Based on the aforementioned projects and also ongoing activities with electrolyser technologies,
Equinor is well prepared for (co-)developing hydrogen value chain technologies and projects.
2.1 Current hydrogen projects in Equinor
Some of the current, early-phase hydrogen projects involving Equinor are [8]:
• Zero Carbon Humber: Blue hydrogen is planned to be produced at a new plant at Saltend in the
UK in 2027. The hydrogen would be used by chemical industry and flexible power plants in the
Humberside industrial cluster. Equinor is cooperating with Drax and National Grid Ventures on
this project
• H2Morrow steel: A 2.7 GW blue hydrogen plant would be used to decarbonize German steel
production, in partnership with ThyssenKrupp Steel Europe, in the second half of the 2020’s
• H2Magnum: Equinor is working together with Vattenfall and Gasunie on a project to supply blue
hydrogen to one of three 440 MW power plant trains at Magnum in the Netherlands, to produce
flexible clean power
• HyDEMO: Equinor is evaluating a small-to-medium scale blue hydrogen plant on the west coast
of Norway to serve onsite and maritime users, which would produce 60-130 MW of hydrogen [9]
• NortH2: Equinor has joined the project which aims to produce green hydrogen from offshore wind
off the north coast of the Netherlands. The project would produce 1 GW of hydrogen by 2027 and
over 10 GW by 2040
• LH2 Maritime: Equinor is a partner in a project led by BKK to produce green hydrogen at its
Mongstad refinery, for use in maritime applications and other transport. Liquid hydrogen from the
plant would also be distributed by hydrogen-fuelled ships along the west coast of Norway
3.0 SAFETY AND RISK MANAGEMENT
3.1 Understanding the risk
Managing risk is about understanding and controlling the hazards involved in the relevant activity.
This includes having a perception about what can go wrong, what the causes can be and what the
consequences may be. Uncertainty, or strength of knowledge, and how to deal with this is also a factor
in risk management.
Hydrogen has been used and handled in industry for many decades, and the strength of existing
knowledge, at least regarding gaseous hydrogen, is high in the industries familiar with hydrogen. As a
result of increased focus on a low-carbon society, utilisation of hydrogen as an energy carrier is also
becoming more relevant for new types of industry. Hydrogen is introduced to new contexts and by
users that have so far been unfamiliar with the properties and behaviour of hydrogen. Thus, transfer of
experience and knowledge is vital.
Several of the potential new actors in low-carbon energy production, like Equinor, have a massive
knowledge basis related to handling of other flammable gases, for example hydrocarbons, and
therefore have a good understanding of safety barriers related to such gases. It is important to
comprehend the differences between hazards introduced by hydrogen, compared to the gases the oil
and gas industry are used to handle. The main differences are related to larger flammability range,
lower ignition energy and higher laminar burning velocity. Table 1 shows the combustion parameters
of hydrogen compared to other well-known fuels, ref. [10].
Hydrogen’s properties mean that there is a high probability that a flammable gas cloud will ignite, and
that if ignited in an obstructed or confined area, there is an increased possibility of deflagration-to-
detonation-transition, causing very high explosion pressure loads. Appendix A provides a brief
description of two accidents involving hydrogen, illustrating the hazards involved.
3
Other characteristics that need to be considered include the high gaseous buoyancy and diffusivity -
meaning that if released in open air the gas will rise and dilute rapidly. In addition, the ability to cause
embrittlement of certain common materials if certain conditions are present must be considered.
Table 1. Ignition and combustion properties for air mixtures at 25°C and 101,3 kPa for several
common fuels (reproduced from [10])
Fuel LFL 1 Stoich. UFL 2 Minimum Auto- Laminar
mixture ignition ignition burning
energy temperature velocity
% vol. % vol. % vol.
fraction fraction fraction mJ K m/s
Hydrogen 4 29.5 77 0.017 858 2.70
(H2)
Methane 5.3 9.5 17.0 0.274 810 0.37
(CH4)
Propane 1.7 4.0 10.9 0.240 723 0.47
(C3H8)
Gasoline 1.0 1.9 6.0 0.240 488 0.30
(C8H18)
When it comes to liquid hydrogen (LH2), the knowledge is somewhat weaker, or at least not as
widespread. The boiling point of hydrogen is about 20 K at atmospheric pressure, a property which
alone creates several challenges. Research is on-going on the behaviour and characteristics of liquid
hydrogen, including required ignition energy at very low temperatures, ref. [11] and [12]. This paper
will mainly focus on gaseous hydrogen but will also discuss some aspects of liquid hydrogen.
