Domestic central heating boiler control panel

Net zero and domestic hydrogen: a forthcoming marriage?

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A series of obstacles will need to be overcome if hydrogen is to make a genuine contribution to reducing electricity demand.

Since pure hydrogen isn’t present in the Earth’s atmosphere, we have to manufacture it. Irrespective of the method used, the energy released by the resulting hydrogen is always significantly less than the energy required to make it. Unlike natural gas, hydrogen is not an energy source, but a rather poor energy carrier.

The two techniques most commonly used to manufacture hydrogen are water electrolysis and steam-reforming of natural gas. The former needs 50-55kWh of electricity to produce 1kg of hydrogen with a specific energy of 40kWh, making it 70-80 per cent efficient; the latter is 65-75 per cent efficient.

An October 2018 report by the Department for Business, Energy & Industrial Strategy estimates that greenhouse gas emissions from electrolyser construction and operation are equivalent to 122g carbon dioxide per kWh of hydrogen produced, 96 per cent of which is accounted for by electrolyser manufacture. For steam reforming, without carbon capture and storage, the figure is between 222g and 325g CO2 equivalent/kWh.

There are few examples using carbon capture and storage on a significant scale, and none in the UK, but a couple of those that do exist claim 37g and 45g CO2/kWh hydrogen. Electrolysers’ short lifetime and periods of low load if supplied by wind turbines also increase their associated greenhouse gas emissions.

The Committee for Climate Change and the UK government are starting to focus closely on expanding the use of hydrogen as part of the path to achieving ‘net zero’ emissions. The UK’s annual energy demand for electricity is approximately 350TWh, while transport requires 660TWh and heating 730TWh, so it is obvious that the present electricity grid cannot today cope with transport and/or heat.

Is there an economically and technically achievable role for hydrogen to ease our future demand for electricity as we aspire to net zero?

The government’s 'Hydrogen Task Force' was launched last March, following earlier investigative studies into the decarbonisation of heat. It recognises that the hydrogen route is not problem-free and will require huge investment, with an initial report asserting that “meeting net zero at all is not possible without hydrogen [and that] investment must be an immediate priority.”

National Grid has confirmed that it is “still investigating the conversion possibilities of our infrastructure for the transmission of hydrogen/natural gas blends and 100 per cent hydrogen.” This assessment is in its infancy and it is constructing a testing facility in Cumbria, using decommissioned assets, where testing is due to start in 2022. In late March 2021, National Grid announced that it intends to sell a majority stake in its UK gas-transmission business later in the year; whether this impacts its proposed testing programme remains to be seen.

Switching our natural gas grid to 100 per cent hydrogen - or even to high concentrations of hydrogen - poses significant challenges. The potential issue of hydrogen embrittlement of existing gas mains, distribution piping and welds is a known concern. Cyclical variation in pressure is thought to be a contributing factor and it may transpire that introduction of hydrogen into the gas grid presents a major engineering and financial challenge. Depending on the type and quality of steel, combined with the amount of atomic hydrogen penetrating pipe surfaces, progressive embrittlement could accentuate the spread of existing cracks and potentially, according to some experts, reduce the service life of affected piping by 50 per cent or more.

The UK is aiming to complete the change from widespread smaller-bore iron piping to polyethylene, which is regarded as hydrogen-compatible, for medium and low-pressure city distribution over the next five years. A recent major study, H21, into converting Leeds city to 100 per cent hydrogen considers this replacement to be relatively affordable, as by good fortune the change-out is already well advanced.

The study scope was not required to address the large-bore UK grid. Converting existing large-bore grid natural gas pipelines to carry 100 per cent hydrogen introduces another factor. At standard temperature and pressure, methane density is around eight times that of hydrogen with three times its calorific heating value, so hydrogen needs a flow velocity three times higher than natural gas to deliver the same amount of energy.

These properties partly offset each other, though, as hydrogen is much lighter. Existing plant and piping pressure ratings, control equipment, system hydraulics and compression plant will need to be investigated and the investment level determined by whether hydrogen transport conditions need grid designs to change significantly. We may be fortunate and achieve this at close to existing pressures, but the studies are presently incomplete.

Blending with natural gas is seen as a potential way of heating homes and providing hydrogen to market by installing downstream plant to extract hydrogen from the combined gas mixture. Having this underway is considered possible by the end of 2022. There are at least three fairly well established engineering methods that might be applied, but all would be expensive. In addition, the UK will need to amend the existing Gas Safety Management Regulations to permit it.

The UK’s position with regard to the European Commission’s new hydrogen strategy, in the wake of Brexit, and the part it might play in the European Clean Hydrogen Alliance, are yet to become clear. Germany has already started serious studies in this area and the prospect of divergence of standards may become an issue; there is a shortage of Euronorms that cover hydrogen combustion and the UK will likely seek piping links to Europe. Creation of the UK Task Force at least shows that we are starting to seriously address these and other issues.

The EU has been reported as expecting to have 6GW of electrolysers in operation by 2024 and 500GW by 2050 - a huge ambition when less than 0.1GW is operational today. Associated plans to store large volumes of hydrogen in salt caverns present a further area of engineering challenge and related cost.

