Assessing UK CCS policy - there are actually two types of blue hydrogen project, with very different characteristics

Once again IEEFA is challenging the CCS community, with a report querying if UK CCS policy is “Out of step with net-zero goals” that raises some valid questions but that also misses some absolutely crucial technical issues.? The areas in IEEFA’s report that probably most need attention are blue hydrogen (hydrogen production from natural gas with CCS) and its relationship to CCS for power generation from natural gas.? Two of the report’s three ‘Key Findings’ refer to these topics:

·?????? “UK government incentives for carbon capture are disproportionately supporting the development of blue hydrogen projects, increasing long-term reliance on fossil gas within the UK energy mix.”

·?????? “Support for abating emissions from the UK’s existing gas and bioenergy power stations is severely lacking, potentially putting at risk the UK’s target to decarbonise the power sector by 2035.”

What needs to be noted, though, is that there are actually two types of blue hydrogen project, with very different characteristics, and that the latter type can include power generation:

A. Hydrogen for use as hydrogen, where all of the costs, both capital and operating, of the equipment to make and use the hydrogen are covered, the inevitable natural gas consumption in conversion too, and also some of the costs of CO2 separation.? Only the remaining costs of CO2 capture, transport and storage have to be met and there is minimal additional natural gas use compared to ‘grey’ hydrogen production.

B. Hydrogen for use as a fuel, where the original natural gas being used as a fuel in the process is switched for hydrogen, possibly with a loss in thermal efficiency.? All of the additional costs of making, transporting and possibly storing the hydrogen, plus the conversion and any utilisation efficiency losses that give increased natural gas consumption, have to be covered, plus all the costs of CCS.

The fundamental differences between the two types of blue hydrogen projects in respect of what extra equipment and operating costs have to be paid for in order to cut CO2 emissions are illustrated in the figure above.? Obviously Type A blue hydrogen projects will have much lower costs per tonne of CO2 no longer emitted (per tonne avoided or abated) than Type B , even if the same technology (or even the same plant) is used to make the hydrogen and capture the CO2.? Because of these lower costs Type A blue hydrogen projects are probably a ‘no-brainer’, while Type B projects need more examination on their value for money.? So, at variance with what IEEFA suggests, only a portion of the proposed blue hydrogen projects could be questioned as possibly excessive, although it is uncertain how much of proposed UK blue hydrogen productions falls into the Type A and Type B categories.

Type A blue hydrogen projects will typically involve supplying hydrogen to existing users who already specifically require hydrogen.? In the UK this will include refining, chemicals and ammonia for fertilisers.? An additional new use that specifically requires hydrogen is synthetic fuel manufacture, but breaking down a hydrocarbon to hydrogen and CO2 and then reacting that same hydrogen with other carbon sources to make a ‘sustainable’ hydrocarbon fuel doesn’t make sense thermodynamically and probably won’t be eligible for subsidies; electrolytic (green) hydrogen will be used instead.? Using the captured fossil CO2 from a blue hydrogen project with electrolytic (green) hydrogen to re-make ‘sustainable’ hydrocarbon fuels would also be incongruous, as well as obviously not compatible with net zero because it will result in the release of fossil CO2.?

Of the UK Track 1 hydrogen production projects , only one is apparently predominantly Type A, the Teesside Hydrogen?CO2?Capture project, because it will fit post-combustion amine capture to an existing steam methane reformer (SMR) that is already supply H2 to customers that specifically need it.? But, although details appear not to be available, there may be Type B uses for part of the output:? BOC note s that “coming on stream in 2027, the BOC facility will play a key part in supporting the increasing demand for low carbon Hydrogen from the Teesside Chemical Cluster and the North East of England economy”.?

Capture rates at the emerging UK standard of 95% or higher are likely from this plant, with at least some of the CO2 captured from the SMR flue gas stream.? This has not been done on previous SMR CO2 capture projects, which is why the “CO2 Real-World Capture Rates at Commercial-Scale Hydrogen Production” in Fig. 1 in the IEEFA report are lower, not because of any inherent limitations.? But, as work by Daniel Mullen has shown, very high rates of on-site CO2 capture are entirely technically feasible for hydrogen production with SMRs.