3.2 Safety strategies used in Equinor
In Equinor, all facilities shall establish an installation-specific safety strategy. The objective is to
provide understanding of why a safety barrier (technical or operational) must be established, and
which design solutions and performance requirements are needed in order to fulfil the barrier’s
intended function. The document provides a “bridge” between identified hazards and risks, on one
side, and the need for and role of safety barriers in different areas of the facility, on the other. The
description is based on relevant Equinor requirements and specifications for the safety barriers but
further detailed, adjusted and made specific for the facility.
Fig. 2 shows how various conditions, documents and tools are related. Authority and company
requirements form the framework conditions. Within these conditions, the risk picture, presenting the
hazards, the risk contributions and the risk level, is the basis for establishing the safety strategy. Based
on requirements and strategy, maintenance and inspection plans are specified. Verification activities
are performed to prevent drifting into an unsafe state over time. Regular review is necessary.
For each safety barrier, its role / purpose and the specific design and performance requirements are
described. For example, the role of gas detection can be described as: “The gas detection system shall
continuously monitor for the presence of flammable or toxic gases, alert personnel and allow control
actions to be initiated manually or automatically to minimise the probability of personnel exposure,
explosion and fire”. The description of the specific requirements would include type, location, and
quantity (number or density) of detectors, voting principles and detection response (automatic and
manual). References to further documentation must be included.
1
LFL - Lower Flammability Level of fuel in air
2
UFL - Upper Flammability Level of fuel in air
4
The safety strategy would normally include both technical and operational barrier elements. This paper
will mainly focus on the technical elements.
Figure 2. Documents and tools for risk management
4.0 HYDROGEN SAFETY IN DESIGN
4.1 Hydrogen specific requirements to safety barriers
Main safety barriers to prevent, detect and control the fire and explosion risk connected to flammable
gases are illustrated in the bow-tie diagram in Fig. 3. These barriers will also be applicable for
hydrogen facilities. This chapter describes recommendations to be implemented in design based on the
properties and the risk connected to hydrogen. These recommendations would be the basis for a
facility specific safety strategy.
Figure 3. Bow-tie diagram summarising safety barriers in design for flammable gases.
Containment - Hydrogen storage might include very high pressure or cryogenic temperatures (for
LH2) which determine design specifications. Materials that are in contact with other materials must be
compatible with each other, as well as with hydrogen. Material and equipment considerations for a
hydrogen system may include choice of both metals and nonmetals (such as polymers and
composites). The phenomena that influence material selection and system design are: temperature and
pressure, hydrogen embrittlement, permeability, porosity and compatibility of dissimilar metals when
used together. For metallic materials reference is made to the American Society of Mechanical
Engineers (ASME) B31.12 standard [13]. For polymers reference is made to the DNV JIP proposal H2
Composite Pipes [14].
5
Layout design principles - To exploit the diffusivity and buoyancy properties of hydrogen-containing
/ process equipment should be located in the open, as much as possible in uncongested areas, and at a
high level. This will optimise the conditions for dilution and limit flammable gas cloud build-up, and it
will also reduce the risk of strong explosions if ignition occurs. Pipelines should be located on the
outside and upper part of buildings, structures and piperacks. Potential leak sources (filters, valves,
flanges etc.) should be located in a common area and prevented from dispersing into congested areas.
This is illustrated in Fig. 4, by an “open box” where hydrogen instrumentation and equipment could be
located to avoid any leaks being directed toward the congested module. A leak will be forced upwards
and into open air instead of flowing into the congested area.
Figure 4. Illustration of “open box” structure. The left wall will prevent leaks from flowing into the
congested process area to the left of the box and direct the leak upwards
If location of hydrogen pipes and equipment in enclosed and obstructed areas cannot be avoided,
welded connections are recommended. An alternative option for piping is pipe-in-pipe solutions.
Natural and mechanical ventilation - Effective ventilation would dilute released hydrogen gas to
non-flammable concentrations. Good natural ventilation will be achieved if the hydrogen
containing/processing equipment is located in the open and as much as possible in uncongested areas,
at a high elevation.
If enclosed areas cannot be avoided, mechanical ventilation might be used to dilute accidental releases.
