue that necessitates a high pipe pressure rating, preferably high enough to withstand a detonation.

The nominal H2-air detonation peak pressure is about 10-20 times the initial pressure, but there are also possible reflected pressures, a comfortable margin is needed to withstand shock wave pressures above the nominal detonation peak pressure. It’s possible for reflected pressures to get a little higher, but these generally remain within 20X. If a pipe is at atmospheric pressure, 300 psig will result in 20X the pressure, so that is the basis for the 1200 psig pipe having sufficient margin. 

LNG storage, plumbing, and other systems can’t be directly retrofitted to handle hydrogen. The LNG components and systems will need to be removed and replaced with equipment specifically designed for hydrogen. If the concept is to convert existing equipment or an existing ship, then it’s probably impossible. If it’s to convert an existing LNG design on paper, then it’s probably impractical. Much better to start from the ground up with an H2 design.

From a materials perspective, there would be issues related to both the lower temperature of hydrogen and hydrogen embrittlement.   The temperature of LNG is 113 K, so many materials specified for this temperature will not be suitable for liquid hydrogen’s temperature of 20 K. In addition, liquid hydrogen’s lower temperature will condense air, so insulation systems will need to be significantly different for vessels and piping.

Another consideration is that electrical classification for LNG is different than H2, so would likely require substantial retrofit of instrumentation and controls. LNG equipment also frequently has non-captured vents, which would not be acceptable for hydrogen. Much of the LNG equipment might be located in enclosed areas, in which case the properties of H2 are going to drive design changes. Enclosed areas may also be a hazard for LH2 systems since air may condense on the piping and create a localized oxygen rich environment, especially if poorly ventilated.

Based on the question, it’s not clear if the reference to stress corrosion cracking (SCC) has been proven or is only suspected. It can be difficult to identify the nature of the cracks (SCC vs H2 embrittlement without analysis and microscopy). In addition, the question does not mention that the cylinders contain hydrogen gas, but it’s assumed since it was submitted to the Panel. 

In this case, it is the experience of Panel members that H2 cylinders rarely used Cu-Ni alloy discs due to concerns over embrittlement. Most discs for high pressure cylinders are copper to resist hydrogen embrittlement. Corrosion and/or SCC from the atmospheric environment are concerns and care should be taken to protect the disc if conditions for SCC might exist, such as the Teflon coating mentioned. The outlet of the vent stack should also be capped to avoid atmospheric contaminants and water/snow/ice.  It’s important that the cap does not interfere with the ability of the disc to function. If the gas is hydrogen and the inquiry is directed toward hydrogen embrittlement, then more information is needed on the alloy. Is it copper-based with nickel as an alloying element or nickel-based with copper as an alloying element? Either way, if the inquiry is about resistance to hydrogen embrittlement from contact with H2, then 300-series stainless steel burst discs are often used at lower pressures (e.g., for LH2 equipment) and copper burst discs are used for high pressure gas. Nickel alloys are not generally recommended for H2 service, but specific alloy qualification is needed. Limited available data show these alloys to be highly susceptible to hydrogen.
 

The answer could be no devices at all, just a TPRD, just a PRD, or both. It depends on the potential overpressure scenarios identified during a hazard assessment. TPRDs typically are not used on ASME pressure vessels since they are not ASME compliant devices and since  system siting provides protection from engulfing fires. However, TPRDs are frequently used in portable applications for both hazardous materials transportation and as vehicle fuel tanks.

HSP members generally agree that rupture discs are problematic due to spurious activations and large releases. They should be avoided in most applications, since the entire vessel contents will empty and the tank will require inerting before replacing discs and be put back in service. TPRD’s can provide additional protection against spurious activation, but have also experienced this issue, plus might not meet code requirements for stationary service.  Spring loaded or pilot-operated relief devices may also prematurely activate but usually will reclose to limit the size of release. However, The Panel recommends complying with the adopted edition of ASME Boiler and Pressure Vessel Code (which provides direction for stationary vessels), NFPA 2 - 2023 (para 7.1.5.5), and CGA S1.3 (which is referenced by NFPA). NFPA 2, Section 7.1.5.5.1, requires the use of a PRD device to prevent the maximum design pressure of the vessel from being exceeded. The use of CGA S1.3 is also required. CGA S1.3 provides guidance on when protection needs to be provided, the types of devices to be used, and the sizing of those devices. For most overpressure scenarios, the vessel usually must be protected at MAWP and within the rules of ASME Code and CGA S1.3. 

This usually means a spring-activated pressure relief valve since rupture discs and TPRD’s rarely can be set as precisely as needed. If there are thermal exposure scenarios, methods to eliminate the thermal exposure and/or adding supplemental  thermal activated pressure relief devices may be appropriate. Spring-operated relief valves are often used to meet thermal exposure scenarios but have limited effectiveness and may not be optimal. The number of either pressure or temperature protective devices depends on the demands present and the device sizing. The need for redundancy of devices depends on the results of a risk assessment. Means to service the devices should be considered in the design. The location of device discharges must also be considered, particularly when devices are used for thermal protection. The installation of devices, inlet piping, and vent piping must be designed per ASME requirements.  

A few additional topics to consider: Ambient temperature effects should be considered when designing relief systems. While selection and sizing are detailed in the standards, performance may be affected by pressure effects that are not considered under the standards. For example, a code-compliant pressure relief valve could open if ambient temperature or process conditions are not sufficiently addressed. Flow capacity and setpoint are important issues to discuss for relief devices. Setpoints are usually based on MAWP or design pressure, as well as the type of overpressure exposure. For example, overpressure due to fire will often have a higher allowable pressure accumulation. Flow capacity is normally determined by the flowrate into the vessel from a compressor or pump, failure of upstream control valves, and/or heat flux into the tubes. Heat flux can be considered separate or in addition to the compressor or pump max flow capacity depending on risk assessment results. 

