The worst greenhouse gas: why the electricity industry has to grapple with SF6

In 2018/19 National Grid Electricity Transmission (NGET) allowed about 12.25t of a gas called sulphur hexafluoride to leak from its system. That may sound like a small amount, but it’s importance to managing greenhoue gas emissions is tens of thousands of times greater. And it  is a problem that the electricity industry has to address.

This gas – generally abbreviated to its chemical formula, SF6 – is used in substations and switchgear, where it has been used over recent decades. Over the last decades SF6 has been used by transmission network owners to provide an electrically insulated environment for substation equipment, which would previously have relied on an ‘air gap’, to avoid short circuits and subsequent local blackouts.

Why is it preferred over air? Because its insulating properties are so much better. Electrical arcing is about 100 times less likely in SF6 than in air. As a result, sealing the switchgear in an SF6 atmosphere means the various components can be placed much closer together, so the volume required by the substation can shrink.

The footprint of a substation with gas-insulted switchgear is 30-40% smaller than that an air-insulated version.  This gives network and building designers more options on where to place electrical equipment and it is important in areas – such as cities – where space is expensive. After all, eventually, the space cost of substations feeds back to user bills.

In addition, air insulated switchgear is generally exposed to environmental conditions – dust, rain, or even animals on the equipment, which makes it vulnerable to failure.

Transmission companies have to reduce or eliminate emissions from SF6 if they want to meet commitments on reducing their own carbon footprint.

But SF6 carries a sting: it is  the single most damaging greenhouse gas. Each tonne released is equivalent to 23,900 tonnes of carbon dioxide. It is (with similar gases) the biggest contributor to NGET’s business carbon footprint (BCF), and (to a lesser extent) to the BCF of other transmission networks.The electricity supply industry is almost the only use of SF6 and emissions to air have increased noticeably since it entered common use in the industry.

Transmission companies have to reduce or eliminate emissions from SF6 if they want to meet commitments on reducing their own carbon footprint.

But now transmission companies have to reduce or eliminate emissions from SF6 if they want to meet commitments on reducing their own carbon footprint.

New options

Suppliers to the industry have responded with new types of insulating gases that are carbon-friendly. But although they are now commonly available for lower-voltage applications,  they have yet to be developed for the more testing environment of high-voltage substations.

SF6 initially had a variety of uses – from double-glazed windows to tennis balls, according to Eaton, which is marketing SF6-free switchgear for low and medium voltage applications. The EU has progressively outlawed these SF6 applications, but electricity networks have remained an exception. Now, however, the EU is set to place more pressure on the electricity industry to stop using the material. Under a 2014 regulation the EU must publish a report on alternatives to SF6, at least for low and medium voltage applications. The report is likely to be followed by new restrictive legislation.

That may prove a tipping point for medium voltage solutions. Eaton says that for medium voltage applications SF6-free switchgear “has a capital cost of around 20% more than SF6 alternatives on the market”. It believes that “there is no reason why, with scale manufacturing, the costs wouldn’t fall to a similar level” – global sales volumes are currently relatively small. Eaton also suggests that if a replacement removes the need to maintain, top-up, test, inspect, report on and dispose of SF , “the total lifetime cost of ownership is already lower”.

A briefing document produced for the EU in March 2020, by consultants RE-xpertise and Öko-Recherche, notes that limiting factors that restricted the choice of switchgear include initial investment needs, space constraints, maintenance effort and environmental conditions (e.g. humidity, dust, salt, temperature). It says that “SF6 free switchgear can become technically feasible and associated with reasonable extra investments for nearly all segments of MV applications within 2 to 4 years. However, in general such a shift may result in an initial cost increase of up to 20%, raising to 30% in exceptional cases.”

That has to be weighed against  lower ‘end of life’ costs. But, “The time needed for large-scale application in HV is longer, in particular for applications >145 kV where the scheduled development periods can last up to 5 years and the commercialisation can start only after this period.”


RIIO incentives

It remains to be seen what implications tighter EU regulations would have in the UK post Brexit. In the meantime, transmission network owners have proposed incentive regimes for replacing SF6.

