Getting from A to B: Hydrogen Distribution


Supply, meet demand: moving energy in bulk

One of the challenges with decarbonisation through electrification is that our energy system becomes a ‘flow-based’ system. We cannot put electricity on a ship or leave it sitting in a storage tank or heap somewhere, in the way that we do with fossil-fuels in a ‘stock-based’ way.

Of course we can store electricity in a battery, though with losses between what we get out compared to what we put in; and indeed losses simply by leaving it sitting there for too long. But to hold the same amount of energy, batteries are heavy and large relative to ‘fuels’.

That may not matter for stationary storage. But it does become problematic if we want to move large amounts of energy from place to place and these places are distant. We aren’t going to stack up batteries of stored electricity and ship them around the globe, in the way that we do with oil, coal and – increasingly – gas.

On the other hand, we can distribute electricity extremely quickly. Put it in one end of a wire and – hey presto! – it appears at the other end almost instantly; even if that other end is a long way away. That makes it very responsive to rapid and real-time changes in distributed demand, so long as our supply is flexible too (and we have the necessary grid infrastructure reach and capacity).

If we make these grids smarter, more demand flexible, and can time-shift some supply using batteries (or other storage solutions, like pumped hydro), we can incorporate increasing degrees of electrification – at least up to a point.

Beyond that point, our decarbonised future energy systems are also going to need stock-based elements of bulk energy distribution that are more energy-dense than batteries; i.e. fuels. It won’t be a question of either/or, it’ll be a question of both.

Examples where fuels will remain essential include big seasonal energy demand and supply variations, very heavy and/or intensive transport needs, and energy excess and deficit trades between different countries.

This is why many believe hydrogen, if cleanly produced, becomes essential to many long-term, low-carbon energy mixes; including ones where electrification plays an increasing (even dominant) role.

So how can we move hydrogen fuel about?

 

Energy dense… if squashed

It’s not uncommon to read that hydrogen is “the most energy dense of any fuel”. However this statement conveniently skips a couple of vital missing words!

Hydrogen is the most energy dense fuel by mass. That’s because of hydrogen is light. But, under normal ambient conditions, it’s also a gas – one with a frankly terrible energy density by volume. This obviously matters if we want to move a lot of it about in any practical container.

As with other gases, an obvious way to increase the energy density of hydrogen is to compress it.

Much hydrogen today is transported overland by truck, on what are known as ‘tube trailers’. These are so-called because they consist of a number of cylinders of compressed hydrogen gas, with the gas typically compressed to pressures of around 200 bar or higher (where 1 bar is the approximate air pressure at sea level). The allowed pressures and total quantities of hydrogen which can be transported on a single trailer are determined by local safety, size and weight regulations.

While steel cylinders have been standard in the past, new composite materials allow much higher pressures (up to 500 bar) within lower weight containers, thus increasing the amount of hydrogen that can be moved around by an individual truck. In the US, for example, this will mean the hydrogen capacity of tube trailers rising from below 300 kg to as high as 600-700 kg going forwards. Trailers with capacities as high as 900 kg are already becoming available in markets such as the UK.

The other method of transporting hydrogen as a gas is by pipeline. Pipelines are expensive to build and can be difficult to develop due to rights-of-way issues. But over longer distances these initial costs and challenges become offset by much lower operating costs and longer asset lifetimes, when compared to trucks.

Around 5,000 km of hydrogen pipelines already exist today. Most are in the US (~2,600 km) with Belgium (~600 km) and Germany (~400 km) being other notable locations. By comparison, there are around 3,000,000 km of natural gas pipeline worldwide.

These hydrogen pipelines exist for industrial purposes, distributing hydrogen to chemical facilities and refineries. Pressures are much lower than for transport by truck (typically a few tens of bar).

Of course compression requires energy. Typically this is a few percent of the energy content of the hydrogen being transported: the exact figure depends on how the pressure at which hydrogen is produced compares to that required for transportation. Traditional mechanical compression must contend with maintenance and downtime, which can be significant. That said, new electrochemical separation and compression technologies claim to remove moving parts from the process, reducing maintenance, as well as decreasing the energy losses involved.

 

Brewing the perfect blend?

There is a great deal of work, and many pilot projects, to understand the extent to which hydrogen can be blended into existing natural gas pipelines.

There are clear reasons why this is a useful thing to do, if seeking to develop hydrogen utilisation more widely and more quickly.

From the hydrogen perspective, it means being able to distribute hydrogen over long distances, at low operational cost, without the pesky up-front cost and complexity of building new, dedicated pipelines. Over time, blending could give way to 100% hydrogen through these pipelines, if and when we phase out all fossil fuel usage and perform suitable upgrades.

Even in the near-term, the International Energy Agency estimate that a blend of just 3% hydrogen in natural gas demand globally would require close to 12 million tonnes of hydrogen each year. For that to come from electrolysis would require around 100 GW of installed electrolyser capacity, operating at a 50% load factor. That’s an approximately thousand-fold increase on today.

