There are several concerns with “snuffing” a hydrogen fire from a vent stack. Most importantly, snuffing a hydrogen fire before the hydrogen is isolated can lead to the buildup of a hydrogen vapor cloud, which may then re-ignite, especially with hot surfaces available from the previous fire. The largest hazard is an explosion of the vapor cloud caused by delayed ignition.  It’s always better to isolate the hydrogen at its source to extinguish the fire as fuel runs out. 

Snuffing systems have been used in the past for vent system outlets mainly due to the negative   perception of a visible hydrogen flame at the top of the vent stack, particularly at night.  The success of these systems was marginal since high and sustained rates of inert gas were required to snuff the flame and sufficiently cool the piping outlet to prevent the venting flow from reigniting.  Generally, it’s preferred to design the vent system such that it can withstand a worst-case continuous fire on the outlet without affecting its integrity or surrounding exposures.  If those criteria are met, then it’s inherently safer to allow the vent to burn than to try to snuff it. 

It is best to avoid planned blowdown of large amounts of hydrogen inventory at high flowrates if possible.  Low flow releases from vent systems are normal and occur for purging, delivery operations, and maintenance activity.   A challenge with high flow blowdown of a hydrogen system is that venting large quantities of hydrogen can itself be a hazardous activity.   Large blowdowns at high rates from vent systems can lead to jet fires and explosions after release to the atmosphere.

Flaring can be an option.  However, if flare stacks are used, they must ignite before the hydrogen reaches the end of the vent stack, so that a delayed ignition of the hydrogen does not occur, as this could create damaging overpressure.   A flare system is a complicated design for hydrogen. It is not normally a best practice unless the timing of the release is always known, and the flare cannot be extinguished until the hydrogen flow is stopped. Flares are generally only used at large production facilities which have the necessary infrastructure. 

A best practice for any storage system is to site the storage vessels away from any flammable substances and/or protect the vessels with barriers or insulation. It’s inherently safer to avoid   fire exposure onto the vessels, especially since relief devices may not be well suited to protect a vessel in the case of an impinging fire.  Similarly, there may be other methods to limit the H2 released by reducing the size, type or quantity of safety devices on a storage system. 

A best practice, when the storage vessels are not subject to an engulfing fire, is to use reclosing safety devices, such as spring loaded or pilot operated safety valves.  These do not empty the entire contents of the tubes, but open just to maintain the pressure within design criteria. 

Where it may be impossible to completely eliminate engulfing fires, rupture discs or thermally activated pressure relief devices (TPRD) are often preferred since once they activate, they will continue to vent until all pressure is released.  This is important since the fire may weaken the vessel while still at the reclosing devices’ setpoint, causing a vessel failure and a large sudden release of its content. However, non-reclosing relief devices can also be prone to inadvertent or spurious activation.  This can result in unnecessary and unwanted releases which can cause hazardous situations from high reaction forces and large quantity of the release. 

The design of vent systems is critical to the safety of the system. From a process perspective, the pipe design must be sufficient to withstand back pressure, internal pipeline pressure, deflagration 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. 

The vent system design starts with relief devices. Devices must first be sized based on the expected demand cases.  Documents such as CGA S1.3 or API 520 can provide guidance to size devices for fire situations.  It’s up to the designer to develop potential relief cases for other process demands, such as runaway heaters, compressors, backflow, etc. Once the relief devices are properly sized, then the discharge piping can be designed such that flow is not restricted.  For example, ASME relief valves will usually require the pressure drop on the downstream side of the device to be no higher than 10% of the set pressure.  Rupture discs don’t have the same requirement, but it is still necessary that the relieving capacity is not reduced below the demand case.  It’s also important to size the relief discharge piping for multiple devices where these devices (from different vessels, piping, etc.) could potentially vent simultaneously.  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.  As a rule, discharge piping will nearly always be larger than inlet piping, and the piping must be larger than the device orifice.  If there is a piping venting case (even if manual) into the same stack where both the vent case and the safety relief device can open simultaneously, the vent stack must be designed for all these cases.

Documents such as CGA G5.5 and API 521 provide guidance, requirements, and best practices for the design of vent systems, including addressing the thrust forces caused by high flow and velocity. 

There are advantages to reducing the amount and rate of hydrogen released.  Relief devices should not be oversized with an unnecessary safety factor.  Reduction of flow will lower reaction forces and the mass of hydrogen in the released cloud during an event.  A method to reduce the amount of hydrogen released is to use relief devices that reclose rather than emptying the entire inventory (i.e., rupture discs). However, rupture discs may still be needed if the storage vessels are subject to an engulfing fire to ensure the pressure is reduced before the mechanical integrity of the vessels is lost.

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 lower set pressure device were connected to the same header, then the backpressure would not allow it to operate properly, 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.  A best practice is using a maximum 5:1 ratio to determine when a separate higher-pressure vent system is needed. For example, discharge from a device set at 100 psig should not be piped into the same vent system as a device set above 500 psig, even if the piping is nominally sized to allow minimal backpressure.