My previous article - ‘Are hydrogen-fuelled vehicles a waste of our time and energy?’ (published in February 2021) - looked at how some new windfarm developments are incorporating the production of hydrogen by electrolysis when their power output capability exceeds grid demand.

This approach, seen as a means to ultimately provide energy storage via the UK gas grid, offsetting wind variability, is no silver bullet. The infrastructure costs will be enormous given the amount of hydrogen production required to approach anywhere near the domestic heating demand presently met by natural gas and National Grid estimates that 75GW of wind turbines would be required by 2050 to render net zero by this route a viable prospect. That’s three times the existing entire UK installed wind capacity, much of which will come to the end of its working life in the next 30 years and need to be replaced. Commercial viability will, of course, depend on being able to secure higher revenue than from constraint payments.

National Grid’s Future Energy Scenarios 2020 Report anticipates the heating of more than the considerable majority of homes with hydrogen by 2050 under its ‘System Transformation’ scenario as one projected pathway to net zero, but this, combined with projections of its use in domestic cooking, present big challenges.

Hydrogen is an asphyxiant which, at 1/14 the weight of air, disperses very quickly and rises on escape, mixing with air and becoming dangerous due to its wide flammability range (from around 4 per cent to 75 per cent); a very low ignition energy; high combustion energy, and a near-invisible flame that can reach 2,000°C.

Burning invisibly, there are known challenges in adding an odour that can keep up with the inherent very rapid hydrogen dispersion rates, enabling us to detect the smell before the hydrogen concentration becomes flammable; cooking risks will need serious assessment and related appliance development worldwide is presently fairly minimal. In addition, 60 per cent more water vapour will be formed for the same energy compared with natural gas.

When hydrogen is burnt in pure oxygen the chemistry is simple and we get water and heat. When burnt in air, which is 78 per cent nitrogen - as in an existing flame-combustion domestic boiler - the higher hydrogen flame speed means that the oxygen combines with nitrogen in the air to form up to six times the NOx emissions compared to burning natural gas in air. This presents a seriously increased health risk over natural gas.

NOx emissions can be reduced by deploying catalytic combustion designs which require the use of precious metals such as platinum. Leading boiler manufacturers believe they can develop the technology for the domestic market and some have prototypes under test and are pressing the government to commit to 100 per cent hydrogen-ready boilers by 2025, although much of the present literature is light on the engineering of NOx minimisation. Indicative costings were not available to the H21 Leeds Study. However, world production of platinum last year was around 130 tonnes compared to around 1,800 tonnes of gold, representing a very limited supply chain if platinum is to be widely employed.

The siting of domestic boilers within the home will be another concern, as some will presently be inside bedrooms or integral garages. No housing in the UK has electrical equipment certified for use in hydrogen atmospheres, so many existing boiler locations will have to change.

The technology is still in the development stage and has some way to go. All domestic boilers sold since 1996 must be able to sustain 23 per cent hydrogen; Keele University has been running a substantial trial of a 20/80 hydrogen/natural gas mixture. 650 homes near Gateshead start trials this Spring also using a 20/80 blend, while a four-year test in Levenmouth, Fife, to run 300 homes on 100 per cent hydrogen is currently going through the stages of planning approval.

It is unsurprising that National Grid this year has considered four future energy scenarios in addressing net zero by 2050, following government policy shift from 80 per cent decarbonisation. ‘Steady Progression’, as the name implies, largely sets aside new initiatives and is broadly a worst-case plod along. In two of the remaining three scenarios, ‘Consumer Transformation’ and ‘Leading the Way’, home heating and transport is modelled predominantly by electricity and not hydrogen boilers, the latter with predominately hybrid heat pumps.

‘System Transformation’ is the only scenario that includes high levels of domestic hydrogen boiler adoption, with steam reforming of natural gas incorporating carbon capture having to greatly surpass windfarms to achieve the estimated demand. This continues very high level usage of the planet’s fossil resources and a high UK reliance on gas imports.

However, it should not be overlooked that since April 2018, Clean Energy Growth legislation has dictated that new domestic gas boilers must be a minimum of 92 per cent efficient. Using gas turbine generation instead to provide electricity to heat our homes reduces efficient use of the gas to 65 per cent, thereby creating a huge increase in related greenhouse gas emissions for the equivalent amount of electrical heat energy delivered.

If we cannot achieve a switch to either a blended 20/80 mix of hydrogen/natural gas for domestic heating or something closer to ‘System Transformation’, then National Grid and the major gas companies could be left with billions of pounds in stranded assets.

It is presently unclear, given the challenges of hydrogen, whether we can overcome the technical obstacles and at prices the public can afford without major government subsidies. Some prominent academics and engineers consider that the main prospects for hydrogen by 2050 are likely to be hydrogen-carrying ammonia for ship propulsion and in industrial high-temperature processes such as steel making. The results of the net zero study work will define our future.

David B Watson is a chartered electrical engineer who before retirement was manager of projects at Foster Wheeler Energy, based in Glasgow and responsible for project-execution management at the company’s Scottish operation.

This article was updated on 7 May 2021 to include National Grid's announcement in March of its intention to sell a majority stake in its UK gas-transmission business.

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