So even minimal blending allows plenty of scope for scaling up hydrogen use – a critical requirement to drive production costs down.

For natural gas pipeline owners and operators, blending provides a future for assets which might otherwise risk becoming underutilised (or stranded altogether) as fossil fuel usage declines. In many cases, these are assets long-since paid for, often by taxpayers. So policymakers too can be keen to keep them operating.

Blending isn’t as simple as it sounds though!

As well as being low on volumetric energy density, hydrogen is also annoyingly small. That means it is prone to escape unless both pipeline materials and seals are suitable. Even if it doesn’t escape altogether, it can absorb into metals and cause their load-bearing and ductile properties to worsen: a set of asset-lifetime and safety-reducing processes known as ‘embrittlement’.

There is still disagreement and debate regarding how different levels of hydrogen blending, pressures and purities will impact existing natural gas networks. Newer polyethylene distribution pipelines can handle up to 100% hydrogen, but the cost requirements in upgrading older sections will likely determine whether and how much blending is economically feasible.

Another limit on blending is the end-usage of the gas by users on the network.

Hydrogen is not a straight swap for natural gas in terms of its performance. The volumetric energy density of hydrogen is around a third of that of natural gas, so a blend reduces the energy content of the delivered gas: end users would need more gas to meet a given energy need. It also burns at a different rate, which affects the performance and safety design of end-use devices.

This means blending is limited by the ‘least-adaptable’ customers on the gas network.

Although many domestic gas heating and cooking appliances in Europe are certified for up to 23% hydrogen, bigger constraints arise from industrial sectors. For power generation in particular, control systems and seals of existing gas turbines may tolerate less than 5% blended hydrogen (and standards stipulate gas streams with less than 1%). Many installed gas engines prefer no more than 2% hydrogen.

Across Europe, policies vary. Permitted levels of hydrogen in the gas supply vary from 0.1% in the UK to up to 12% in parts of the Netherlands. Pilots such as HyDeploy in the UK, testing 20% hydrogen blending, require exemptions to be granted by relevant authorities. In the UK this means the Health & Safety Executive, who did so only after the project gathered extensive evidence to demonstrate the hydrogen blend would be ‘as safe as natural gas’.

While minor modifications might enable higher blending levels in future and new end-use equipment can be designed specifically for higher hydrogen blends, such adjustments take time (and money) to feed through.

Even with 100% hydrogen-capable pipeline networks, there are still important questions to be considered around the gas that goes into them and the issue of ‘lowest common denominator’ end-usage. In particular, how pure should that ‘100%’ hydrogen actually be?

Fuel cells require extremely high levels of purity; more-so than that required by combustion appliances. They are also fouled by current odourising agents applied to natural gas (required so that we can smell when there’s a leak).

So a network designed to feed fuel cell users requires different tolerance considerations than one that’s okay for feeding combustion devices (such as boilers or cookers).

 

Energy dense… if cold, very cold

The other common way to increase the energy density of hydrogen is to liquefy it.

The challenge is that hydrogen has a chilly boiling point of just −253°C (−423°F). Liquefaction is therefore expensive and energy-consuming. Using current technology, the process can consume more than 30% of the energy content of the hydrogen.

Once liquefied, hydrogen can be stored in large insulated tanks or transported in super-insulated, cryogenic tanker trucks.

Even then, some of the stored hydrogen will inevitably be lost through evaporation, or “boil off”, especially when using small tanks with large surface-to-volume ratios (hence stationary storage tanks tend to be spherical).

Given these challenges, you’d be forgiven for thinking that liquified hydrogen transport doesn’t happen in practice. You’d be mistaken though: cryogenic tanker trucks do carry loads of up to 4,000 kg of liquefied hydrogen, used today for long journeys (up to a few thousand km).

There are also companies betting (and investing) on the fact that liquification may play a role in international distribution of the fuel. Kawasaki Heavy Industries, for example, debuted what they described as “the world’s first liquefied hydrogen carrier” at a shipyard in Japan in December 2019. Due for completion late this year, it will be a technology demonstrator, shipping the fuel from Australia to Japan. It will have storage capacity of about 1,250 m3. By way of comparison though, that is less than 1% of the size of typical liquefied natural gas (LNG) carriers.

 

Distributing hydrogen within, or as, something else

Another area of focus for bulk hydrogen distribution is to move it not in its pure form, but chemically or physically locked away inside something else.

An example is ammonia, NH3, for which a supply chain is already well established. Suitable ships, pipelines and trucks all exist today, to move this important commodity about.

Ammonia liquefies at -33°C. That’s a much less difficult temperature to achieve than for hydrogen (and a higher temperature than LNG too). There is still a considerable energy penalty to the process though, ranging between 7% and 18% of the energy contained in the hydrogen.

There are similar energy losses if the ammonia needs to be reconverted back to high-purity hydrogen at its destination. So a more attractive option in many cases will be not to do so, but to use the ammonia itself as the end-use product (for example in fertilizer).

