Category Archives: hydrogen

Hydrogen and heat pumps may both play a role in UK building heating

Low carbon hydrogen and electricity via heat pumps may both play a large role in decarbonising building heating in the UK.  Ways forward are needed that maintain optionality around solutions while more is learnt about the right mix.

This is the second of three posts looking at the potential role of hydrogen in residential heating in the UK.

Decarbonising building heating in the UK poses a range of challenges.  First, the required transition is very large scale.  There are around 27 million households in the UK, with many more commercial buildings, small and large.  This implies around a million or more premises a year on average need to be converted to low carbon heat between now and 2050.

Along with scale, there is cost.  Replacing the UK’s heating system is expensive both on in total and by household, even if the existing natural gas network can be used for hydrogen.   This challenge is made more difficult by the high seasonality of heating demand (Chart 1).  Building natural gas supply chains, reformers to produce hydrogen from natural gas, CCS, low carbon electricity and heat pumps all involve major capital investment.  Running this for only part of the year – the colder months – increases unit costs substantially. The chart below shows daily gas and electricity demand from non-daily metered (i.e. small) customers.  Demand for energy from gas, the major source of building heating at present, is about two or three times electricity demand during winter, and is much more seasonal.

Chart 1: Heating demand is highly seasonal …

Source: BEIS (2018) ‘Clean Growth – Transforming Heating’ https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/766109/decarbonising-heating.pdf

Furthermore, the transition to low carbon heat needs to be made largely with the UK’s existing building stock, which is mainly old and often badly insulated.  Improved insulation is a priority in any programme, but there are practical and cost constraints on what can be done with existing buildings.  (Buildings also need to be able to cope with the increased prevalence of heat waves as the climate warms, but that is a separate topic.)

Finally, building heating directly affects people’s day to day lives, so consumers’ acceptance is critical.  On the whole the present system, based mainly on natural gas boilers, works quite well except for its emissions.  Any new system should preferably work as well or better.

The leading candidates for low carbon heating in buildings are electricity, almost certainly using heat pumps to increase efficiency, and low carbon hydrogen.  Biomass seems unlikely to be available either at the scale or cost that would be needed for it to be a major contributor to low carbon heating, though it may find a niche.  District heating networks require low carbon heat and this must draw on the same ultimate set of sources of heat.  Waste heat from nuclear, once discussed as a possibility, no longer seems likely to be either practical or cost effective.

Recently the Committee on Climate Change (CCC) analysed the costs of decarbonising heat in 2050 using different approaches.  They looked at electricity, hydrogen, and combinations of the two.  The analysis concluded that a 50% increase over current costs was likely (Chart 2).  The remarkable thing about the analysis is that this cost was similar for all of the options considered.  Any differences were well within the uncertainty of the estimates.

Chart 2: Costs of different modes for decarbonising building heating …

Source:  Committee on Climate Change

With no large cost difference leading to one or the other option being preferred there is a need to test each option out to see which works better in practice.  Mixed solutions may be appropriate in many cases.  For example, hydrogen may be useful in providing top-up heat even if heat pumps are providing the baseload, or may be the only solution for some poorly insulated properties for which heat pumps don’t run at high enough temperatures.

The CCC’s analysis includes expected cost savings.  The transition to low carbon heat will clearly be more acceptable if this cost can be reduced further.  In particular there seem likely to be both technical advances and large economies of scale in heat pump manufacture and installation, and the costs of low carbon power may fall by more than assumed by the CCC.  As the analysis stands, a 50% increase is clearly politically difficult, especially when there do not seem to be advantages for the customer, and potentially some drawbacks.  However, this is less than a 2% p.a. compound increase in real terms over a 30 year period, which might be politically feasible if introduced gradually spread across all consumers.

With such large changes in demand between summer and winter, seasonal storage is a major issue for reasons of both cost and practicality.  This is an under-researched area, and needs further work.  There are various possibilities – storage of hydrogen itself in salt caverns, storage of hydrogen as ammonia or storage of heat in ground sinks, but each has its problems and the scale involved is very large.

A final uncertainty is the form which hydrogen production will take.  At the moment methane in reformers predominates and, with the addition of CCS, may continue to do so.  However both the costs of low carbon electricity and of the electrolysis are decreasing rapidly.  Over the long term this may become the main pathway for hydrogen production.

These uncertainties imply that building heating poses a particularly difficult set of choices for policy.  It is not clear what route, or mix of routes is the right one.  The transition needs to be quite rapid relative to the lifetimes and scale of existing infrastructure, and it involves the need for consumer acceptance.  There are also potentially strong network and lock in issues.

The best approach is likely to be to develop several types of solution in parallel, maintaining optionality while learning, and being prepared for some approaches to be dead ends.  The implications of this include the need for roll out of low carbon heat sources in some districts now to get an idea of how they will work at scale.

Some of this is happening, much more is needed.

Adam Whitmore -29th October 2019.

 

Comparison of cost estimates with previous analysis by this blog.

Around four and a half years ago I looked at the costs of decarbonising domestic heating in the UK in winter using low carbon electricity.  I concluded that switching to low carbon heat would add 75% or more to domestic heating bills, with some drawbacks for consumers (I also looked at higher cost case, but this case no longer seems likely due to the fall in the costs of low carbon electricity, especially offshore wind, since the analysis was done.)  I suggested that this meant that the transition would be difficult and that reductions in capital costs were necessary.

