Cracking on with hydrogen [NGW Magazine]

The need for a hydrogen strategy has surged up the priority list of many oil and gas organisations. It is now seen as the key to global decarbonisation efforts, according to a new survey of over 1,000 senior oil and gas professionals, Heading for Hydrogen, published by Norwegian technical consultants DNV GL.

And indeed many industry actors agree that the advantages hydrogen has over its competitors are compelling, not least from the point of view of energy-intensive users. It can flow through existing networks; and it may be relatively cheaply stored. It may also be blended with other low or zero carbon gases in the grid, as well as with fossil gas.

The chief negatives are the by-products of combustion and the need to change burner tips – it burns with a hotter flame and producers more moisture – and possibly steel installations and pipelines. All these risks are being studied in laboratories.

This adaptability is the reason for the tentative support from end-users now reliant on fossil gas, as NGW’s interview with the British Ceramics Confederation (BCC) below makes clear.

Nevertheless, the switch to hydrogen is still a problem to overcome in a world where European manufacturers are already beset by genuine threats to their competitiveness from regions that are less troubled by decarbonisation. And the idea of a carbon tax is not necessarily easy to administer, again as the BCC points out.

Switching to hydrogen may also poke holes in the energy efficiency aspirations of policy-makers: much of the hydrogen will be produced by electrolysis, using cheap or free surplus renewable electricity. That implies excessive capacity; while renewable energy generators will depend on inefficient gas engines to step up on a second’s notice to fill the gaps in wind and solar. Using high-efficiency conventional combined-cycle plant would save on that and make gas procurement and storage needs more predictable.

However, despite the urgency of moving to hydrogen, DNV GL’s report says that it will require a concerted effort to make expectation a reality.

A little over half the sample surveyed in each of four regions – Asia Pacific, Middle East, North Africa and Europe – says that hydrogen will be a significant part of the energy mix within 10 years. North and Latin America are a little behind, at 40% and 37% of the sample agreeing with that proposition. And the proportion intending to invest in the hydrogen economy doubled from 20% to 42% in the year leading up to the coronavirus-induced oil price crash. That was the biggest year-on-year increase for all the clean energy options, although offshore wind already was the first choice at 40% last year and is now at 63%.

Further, the report also finds substantial obstacles in the way of hydrogen. “It is in the spotlight as the energy transition moves at pace – and rightly so. But to realise its potential, both governments and industry will need to make bold decisions," says the head of DNV GL's oil and gas division, Liv Hovem. "The challenge now is not in the ambition, but in changing the timeline: from hydrogen on the horizon, to hydrogen in our homes, businesses, and transport systems."

The success of a hydrogen energy economy is closely aligned with the future of natural gas, renewable energy, and carbon capture and storage (CCS) technology, the report says. Analysis shows that while the goal is green hydrogen, using renewable energy to electrolyse water, for example, the sector can only realistically scale up to large volumes and infrastructure with carbon-free hydrogen produced from fossil fuels combined with CCS technology (blue hydrogen) while most is ‘grey’ – ie no CCS is involved..

"To progress to the stage where societies and industry can enjoy the benefits of hydrogen at scale, all stakeholders will need immediate focus on proving safety, enabling infrastructure, scaling carbon capture and storage technology and incentivising value chains through policy," Hovem says.

DNV GL is involved in projects spanning all four of these enabling factors, including the Hy4Heat programme in the UK, which aims to establish whether it is technically possible, safe, and convenient to replace methane with hydrogen in residential and commercial areas.

In an interview with NGW, Liv Hovem said that the main finding of the survey was the extent to which the oil and gas industry saw hydrogen as a means to achieve the net-zero carbon goal. In recent months many of the majors have set targets: global aspirations have become nationally declared commitments and now companies are responding to the challenge.

Switching to hydrogen, using methane as feedstock, will have a cost: so having an abundant supply of cheap natural gas as exists now is very convenient. It means the additional costs of decarbonising can be absorbed much more acceptably, she said.

Another author, Jorg Aarnes, said that DNV GL is working with distribution companies to prove the safety case of injecting hydrogen so that it may become a viable policy option for the domestic sector. It has built houses to test the use of gas mixed with hydrogen in domestic boilers, at its Testing and Research facility at Spadeadam. But unless there is major demand, there will be no commercial incentive for hydrogen production.

The government has an important role to play in CCS as the cost of carbon is too low: the break-even carbon price differs for different applications but for coal fired power, cement and steel it can be $100/metric ton or more to be sufficient to create a business case for blue hydrogen production, relative to grey hydrogen production. But it takes time and money to make a site CCS-ready.

For industry, steel production has possibly the highest potential for converting to hydrogen, Aarnes said. Only 5% of the steel mills however use a smelting process that is compatible with hydrogen as the reduction agent: the other 95% are blast furnaces that use carbon. But that is a less efficient process. Blue or green hydrogen can displace syngas or methane to decarbonise the steel process, he said.

Ceramics is another energy-intensive industrial sector that is promising for hydrogen: DNV GL is working with 25 industry partners on kilns that can run on pure methane, pure hydrogen, and any mix of the two.

As for storage, hydrogen has been stored in salt caverns for industrial processes for over 40 years, but only on a small scale. It has at least been demonstrated. Based on one case study involving DNV GL, salt caverns were the lowest cost means of storage, Aames said; conversion to ammonia with nitrogen and then separating again costs three times as much; and liquefying hydrogen for storage costs four times more than ammonia.

Footing the bill

UK industry is taking a very positive attitude to hydrogen – both end-users and network operators – as not to do so will come at a high price, said former major industrial gas buyer Eddie Proffitt, now technical director at the Major Energy Users Council.

Converting burner tips and networks to run on hydrogen instead will be very expensive, but it will also cost an average £30,000 to convert each of Britain’s 28mn homes from gas to heat pumps and so on, according to the Climate Change Committee. So either way decarbonising will be expensive and household heating has accounted for half the UK’s gas demand in winter.

The price control process for network operators that regulator Ofgem is working on will reward those networks that innovate. National Grid, Cadent and Northern Gas Networks are all working on different approaches to injecting hydrogen into the grid. The Health & Safety Executive is also involved: the highest proven safe percentage of hydrogen is 20%, based on town gas experience. But higher percentages may also be safe, he said, and tests into higher ratios are ongoing.

And there is a precedent for hydrogen: energy intensive industries that operate around the world generally use the cheapest energy available in each country they operate in: this might be orimulsion, in Brazil; but in South Africa at one point it has been hydrogen.