Hydrogen is unlikely to have a place in home heating. But there are other needs for it – and the existing transmission system offers a way to match supply and demand.

For now, low-carbon hydrogen plans are largely co-located with consumption sites. This provides a way to flesh out the early plans and prove out the technology.

In future, for the market to grow, transportation of hydrogen will be essential. This will allow producers and consumers to pick and choose according to needs, in addition to being the first steps towards financialisation, such as hedging.

There is not yet a means to transport hydrogen over long distances. The UK does, though, have a well-resourced transmission pipeline network for natural gas.

Recently, National Gas carried out tests at its FutureGrid facility. These show its transmission assets are largely ready to transport hydrogen safely and effectively.

The UK has big plans for low-carbon hydrogen. It aims to reach 10 GW by 2030.

The government has backed this through its Hydrogen Allocation Rounds (HARs). The first, HAR1, covers 125 MW of capacity. HAR2 reached its deadline in April and aims to secure another 875 MW. HAR3 and HAR4 should add another 1.5 GW of capacity.

Making the transportation easier will take UK one step closer to its ultimate hydrogen aims.

Rather than building new, bespoke pipelines for hydrogen, repurposing the country’s existing National Transmission System (NTS) infrastructure is a more attractive option. A study has found repurposing existing gas pipelines would be 50-80% lower cost than building new dedicated links.

Fast integration

To get there, National Gas has sketched out plans for blending hydrogen into the natural gas flow. The end goal would see the system carrying only hydrogen.

Blending would integrate hydrogen quickly into the energy system. It would create incentives to scale up production without upfront investment costs in new infrastructure, while supporting gradual market adoption of the fuel.

It also maximises efficiency. For example, a company generating renewable energy with an electrolyser to produce green hydrogen can feed extra hydrogen it cannot deliver to local industry and cannot store into the gas system. Otherwise, it would have to cut output, causing problems in surplus power and underused electrolysers.

“Hydrogen blending is extremely important for the economics of hydrogen production,” Jake Tudge, National Gas’ director for corporate affairs, told E-FWD.

“Blending gets the production going, ensures the managed growth of a hydrogen economy by balancing supply and demand, and supports efficient infrastructure build-out so you have the most cost efficient pathway to net zero.”

Test results

Over the past year, transmission system operator National Gas has tested hydrogen blending at its assets. This has ranged from a 2% blend of hydrogen with natural gas to up to 100%, at its FutureGrid facility in Cumbria. Last month, the operator’s report concluded that there were no major obstacles to repurposing the transmission network for hydrogen.

The report “presents a promising picture on hydrogen blending, which can help the government meet its ambition of making the country a clean energy superpower as we progress to 100% green hydrogen, and all while using our existing infrastructure,” National Gas CEO Jon Butterworth commented.

Sliding scale

The study covered asset leak, rupture, fatigue, flange, material permeation, pipe coating and cathodic protection testing. It found that no modifications were needed for blends up to 5%.

For a 20% blend, the ultrasonic meter that measures the gas flow rate needed a new transducer, and the carrier gas in the gas analyser was switched from hydrogen to argon and recalibrated. A new orifice plate also had to be fitted to the meter for 100% hydrogen.

National Gas tested 100% natural gas to establish a baseline result. It found there was little to no change in leak rates when compared with hydrogen blends. Even at 100% hydrogen, there was only a slight increase in leakage. It was able to predict this – and mitigate it.

“If a pipeline is gas-tight with natural gas, it remains gas-tight with hydrogen,” Tudge told E-FWD.

Regulators and slam-shut valves performed “exceptionally well,” functioning without needing recalibration, and temperature results were close to predictions.

“We did notice a difference in noise between planned venting operations, which will need more investigation to understand how vent size and gas flow affect noise,” Tudge said.

National Gas worked on the project with DNV, HSE Science Division, Northern Gas Networks, Fluxys, Durham University and the University of Edinburgh.

Core network

The results show that around 60% of National Gas’ assets are ready for the hydrogen blends tested, Tudge said.

The next phase, FutureGrid, will involve testing hydrogen deblending and is due next year. To extract purified hydrogen for use in the transport sector, the mix must be deblended. In 2025, compressor system tests will follow.

“So by 2026, we expect 100% of our representative assets will have been tested, and we will be on the way to being ready to deliver the core hydrogen network,” Tudge said.

Late last year, the government decided to support blends of up to 20% hydrogen in the UK gas distribution network. National Gas is seeking a similar decision to be taken for transmission. The operator is preparing to accept up to 2% blended hydrogen by the end of the year, and up to 20% by 2027.

An Austrian study from earlier this year found deblending costs depended on a number of factors, including separation technology, throughput and blend rates. It reported costs of 0.75-1 euros (£0.64-0.85) per kg, to recover at least 98% of hydrogen from a 20% blend.

National to international

These results will feed into the assessment for Project Union, which aims to establish a 2,000-km national hydrogen network. This is around a quarter of the size of the current natural gas transmission system.

National Gas recruited Jacobs and ERM to carry out a pre-front-end engineering design (pre-FEED) study on the initiative last October.

Still, the work at FutureGrid only covers one aspect of the planning for Project Union. Research on economic feasibility, safety, consumer acceptance and financing is also underway.

Project Union will link up with the planned continental-wide European Hydrogen Backbone (EHB) system. This would enable hydrogen trade between the UK and the rest of Europe. National Gas wants Project Union to be operational when the neighboring EHB sections are live. Tudge said this would provide “a fantastic opportunity” for UK hydrogen exports.

Parts of the puzzle

Scaling up hydrogen storage capacity to align with the development of transport networks is a particular challenge, Hayleigh Barnett, Hydrogen Technology Manager at the Aberdeen-based Net Zero Technology Centre, told E-FWD.

Hydrogen storage poses unique challenges due to its low energy density by volume compared with natural gas, and the need for high pressures or very low temperatures. The UK has relatively little gas storage capacity compared to other major gas markets in Europe. Therefore, operators may need to develop more hydrogen storage capacity from scratch, instead of repurposing facilities.

In a July report, the National Engineering Policy Centre of the Royal Academy of Engineering warned that the government needed to act fast to facilitate the development of hydrogen storage projects in geological salt caverns. These have relatively long lead times of around eight years. Ahead of 2030, it could also consider converting the Rough gas storage site, in the Humber region, to hydrogen.

“Storage must be developed hand in hand with the transport network, both to provide a buffer, operational storage and to cover those interseasonal peaks and troughs in energy demand,” Barnett said.

Many hydrogen supply projects have been announced and long lead times on key equipment are also an issue here.

“Meanwhile, on the demand side, strong market indicators would encourage potential users to switch, accelerating the build-out of the hydrogen economy,” she said.

“We also need to think about not just our own domestic demand but the global opportunity to export as well,” she said.

Related Content

The UK’s renewable energy costs paradox

Chris Stark talks ‘surgery’ on renewable energy queue to hit 2030 targets

Right pieces, wrong picture for Scotland’s energy puzzle