1.    As of January 2024, we are not aware of any public data on incidents or investigations where a hydrogen fired steam boiler exploded.

2.    The potential for detonations within a boiler tube would depend on both the equivalence ratio of the hydrogen present and the diameter of the boiler tube.
a.    At a minimum, if the circumference of the tube is smaller than the detonation cell size, then a detonation cannot propagate in the tube (experimentally, the critical diameter might be significantly larger).
b.    If you have a very large diameter tube, but the concentration of hydrogen is below the limit for fast flame acceleration (something like ~10-12% vol. H2), then the hydrogen-air mixture cannot run-up to detonation.

3.    There’s a good database of detonation cell sizes and critical tube diameters at: https://shepherd.caltech.edu/detn_db/html/db.html
a.    Here’s an example of critical tube diameter data for hydrogen-air mixtures: https://shepherd.caltech.edu/detn_db/html/H2-Air11.html
b.    Here’s an example of detonation cell size for hydrogen-air mixtures: https://shepherd.caltech.edu/detn_db/html/H2-Air1.html

4.    For information on pressure loads in tubes resulting from a detonation, there’s information in NFPA 67.
a.    The peak pressure would be related to the CJ detonation pressure of the mixture that forms.  Not applicable to a fire tube boiler, but for other geometries there could be regions where pressures significantly higher than the CJ detonation pressure could develop due to shock reflection at end caps/elbows.
b.    The pressures would be significantly higher in the region where the deflagration transitions to a detonation.
c.    The CJ detonation pressure of a mixture can be calculated with tools like the Shock and Detonation Toolbox: https://shepherd.caltech.edu/EDL/PublicResources/sdt/
d.    Even without a detonation, a fast flame propagating within a tube can generate maximum pressures on the order of the constant volume explosion pressure of the mixture, which can be estimated by a chemical equilibrium solver like Cantera or NASA CEA.

5.      For the pressures where a DDT occurs (i.e., where the pressure can be significantly higher than the CJ pressure), we have seen this in incident investigations, and put out a paper illustrating this. These loads extend over several pipe diameters and have significant associated impulse (i.e., the structure containing the mixture is likely to respond to the peak pressure).
Geng, J. and J.K. Thomas (2012) “Pressure Distribution Inside Pipes Due to DDT,” PVP2012-78590, ASME 2012 Pressure Vessels and Piping Conference, Toronto, July 15-19, 2012.

6.      If you fill the boiler with an H2-air mixture, a DDT can occur.  A fairly applicable example would be a test we ran at very low congestion, which may be representative of the congestion in a fire tube boiler, within our DLG test rig 48 ft long x 24 ft deep x 12 ft high (15 m long, x 7 m deep x  4 m high), with one long face open as a vent.  We got a relatively strong deflagration at 20%H2.  We got a DDT at 22.5%H2.  A paper describing these tests:
Horn, B.J., O.A. Rodriquez, D.R. Malik and J.K. Thomas (2018) “Deflagration-to-Detonation Transition (DDT) in a Vented Hydrogen Explosion,” 14th Global Congress on Process Safety (52st Loss Prevention Symposium), AIChE Annual Meeting, Orlando, FL, April 22-25, 2018.

7.    The DLG tests described above were performed with the entire test rig filled with a relatively uniform and quiescent mixture.  In an accidental scenario, the boiler could have a non-uniform concentration and, depending on the scenario, only a portion of the boiler may be filled with a flammable mixture.  In this case, we would normally turn to computational fluid dynamics (CFD) analysis using the FLACS code.  We have developed a criterion for evaluating the FLACS results to determine if a DDT would occur.  An example of the application of this approach for a H2-air explosion within a vaporizer set is described in:
Thomas, J.K., J. Geng, O.A. Rodriquez, et al. (2018) “Potential for Hydrogen DDT with Ambient Vaporizers,” Mary Kay O’Connor Process Safety International Symposium, College Station, TX, October 2018.
Relative to the point above, please note that some experts do not concur with using FLACS for DDT analysis. That being said, we have gotten a reasonable match to our VCE test data using this approach.

8.    Relative to natural gas fired steam boiler failures due to internal explosions, some work we did relative to reformers is somewhat applicable, although we did not establish the type of frequency information he is looking for:
Maxwell-Shaffer, D.F., A.G. Sarrack and J.K. Thomas (2014) “Unusual Reformer Events and Modeling,” 2014 AIChE Safety in Ammonia Plants and Related Facilities Symposium, Vancouver, September 2014.

See attached files for several references.

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.

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.

The Global Asset Protection Services (GAPS) standard was written 20 years ago for property loss prevention at crowded chemical plants and is intended for existing and new oil and chemical facilities to limit explosion over-pressure and fire exposure damage; thus, the purpose is different than NFPA 2. NFPA distances were based on studies from the 1960s as well as qualitative factors that were deemed successful based on applied experience over the years. A risk informed approach as described within Annex E of NFPA 2 was applied to GH2 separation distances in the 2011 edition. These were further revised in 2020. Similar changes as described in Annex N of NFPA 2 were applied to LH2 distances in the 2023 edition.

These distances are based primarily on hydrogen piping releases as a function of pipe diameter and pressure. Exposures were aggregated into three groups and separation distances applied to each as applicable based on unignited vapor clouds, radiation exposure from jet fires, and overpressure. 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 models to fully assess risk.
 

The lifetimes of these components will vary depending upon the application, their installation environment, and usage. It is also important to adhere to the component inspection, maintenance and replacement specifications as recommended by the manufacturer. However, as many are made of stainless steel, their life expectancy is longer than other materials. Estimated lifetimes are below in years: 
•    Liquid Hydrogen Tanks: 15-20 years between refurbishment but lifetime over 40 years is typical (tanks have lasted 40+yrs)
•    Ambient Vaporizers: 15-20 years
•    Pressure control Manifolds: 10-15 years
•    Cryogenic Liquid Pumps: 15-20 years but generally require annual maintenance for wear items
•    Valves instruments, etc.: 5-7 years but may require seal replacements depending on usage