This analysis is broadly consistent with the CCC analysis quoted here, which suggests a 50% increase on current costs.  The estimates are roughly similar given the large uncertainties involved , the inevitable differences is assumptions, and different basis of the estimates.  In particular the CCC analysis factors in reductions in costs of low carbon heating likely by 2050, whereas my previous analysis was based on current costs to make the point that cost reductions are necessary,  Consequently it would be expected that the CCC analysis would show a smaller cost increase relative to current costs.  Also, the CCC’s analysis may exclude some costs – estimates such as these have a tendency to go up when you look at them more closely.  Equally it may understate the cost reductions possible over decades.

 

 

Hydrogen and electricity for low carbon heat

Hydrogen and electricity are competing carriers, and there may be a role for both in providing low carbon heat.

There has recently been a lot of interest in the role of hydrogen as a carrier of low carbon energy, because it produces no CO2 on combustion (or oxidation in a fuel cell).  This is the first of three posts looking at hydrogen and how it might compete with electricity to provide low carbon heat.  Hydrogen and electricity may also compete in transport, but that is a large subject in its own right and will need to await further posts.

This first post outlines some of the possibilities and the issues raised.  The next post will compare electricity with hydrogen for heating in buildings.  The third post will look at the ways they may complement each other to supply heat.

There are broadly two main sources of primary energy for low carbon heat:

  • Fossil fuels with CCS, which I’ve assumed in these posts will usually be natural gas.
  • Renewables, likely in practice to be mainly wind and solar.

Each of these primary energy sources can get to the energy consumer in the form of electricity or hydrogen.  Wind and solar can produce low carbon electricity directly, or they can produce hydrogen via electrolysis of water.  Natural gas can be burnt in a CCGT to produce electricity.  It can also be processed to produce hydrogen, most commonly in a steam methane reformer (SMR).  I’ve assumed here that SMRs are used, although many are looking at alternative approaches such as autothermal reforming (ATRs) which may allow for higher efficiencies and capture rates.

If fossil fuels are used CCS is required, as both CCGTs and SMRs produce CO2.  This means they provide low carbon energy, rather than a zero-carbon energy, as a maximum of 90-95% of the CO2 produced is captured.  Any CCS built now or in the future will likely still be in use by 2050, so its capture rate must be judged against 2050 net-zero targets.  In this context, the residual emissions from any large-scale use of CCS for fossil fuels are likely to be significant, and may place limits on the extent of deployment.  SMRs produce different streams of CO2. Some of this is concentrated and so relatively easy to capture, some is more dilute.  Both streams need to be captured for the technology to play an appropriate role in a net-zero carbon economy.

Both CCGTs and SMRs also produce waste heat, which may be used, so improving the overall thermal efficiency, although applications to date have been limited.

Hydrogen can be converted into electricity using a fuel cell or CCGT (with appropriately designed turbines).  This may enable use of hydrogen for electricity storage.

Electricity for building heating is likely to come from heat pumps (likely mainly air source heat pumps) as these greatly improve efficiency.

This gives a variety of routes for primary energy to low carbon end use. These are shown in the diagram below.  In practice several of these may co-exist, and some may not happen at scale.  The pathways shown assume natural gas cannot continue to act as a carrier of energy to individual buildings.  This is because its combustion inevitably produces CO2 and very small-scale CCS for individual buildings is likely to prove impractical, for example because of the very extensive CO2 transport network that would be required.

Both fossil fuels and renewables can deliver energy as electricity or hydrogen …

Which mix of these pathways will provide the best solution? It’s not yet clear.  It will depend on various factors.

Suitability for end use.  Some industrial processes require high temperature heat or a direct flame, which heat pumps cannot provide.  Conversely, hydrogen needs to demonstrate its safety in a domestic context, though this is likely tractable.

Consumer acceptability. This is critical for residential heating, and both hydrogen and heat pumps face potential difficulties.  For example, heat pumps may be perceived as noisy, or require modifications such as installation of larger radiators which people resist.

Costs.  Which route is cheaper depends on a wide range of factors, including :

  • The capital costs of the equipment (e.g. CCGT or SMR, hydrogen boilers, and heat pumps)
  • The costs of reinforcing, creating or repurposing grids, including the extent to which the natural gas gird can be repurposed for hydrogen, and the cost of reinforcing the electricity distribution network to accommodate demand from heat pumps.
  • The cost of the primary energy, for example whether renewable energy is produced at times of low demand so might be available at a low price. If electricity from renewables is available very cheaply then resistance heating without heat pumps may make sense in some cases.
  • The thermal efficiency of the processes, for example the extent to which CCS adds costs by requiring additional energy, and the coefficient of performance (heat out divided by electricity in) for heat pump, especially in winter.
  • The costs of electricity storage via batteries or as hydrogen.
  • Load factor for heat and electricity production.

Many of these variables are uncertain.  They also vary with location and over time. The very large cost falls for renewable electricity demonstrate the need for caution in judging options on present costs.

In my next post I will take a look at how these factors may play out for building heating in the UK, and will consider the policy implications.

Adam Whitmore – 30th September 2019