Another consideration during the hazard review is to ensure that vent headers do not create a common mode failure such that redundant devices could be blocked from a single failure. Care must also be taken so 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 perform a process safety analysis to ensure 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. One simple best practice is to vent hydrogen vertically where possible, using momentum to supplement its natural buoyancy. Wind can affect hydrogen flow, so it does not always rise straight up after release. Top works should also be designed to minimize plugging due to weather and other causes.

Numerous incidents have occurred where vent systems failed or leaked during device activation. A best practice is to pressure test vent systems above the expected backpressures to ensure integrity per ANSI B31.3.  Additionally, it is critical to support the vent stack to ensure it maintains its mechanical integrity during venting and weather events.

It is difficult to control fluid velocity in a vent header since nearly all relief systems will operate at a pressure that will result in choked/sonic flow at some location in the discharge piping or outlet.  There is generally no velocity limit within the piping, but from a practical perspective, high velocities will result in high, excessive pressure drop.  The velocity is only limited by the requirement to maintain maximum pressure drop of no more than 10% of the relief device set point in the vent system.

The answer is dependent upon the nature of the system and a hazard assessment which evaluates a balance of risk. 

Keeping the hydrogen in the vessel is better so the hydrogen release does not compound the original hazard. Large flowrates from vessels can create significant risk of vapor cloud explosion, jet explosion, or radiation exposure. Vent systems can also fail from poor design or effects of the incident, so they may not work as intended to vent to a safe location. 

However, once exposed to an impinging or engulfing fire, there is a risk that vessel walls may weaken and result in a vessel failure. A vessel failure is generally looked at as a worst-case scenario in most situations and should be prevented if possible. In those cases, the relief systems play a key role, and depressurization of the system is a means to prevent failure. 

The most common means to depressurize a system or vessels are through the use of non-reclosing devices such as rupture discs or TPRD’s, or special instrumented systems that purposely depressurize the system in an incident. It should be noted that these devices and systems are not foolproof and could activate spuriously or in unintended situations which can lead to large releases and create significant hazards. The risk must be evaluated by a hazard assessment.

Yes, numerous incidents have occurred where frozen air (which contains oxygen) has built up within a hydrogen process or vent system. These incidents with vent systems incorporate more than just a vent stack, but include a vent system consisting of additional atmospheric equipment (such as a tank) where the equipment stays cold and allows air into the system in contact with a cold hydrogen stream. 

Vent systems are at risk since they are “open” to the atmosphere and certain flow conditions might result in the aspiration of air into a cold hydrogen flow which then leads to the freezing of the air. 

A small quantity of solid air can create an explosive hazard which then leads to cascading failures from the initial incident. Solid air in hydrogen is also shock sensitive which can lead to unexpected ignition.

Purging is not recommended as a continuous part of vent stack operation. However, maintenance activity is a transient event and it’s prudent and recommended to purge a vent system prior to performing maintenance. It’s always possible that hydrogen could be leaking internally from a valve or other component and therefore create a hazard. Of particular note, care must be taken that proper isolation of the vent system is performed such that the vent system can’t be inadvertently used during maintenance. Since vent systems and stacks rarely have isolation valves to prevent unintended isolation of relief devices, proper maintenance on the vent system may require the entire system or plant to be taken offline.

We are not aware of a study for blended NG/H2. However, for high concentrations of NG, the vent system should be similar to NG, which still recommends a vent system as NG is less dense than air. For nearly pure hydrogen the recommendations of this presentation are in effect.

Nearly all hydrogen storage tanks and hydrogen storage systems will need some type of pressure relief system to protect the vessels from overpressure. If there are pressure relief devices, some means to vent the hydrogen to a safe location will be needed. An exception to this is hydrogen cylinders due to their relief device type (lead-backed rupture discs (CG-4/5) and
the need to transport them.

However, the nature of the devices and vent systems depends on the type, size, location, regulations, and pressure of the hydrogen tank, storage tubes, or tube trailers and related system. There may be other means to protect against overpressure or fire exposure, and there are situations where the risk of a release could exceed the risk posed by the relief device and
vent system. For example, many GH2 transportation trailers in the EU are not equipped with PRD’s or TPRD’s which are not required by local regulations. Ultimately the decision and design of vent systems is based upon a hazard assessment.

We would not open the vent system to inspect the internal piping without a good reason.

It is recommended to check for water in the vent stack trap

1. At startup and daily during startup.
2. On LH2 tank system, every delivery
3. After the 1st rainstorm after a system is installed
4. LH2 vent stacks after establishing the baseline above
   1. After every large venting event
   2. Quarterly unless baseline requires more frequent
5. GH2 stack after baseline
   1. Check caps are still on quarterly for stationary tubes.

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)