There is no standard which specifically specifies the use of a flapper. A properly designed flapper should provide de minimus restriction to vent flow, yet still provides weather protection which allows for a vertical release of the vent stack flow, which is best from a dispersion and radiation perspective. Flappers are extensively used successfully and safely on nearly all liquid hydrogen road tankers as well as a supplemental means to vent large flows from stationary tanks in a vertical direction. However, vertical vent systems with a flapper must be monitored to ensure the flapper closes after operation to ensure no water enters the vent systems. LH2 systems are especially susceptible to this due to water freezing on the vent stack cap and its components and expansion contraction.

There are no differences in the process design of the vent stack since the venting requirements will follow the same sizing and pressure rating requirements regardless of vent configuration. However, vent systems often create liquid air on their exterior due to the cold venting temperatures. Since this liquid air will drip off the stack, it should be diverted such that it does not directly impinge on the outer vacuum jacket of the vessel. The jacket is often constructed of carbon steel which is not rated for the cold temperature of the liquid air, and as a result, may crack and cause loss of vessel integrity. Horizontal tanks will usually place the vent stack such that liquid dripping from the bottom of the stack will drain to the ground. This is more difficult due to the geometry of a spherical tank so the stacks must be sited and supported differently and/or a shield be placed to prevent impingement. 

Liquid hydrogen is rarely vented as a liquid. If liquid hydrogen is vented, there should be a means to ensure that it is fully vaporized. The vent systems for LH2 tanks are connected to the vapor space on the tanks to ensure in most instances, this occurs. Most vents from a liquid hydrogen system will vent gaseous hydrogen, but this gas, may still be as cold as -420 F. There are no code requirements for warming the vented hydrogen, and cold gaseous hydrogen is frequently vented safely through the use of a tall enough stack, preferably with a vertical discharge, such that the cold hydrogen sufficiently mixes with the ambient air before it would otherwise reach the ground. The vent systems for the safety of people, must meet the radiation requirements of CGA G-5.5 and API 521.
 

Some practical considerations include:

1. The wind can greatly affect the rate at which hydrogen rises due to the low weight of the hydrogen molecule.
2. Warming to at least -390 F will ensure that the hydrogen is above neutral buoyancy. However, venting hydrogen into the atmosphere at these cold temperatures can still cool the surrounding air and create downdrafts that can push the hydrogen towards the ground if not vented at a high enough elevation.
3. Uninsulated vent system piping below about -300 F can create conditions where oxygen enriched liquid air can form and drip to the ground. While this can be addressed with proper materials of construction under the piping, it can still create personnel hazards, especially if dripping down the sides of a tall vent stack.
4. Venting cold hydrogen below the atmospheric dewpoint will result in a visible water vapor cloud. While this can draw attention to the cloud and can create some confusion as to the extent of flammable mixtures within the cloud, it can be very difficult to warm hydrogen sufficiently to avoid all water vapor formation. 

Yes, for all stacks. GH2 has a minimum prescriptive height of 10 ft. There is no minimum prescriptive height for LH2. However, 25 ft has been a best practice for the industry for years. Vent stack outlets that orient the release vertically help reduce the radiation exposure at ground level. Care must be taken to consider varying weather conditions, particularly wind, as well as surrounding exposures that might be elevated in the vicinity of the vent stack outlet, such as nearby equipment, buildings, catwalks, and grade elevation changes. 

Generally flaring is not recommended. Normally GH2 is not flared for most hydrogen equipment as the piping diameters are smaller. The largest stacks are the LH2 vent stacks on trailers and on tanks for the main safety valves are 3”. For GH2 systems the flare stacks are generally smaller in diameter. 

Flaring is a deliberate ignition of a hydrogen stream. If the hydrogen stream is to be ignited, the timing of the ignition must be exact at the very beginning with a flame igniting the hydrogen before the cloud gets too large and represents a deflagration/detonation danger. 