In this respect, decarbonising ammonia production already represents an opportunity to scale clean hydrogen without waiting for new supply chain infrastructure. Further ahead, there are already studies and trials investigating other ideas: for example the use of ammonia as a maritime fuel (including utilising a small portion of the ammonia being carried by a tanker to propel that same tanker).

Beyond ammonia, LOHCs (liquid organic hydrogen carriers) are a group of chemicals which can act as carrier molecules which can be “loaded” with hydrogen for transport, with the hydrogen extracted at its destination. There are a wide variety of such molecules under development, many with long names such as ‘methylcyclohexane’ but some more familiar; including methanol or formic acid.

The advantage of LOHCs is that they have similar properties to crude oil and oil products – in particular they can be transported as liquids without cooling. So, like ammonia, they can use existing shipping, pipeline and trucking solutions.

However, as with ammonia, there are costs and inefficiencies associated with the conversion and reconversion processes: in some cases an energy equivalent of 35% to 40% of the hydrogen itself. In addition, the carrier molecules are not used up when hydrogen is extracted at the end of the process. They need to be shipped back to their place of origin if they are to be re-used.

Compared to ammonia, using LOHCs for hydrogen distribution and transport remains much more at a research & development stage.

Finally, other potential future hydrogen carriers at R&D stage include solids such as metal hydrides, carbon and other nanostructures. (I say ‘largely’: US company Power Plug has commercialised a nickel-aluminium alloy hydrogen storage material called Hy-Stor 208, used as the fuel tank in some of their hydrogen-powered forklifts).

 

Developing the hydrogen distribution supply chain

We’ve seen that there are a variety of ways to move hydrogen about, including an established supply chain that feeds its existing industrial and chemical uses.

Many solutions mimic the way we move other gases about, but with some stiffer challenges around temperature, leakage, embrittlement and so on. Others are emerging. Some involve sharing infrastructure. All remain commercially uncertain in terms of future scale.

Where hydrogen must be moved, the distances involved and the scales of trade will determine the optimal mix of solutions. Where existing infrastructure can be utilised, blending hydrogen with natural gas for example, that could save up-front cost and buy time before more extensive or incremental investment is required.

So choices and outcomes will depend on local and regional factors: existing infrastructure, locations of hydrogen production and customers, gas purity requirements, new infrastructure development barriers (such as rights-of-way) and more.

Nevertheless, any method of moving hydrogen about comes with cost and efficiency (energy loss) penalties. The ideal option is to produce and use hydrogen at the same location: if we can avoid distributing it at all, hydrogen business cases should be easier to create.

Indeed it will likely be distribution rather than production or utilisation challenges that ultimately determine how the future of hydrogen plays out: will it become a small-scale, distributed energy solution or the basis of a large-scale, bulk energy ‘economy’?

If the latter is to happen, big investments are going to be unavoidable.

 

NB. This is one of a series of articles written for Green Power Global, organisers of the 2020 World Hydrogen Congress in Paris.

** Good news: as I’ll be speaking there, I’m able to offer my readers a discount on the event: just use the promo code JM20% when you book. **

 

References & further reading:

  1. A good overview of hydrogen transport by compression and liquification and by truck and pipeline: https://www.thechemicalengineer.com/features/hydrogen-transport/ (May 2019)
  2. The US Department of Energy pages on hydrogen delivery: https://www.energy.gov/eere/fuelcells/hydrogen-delivery
  3. An example of electrochemical compression technology, in this case a claimed ‘world first’ from Skyre: https://www.prnewswire.com/news-releases/skyre-announces-the-worlds-first-commercially-available-high-pressure-electrochemical-hydrogen-separation-and-compression-system-300834562.html (April 2019):
  4. Another good general article on hydrogen storage options, which includes the example of Power Plug’s solid state hydrogen ‘fuel tank’ on its forklifts: https://www.chemistryworld.com/features/hydrogen-storage-gets-real/3010794.article#/ (Aug 2019)
  5. A comprehensive report on hydrogen by the International Energy Agency, including sections on blending and transport and plenty of data (current and projected) on efficiencies, cost comparisons and so on: https://www.iea.org/reports/the-future-of-hydrogen (July 2019)
  6. The HyDeploy natural gas/hydrogen blending trial in the UK: http://www.hydeploy.co.uk/
  7. The ‘world’s first’ liquified hydrogen tanker ship announced: https://www.bloomberg.com/news/articles/2019-12-12/world-s-first-liquid-hydrogen-ship-debuts-in-green-economy-boost (Dec 2019)
  8. Support for ammonia as a maritime fuel: https://www.ammoniaenergy.org/articles/sailing-on-solar-edf-report-identifies-ammonia-as-one-of-the-most-promising-maritime-fuels/ (June 2019)
  9. Another ‘world first’, this time testing 100% hydrogen in natural gas networks: https://www.northerngasnetworks.co.uk/2019/07/04/worlds-first-100-hydrogen-testing-facility-unveiled/ (July 2019)

 

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