Absolutely. Vent systems will experience a variety of transient conditions of pressure, temperature, and thrust load, so stress analysis to anticipate the strength and flexibility needed are important for safe design. These issues are often overlooked and only become an issue when they are called upon to operate in emergencies. 

It is a best practice to include the vent system in the process hazards analysis (PHA)

Yes, small flowrate vents may be invisible, particularly in daylight. Sometimes it may still be possible to see heat striations in the air from the heat generated by the fire, but it can be difficult to discern at low flowrates. 

A release is defined by the amount of hydrogen, the rate of hydrogen flow, vent location (indoors or outdoors), geometry in the area (confined or not), and pressure. 

A small or large release should be differentiated by the damage that can occur because of an ignition. This can be a fire, deflagration, or detonation.

Therefore, the relative size of the release will vary based on all the variables above.

If outdoors in an unobstructed area, a small release could be defined as a release that keeps the flammable hydrogen cloud from damaging its surroundings. 

1. Understand any reactions the hydrogen can add to what is being vented. For instance, O2/H2 vented in the same stack would not be a good idea.
2. Understand all the flow and operating parameters of the streams to ensure no back flow into the hydrogen system or vice versa.
3. Ensure the venting/flaring system can handle the hydrogen flow parameters.

Yes, there are differences due to the differences in the fluid properties. We’re not sure what is meant by blowdown. If this means that should the gases be vented to a vent stack, possibly, but for certain these need to be vented to a safe location.

The ASME BPV Code, and other Codes by reference, require less than back pressure of 10% of device set pressure from the release flowrate for proper operation of reclosing relief devices such as relief valves. Backpressure from non-reclosing or non-ASME devices may be higher so an analysis is required. It’s not enough to assume the vent system need only be designed for 10% of the set pressure. Instantaneous backpressure can reach as high as 50% of set pressure for some PRD or TPRD applications.

No, but it depends on the application. Nearly all vents less than 4” in size are not purged with N2. This is primarily due to: 1) large flows required to dilute hydrogen below the flammable range, 2) the cost of the nitrogen, 3) the potential blockage of the stack when being inserted a vent header/stack serving a liquid hydrogen system, 4) the potential for backpressure (depending on the source) to damage or restrict operation of relief devices, and the lack of incidents with non-purged system.

However, a nitrogen flow can be a means considered for specific systems warm GH2 system as part of a hazard assessment. For example, a nitrogen purge might be appropriate for a large diameter vent header that operates at very low pressure such that it might not be able to be designed for an internal deflagration. 

If a nitrogen purge is to be used on a liquid hydrogen system, then the vented hydrogen should have a means to be warmed above -320 F to prevent liquefaction or freezing of the nitrogen. N2 is not allowed for the purging of LH2 systems per CGAG-5.5.

There is no specific requirement not to vent liquid hydrogen from a vent system. Best practice would be to only vent gas from the top of the vessel to relieve pressure. If liquid must be vented, it should be vaporized first. 

Note: It is very unusual to have LH2 flow from a liquid tank out the vent system, as the vent system is connected to the vapor space on the LH2 tanks and there is a large amount of heat transfer into the fluid leaving the vent stack due to the large temperature difference between the cold GH2 and the environment (between 400 and 525 degrees F, a large multiplier). 

However, there are liquid-venting scenarios that must be considered during upset conditions such as when a road tanker might have rolled over. Liquid can be vented from the gaseous portion of the system so the system should be designed for that possibility. 

Design of vent header lines is critical to the safety of the system. From a process perspective, the pipe design must be sufficient to withstand back pressure, thrust forces from the flow, and must be of a sufficient size to not create a restriction that prevents proper flow or activation of the devices. Per ASME BPV Code requirements, backpressure should be limited to no more than 10% of the set pressure.

When more than one source is connected to a single vent, two critical design issues are the pressure rating and flow capacity. The vent header should be of sufficient size to simultaneously meet the required flows from the different sources where it’s possible for them to activate at the same time. This is a particular concern where there may be many, sometimes even dozens, of devices on pressure vessels used for fire protection where all vessels can be exposed to fire at
once.

Pressure rating and set pressures of the devices are also a concern. For example, a 3000 psig set pressure device with the typical 10% allowable back pressure, would allow up to 300 psig in the vent header. If a 300 psig set pressure device were connected to the same header, then it would not activate if required due to that backpressure, leading to possible overpressure of the process system. Best practice would be to use different headers on systems that operate at significant differences in pressure.

Another consideration is to make sure that common vent headers do not create a common mode failure such that redundant devices could be blocked from a common failure. Care must also be taken that incompatible materials (e.g. hydrogen and oxygen) aren’t vented on a common manifold and that contamination (e.g. compressor oil) doesn’t affect other portions of
the system where a source of contamination is present. 

When designing a vent system, the designer must review in a process safety analysis that the hydrogen cannot flow to unexpected locations. It is never a good design to tie a hydrogen vent system into a building ventilation system.

Maintenance is also an issue since vent headers can be an overlooked cross tie between portions of systems that otherwise are properly isolated on the upstream side. For example, if maintenance is being performed on a relief device, and a separate device activates elsewhere on the same header, then backflow could create a hazard while the vent piping is disassembled.

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.