Out of the blue, I got an invitation to a meeting in Whitehall.
I was to join industrial developers and academic researchers at the Department of Energy and Climate Change (DECC) in a meeting of the “Green Hydrogen Standard Working Group”.
The date was 12th June 2015. The weather was sunny and hot and merited a fine Italian lemonade, fizzing with carbon dioxide. The venue was an air-conditioned grey bunker, but it wasn’t an unfriendly dungeon, particularly as I already knew about half the people in the room.
The subject of the get-together was Green Hydrogen, and the work of the group is to formulate a policy for a Green Hydrogen standard, navigating a number of issues, including the intersection with other policy, and drawing in a very wide range of chemical engineers in the private sector.
My reputation for not putting up with any piffle clearly preceded me, as somebody at the meeting said he expected I would be quite critical. I said that I would not be saying anything, but that I would be listening carefully. Having said I wouldn’t speak, I must admit I laughed at all the right places in the discussion, and wrote copious notes, and participated frequently in the way of non-verbal communication, so as usual, I was very present. At the end I was asked for my opinion about the group’s work and I was politely congratulational on progress.
So, good. I behaved myself. And I got invited back for the next meeting. But what was it all about ?
Most of what it is necessary to communicate is that at the current time, most hydrogen production is either accidental output from the chemical industry, or made from fossil fuels – the main two being coal and Natural Gas.
Hydrogen is used extensively in the petroleum refinery industry, but there are bold plans to bring hydrogen to transport mobility through a variety of applications, for example, hydrogen for fuel cell vehicles.
Clearly, the Green Hydrogen standard has to be such that it lowers the bar on carbon dioxide (CO2) emissions – and it could turn out that the consensus converges on any technologies that have a net CO2 emissions profile lower than steam methane reforming (SMR), or the steam reforming of methane (SRM), of Natural Gas.
[ It’s at this very moment that I need to point out the “acronym conflict” in the use of “SMR” – which is confusingly being also used for “Small Modular Reactors” of the nuclear fission kind. In the context of what I am writing here, though, it is used in the context of turning methane into syngas – a product high in hydrogen content. ]
Some numbers about Carbon Capture and Storage (CCS) used in the manufacture of hydrogen were presented in the meeting, including the impact this would have on CO2 emissions, and these were very intriguing.
I had some good and useful conversations with people before and after the meeting, and left thinking that this process is going to be very useful to engage with – a kind of dragnet pulling key players into low carbon gas production.
Here follow my notes from the meeting. They are, of course, not to be taken verbatim. I have permission to recount aspects of the discussion, in gist, as it was an industrial liaison group, not an internal DECC meeting. However, I should not say who said what, or which companies or organisations they are working with or for.
In the July 2015 version of the “Green Hydrogen Standard : Government Response to Call for Evidence” from DECC, Document Reference Number URN 15D/057, the February 2015 version downloadable from https://www.gov.uk/government/consultations/green-hydrogen-standard-call-for-evidence, it says, “Hydrogen, as a fuel, is not new – what is new are the innovative approaches British industry is taking to produce it in such a way as to support our decarbonisation effort.” Well, yes, but no. Whilst it’s true that more hydrogen is and will be coming to market, none of the technologies being deployed in the first instance for large production volumes of hydrogen could be said to be “innovative”.
The key processes, established over periods of decades or even several hundred years of engineering are : the steam methane reforming of Natural Gas (SRM or SMR), the catalytic reforming of light petroleum oils, the gasification of coal and biomass, a range of standard industrial chemical processes, and the electrolysis of water. One could quibble that the award for the oldest technology should go to the carbonisation of coal, however the splitting of water into hydrogen and oxygen gas by the use of an electric current hails from at least as far back as the year 1789 AD, even though electrolysis might seem quite novel as it remains fairly uncommon.
