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How can Europe's gas networks be decarbonised?

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Decarbonising Europe’s gas networks could save consumers €1150bn by the year 2050, according to a study by the consulting and engineering firm Pöyry. The study compared the costs of decarbonising gas with an all-electrification approach.

Given the advantages of using existing infrastructure as part of the decarbonisation drive, we ask: what are the available options for “greening” gas, and what would a decarbonised gas network actually look like?

This article has been adapted from our industry review paper, Gas in a Low Carbon Energy System, available here.

The H21 Project

In the north of England, a revolution is taking place within the region’s gas networks. Centred initially on the United Kingdom’s third most populous city, Leeds, the H21 project aims to build what will be the world’s first hydrogen economy.

The introduction of steam methane reformers, hydrogen transmission pipelines, converted salt cavern storage and hydrogen compatible infrastructure in the Leeds region (known collectively as the H21 Leeds City Gate Project) is the first in a series of developments – some planned and some already underway – that include the H21 North of England Project and the H21 NIC programme.

If the technology proves successful in Leeds, the goal is to convert gas networks to hydrogen in the surrounding cities, the major urban centres of the north of England, and the rest of the country, all over a timescale of approximately thirty years.

The H21 Project’s Programme Director, Dan Sadler, explains that the objective was “to ask whether we can convert the gas networks to 100% hydrogen: are they the right size, is the pipeline capacity large enough to do that in terms of energy security, how do we source the hydrogen at that credible scale in a low carbon system approach, how much would it all cost, and how would we roll it out to the UK?”

The answers so far have all been positive. If it is successful, he believes H21 will be “the most impactful project in terms of climate change anywhere in the world.”

The H21 project takes one of two possible approaches to producing hydrogen; the other being the power-to-gas approach. Power-to-gas utilises energy from other sources, typically renewables, to convert water into hydrogen for later use as a fuel.

The H21 project, on the other hand, uses a process of steam methane reformation to strip hydrogen atoms away from the carbon molecules in natural gas. Carbon capture and storage technology is then employed to trap approximately 90% of the remaining carbon, which can be injected into the North Sea’s extensive network of depleted hydrocarbon reservoirs.

There are numerous advantages to producing hydrogen from natural gas in this manner. Sadler explains that “in terms of the supply chain nothing changes,” allowing the hydrogen economy to build upon existing business models while simultaneously facilitating the transition to a profoundly less carbon intensive energy system.

“What you want is a market push with credible, scalable technology today,” he says. “Natural gas can be used as the feedstock to produce the hydrogen with the aid of CCS… and this can be the bridging system to a longer term, entirely sustainable green hydrogen future.”

Scalability is central to Sadler’s understanding of the H21 project’s necessity. Though he recognises the important role power-to-gas can play when used in conjunction with renewable power generation, a lack of surplus renewable power in the present means that he sees its full potential realised only as an “end game” solution.

“We don’t want to wait forty or fifty years,” he says. “We want to start the hydrogen economy now, with systems that are over 90% decarbonised, with credible technology at the right scale.”

To place the challenge in context, he provides the example of the London Array, currently the world’s largest operational offshore wind farm. The array “produces an intermittent 2 terawatt hours,” he says. “But you need 6 terawatt hours for just one city.” In Sadler’s opinion meeting this much demand with hydrogen, at least in the near future, leaves no alternative other than using natural gas as a feedstock.

The example of the London Array illustrates what is probably the most persuasive part of Sadler’s case for the H21 projectas a model for meeting the climate challenge – his insistence on placing proportionality front and centre when discussing the available options. “I get a bit tired of the comment, ‘there’s no silver bullet’,” he says.

It is self-evident that while reducing carbon emissions will involve a broad range of different technologies operating in tandem, the contributions of these solutions will by no means be equivalent. “At the end of the day you might need every bullet you’ve got,” he says. “But a 100% hydrogen conversion would solve around 60% to 70% of the net decarbonisation challenge – so it’s a big deal.”

