From the archive: can the gas be used to aid decarbonisation? Some projects investigated

 

Despite the carbon cost, use of the gas network is expanding. Proponents argue that it can be a low carbon bridge. In the September 2017 issue of New Power Report Janet Wood took a look at some projects

Efforts to decarbonise the UK are tackling just the tip of the iceberg, by focusing for so long on electricity.

That has been the approach because otherwise the undertaking is so massive, given that fossil fuels have for so many years underpinned our power, heat, transport and energy storage requirements. For example, talking about the Future Power Systems Architecture work, Simon Harrison, chair of the project delivery board, says there is a danger of trying to “boil the ocean” if the project took on too many energy vectors.

But  it has become clear that simple assumptions that gas heating would be replaced by decarbonised electricity gravely underestimated the scale and complexity of the challenge. (See New Power’s interview with Jeff Douglas of the Energy Systems Catapult, May issue, for more discussion about heat futures.)

Far from being wound down, gas distribution networks have seen a surge in use as fleets of small gas engines – used for peak shaving and balancing – have been installed, and there has been renewed interest in local combined heat and power (CHP) projects, largely gas-fuelled. Discussions at a “hot topic” meeting hosted by the Institution of Gas Engineers and Managers made it clear that even including heat does not go far enough in tackling energy decarbonisation. One speaker said: “When the electrical guys talk about ‘whole system’, they think it’s just the generator, the wires and a fridge at the end”. But there is more to it. Discussions included transport and storage – Northern Gas Networks has 25GWh of daily storage in its network – as well as heat, and covered how to evolve the gas network to make use of it as a huge reservoir of energy.

There may be some relatively easy wins. Peak demand in the electricity system has fallen by 10% over the past few years and “in gas, 10% peak shaving is a big number”, said Keith Owen, head of systems development and energy strategy at Integral, which aims to “integrate transport, electricity, gas, research and laboratory work”. It’s one of a large number of projects that are exploring energy vectors that originate outside the electricity industry.

The event was hosted by Northern Gas Networks (NGN) and focused on projects where it has an involvement. Ofgem’s Network Innovation Competition has helped fund many of the projects. Delegates heard about initiatives that included using compressed natural gas for heavy-duty vehicles that are unlikely to go electric. They also heard about using renewables to produce hydrogen gas for transport (see New Power’s interview with ITM Power chief executive Graham Cooley).

A fundamental question is whether the network will still be transporting fossil gas or whether the composition can change to cut its carbon burden. That could include injecting biogas, made from waste or dedicated crops. All the gas distribution networks have received hundreds of enquiries about such projects, but industry growth is hampered by inconsistent technical requirements and processes across the gas networks and, crucially, a long wait to receive confirmation from government about support under the Renewable Heat Incentive, New Power heard. The industry hopes there will be clarity on that support before the end of the year.

Meanwhile, Gas2thefuture is examining the network to find out at which points gas from new sources – which may be biogas, hydrogen or even local shale production – can be injected most easily and often. This is already a practical issue. At times, if the network is at high pressure (when gas use is low or the network is pressuring up in readiness for peak) companies cannot inject biogas.

The HyDeploy project – backed by NGN, Cadent and Keele University – is investigating what proportion of hydrogen can be injected into the existing network without causing technical problems – whether that is making steel pipework brittle, or requiring changes in users’ appliances.

That is likely to be a stepping stone towards one of the industry’s flagship projects – plans to convert the gas network in Leeds to carry 100% hydrogen, instead of natural gas.

The situation seems to be that, while policymakers assume the gas network will change and eventually disappear, for developers and domestic customers it is a permanent asset that will always be available, wherever it already exists.

New Power spoke to Nick Phillips,in the strategy and asset management team at NGN, about the initiatives. Are the different options being explored – including biogas and hydrogen – going to lead to a patchwork of different gas networks?

Philips says he hopes they will come together. The company is “investing in infrastructure that can not only transport methane [natural gas] but also can accept synthetic natural gas, biomethane and transport hydrogen… a range of gases”.

Are customers aware of the different tracks being explored and that, in the long term, gas composition may change?

“What a customer has at home or what a CHP unit uses… we can’t necessarily influence that, but we will be communicating to them that we are trying to transport different types of gas. The HyDeploy project shows we are looking at the impact. But the primary focus is our infrastructure,” he says.

Of the Leeds project, he says: “The aim for us is to solve that UK-wide heat issue and to show that the 100% hydrogen solution can work in cities with certain characteristics.” As a whole-hydrogen system it would not take other forms of gas, but “that’s the beauty of the gas network – we can isolate certain parts of it and treat them differently”.

Where will the hydrogen come from? The GDN’s role is transport, not production. Phillips admits: “We don’t yet know how much it costs to produce the hydrogen… but we know there are two primary sources.” (For more detail on these, see article opposite.)

One source is steam reforming. That is “most feasible at a large scale”, Phillips says, but, “that depends on you capturing the carbon and storing it safely”. The other is electrolysis that, to ensure low carbon emissions, would have to use electricity from renewable power sources. Here, says Phillips, “the gas network is effectively operating as a store for renewable energy”.

 

More large loads

Use of the local gas network is changing – with more inputs, such as biogas, and new large users, such as CHP projects, and a surge of interest in gas engines that generate electricity at peak times. Is that changing the gas networks?

Phillips says there are more “large loads” coming on to the system. “Historically we only dealt with a few each year, but at the moment we have a couple of hundred ‘live’ enquiries. These are typically gas engines trying to make the most of the opportunity to provide peaking power. In the past year or so we have seen a big increase in those. But overnight we can increase the pressure in the pipes so we are able to use the energy stored in the pipes. It’s one of the main advantages of the network, like a large battery it is storing energy”.

Are these new types of user changing how the network is operated? It’s not a concern yet, says Phillips. “We don’t have much data on that at the moment and it’s part of where we have to start sharing data with the power networks. If we can see the peak coming in the power network, we know small power generation is turning on.”

At present, it is connecting new plant that is the biggest issue. “We guarantee a minimum supply with every connection and we have to be able to guarantee that.

“It depends on where they are, because at different parts of the network we have a different capacity. In some areas when we get requests unfortunately the answer has to be no,” unless the network can be economically reinforced.

With gas from more sources being injected into the network, and more, possibly more active, users, are GDNs facing the need to become more active system managers? “In terms of customer-facing activity, there are far more enquiries, the same with biomethane. In terms of day-to-day running, it’s not a huge amount more once they are connected. The management at the moment is not much more intensive.” But how that will evolve is not clear.

 

Looking forward to RIIO

Price reviews are always in view for networks and I ask whether NGN would like to see changes in that process.

Phillips says the timetable is the issue. “We’d be keen to see the electricity and gas distribution periods aligned – at the moment they are two years out. We think there is merit in having the period at the same time.” It would align business plans and “you could regulate it as one system”.

He adds: “We haven’t had much progress with that so far.”

Of course the gas industry wants to see the network retained in some form. “It’s a huge asset and our customers are investing in it and we do think it has a role to play in the low-carbon future. We think it doesn’t need to be stranded,” says Phillips. Whether it can evolve, or radically change, to maintain use of that asset in a decarbonised world is not yet clear. What is clear is that the issue has to have much more attention, both in public debate and inside the energy industry, where discussions on decarbonising energy must encompass much more than just electricity.

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