The other two Track 1 hydrogen projects apparently both propose to use the same novel Johnson Matthey LCH process and, as they are new hydrogen facilities, presumably at least some of the produced hydrogen will be for Type B fuel substitution.? CO2 capture rates of 95% or higher can be expected from these units, plus measures to reduce the carbon footprint of the imported electricity or oxygen to avoid ‘carbon leakage’.? Proposed uses for the hydrogen are also apparently not publicly available for these plants, but what has been said includes:

bpH2Teesside

“Industry: low carbon fuel and feedstock

Clean power and steam: decarbonizing scope 2 industrial emissions

Mobility and transport: heavy duty fleets, buses, rail, aviation and marine

Grid blending: Potential for 20% hydrogen blending into gas network, supporting building heating”

HyNet Hydrogen Production Plant 1 (HPP1)

“The HPP1 plant will produce some 350MW of hydrogen from 2026 …… Vertex provides vital but ‘hard to abate’ industrial and power generation businesses with a route to decarbonise.”

As already noted, to the extent that these Type B hydrogen projects involve fuel switching to hydrogen from natural gas in the gas turbines on power and CHP (cogeneration) plants then there will potentially be additional capacity for ‘abating emissions from the UK’s existing gas ….. power stations’ that was not identified by IEEFA. However, using hydrogen in gas turbines does come with a limitation, and also an extra cost, compared to direct CO2 capture from gas turbine exhaust gases.

The limitation is that the large, efficient gas turbines most widely used for power generation do not appear to offer 100% hydrogen use (the equivalent of high CO2 capture rates) commercially in the current generation of special burner systems required to achieve low levels of NOx.? The reduction in CO2 emissions (analogous to the capture rate for post-combustion capture) is much lower than the percentage of hydrogen fired because of the low heating value of hydrogen per unit volume, even assuming that the gas turbine does not have to be derated to a lower efficiency because of differences in flue gas properties with the different fuel mix.? Typical values (calculated taking natural gas as methane) are:

Hydrogen by volume????????????? Reduction in CO2 emissions (analogous to CO2 capture rate)

??????????? ??10%?????????????????????????????????????? 3%

??????????? ??20%?????????????????????????????????????? 7%

??????????? ? 30%?????????????????????????????????????? 11%

??????????? ??40%?????????????????????????????????????? 17%

??????????? ??50%?????????????????????????????????????? 23%

??????????? ? 60%?????????????????????????????????????? 31%

??????????? ? 70%?????????????????????????????????????? 41%

??????????? ? 80%?????????????????????????????????????? 55%

??????????? ? 90%?????????????????????????????????????? 73%

??????????? 100%?????????????????????????????????????? 100%

Some references on the status of hydrogen firing in large gas turbines follow, but the situation is moving fast and they should not be taken as definitive.? The general suggestion by gas turbine manufacturers seems to be, though, that 100% hydrogen firing will be possible by around 2030.?

GE has said , “GE’s DLN 2.6+ combustors are capable of operating on hydrogen levels as high as ~15% (by volume). The associated fuel systems for these combustors are typically only configured for a maximum of 5% (by volume) hydrogen and would require upgrading to safely operate at higher hydrogen concentrations. ……. the hydrogen capability of the DLN 2.6e combustion system was evaluated. Results of preliminary testing indicated that this combustion system has entitlement to operate on fuels containing up to 50% (by volume) hydrogen.”

MHI has stated , “by switching fuel from natural gas to 30% hydrogen mix by volume, it is possible to reduce a gas turbine's carbon emission by around 10%.? Mitsubishi Power is currently developing dry low NOx combustion technology for 100% hydrogen firing and targeting March 2025 for the rig tests completion which will be a monumental step towards the goal of carbon-free gas turbines.”

Siemens is also reported to currently accept up to 30% by volume hydrogen in their large power plant gas turbines and is working to increase this.

The extra cost compared to direct CO2 capture from gas turbine exhaust gases for using hydrogen in combined cycle gas turbine power plants arises because of the lower overall efficiency (so higher natural gas use and hence fuel input costs) and generally the greater capital costs involved in going from natural gas to low-CO2 electricity via hydrogen rather than burning the natural gas directly to generate electricity and capturing the CO2 from the resulting flue gas.? The exact ratio between the costs of electricity for the hydrogen (pre-combustion capture) route and for the post-combustion capture route depends on natural gas prices and project-specific capital and operating costs (including for a suitable hydrogen-burning gas turbine) but in a 2018 study by Wood for BEIS the hydrogen/pre-combustion capture route was predicted to be over 40% more expensive for baseload operation, using an integrated hydrogen production system that probably gave some advantages over the separate hydrogen production now being proposed.