It would appear that the arguments made by Sadler and other SMR advocates are not falling on deaf ears. He reels off an impressive list of countries that have either initiated H21-style projects or expressed interest in doing so, including New Zealand, Australia, Japan, Hong Kong, China, the Netherlands, Italy, France, Germany, Norway and Canada.

Whether H21 and its counterparts can deliver on Sadler’s vision of a low carbon hydrogen economy – and whether the United Kingdom will be the first to achieve it – is a question that remains to be settled.

The H21 Leeds City Gate Project in Numbers

  • 1025 MW: production capacity of the four Teeside based SMR facilities
  • 6.4 TWh: total annual demand in a peak year
  • 4000 MWh: of intraday salt cavern hydrogen storage
  • 700,000 MWh: of interseasonal salt cavern hydrogen storage
  • 1500,000 tonnes: of CO2 sequestered per annum
  • £2000,000,000: cost of converting Leeds to a fully hydrogen based gas network (including associated infrastructure and appliance conversions)

Source for figures: March 2018 H21 Update

 

Power-to-Gas (P2G)

Although SMR may provide a faster route for delivering a hydrogen economy in the near-term, particularly in countries with highly developed natural gas networks, hydrogen production through electrolysis (or power-to-gas) is starting to gain a foothold on the continent.

Prominent power-to-gas projects, such as Uniper’s WindGas facilities in Falkenhagen and Hamburg, are demonstrating how gas networks can develop alongside renewable power to deliver energy reliably and efficiently.

“Currently, there are about 30 different pilot projects in Germany that test the technology for efficiency factors, scalability and cost benefits,” Zukunft ERDGAS’s Timm Kehler tells us. The number of such projects will only grow as the share of renewable energy increases, and the need to store excess energy from peak generation periods becomes more pressing.

A point worth noting is that the size of the demand and the resources available for converting gas networks to hydrogen differ somewhat between the UK and the continent.

Justin Goonesinghe, of National Grid, explains that in countries such as France, which have fewer available options for carbon sequestration and are already more reliant on electricity for home heating, “a relatively small amount of hydrogen” would be needed to replace the existing demand, making power-to-gas a much more realistic near-term option.

How the hydrogen economy develops, whether primarily through power-to-gas or SMR, will therefore probably be strongly influenced by the state of the existing natural gas infrastructure, and the amount of progress made with introducing renewable power. The end state objective for both will be the same, though: a hydrogen gas network supplied entirely or almost entirely by renewable power-to-gas.

A second point worth noting is that the name power-to-gas imparts a somewhat more linear impression of the technology’s potential than it deserves. Johan Zettergren, CEO of Swedegas, believes the future will bring “modern energy hybrid system where gas can become power and vice versa” – where surplus energy from renewable power generation can be stored indefinitely, and then either fed into the gas network, or used to cover demand from baseload power generation.

As with the H21 project, the underground salt caverns currently used for natural gas storage could be used for this purpose, or if the options for underground storage are limited, ammonia could be employed as a carrier to store the hydrogen in above-ground tanks.

Hydrogen’s other virtue – as with all gaseous fuels – is its facility for transporting energy over long distances without significant inefficiencies. In a future with substantially more power-to-gas capacity, the effects on the world economy could be transformational. Regions such as Australia, “which can produce 10,000 times more energy in solar alone than they can ever use domestically, can start to trade green hydrogen globally,” Dan Sadler predicts. “But that’ll take fifty years at least.”

Biogas & BioSNG

Besides hydrogen and CCS, the other frontrunner for decarbonising gas is biogas and bioSNG. Biogas is typically produced from waste materials, such as animal manure, sewage or green waste, by subjecting them to a process of anaerobic digestion or fermentation.

This releases a combustible combination of methane, CO2 and hydrogen-sulphide, which can be burned to meet local heating or power generation requirements, or – more commonly – cleaned of impurities to produce biomethane. As with fossil methane, biomethane can be fed directly into gas networks, or liquefied and traded as bioLNG.

In distinction, bioSNG (bio-synthetic natural gas) is produced through the gasification of cellulosic feedstocks, such as woodchips, cellulosic fuel crops or inedible food crop by-products.