The properties of hydrogen should also be exploited for mechanical ventilation, with the air inlet at a
low level in the room and the outlet at a high level. It must be ensured that the outlet leads to safe
location and that the ventilation system is approved for the relevant hazardous area classification.
Since hydrogen mixes easily with air, and has a large flammability interval, it might be more
challenging to achieve good enough ventilation compared to other gases. The effect of the ventilation
should be validated, e.g. by gas dispersion calculations.
Recognised standards such as International Electrotechnical Commission (IEC) standard 60079-10
[15] open for introducing ventilation as a means for reducing the extent of, or need for, hazardous
areas and thus explosion (Ex) proof equipment. However, this approach should be used with care for
hydrogen.
Gas detection - Common technologies for flammable gas detection are infrared and catalytic
detectors. Hydrogen does not absorb IR radiation; thus, IR gas detectors cannot be used. Catalytic
detectors using palladium and/or platinum as catalyst can be used for hydrogen.
Acoustic detection, based on the measurement of ultrasound (typically 25 kHz+) generated by the
leakage itself, can be also be used. A leak will produce noise within a frequency band of 80-100 kHz,
6
which is normally different to the noise made by rotating and vibrating machinery, and other man-
made noise sources. Acoustic detectors can detect a leak, but not indicate exactly where or how large
the leak is. The detection reliability depends on the background noise.
Other means of detection are electrochemical, semi-conduction oxides, thermal conductivity, mass
spectrometers and glow plugs (used to ignite flammable gas volumes which then can be detected by
flame/heat detection instruments). Monitoring of process variables (pressure, temperature, flow, level)
and process abnormalities can be utilised to indicate possible leaks.
In naturally ventilated areas hydrogen detectors should be located close to potential leak points
(valves, flanges, process equipment, fuel dispenser), at locations where there is a natural flow path and
where detection might indicate a hazard, like air intakes, ventilation outlets or vent stack outlets. For
gaseous systems, location at a high elevation is important. For liquid hydrogen, being less buoyant,
location of gas detection at low points is also relevant. In mechanically ventilated areas detector
location should be based on the airflow to secure fast detection. Gas detection could also be
implemented in pipe-in-pipe systems, at the upper end of the outer pipe where leaked gas would flow
if open-ended.
Fire detection - The purpose of a fire detection system is to monitor for the presence of a fire, to alert
people in the area and to initiate control actions. This will minimise the likelihood of fire escalation to
other equipment and reduce the probability of people being exposed.
A pure hydrogen flame is almost invisible in daylight. The emissivity outside of the flame also
decreases very quickly, so it may be difficult for people to know that they are approaching a flame
before they are exposed to it.
There should be means for detection of fires in all areas where leaks, spills or accumulation of
hydrogen may occur, where a fire might expose people or where it could lead to escalation, such as
near hydrogen dispensers, close to storage vessels and main safety functions. Detectors should provide
a rapid and reliable indication of the existence, location, and size of a hydrogen flame.
Thermal and optical sensors can be used to detect burning hydrogen. To cover a large area or volume,
many thermal detectors are needed and should be located at or near the site of a potential fire. A
hydrogen fire does not normally generate smoke, so smoke detectors are not effective.
More details about fire and gas detectors suitable for hydrogen can be found in [16], [17] and [18].
Fire and gas detection systems might have interfaces with the other safety systems and functions such
as natural and mechanical ventilation, emergency shutdown (ESD), emergency depressurisation, flares
or vents, active fire protection, layout and explosion barriers, emergency power and lighting, alarm
and communications systems.
Emergency shutdown systems and “safe condition” – The purpose of the ESD system is to prevent
escalation of abnormal conditions into a major accident and to limit the extent and duration of such
events. ESD have interfaces to leak and fire detection, ignition source control, emergency depressuri-
sation and flaring/venting systems and safety and automation systems. In addition, ESD initiation
might activate (directly or indirectly) other safety systems and functions such as emergency
ventilation, emergency power and lighting, alarm and communication system for use in emergency
situations.
Emergency shutdown means that a technical system is set in a «safe condition» if a hazardous
situation arises. Such situations are usually identified in design through a systematic identification of
possible deviations (e.g. HAZOP analysis). Technical safety barriers are identified to set the system in
a safe condition. This might involve closing of ESD valves to limit/stop the leak, safe venting,
7
blowdown or flaring of contained gas to safe location. It might also activate emergency ventilation,
deactivate ignition sources, start deluge or inert systems, etc.
