Going beyond fossil gas means fundamental change for more sectors than domestic heating. Janet Wood spoke to IGEM’s Oliver Lancaster about some of the issues ahead
The gas network has provided a large part of the nation’s heating and industrial energy for many decades. But what is its future? When I discuss this issue with Oliver Lancaster, chief executive of the Institution of Gas Engineers and Managers (IGEM), it is against a background of declining use of gas for domestic heating, where insulation has improved the building stock. But Lancaster notes that at the same time there is increasing demand for other uses. He says, “the future of the gas grid is talked about in relation to homes, and separately about flexible power generation and supply to industry. But what we find across most areas of the gas grid is that pipes are shared, between homes and distributed industry and flexible power generation”. That makes the conversation about its future very complex.
During our conversation we talk about several examples of other gas network users.
Arrays of small gas engines have been installed over the last decade that provide peaking power to the electricity grid and can switch off and on faster than large gas turbines to respond to fluctuations in demand. They now total thousands of megawatts.
Another use that has expanded in recent decades is combined heat and power (CHP) plants, which have been installed as an energy efficient way of supplying new housing or industrial and commercial developments. Lancaster says, “CHP in buildings is a hidden capacity. It is hard to try to understand the size of it. Effectively, electricity is brought to the building in molecule form and as well as meeting on-site electricity demand there may be times when the facility is exporting surplus electricity to the grid”. Most are owned and operated at building owner level, so aggregating the data is difficult, but it too may represent thousands of megawatts. Some CHP owners are moving away from gas – perhaps by replacing it with a heat pump – but Lancaster says there are complex interactions between the gas and electricity loads, especially as there is increased need to reinforce the electricity network. If the business has been using CHP supplied from the gas grid, its electricity need has been hidden.
CHP in buildings is a hidden capacity. It is hard to try to understand the size of it.
Lancaster also points out that there are also new industries injecting gas into the system, notably biomethane. Biomethane sites have not been injecting as much gas as they could, but he says they are getting closer to delivering most of their capacity at fairly flat rate throughout the years. “The capacity of these sites is quite substantial”, he says, with one network seeing plants in the build phase that would together supply enough biomethane for 500k homes in a few years. “ If you drop into the equation the potential use of that biomethane in hybrid heating (with the heat pump when you have wind and the boiler when you don’t) that will be enough for 2.5 million homes”.
In fact, planned new biomethane injection sites are currently outstripping the ability to connect them. To try to maximise biomethane injection Lancaster says one option is reverse compression, in which demand is created in a higher pressure tier to draw it up into the wider network, instead of using it locally. That requires investment to convert stations to be reversible that were only used in the past to send gas one way (from the high pressure transmission network to medium pressure local pipe networks). That is at the pilot stage in GB but it has been done elsewhere – Denmark, for example, has a fully reversible gas grid.
At the moment most biomethane customers are truck fleet operators, who are taking some of their fleet off diesel and moving them to biomethane. In fact, heavy transport is another new user of the gas network. In this application trucks use compressed natural gas (CNG) instead of diesel, delivered via CNG refuelling stations.
Other biomethane customers include Scottish distilleries and it would be far from impossible to run small local networks using biomethane instead of fossil gas. Lancaster notes that GB still has seven small standalone gas networks, each with up to a thousand homes plus businesses – that were too far to be connected when the country’s local gas networks were linked into a national network. Lancaster explains that such networks could be switched to biomethane: “There is a defined profile of demand over the year. LNG is delivered to them by tanker and stored, then it is vaporised into the local network. You have a good understanding of what is required for a 1 in 20 winter, what the profile of supply needs to be and whether there is a local circular economy of feedstock for a biomethane supply and how much storage has to be built into that to deliver for peak days.” In fact, on that model, “you could also sector off parts of the network for biomethane that are not discrete now but could be in future, with enough of a higher tier pipeline to give storage capacity.”