Whilst the electrolysis of water could be said to produce “green” hydrogen (if the electricity is sourced from renewable power such as from wind farms or solar parks), and the gasification of biomass could be made more-or-less carbon neutral (depending on the lifecycle analysis of the biomass resourcing), the thermal treatment of coal and hydrocarbons could never be painted as carbon-controlled – unless of course the carbon rejected from the processes is captured and stored (Carbon Capture and Storage – or CCS). Some industrial chemistry produces hydrogen in vast quantities that is currently being vented to the atmosphere through lack of a market, so clearly there could be a case made for calling capture of this wasted resource “green” – particularly if there were no extra carbon dioxide emissions from having done so. I would like to sub-categorise this as “waste hydrogen”.
In petroleum refinery there are several typical processing stages in modern plant that produce large quantities of hydrogen, and since the demand for hydrogen in refinery is increasing, and set to increase further owing to stronger environmental regulations and worsening quality in crude oil, hydrogen capture and reutilisation is already vital to this industry. In some cases, refineries may produce more hydrogen than they can use – for example if they have a gas processing plant on-site and make their own hydrogen from the steam methane reforming of Natural Gas (SMR or SRM), or from refinery off-gas – any light hydrocarbon gas by-products from any plant processing units. In this case, although the resources used to produce the hydrogen are definitely not “carbon-free”, it would make sense to make use of this hydrogen “over the fence” in other industries, such as transport mobility, and since it would be otherwise wasted, this too could be classed as “green”, or “waste hydrogen”.
And talking of petrochemicals, there is another potential source of “waste hydrogen”, from the post-consumer waste processing of plastics and other materials with a high hydrogen content. The exact thermal processing could vary, but gasification, perhaps via the use of plasma, might be the most efficient.
From this short summary, it is clear there are a range of ways that hydrogen can be produced, and the option that hydrogen from many sources could be blended, so a key part of DECC’s proposed standard is setting the bar on what differentiates “green hydrogen” from “brown hydrogen” (or in the case of hydrogen produced from coal, perhaps “black-as-night hydrogen”).
Another key factor is the purity of the hydrogen produced, as some chemical processes produce a range of carbon oxides and light hydrocarbons, such as methane, mixed in with the hydrogen. Biomass and waste treatment processes will also offer up contaminated hydrogen. Obviously, mixed gases as a whole could not be treated as “green hydrogen” unless the carbon profile of the whole gas were low enough to permit the hydrogen fraction to meet the standard.
The DECC Green Hydrogen Standard Working Group meeting of 12th June 2015 got off to a fine start when this very question was considered, in the context of answering whether the “Green Hydrogen” standard should be considered as a number calculated at the point of sale of the produced hydrogen (Point of Production or PoP), or a number calculated at the Point of Use (PoU). It was pointed out that what consumers do with hydrogen could make the calculations on a PoU basis unwieldy and inaccurate, and also impossible to monitor. The majority of the respondents to the Call for Evidence had alighted on exactly the same issue, so the final standard is likely to be based on PoP.
The meeting touched on the Call for Evidence where respondents argued that transport mobility could perhaps be a special case as the hydrogen required needs to be of a very high purity in its production, and then compressed for use, which has a carbon emissions implication through the additional use of energy to purify and pump it. Urban air quality is going to be very much improved by the use of hydrogen as motor vehicle fuel, so it was suggested in the meeting that some might argue that this would imply that hydrogen of any provenance and any related carbon dioxide emissions, and fuelling any engine technology, should qualify for the label “green”. However, it was felt that specious arguments should be put aside. The Standard should only have a single number in it, because of the requirements of any future legislation.
It was suggested that calculating a PoP figure for any hydrogen production pathway is going to be complicated enough in itself, as for example, some technologies are going to be producing “brown hydrogen” as well as “green hydrogen” from the same processing unit. For example, electrolysers (for producing electrolytic hydrogen through the process of electrolysis) would produce “brown hydrogen” if they are run on “brown power” and “green hydrogen” if they are run on renewable electricity.