Pressure relief systems, blowdown/flaring/venting – This requires that the gas can be released or
burnt safely without causing additional risk to the surroundings. Flares normally include a pilot flame
to ensure ignition. Backflow of air into a vent system must be avoided since ignition might lead to
explosion in the vent line. This might be done by purging the vent line with a small flow of inert gas.
Liquid storage must be equipped with boil-off valves and the outlet from such valves and other
pressure relief systems must go to safe location. Liquid-hydrogen vent systems must not be exposed
to water, including firewater, since there is a risk that these vent points are below the freezing
temperature of water, leading to clogging of the vent system.
Open drain systems - The intention of this system in general is to prevent further hazardous
spreading of the spill, and to lead spilled flammable liquid to safe disposal, but it must be ensured that
the spill does not lead to an additional hazard. This could for example be prolonged duration of a
flammable gas cloud in congested and confined areas, or risk of a fire exposing storage vessels or
other equipment containing hazardous chemicals. This is highly relevant for liquid hydrogen since a
liquid leak might cause a significantly heavier gas cloud than gaseous leaks. According to the National
Fire Protection Association (NFPA) standard 2 [19] “diking shall not be used to contain a liquid
hydrogen spill”. This also means that liquid H2 containers cannot be located in diked areas with other
hazardous materials.
Ignition source control - The minimum ignition energy is significantly lower for hydrogen compared
to other fuels, meaning ignition might occur without any clear ignition source. Pressurized hydrogen
can, if released under certain conditions, self-ignite due to shock effects [20].
Based on the minimum ignition energy, electrical and mechanical equipment in hazardous areas must
be approved for gas group IIC. Additional requirements are necessary to reduce the ignition
probability. These are 1) proper grounding and bonding of metallic equipment, 2) avoid materials that
might cause static electricity, 3) use of anti-static materials on floors and walls, antistatic window
glass, 4) avoid open fire, hot work such as welding, air intakes of combustion engines or other
combustion processes, presence of cell phones and smoking 5) use antistatic clothing and shoes,
conductive footwear 6) spark-proof tools. The IEC 60079 series [21] provides comprehensive
information on ignition mitigation. NFPA 2 [19] provides design and operational requirements related
to ignition source control and avoidance of ignition sources specific for hydrogen.
Since accidental leaks might be significantly larger than the scenarios used to determine hazardous
areas/ex-zones, the additional measures as listed above, should be used also outside the actual
hazardous areas.
Passive and active fire protection - The role of passive fire protection (PFP) is to ensure that relevant
structures, piping and equipment components have adequate fire resistance, whereas the main purpose
of the active fire protection is to provide quick and reliable means for firefighting in addition to
cooling of equipment and structures.
The best way of handling a hydrogen fire is to let it burn under control until the hydrogen flow can be
stopped, unless it exposes equipment that could rupture. Extinguishing the fire may create a larger
hazard due to an increased potential for an explosion if gas from a release subsequently re-ignites.
This applies especially in congested areas and where hydrogen can accumulate in case of a leak.
Water deluge activated by gas or fire detection systems, can be effective at reducing worst-case
explosion pressures for natural gas. However, the performance of water deluge will depend on
parameters like scale, confinement, congestion and how water is applied [22], and the performance is
not fully understood for hydrogen. Recognized international standards for general design of deluge or
8
water spray systems are NFPA 13 [23] and NFPA 15 [24]. However, this is an area where more
research is needed.
Explosion barriers and design to avoid detonations – The risk of explosions is, also for hydrogen,
mainly connected to enclosed or densely obstructed areas. The large flammability interval, effective
mixing with air, low ignition energy, high burning velocity and small detonation cell size (i.e. high
reactivity) increase the risk of strong explosions or even deflagration to detonation transition (DDT).
The risk of high explosion pressures in enclosed areas is higher for hydrogen than for most other
flammable gases. To reduce this risk the following safety barriers must be considered: 1) Limited
number of leaks points inside the enclosure, 2) restricted inflow of hydrogen (i.e. limit the maximum
leak rate) 3) high ventilation rate, 4) ESD and relief of gas inventory to safe location in case of
confirmed gas detection, 5) explosion relief panels that pop out to safe location at low pressure, 6)
designing the enclosure to withstand explosion.