Electricity production from natural gas via hydrogen can, however, be less costly in principle than direct natural gas use with post-combustion capture at low power plant load factors, perhaps below somewhere in the region of 10-20% load factor.? But this cost crossover load factor is highly dependent on the actual details of implementation and currently unknown factors, including future natural gas prices, and, crucially, depends on storing the hydrogen so that the hydrogen plant capital cost charges can be lower.? Just diverting hydrogen from one natural gas fuel switching use, e.g. addition to the gas grid, to another, i.e. electricity generation when the power is required, obviously doesn’t give any additional reduction in CO2 emissions compared to just maintaining the first use and so is not a substitute for actual storage to average out the demand on the hydrogen production facilities.

So, in conclusion, the IEEFA report has suggested that there may be excessive provision for hydrogen production in UK CCS plans but IEEFA apparently has not considered how much is the ‘no-brainer’ cost effective Type A blue hydrogen production that is being substituted for existing consumption of ‘grey’ hydrogen.

IEEFA has also stated that there is inadequate provision for power generation from natural gas in current UK CCS plans but seem to have ignored the possibility that some of this hydrogen production from natural gas is being proposed to be used for power generation.?? The amounts of hydrogen that any of the projects are planning to supply for electricity generation (in excess of their own use) do not, however, appear to be identified in the public domain.

What CCS projects actually go forward in Track 1 and subsequently is, of course, also still to be confirmed by which projects make Final Investment Decisions (FIDs), presumably some time in 2024 for Track 1 projects and perhaps somewhat later for others.? The government side of this will no doubt involve value-for-money considerations and in this context a study by the National Audit Office on Carbon Capture Utilisation and Storage (CCUS) that is in progress and due to report in Spring 2024 can be expected to be informative.? The NAO report will examine if DESNZ:

·?????? set up the CCUS programme in a way that considers costs and benefits, and addresses implementation challenges

·?????? is making good progress implementing the programme

·?????? is well placed to support the longer-term deployment of the CCUS programme

It seems likely that the NAO assessment of costs and benefits will be acceptable for Type A blue hydrogen projects. But their cost/benefit balance for Type B blue hydrogen projects may vary, depending on the costs of alternatives for the natural gas substitutions being proposed and other opportunities for CCS support.? For electricity generation using Type B blue hydrogen the benchmark is likely to be the cost of low-emission electricity (i.e. looking at the end product to avoid perverse incentives from e.g. hydrogen pricing subsidies) for power plants burning natural gas directly and capturing the CO2 from the flue gases.? But, if taking into account actual project cost/subsidy estimates and projections of future circumstances such as natural gas prices, plant load factors and technical progress on hydrogen-burning gas turbines, using blue hydrogen for electricity generation appears to offer a reasonable cost/benefit balance compared to post-combustion capture then IEEFA’s numbers for planned gas to-electricity capacity will be seen to be an underestimate.

Government decisions on blue hydrogen will also have to take the target for hydrogen deployment by 2030 into account.? In a recent response to a Science and Technology Committee report on ‘The role of hydrogen in achieving Net Zero’ the government noted that “the British Energy Security Strategy doubled the UK’s ambition to up to 10GW of low carbon hydrogen production capacity by 2030, subject to affordability and value for money, with at least half of this coming from electrolytic hydrogen.”?

With respect to reducing energy import requirements the production of blue hydrogen can, however, be seen as having different effects.? Obviously indigenous blue hydrogen production will reduce the need for imports of low-carbon hydrogen, as being contemplated by, for example, Germany .? But blue hydrogen production for Type B projects where it is used as a fuel requires up to 40-50% more natural gas than direct gas use without CCS and perhaps around 25% more natural gas than using natural gas directly in power plants with post-combustion capture of CO2 . ??So the role of Type B blue hydrogen projects in enhancing UK energy security, as well as supporting net zero delivery, is probably still a moot point.