The meeting considered the parallel with the low carbon biomethane standard – gas high in methane produced from low-methane mixed biogases, and how it is possible to come up with an average figure of carbon emissions for the final product which is reasonably representative, and earns producers a Green Gas Certificate.
The difficulties in accounting for carbon in industrial processing was raised. The Standard for “green hydrogen” is therefore likely to ask for some simple calculation of the “embedded carbon” in any hydrogen sold to market – or used in the same industrial plant or refinery. There are going to be some general categories – relating to the technology used, for example, the carbon dioxide emissions of steam methane reforming (SMR or SRM) of Natural Gas, which would have a much “greener” profile than the gasification of heavy oils and coals. The meeting considered whether there should be one bar for the standard, under which all hydrogen should shimmy or limbo in order to be considered “green”, or whether there should be a rainbow scale of shades from brown to green – which, “hors discourse”, would be worse than useless for the colour-blind. The meeting thought that regardless of whether there were to be bands of “greenness” or not, that the criteria should be simple enough to use.
The meeting also considered the issue of whether the Standard should be specified for the carbon dioxide emissions on the Lower Heating Value (LHV) basis or the Higher Heating Value (HHV) basis – as this is a continual source of confusion in all engineering with gas. Then there was the inevitable discussion about which units the Standard should use. It was pointed out that most engineers in energy use kWh – kilowatt hours. As does much of the computer software. It was also pointed out that the only definite measurement should be kg – kilogrammes. One of the meeting said that they only think in grammes per megajoule, but that felt like a spanner in the works, so the discussion moved swiftly on from there. Thankfully it didn’t descend into a discussion of whether carbon dioxide emissions should be measured by the carbon content or the carbon dioxide content, or the carbon dioxide equivalent content (for non-carbon dioxide greenhouse gas equivalence), which could have been a discussion that ranged and raged for centuries. But we haven’t got that much time.
It was agreed that the priority was accessibility – being able to say “this is green” about hydrogen – the actual number not being of prime importance to begin with. It was pointed out that the route to hydrogen would be highly sensitive to carbon capture – for example, where a process would capture 80% of its carbon dioxide, or 90%. The meeting discussed gas blending, and how to manage the green/brown binary condition – and that real measured numbers need to be used. The meeting also discussed the timeframe for compliance – the trajectory to a date from which the Standard could be applied. One of the meeting members said that this Standard should be set in such a way as to “energise” hydrogen, just to get it onto the marketplace. Another opened up the question of whether the development of green hydrogen would be impacted by potentially higher prices for carbon. What ? A high price for carbon ? Said one, “that would be lovely, wouldn’t it ?”
The meeting discussed the potential for a new Green Hydrogen Standard – that industrial players would blend up to the threshold and there would be many hydrogen resources just under the bar : “people will always game the system”, said one. But it was generally agreed that this Standard is needed because there are significant sources of industrial hydrogen that are being wasted at the moment.
Somebody raised the issue of accounting for grid electricity – for example in electrolysis. The carbon profile of electricity in the UK is strongly dependent on the time of day and day of the week. It was suggested that the best way forward was to accept the use of the annual average as calculated by the grid network operators and regulators, as otherwise there would need to be constant policing of the actual moment-by-moment figures, and the risk of “double incentives” – or fudging. It was stressed that “black-as-night electricity” with a very high carbon dioxide emissions profile varies daily and yearly – and there are arbitrary decisions about the fuels used to generate power – so the grid average calculated postdated year-on-year is probably the only fairly reliable number that can be achieved. Using a carbon grid average makes sense as electrolysers are normally most efficient when running all the time – so it is likely that electrolytic hydrogen production would become continual.