For gaseous hydrogen, the risk of a detonation propagating in an unconfined gas cloud is less relevant
since hydrogen gas clouds in open and unconfined areas will be limited in size due to the buoyancy
and diffusion properties. There might, however, be a higher risk for detonations in unconfined areas
for LH2 systems. Fig.5 illustrates how a detonation can be initiated for flammable gases. This
mechanism was studied by Oran et al [25]. The circle represents a flammable gas cloud and the
rectangle an enclosed/obstructed area. The cross illustrates the ignition point, the yellow area a cloud
that deflagrates and the red area is the cloud that detonates. Illustration nr 3 represents the worst-case
situation: Ignition and DDT might start in an enclosed area, caused by a strong ignition source and/or a
high degree of obstruction/congestion increasing the turbulence in the combustion. The detonation can
then propagate to the whole flammable volume, causing very high pressures and at longer distances.
For accidental releases of LH2, the very low temperature and tendency to form a heavier gas cloud at
ground level with prolonged duration can cause significant flammable gas clouds in open areas. A
DDT might then be initiated in an obstructed or enclosed area and propagate into flammable gas re-
maining in the open area. This mechanism needs to be considered in design, by avoiding strong
ignition sources and obstructed areas and ensuring good natural ventilation.
Figure 5. Illustration of the risk of detonation and dependence on ignition point [25]
9
5.0 CONCLUSIONS
Equinor has recently initiated the development of several hydrogen value chain projects. These are
based on hydrogen production from either electrolysis or reforming of natural gas or other
hydrocarbon-based feeds, with CCS. For a safe and sustainable implementation of hydrogen value
chains, safety strategies and risk management are a necessity. Equinor’s system for establishing safety
strategies has been presented in this article, illustrating how safety barriers are designed based on the
risk picture. Safety barriers in design, adapted to the properties and risk characteristics of hydrogen,
have been described.
6.0 REFERENCES
1. Equinor’s Climate Roadmap, https://www.equinor.com/en/how-and-why/climate.html, 2020.
2. Eiken O, Ringrose PS, Hermanrud C, Nazarian B, Torp TA, Høier L. Lessons learned from 14
years of CCS operations: Sleipner, In Salah and Snøhvit. Energy Procedia 2011; 4:5541-5548
3. Ringrose PS. The CCS hub in Norway: some insights from 22 years of saline aquifer storage.
Energy Procedia 2018; 146:166-172
4. Technology Centre Mongstad, www.tcmda.com, 2020
5. Mulighetsområdet for realisering av fullskala CO2-håndtering i Norge. NC00-2012-RE-00034;
2012 (Translation: The opportunity area for realization of full-scale CO2 handling in Norway;
in Norwegian only)
6. Northern Lights – A European CO2 transport and storage network,
https://northernlightsccs.com/en, 2020
7. Longship – Project by the Norwegian government for full-scale CCS that comprises of
capture, transport and storage of CO2, https://langskip.regjeringen.no/longship/article, 2020
8. Equinor website on hydrogen; https://www.equinor.com/en/what-we-do/hydrogen.html, 2021
9. Hamborg, E.S., Gulbrandsen, T.H., Steeneveldt, S, Svenes, S, Berggren, H, Kvarsvik, S and
Pettersen, J. Norwegian hydrogen value chain demonstration based on decarbonized natural
gas. 15th International conference on greenhouse gas control technologies, 2021
10. ISO/TR 15916: Basic considerations for the safety of hydrogen systems. Second edition,
2015-12-15.
11. PRESLHY, Pre-normative Research for Safe Use of Liquid Hydrogen, Research and
Innovation Action Supported by the FCH JU - Grant Agreement No 779613, www.preslhy.eu,
2021
12. SH2IFT project, Safe Hydrogen Fuel Handling and Use for Efficient Implementation,
www.sintef.no/projectweb/sh2ift/, 2021
13. ASME B31.12 Hydrogen piping and pipelines
14. DNV Joint Industry Project proposal for H2 Composite pipes, 2021
15. IEC 60079-10-1:2020 “Explosive Atmospheres. Part 10-1: Classification of areas. Explosive
gas atmospheres
16. Bain, A., Barclay, J.A., Bose, T.B., Edeskuty, F.J., Fairlie, M.J., Hansel, J.G., Hay, D.R. and
Swain, M.R., Sourcebook for hydrogen applications, Hydrogen Research Institute and
National Renewable Energy Laboratory, 1998
17. Buttner, W.J., Post, M.B., Burgess, R., Rivkin, C., 2011, An overview of hydrogen safety
sensors and requirements, International Journal of Hydrogen Energy, 36(3), pp. 2462–2470.