None of the networks proposes to end the use of SF6 at this stage.But transmission operators are participating in work towards alternatives. NGET, working with GE Grid Solutions and 3M, has commissioned gas-insulated switchgear using an alternative at the Sellindge 400kV  substation in Kent. The project uses 3M and GE Grid Solutions’ green gas for grid – or g3 - instead of SF6.

However, Ofgem  accepted that for assets at higher voltage (ie 275kV and 400kV), alternatives to SF6 will only be available in the second half of RIIO-2 (after 2026).  SPT promised to set a new benchmark by procuring assets with only half the leakage currently guaranteed by manufacturers. But that means new assets being installed will have leakage levels of 0.25% (instead of 0.5%) over their lifetime.

New assets being installed will have leakage levels of 0.25% (instead of 0.5%) over their lifetime. 

The regulator does, however, expect that alternatives without SF6 will be used – if commercially available – at lower voltages. Ofgem says, “In effect, this will mean that the TOs will no longer procure new 132kV assets containing SF6.”

Meanwhile, NGET proposes to spend £190-325 million over the next five years dealing with existing leaky assets, with the aim of reducing annual emissions by 33% by the end of RIIO-ET2 compared to 2018/19 levels.

Regulator Ofgem gave that a partial welcome, declining to agree the funding in the original form but asking the network to come back with a better-evidenced plan, indicating it would look favourably on a revised proposal.


A watching brief offshore

If transmission company commitments and Ofgem incentives work as planned, emissions from onshore transmission operators should fall. But is the industry running to stay still? Although incumbent transmission operators have committed to reduce SF6 emissions and those reductions should be ‘locked in’, and bettered in future periods, most network new-build is currently taking place outside their market.

The biggest expansion of the transmission network is offshore, where the UK’s investment in offshore wind is bearing fruit. The numbers are large: the UK expects to have at least 40GW of offshore wind to help it meet net zero carbon emission targets by 2050 – more from offshore alone than is currently being contracted in the entire Capacity Market.

Of course, offshore wind farms require offshore switchgear in the turbines and the substations. As offshore wind turbines scale up, so does the associated equipment. For example, Vattenfall’s application for the Thanet extension said that a typical 12MW turbine would contain 100kg of SF6 gas, while the site’s offshore substation would include 1.5t of SF6.

Vattenfall’s application for the Thanet extension said that a typical 12MW turbine would contain 100kg of SF6 gas, while the site’s offshore substation would include 1.5t of SF6.

SF6 switchgear is intended to be permanently sealed but routine leakage occurs, as it does in the onshore assets discussed above.  As a rule newer assets should suffer less routine leakage, as promised by SPT in its RIIO submission (above).

Offshore Transmission Owners (OFTOs), however, are not subject to five-yearly price reviews like those of onshore transmission operators,  with public engagement and with the draft determination subject to public consultation. Instead, they own and operate single transmission lines under a licence lasting for the lifetime of the associated wind farm – more than two decades.

Equally, offshore substations and other assets containing SF6 may see failures that produce larger leaks – and in an offshore situation the opportunity to seal the leak may be delayed, as maintenance may have to wait for a favourable weather window.

At least two significant leaks are in the public domain.

Sheringham Shoal OFTO topped up SF6 levels three times in 2017, when the substation was out of action for short periods in October, November and December. The onshore connection was topped up with SF6 in 2018.

At Robin Rigg, an onshore substation was the site of an SF6 leak in 2016. Pressure levels fell rapidly and eventually required the system to be de-energised. The connection was out of use on six occasions during August and September while the SF6 levels were topped up and repairs made. That leak was ascribed to manufacturing faults before the equipment was installed in 2009.

These two SF6 leaks were revealed because they formed part of Ofgem assessments of so-called ‘income adjusting events’ in which OFTOs seek credit for periods when the link was out of action through no fault of the licensee. SF6 leaks in other circumstances may not be made public. Nor is it clear what penalty will be paid.

This article was first published in New Power Report August 2020

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