The meeting asked whether “by-product hydrogen” – otherwise waste hydrogen from industrial chemistry that could be re-routed to hydrogen consumers – should be accounted for on an economic basis. For example, whether it should be accorded a value based on a share of the overall profits or losses of re-routing it to market. One meeting participant said it would be hard to discuss what the revenue side would be – but that a company would still need to attribute costs internally to the company. The only consistency needed would be the carbon accounting – not something for the sales departments to handle. The carbon should be apportioned on a cost accounting basis. Another meeting participant felt that to demand finely-graded specifications on accounting for carbon would parallel and therefore replicate the complexities of the already gargantuan tasking of accounting for the costs of each processing step in any industrial activity. And anyway, companies would rig the process accounting so that the carbon content of the hydrogen for sale would be minimal, pushing it into the “green hydrogen” grade. Smaller companies wouldn’t be able to do this, though, only large ones. It may well turn out that guidelines are issued on this question that bear a resemblance to the guidelines issued for biomethane.
One person in the meeting asked – well, if this is “waste” hydrogen – and you’re going to get paid for it – why do you need another subsidy to say it’s “green” ? Another person said ruefully, “waste is a grey area”. And somebody else said, “another gaming problem”. The subject of the so-called “market” in hydrofluorocarbons or HFCs was raised. HFC plants that transitioned were given credits under the Kyoto Protocol. It was thought that nobody was going to build an HFC plant just to close it down for the credits, but that’s where three quarters of the credits came from : for example : https://www.newscientist.com/article/dn11155-kyoto-protocol-loophole-has-cost-6-billion/
Another person at the meeting said that there is a real value to freeing up hydrogen. And another said the Standard should incentivise the market to capture and (re-)use this “waste hydrogen”.
Another person said we should think about Carbon Capture and Storage (CCS). They could imagine plant fitted with CCS constantly in operation, either making hydrogen or making power – big assets being used for one thing or another – both making profit. [ The plant would be used to generate power only when needed. At other times it would be making gas to store for the winter months or other times of peak demand – either peak demand for gas or peak demand for power. ] Somebody else said it wouldn’t be “green” if it were a larger plant [ I think the implication was that if this was a large coal-burning plant, then it would have significant environmental impacts aside from the carbon dioxide emissions avoided by the use of CCS. ]
Another meeting member suggested that with hydrogen, the largest producers are often the largest consumers – and we need an incentive to capture hydrogen that would otherwise be wasted – investing in the recovery process – and that this would produce very large volumes of hydrogen potentially. There was discussion that questioned whether setting a Green Hydrogen Standard would incentivise future investment or whether it would simply reward hydrogen capture and utilisation in existing plant. The meeting wanted the Standard to be applicable to both current and future situations – to be clear that “we’re not against by-product hydrogen”.
The meeting discussed the use of biomass to produce hydrogen. It was claimed that the current regulation on the use of biomass in energy and the measurement and control of its carbon dioxide emissions liability was “not good enough as far as the academic community are concerned”. It was made clear that the Green Hydrogen Standard Working Group had no possiblity of changing the existing body of policy on biomass, nor deny the option that biomass be used to produce hydrogen. Somebody stated that biomass hydrogen had the potential to be carbon-negative, and somebody else suggested to the group that the biomass regulations are possibly going to be revisited. Somebody else said that there was no clear lifecycle analysis on biomass agreed by all parties. Somebody else said that the biomass regulations were “generally perceived as inadequate” as regards meeting the European Union Renewable Energy Directive (RED). Somebody said they would like to see one biomass way of producing hydrogen that had potential. Somebody else said that the “big one” is bulk wood gasification. Somebody else said that although thermodynmically it would make no sense to do, some might try to reform biomethane to hydrogen. Somebody else said this would depend on where the green/non-green number was set. Somebody else said that biomass was “just another feedstock”. Somebody else said that lots of people are already worried about biomass, and that there was a risk that the Green Hydrogen Standard could be seen as “greenwash” : this point was parked to come back to at a later date if so wished.
