Brian Gibbs Senior Consultant
Brian and is a highly experienced Integrity Management (IM) and Risk Specialist. His achievements span the entire asset life cycle including concept/ feasibility design...
In this is the third of five short blogs, we will address, again without going deeply into the weeds, the transportation options for hydrogen. There is considerable discussion in the literature about the options for the transport of hydrogen. It can be transported by truck or rail as either a liquid or gas; by ship as a liquid; by pipeline either pure or blended with natural gas; or by using a hydrogen carrier e.g., ammonia, methanol, or liquid organic hydrogen carrier. Pipelines are by far the most economical method for large-scale transportation, but the options depend on factors such as source of hydrogen, proximity to end users, distance to be transported, scale of the operation, etc. Meeting regulatory requirements will inevitably vary with national and local regulations and it’s likely that this is a detailed topic of discussion in its own right and, where codes and regulations do not exist, achieving consensus will have many challenges.
It has been proposed that while large-capacity production is being developed, hydrogen could be blended with natural gas as a stepwise approach to decarbonization. Literature indicates that the concentration of hydrogen in natural gas will be limited to about 20% due to embrittlement concerns. Transportation in of this mix raises many issues that need to be carefully addressed such as:
• Impact on compressor operation, seals, leakage, modifications needed, etc.
• Reduction in the delivered energy capacity. Assuming normal operating pressure and volumetric capacity can be achieved with existing or modified compressors, the energy delivery capacity of the line will be only about 86% of that of pure methane. Adding 20% hydrogen to methane will reduce the energy capacity of the blend to 782 Btu/SCF (compared to the 909 Btu/SCF for methane).
• The overall safety risk should not be significantly different in the main distribution system. However, the risk in service lines will be higher, particularly when installed in confined spaces thus increasing the explosion risk from a gas leak.
• Impact on end users from an operability viewpoint e.g., burner adjustments, safety and potential derating of applications using this new fuel mix, etc.
• Impact on existing peaking shaving storage plants which are located along existing natural gas pipeline. Peak shavers are small LNG liquefaction plants that condense and store natural gas as LNG when gas demand is low and re-vaporize and send it out to the pipeline when demand is high. Peak shavers are designed to condense natural gas containing minimal inert gases. Hydrogen due to its much lower boiling point will not be condensable and will perform essentially as inert. Thus, likely making peak shaving installations inoperable.
• End users that need pure hydrogen will need to separate it from the mix. The technology exists but needs to be economic for a specific application.
Dedicated hydrogen pipelines exist in both the USA Gulf Coast and in Europe. The end users are all industrial applications used as a feedstock in processes and not as a fuel. Generally, these are clustered in the same area so fewer or shorter distribution pipelines.
There are proprietary systems for adapting existing hydrocarbon pipelines to allow them to transport pure hydrogen as a gas. This includes hydrogen-tolerant linings and pipe-in-pipe options. This, of course, solves only part of the problem as all fittings, equipment including compressors, flow meters, etc. interconnecting piping, and safety systems all need to be suitable for hydrogen service. Replacement of these items is totally feasible as the technologies and commercially available equipment exists. As with many aspects of energy transition, economics will finally determine the practicality of adapting existing pipelines for hydrogen service.
Small volumes of hydrogen, such as those needed at hydrogen refueling stations, will most likely be transported for short distances by truck in the form of compressed gas having long multiple tubes operating at about 2,900 psi. These tube trailers typically have a capacity of about 837 lbs. (0.38 MT) of hydrogen. Larger trucks consisting of containers made of glass fiber composite or carbon fiber can hold about 2,400 lbs. (1.1 mt) of hydrogen compressed to 7,250 psi. While exceptions can be granted, currently U.S. Department of Transportation (DOT) regulations limit tube trailer pressure to 3626 psi.
Modest quantities of hydrogen are transported, for longer distances, as a liquid in insulated cryogenic tanker trucks. to distribution sites where it is vaporized to a high-pressure gaseous product for dispensing. A significant challenge with liquid transportation is the handling of hydrogen boil-off during transportation and handling. For larger quantities of hydrogen, pipeline transportation will almost always be more economic than shipment by truck.
Hydrogen carriers are chemicals that contain a high percentage of hydrogen. These chemicals can be manufactured at points where hydrogen is produced, transported, and then decomposed to release hydrogen at the point of delivery. The two most discussed are ammonia and liquid organic hydrogen carriers.
Ammonia is a major chemical that has been produced for more than a century. It is produced, stored, and shipped as a liquid in vast quantities all over the world. Ammonia is a well-established liquid hydrogen carrier and contains one atom of nitrogen and three atoms of hydrogen. Ammonia has a higher energy density per volume than liquid hydrogen. It can be transported and stored as a liquid at low-pressure 250 psi tanks or in cryogenic tanks at -27 F at 14.7 psi or as a liquid in a dedicated pressurize pipeline. At the point of delivery, ammonia can either crack back to hydrogen and nitrogen and separate from the nitrogen in commercially proven processes or it may be combusted directly in some applications. With respect to its combustion, burning ammonia results in the formation of NOX as part of the combustion products which must be controlled.
Compared to alternatives such as Bio-LNG or liquid hydrogen, ammonia requires less extreme storage conditions having storage, shipping, and handling properties like propane, and has a significantly higher volumetric energy density than hydrogen.
The concept of LOHC’s involves loading up cyclic and heterocyclic compounds with hydrogen, storing and transporting them, and then decomposing them back to hydrogen and the original compounds. The recovered compounds would then usually be shipped back to the site where the hydrogen is being generated to complete the cycle.
Chiyoda recently demonstrated the concept where toluene was saturated with hydrogen to form methylcyclohexane (MCH) in a plant in Indonesia, transported in a normal container ship to Japan where it was decomposed over a proprietary catalyst, dehydrogenating it back into toluene and hydrogen. The decomposition step is a highly endothermic reaction and thus a major energy penalty. The regenerated hydrogen was used as a fuel and the spent toluene was shipped back to Indonesia.
Compared to ammonia, MCH is easier to handle, store, and transport because it is similar to gasoline. It can use existing transportation infrastructure such as tankers, trucks, pipelines, and tanks.
Our next blog in this series will cover hydrogen storage options.