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.
Hynet has funding for studies
Within the UK, one cluster revolving around hydrogen is the HyNet project in Ellesmere Port, northwest England. Distribution network operator Cadent and local industry are looking at industrial-scale hydrogen production coupled with CO2 injection in the Liverpool Bay gas fields, although Cadent says this project is still at a very early stage. It is making progress with partners at a technical research centre at Keele University, in a closed network separate from the national network and has achieved a mix of 20% hydrogen, and 80% methane.
HyNet received government funding totalling £12.7mn for front-end engineering design studies in February but the concept was originated and promoted by Cadent and Progressive Energy in 2017 and since then more companies have wanted to join in.
Over half the money (£7.5mn) is for a hydrogen plant, at Essar Oil UK’s Stanlow refinery to produce 3 TWh/yr of low carbon and low-cost hydrogen from mains gas; and capture over 95% of the carbon used in the process. In an operational year, the facility will capture 600,000 metric tons of CO2.
The hydrogen would then be shipped through a newly installed hydrogen pipeline to energy-hungry industries and also into 2mn homes.
The remainder is to finance live trials of hydrogen fuelling at Unilever’s Port Sunlight manufacturing site, and at Pilkington’s Greengate Works glass-making plant in St Helens which will be a world first.
Diving Into Decarb: NGW Interviews British Ceramics Group
There are four principle means of decarbonising Britain’s ceramics sector, the trade body British Ceramics Confederation (BCC) told NGW: hydrogen; electric kilns; syngas; and carbon capture and storage post-combustion. At the moment, gas provides 85% of its members’ energy needs.
Large scale electric kilns would be physically very different from gas kilns: most bricks produced in the UK are gas-fired in tunnel kilns 100-200 metres long and up to 3 metres high, in stacks; electric firing would require a complete redesign of the kiln as there is less heat transfer by convection. The bricks would need to traverse the kiln in a single layer. Running costs are the biggest barrier to electrification. UK industrial electricity prices are very high compared with the rest of Europe, a spokesman said.
Syngas and biogas lack availability for the ceramics sector as they have too many competing uses: as fuel for heating; power generation; combined heat and power plants; green chemical manufacturing; and transport fuel.
Given the need also for land to grow food, there is unlikely to be enough sustainable and affordable biomass feedstock available for industry. The BCC did visit an experimental site that made syngas through a chemical process but it would be too involved to implement at its members’ sites.
Syngas would need cofiring with gas to keep the temperature high enough, using natural gas at peak firing zones and syngas in other zones.
CCS is also not practical as the factories are numerous, small and to be found where the clay is, which is often not near industrial clusters.
There are 54 ceramics sites big enough to fall under the EU emissions trading scheme but their emissions are relatively small, totalling 1mn metric tons CO2/yr. It makes no sense aggregating their CO2 emissions for delivery to a CCS plant operator.
That leaves hydrogen, which would be taken directly off the pipeline, either in pure form or mixed with methane, but there will need to be co-ordination across many different parties.
It is clear meeting the net-zero challenge will require extensive financial support from government for innovation if it is not to lose its international competitiveness. Quite a lot of the hydrogen that industry uses will probably come over distribution networks, the spokesman said. The advantage of hydrogen is that it can be introduced in small to large quantities into the burners and it is unlikely to radically change the process or kiln design.
Disadvantages relative to methane are that it produces a lot more moisture on combustion, although the impact on the fired goods or the structure and linings of the kilns has not been fully assessed. It also burns with a hotter flame than methane, creating harmful nitrous oxide (NOx) emissions. And hydrogen can also make the steel pipes that carry it brittle.
Japanese car manufacturer Toyota has however developed the world’s first, general purpose hydrogen burner for industrial use that slows down combustion and reduces the level of NOx emissions. This might have broader applications, he said.
The risk is that in pursuing these different routes to net-zero carbon, Europe simply offshores its industry to jurisdictions that are not pursuing net-zero carbon goals. Bricks and clay rooftiles are coming now from China and the Indian subcontinent, partly owing to the higher costs of production in the UK, and carbon prices.
A carbon tax on imports at the EU border may sound attractive but there are hidden drawbacks such as complexity, the spokesman warned. Wall and floor tiles resist a one-size-fits-all approach, for example, as different formulations are fired at different temperatures and durations depending on whether they are for indoor or outside use. This gives very different carbon intensities.