Somebody said that it was nice that the Call for Evidence had come up with the upper range number of 0.25 kgCO2e/kWh, as this would be roughly equivalent to Natural Gas steam reforming (steam methane reforming or SMR, SRM) plus an additional amount for “the NOx” and some other indirect greenhouse gas emissions. It was commented upon that the [ organisation name ] threshold was 185 gCO2e/kWh, or in the range 180 – 190 gCO2e/kWh for the use of Natural Gas.
[ In the DECC Gas Generation Strategy of 2012, in the 200 gCO2e/kWh scenario, Combined Cycle Natural Gas-fired power generation is 181 gCO2/kWh : https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/65654/7165-gas-generation-strategy.pdf : Table 2B. In Defra’s “2013 Government GHG Conversion Factors for Company Reporting : Methodology Paper for Emission Factors”, CO2 emissions from the combustion of methane in a Combined Heat and Power plant is given as 184 gCO2/kWh : https://www.gov.uk/government/uploads/system/uploads/attachment_data/file/224437/pb13988-emission-factor-methodology-130719.pdf : Table 11. ]
Somebody said that the questions/issues should include the methodology for arriving at these numbers. Somebody else said that we have taken a lifecycle analysis (LCA) approach which supports this (simple number). This number could be compared to the biomethane standard, where this is set as 60% better than fossil gas emissions – but it could be too strict. Somebody else said that using Natural Gas as a comparator was already a struggle – and that for SMR to be included in the technologies, there would need to be some CCS attached to it… Somebody else said that if the “green hydrogen” technologies proposed only showed a 10% gain on Natural Gas SMR then we would have a hard time calling it “green”, and that it would be helpful if there were a nice big discontinuity in the numbers of different technologies [ arranged on a spectrum ] – for example, plotting SMR of Natural Gas compared to the gasification of coal to hydrogen.
One of the meeting participants said that there needs to be evidence-based numbers versus aspirational – for example, a projection of the potential for large scale electrolysis – but that there is a lack of production data, and that it’s “very tempting to project the future”.
One of the members of the group gave a short presentation on numbers, showing Scope 1, 2, and 3 emissions (Tier 1, 2 and 3) – direct and indirect emissions from a certain hydrogen production technology. Indirect emissions would include for example : fugitive emissions and the emissions implicated in the use of electricity used in the processing. The example included Carbon Capture and Storage (CCS), and showed that even with strong CCS, the direct side-effects and indirect effects of using the technology reduced the ability to lock away all the emissions. Somebody said about Natural Gas reforming, “we worry in SMR land about steam – sometimes we can use it, sometimes not.” and that they wanted to get back to lifecycle analysis (LCA) all the time. They used a comparison with solar power, where the vast majority of the emissions are in line with the capital expenditure levels. “Those emissions happened on the day you build the plant…can struggle with LCA thing – got to bring capex in.” In SMR, there is little metal to consider (a high factor in embedded emissions). In a gasifier – the capex issue is worse. In nuclear power plants, the embedded carbon emissions in the build or install are “really bad”. The reason nuclear power plants were mentioned of course was because of the potential for France (and other countries) to turn their nuclear reactors over to making hydrogen. A couple of the meeting participants commented that they liked the concept of “nuclear hydrogen”, as this could probably be made as cheap as wind power (especially if you “chuck in” the value of the co-produced oxygen as well).
It was claimed that with 60% CCS, the Tier 1 emissions of the technology showcased would be 0.1 kgCO2e/kWh, or rather to keep the units on a parallel with the previous numbers given here, 100 gCO2e/kWh, which would give it parity with biogas. It was said that the only issue would be “NOx”, but that these plants wouldn’t produce much. Somebody said that “NOx is this year’s issue”, but that is was “not clear how to add them up”. They also said that the numbers being provided by DECC were very good and improving each year.
The leaders of the meeting were asked if the responses to the Call for Evidence would be published. It was agreed that DECC were happy to share the responses within the group. Two sub-groups were established to look at details of some of the agenda issues during July and August. The next main Working Group meeting was scheduled for September 2015.