If there are some new gas users, there are equally some areas where gas use is declining. I ask how the government’s drive to introduce heat networks, generally in town centres, will affect the balance of costs of running the gas network there. Lancaster has some questions about the practical delivery of retrofitting heat networks in cities: “looking down a hole into a street that has been dug up it is very congested. Weaving a new large-diameter trunk pipe through there is very difficult – not just weaving but getting other utilities to move out of the way – is in some respects an insurmountable issue”. He says a heat network requires “a minimum number of customers connecting to it to make it a viable starter. I think it is a great opportunity where you have geographically high demand densities – high rise blocks – but then the question is whether all the flats in one block are owned by one landlord, or if you have a mixture of social and privately owned that will be a challenge to switch over to something else.” He says it is positive for new developments, but up to now, as above, “a lot of them have used gas CHP. I think in the last five years heat networks have done this – whether they have a steady supply of heat from one source or another – that can be topped up from gas CHP.”
That need for a minimum number of users also clearly applies to the gas network, but Lancaster says, “the operational cost of the low pressure gas network, once it is plastic, is negligible and it is 75-80% plastic now”. Distribution pipes that are not plastic are either beyond 30m from a building or are at the lower risk end of the prioritisation scale.
“It may be there are some areas where [the gas grid] is just domestic – no flexible power generation and no industry – and there is a question to be asked there around whether the future for that offshoot of the network is that they retain some option to have a gas supply or hydrogen supply or whether they go to something else.”
The new gas network users we have discussed have a tendency to cluster, and options like heat networks are also obviously very local solutions. Lancaster admits, “It may be there are some areas where [the gas grid] is just domestic – no flexible power generation and no industry – and there is a question to be asked there around whether the future for that offshoot of the network is that they retain some option to have a gas supply or hydrogen supply or whether they go to something else.” He warns, “Then you get in the world of cutting off choice for some people … politicians are probably quite wary about what the public think about this.”
That means understanding the interaction between gas and electricity networks also requires a local dimension. “What would really help is a plan that is national, regional and local,” says Lancaster. There is a role for local councils, but “they can’t do it on their own. There is going to be a balance on what is going to be flexible and economic to deliver between national, regional and local.”
Part of that will be network planning as a ‘whole system’, with gas and electricity down to regional levels and the Future System Operator (FSO) “has a huge role to play in this”. Lancaster says, “It would be a lot of resource for FSO to engage at the bottom end of local everywhere. It has to have its arms around national infrastructure, security of supply, peak demand, ramp rates, energy needs and so on and trying to deliver the right blend of capacities across the energy system, so the assets we invest in are utilised well. There is lots of underutilised asset out there”.
The FSO at the moment doesn’t have much gas experience, so getting its arms around the gas system as well as the hydrogen angle and system options for the future is going to be key
He adds, “The FSO at the moment doesn’t have much gas experience, so getting its arms around the gas system as well as the hydrogen angle and system options for the future is going to be key. Between them and Ofgem there will have to be key regional planning representation working with those who need to be engaged, like electricity and gas networks, and those who are keen to be engaged and looking to deliver. There has to be a clarity of needs and of opportunity that flows between regional and local.”
Long term, he says there may be discrete areas that remain on biomethane supply, and “One or two industries may retain a natural gas pipeline, and they would have to have CCS or some negative emissions elsewhere. But the vast majority of the network will be repurposed for something else and yes there might be some parts of it that close down, that aren’t used anymore, that are decommissioned.”
Lancaster says repurposing may be with hydrogen, where areas of the gas grid would be used to carry that gas. Hydrogen is likely to be the fuel for the other gas network users we have been discussing and at the same time industry that is not within an industrial area might be seeking a hydrogen supply in future. The population of domestic properties around those facilities has to be understood on a case by case basis.
Overall, though, recent government comments have tended to deprioritise hydrogen use in homes. Of two potential hydrogen network trials (so-called ‘Hydrogen Villages’) one has foundered on local opposition and there is clearly a question over public acceptance. I ask Lancaster what the gas industry has taken from the smart meter rollout, as any domestic hydrogen programme would require significant work inside people’s homes. He says, “There is probably learning from a range of rollouts including the transition to digital TV. I think something similar for hydrogen would be beneficial.”
As the users we have discussed illustrate, the existing gas network has often been the first port of call for new energy solutions. Lancaster also notes that its direct or indirect roles in system flexibility are also taken for granted. He says, “Currently the buck is always passed onto the gas system to be there when it is needed. I think there will be an integrated molecule and electron future that serves across multiple sectors but overall it has to work in symbiosis with the least possible cost.”