doi: 10.1016/j.ijhydene.2010.04.176
18. H2tools website: https://h2tools.org/bestpractices/leak-and-flame-detection, 2021
19. NFPA 2 Hydrogen Technologies Code, 2020 Edition
20. Astbury, G.R., and Hawksworth, S.J., Spontaneous ignition of hydrogen leaks: A review of
postulated mechanisms, International Journal of Hydrogen Energy, Volume 32, Issue 13,
2007, pp 2178-2185, https://doi.org/10.1016/j.ijhydene.2007.04.005
10
21. IEC 60079 Series Explosive Atmosphere Standards, 2021
22. Gexcon website: https://www.gexcon.com/us/products-services/Explosion-and-
Mitigation/35/en, 2021
23. NFPA 13 Standard, Installation of Sprinkler Systems, 2019 Edition
24. NFPA 15 Standard, Standard for Water Spray Fixed Systems for Fire Protection, 2017 Edition
25. Oran, E.S., Chamberlain, G., Pekalski, A., Mechanisms and occurrence of detonations in
vapor cloud explosions, Prog. Energy Combust. Sci., 77, 2020, p. 100804,
10.1016/J.PECS.2019.100804
26. Bjerketvedt, D. and Mjaavatten, A.: A hydrogen–air explosion in a process plant: a case
history. 1st International Conference on Hydrogen Safety, Pisa, Italy, 8-10 September 2005
27. Bjerketvedt, D. and Mjaavatten, A., Accident report N1 6.7.85, Norsk Hydro Research Centre,
Doc.nr. 86B.BM7 (report, Norwegian), 1986
28. Pande, J.O and Tonheim, J: Explosion of Hydrogen in a Pipeline for CO2. Process safety
progress, Vol.20 (1), p.37-39, 2001
APPENDIX A: TWO HYDROGEN ACCIDENT CASE STUDIES
Explosion in ammonia plant, 1985
This hydrogen accident has been published in [26], and illustrates the forces if a hydrogen gas cloud,
even when containing a limited amount of hydrogen, ignites in a confined area.
In the summer of 1985, a severe hydrogen-air explosion occurred in an ammonia plant in Norway. The
accident resulted in two fatalities and the destruction of the building where the explosion took place,
see Fig. A1.
Figure A1. Damage caused by the explosion (accident investigation [27], Photo: A. Kjellevold)
The event started when a gasket located inside of a large factory building was blown out, first causing
a leak of water, but after about three minutes hydrogen reached the leak point and started to form a
flammable gas cloud inside the building. The discharge of gas lasted some 20 to 30 seconds before the
explosion occurred. The total mass of the hydrogen discharge was estimated at 10 to 20 kg hydrogen.
The main explosion was very violent, and it is likely that the gas cloud detonated. The ignition source
was almost certainly a hot bearing. Investigations concluded that 3.5 to 7 kg of hydrogen combusted
violently in the explosion. The damage indicates that explosion pressures inside the building must
have reached at least 10 bars. Windows were broken up to 700 m from the centre of the explosion.
11
Concrete blocks weighing 1.2 metric tons were thrown up to 16 meters. The roof of the building was
lifted by an estimated 1.5 meters before resettling [27].
Explosion of hydrogen-air mixture in a pipeline, 1997
Information on this explosion has not been extensively published. However, the potential of the
accident was significant, and the learnings are important. The description below is based on ref. [28].
In 1997 the transfer pipe for CO2-gas from an ammonia plant in Norway exploded. There were no
injuries, but 850 meters of the 1000 m long line were destroyed, and a large number of glass windows
were broken. The pipeline was temporarily out of service. The investigation team concluded that the
trip system had been disabled prior to the explosion, hydrogen enriched gas had entered the pipeline,
the nitrogen purge had not been effective, air had leaked into the line and formed an explosive
mixture, and the mixture had ignited. The investigation team concluded that the damaged line must
have been filled with a mixture containing more than 10-15% air and 40% hydrogen. About 10 kg
hydrogen was involved. A computer simulation indicated that the combustion front had quickly
accelerated and propagated through the line within a couple of seconds, causing it to rupture
(estimated pressure of 10-15 bars) at intervals of 10-20 m. Four of the ruptures are shown in Fig. A2.
Figure A2. Flame acceleration in a hydrogen-air explosion inside a pipeline resulted in several
ruptures [28]
12