Although relief devices are usually required by code or the hazard assessment, they also are subject to spurious or erroneous activation. Considering hydrogen’s likelihood of ignition (when mixed with air), the use of devices should be balanced with other means of shutdown and pressure protection. Where equipped, s, the PRD should normally be the means of overpressure protection with the highest pressure setpoint. To ensure that the above issues are properly addressed, the HSP recommends that the design of high-pressure hydrogen systems be done by engineers with experience in this application. Regarding specific recommendations, the Panel does not endorse specific equipment manufacturers, models, or brands.
 

While HSP members have limited experience with MFCs in experimental setups, the Panel does not consider them to be reliable to provide a positive flow shutoff. For safety, a shutoff valve in series is recommended. Projects will also need to consider hazardous electrical rating and location when flowing H2. Regarding Coriolis mass flow measuring devices, Coriolis flow meters measure mass rate changes by oscillating a flow tube and measuring tube distortion response. Measurement resolution is better with heavier, denser materials. Since hydrogen is the least dense gas, the response is much less than with denser materials. They are also expensive and very challenging to operate at low mass flow rates. 

The HSP is aware of a few used with electrolyzers for flow confirmation at the 500 slpm range but lacks feedback on how well these worked.  The project should consider working with the supplier regarding this application. There is a special MFC for vacuum application that has been observed to work well, the only difference is the valve on this is toward vacuum. On the other hand, MFCs made for pressures of atmospheric or above could be used in slight vacuum (up to 10 psia) and low flow rates (1-2 slpm) but are not very accurate due to the expansion of gas at the exhaust of the valve; it depends on the compressibility of that particular gas. 

The recalibration time recommended is 2 years. If there is a valve leak, check the inlet-outlet valve opening pressure ratings on the spec sheet. From a safety perspective, it is not recommended that an MFC be relied on to provide a leak-tight seal against hydrogen. Further, MFCs are not accurate if the gas has other constituents not originally included in the calibration. For instance, humidification of fuel cell supply gases would significantly change the accuracy.   Also, given the inherent risk in mixing H2 and O2 in a vacuum chamber, the HSP recommends a rigorous, multi-party, hazard analysis.  

It is difficult to provide trustworthy answers to these questions without understanding the design and configuration of the specific installation. It may be best to consult with a pressure systems expert to evaluate the specific installation and uses. The gas provider may also be a good resource for specifics on gas equipment use. Other beneficial resources include the HSP Best Practices online resource and the DOE Hydrogen Safety Training for Researchers, the AIChE Laboratory Safety Course.

NFPA 2, Hydrogen Technologies Code, and NFPA 45, Standard on Fire Protection for Laboratories Using Chemicals, may also be helpful in identifying requirements and best practices. In addition, the project designed should consult with the local authority having jurisdiction for safety guidance that is applicable to locally adopted codes.
 

Panel members have not encountered a device or area classification for ATEX approval within Canada. ATEX is a European Union directive and is not generally recognized within North American standards. The second link below references a UL similarity. https://news.nilfiskcfm.com/2017/03/atex-certification-applicable-north-america/;    https://www.ul.com/services/atex-certification-european-union. As with any area or device classification, the designer is responsible for demonstrating to any regulatory body or Authority Having Jurisdiction granting approval that the design meets the standard. In addition, every attempt should be made to reference and meet current relevant standards and codes, rather than trying having to apply for exceptions.

There are no specific code resources that specifically cover hydrogen liquefaction plants, but they must be built to the general building, electrical, machinery, piping, and mechanical codes for process plants. Codes such as NFPA 2, Hydrogen Technologies Code, for installation and emergency response may also be used for reference. It may also be beneficial to break down the requirements into process safety and storage. For general process safety, there is good guidance for large plants. The Center for Chemical Process Safety provides guidance that is not specific to liquid hydrogen but instead addresses process safety. Other resources include the Hydrogen Safety Panel (HSP) and the Center for Hydrogen Safety (CHS).

The regulations for electrical classification in Europe and a US jurisdiction such as California are significantly different and should not be assumed to be the same. Consultation with Authorities Having Jurisdiction or a Third- Party expert regarding the application of the US National Electric Code is advised. Some additional important points:

The HSP has concerns with the use of ventilation to provide an option to the required electrical classification. The Panel does not advocate for unclassified equipment in the described area. It is a major challenge to achieve the response time required to sense and implement emergency ventilation from continuous ventilation required to cope with internal leakage. While the leak may be small, it might also be large and overwhelm almost any ventilation rate.

The space inside the container should be classified, and electrical equipment in the container should be Class 1, Div 2. Otherwise consider putting the electrical equipment outside the container.
 

The British Standards Institute (BSI) has published BS ISO 22734:2019, a British nationalized version of the packaged water electrolyzer safety certification standard. This standard can be used by a Notified Body (BSI is one of many operating in the UK and in Europe) to certify electrolyzer safety to established norms for this equipment. This standard addresses safety of containerized hydrogen generators using low temperature water electrolysis technologies PEM and KOH. It includes requirements to assess hazardous area classification using IEC 60079-10 and to employ methods to mitigate hazardous areas using air dilution and/or equipment designed for hazardous areas per the ISO 60079 series in accordance with the ATEX directive. The standard provides requirements for on-board GH2 storage.