For relief devices, this is very difficult due to the large instantaneous flow rate Flaring is also not typical as:

• A steady and constant flow is needed to maintain ignition
• Reignition explosively is possible if flameout occurs
• Timing of the initial ignition could cause a large cloud to be ignited

If a flare system is used, it must

• Dispose of H2 safely
• Prevent explosions
• Have a steady flow rate or controls that assure ignition is maintained. Variable
  velocities indicate a flare stack may not be advisable.
• Control the flare to assure
  • Pilot ignition
  • Flameout warning systems
  • Limit the backflow of air into the stack
  • Flame dip does not occur
• Variable velocities can cause
  • Flame blowout/burn-off - High velocity
  • Flame Dip -Allows air into the larger vent system- Low velocity

API 521 is a code that addresses flaring, besides the ANSI document.

There is some information on vent stack flaring below. The ANSI/AIAA G-095A-2017 Guide to Safety of Hydrogen and Hydrogen Systems former NASA NSS 1740.16 document addresses vent stack flow rates for flaring.

This document states “Quantities of hydrogen of 0.113 to 0.226 kg/s (0.25 to 0.50 lb/s) have been successfully vented from a single vent 5 m (16 ft) high”. .226 kg/s is a very large flow rate (340,000 scfh/8000 nm3/hr). Per NASA Figure A4.1, there is no flame dip shown (flame receding into the vent stack) below a 3 in stack size, which is consistent with the best practices. 

The flare systems themselves must incorporate pilot ignition, flameout warning mechanisms, and a means to purge the vent line, ensuring comprehensive safety measures are maintained throughout the process.

There are several levels of documents which can be used to assist with the design, sizing, selection, and installation of the pressure relief device settings for LH2 tanks. 

Pressure vessel design codes, such as the ASME Boiler and Pressure Vessel Code will provide minimum requirements for design of pressure vessels (including LH2 tanks), relief devices, and relief systems. However, these codes will not provide the sizing criteria nor anticipate all of the potential demand cases that might be imparted upon a vessel. 

In the US, the model fire codes require compliance with NFPA 2, which then references documents such as CGA S1.2 and CGA S1.3 for sizing criteria. These documents have been customized by the industrial gas business specifically for cryogenic fluids such as LH2. API Standard 520 “Sizing, Selection and Installation of Pressure-Relieving Devices in Refineries” of is also a helpful document to provide additional guidance. 

For LH2 storage tanks, usually the highest process demand is an engulfing fire with a loss of vacuum insulation to atmosphere. This failure mode can result in additional heat flux from air condensation in the annular space which must also be addressed. 

It is not required to proactively vent the contents of an LH2 tank when exposed to fire. Relief devices are required to prevent the accumulation of internal pressure to unsafe levels. Within the ASME BPV, this is 121% of Maximum Allowable Working Pressure for scenarios involving fire exposure. It is common practice, but not required, that at least one device be non-reclosing (e.g. a rupture disc) for both managing the high flow required as well as to relieve the contents of the tank. Reclosing relief devices will maintain pressure in a fire and are more likely to lead to a vessel rupture if the fire ultimately weakens the pressure vessel.

LH2 tanks are unlikely to BLEVE due to the vacuum insulation outer jacket (usually carbon or stainless steel) preventing direct impingement of fire onto the main pressure vessel, as well as the internal cryogenic contents maintaining the main pressure vessel walls at a cooler temperature until the contents have been relieved by the relief devices. 

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.

Yes, the pressure safety relief system on LH2 tanks is sized for the loss of vacuum condition. The spring-loaded safety valves are sized for lower demand cases such as runaway pressure build or loss of vacuum. Higher demand requirements, such as loss of vacuum combined with fire, are handled by the rupture discs and are sized for such an event.

A pressure gauge is not usually provided, as one set of devices (safety valve and rupture disc) is always online by design. If the diverter valve connecting the two sets of relief devices is in the center position, both sets are online although depending upon the design of the diverter valve, it might not allow full flow in either direction. For the secondary stack with a rupture disc and a locked open valve, a pressure gauge is usually installed since it also serves as an independent means to measure the pressure within the tank. This circuit provides both a secondary means to relieve pressure in the tank as well as monitor pressure. It’s intended to be redundant with the main safety circuit in case of a blockage.