Much like liquid biofuels, biogas is typically described by its supporters as a fast and non-disruptive way to reduce emissions. As it is compatible with existing infrastructure and appliances, increasing the share of biomethane in the gas networks incurs none of the costs associated with conversion to hydrogen.

Moreover, the technology needed to produce it is already proven and well established. “The role of biomethane currently tends to be underestimated,” Timm Kehler tells us. “We have about 200 injection points for biomethane in Germany… [and] there are 120 fuel stations in Germany where customers can tank up with 100% biomethane.”

Kehler is optimistic that increasing biomethane production can help the case for switching to gas in the transport sector. “CNG customers are usually very loyal and convinced of the technology and cost advantages of gas in mobility,” he says, “so the increasing share of biomethane is another argument to opt for a CNG car.”

Unfortunately there are limitations to the total contribution biogas and bioSNG can make towards decarbonising the gas networks, although they have yet to be reached. There is a finite amount of waste material available for conversion to biogas, while opting for the use of fuel crops grown specifically for biogas/bioSNG production brings about the issue of competition for land use with food production.

There is also the potential problem of competition for the use of limited quantities of feedstock with the liquid biofuels industry. Dan Sadler’s perspective is that decision makers ought “to look at the amount of realistic feedstock from a biological source, and say, if that is the net amount, what is the best way to use it in the decarbonisation challenge across transport, electric and gas?”

Nevertheless, there are good reasons to suppose that the use of biomethane and bioSNG will continue to grow strongly for the foreseeable future. One of the advantages of utilising gas produced from biological sources within the energy transition is that it can sit comfortably alongside the development of the hydrogen economy.

Where hydrogen is likely to make the most progress in high cost, high impact urban projects such as the H21 Leeds City gate project, biogas is much easier to introduce in rural areas close to where it is produced, and where the costs of wholesale conversion to hydrogen compatible infrastructure would bring more modest benefits.

The Gas Network in Transition

If the gas industry takes seriously its commitments to delivering a low carbon energy system, networks a few decades from now will look very different to the way they look today.

A gas network in transition, equally reliant on fossil methane, hydrogen and biogas/bioSNG to meet consumer demand, would have completely different flow patterns to the networks we are accustomed to, in which gas supplied typically from a comparatively small number of input points moves mainly in a single direction. The growth in biomethane will see gas flowing outwards from a large number of widely distributed sources, which in Justin Goonesinghe’s opinion will require “network reinforcements in some of the more agricultural areas of the UK in order to manage flows” – perhaps as soon as the mid-2020’s.

How the hydrogen economy develops will also have a sizeable impact on the transmission and distribution networks. A gas network heavily reliant on SMR hydrogen would bring about an increase in demand for natural gas as a feedstock, which Goonesinghe points out “would probably cause a completely different geographical dispersion of that demand; potentially a different dispersion of demand within the day or within the year.”

Adapting to radically different geographical dispersions of demand and supply is understandably imposing. “We have a huge and quite complex gas industry framework, and licenses and codes which have been developed over many years which enable us to safely and efficiently manage the flow of gas in the network,” Goonesinghe says.

“When it comes to hydrogen none of these frameworks exist – so who’s going to develop them, who’s the regulator, what do the codes look like, and how do they work effectively with the electricity system? There’s a huge amount of uncertainty out there as to which model is physically possible, and which model is optimal from a commercial point of view as well.”

National Grid are doing a great deal of work to prepare for these eventualities, daunting as they may be, particularly through the Future of Gas initiative (in which Goonesinghe is a participant). By outlining some of the possible outcomes for the gas network in the energy transition, they are giving industry stakeholders the opportunity to develop some of the tools – technical, regulatory and financial – that will be needed to decarbonise the gas networks while keeping the impact on consumers to a minimum.

Their efforts will need to be matched elsewhere in the industry, supported by policy makers, and met with the proper levels of investment if the goal of a low carbon, gas-based energy system is to be attained.

This article has been adapted from the industry review paper, Gas in a Low Carbon Energy System. You can download the full paper for free here.

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