IN DEPTH | Almost all the technology needed for the global energy transition already exists, but one important element is still missing — how the highly complex grid of the future will operate, writes Leigh Collins

For the world to decarbonise and meet its climate goals, we will need a huge amount of renewable energy. But the variability of wind and solar means that a range of new solutions will have to be put in place to meet demand when the wind isn’t blowing and the sun isn’t shining — including battery and thermal storage, demand response, electric vehicle (EV) smart charging, increased interconnection, virtual power plants and even internet of things (IoT) technology such as smart fridges.

The energy transition is unstoppable, says International Renewable Energy Agency technology and innovation head Dolf Gielen, but “if we don’t manage that process, we’re going to run into problems”.

The complexity of this system will be staggering. Hundreds of thousands of buildings, batteries, EVs, heat pumps and smart appliances will be used to help balance a grid powered by hundreds of thousands of distributed rooftop PV systems and wind turbines/solar farms/hydro plants hundreds of miles apart. And it is a system that is currently operated by multiple entities of vastly different sizes — transmission system operators (TSOs), distribution system operators (DSOs), utilities, independent power producers and, increasingly, new market players such as virtual power plant aggregators, demand-response providers, and EV charging networks.

All of these resources will have to work together seamlessly in a single highly efficient, omnidirectional power system. And herein lies the problem. No-one is quite sure how such a power system will function.

What TSOs and DSOs do know is that there are five related issues that will need to be resolved to enable such a system: 1) the physical changes needed to make grids smarter; 2) the market design needed to ensure that flexibility services are appropriately priced; 3) the software and data management systems required; 4) who will be responsible for what; and 5) overcoming regulatory hurdles.

Physical changes

Generally speaking, national grids consist of high-voltage long-distance transmission networks operated by TSOs, and medium- and low-voltage local networks operated by DSOs. Ownership is a mixture of public and private, depending on the country and region. This arrangement was set up over the past century as a unidirectional system — electricity would flow from large power plants, along the transmission network, to the local distribution grids.

But the electricity network required by the energy transition will be a highly complex two-way system that needs to function as one, with a growing amount of power supply and storage — as well as demand response — on the distribution grid.

In short, we need to move from dumb two-part grids to a single overarching highly flexible smart system.

This will require physical changes to the transmission and distribution grids, with digital sensors placed throughout the system to provide real-time information on the state of the power grid at every location — from the largest wind farm to local transformers and individual homes.

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“On the distribution side, I think one of the key topics is to get more transparency on the status of the distribution system at all times, at all critical points,” explains Ralf Christian, chief executive of Siemens’ energy management division. “So it means we need to put more sensors into the distribution grid to have that transparency of what’s happening. Which is not the case in most distribution grids today.

“A city, typically, is fed from the high-voltage grid, from a transmission operator, so we have a few high-voltage substations. Those are today, in most cases, smart. But then from there you move to distribution network substations and you already have hundreds of them in each city, supplying every city district. Those are not always smart today. And then from there you basically connect to the small transformer stations, where you have several thousand in a city. But those are, in most cases today, not ‘intelligent’.”

The more you invest in digital devices and sensors, the more information and value you will have, he adds, before explaining that “you could run a system” where the sensors (ie, smart meters) are largely placed near consumers.

“Because you know your grid topology, you know your consumers, and if you collect grid data close the points of consumption, then you can aggregate the information and create the right modelling for your power grid. Now, if you don’t have the opportunity, and in some regions it is the case that you can’t place smart meters close to most consumers, then you would go one step back and put additional technology into your low/medium-voltage transformer stations. Then at least you have an aggregated view at the transformer station level.”

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The cost of the roll-out of sensors will have to be considered, says Laurent Schmitt, secretary-general of the European Network of Transmission System Operators for Electricity (Entso-E).

“I think we should be careful because the grid is very large. So this is all about where there is a positive cost benefit,” he explains.

Sensors should be placed, at the very least, at utility-scale renewables projects and in heavily congested transmission corridors “ to really optimise usage of the last megawatt of the lines”, he adds, explaining that sensors can help optimise power lines through “dynamic line rating” — whereby transmission lines can handle more electricity when temperatures are cooler.

Communication between sensors and grid control centres could be carried out in a variety of ways, says Schmitt — fibre-optic cables, 4G mobile telephony or LoRa, a recently developed long-range, low-power-consumption, low-bandwidth wireless data communication system that uses sub-gigahertz radio frequency bands.

And then there has to be real-time communication between the TSO and DSO. For instance, if there isn’t enough wind or solar power available, the TSO can send a signal to the DSO to reduce demand.

The technology required for this is “there to buy, [but] it’s not yet in place comprehensively”, says Christian.

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“Technology companies like us and others have developed all the technologies over the last ten years,” he says, pointing to electronics controls, communication devices, data links and data platforms.

“It’s all there. So the question is, when does it get largely implemented?”

Market changes/price signals

In the future power grid, there will be millions, or perhaps billions, of smart grid-connected devices capable of providing balancing and congestion management services — everything from EVs to home batteries, heating and cooling equipment, and smart IoT home appliances that will turn on or off according to the availability of renewable energy.

But they will only be used for grid services if owners receive adequate payment for their use. The market therefore needs to provide a price signal at every level of the power system, and electricity tariffs must become more flexible to reflect the changing value of electricity at different times and in different places.

For instance, consumers will need to know when to consume energy from their solar panels, when to send it to the grid, when to put it into storage, when to charge their EV, when to reduce consumption to help balance the grid, and when to buy power from the grid. The home energy management system controlling this “nanogrid” will need price signals to determine how to act.

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And on a much larger scale, there will be TSOs interacting with each other at the international or regional level, TSOs interacting with DSOs, and DSOs interfacing with microgrids and individual homes.

“The common denominator through all these systems is the price signal,” says Schmitt. “The price signal should be consistently calculated from the top, representing the scarcity of generation on the wholesale [market] and the scarcity of transmission capacity (ie, congestion), down to the lowest level where we need to represent congestion on the distribution grid and potentially constraint on each transformer.”

This will require intra-day wholesale markets (where energy is bought and sold at one-hour, 15-minute or perhaps, one day, five-minute intervals) and balancing markets (which enables real-time balancing of supply and demand) that allow exchanges of small amounts of energy and the contribution of demand response.

In the EU, proposals to shape such a market design are due to come into force on 1 January 2020 if, as expected, the European Commission’s Clean Energy Package is approved by member states in the next six months.

Obviously, this smarter system will require a vast amount of data to be gathered and intelligently processed.

“It’s not a digital meter that will make the difference. It is the intelligence behind that,” says Chris Peeters, chief executive of Elia Group, which operates the Elia transmission system in Belgium and 50Hertz in eastern Germany.

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“The fundamental question,” adds Schmitt, “is ‘what is the data framework that you need to put in place so that you provide signals to all the systems so that they can transact and interact’?”

Data platform

Data will clearly play a fundamental role in the energy transition, yet there are several important questions on this subject that need to be answered: Who will manage the data? How will the data be managed? How will it be shared? Will it be stored on a single data network or multiple data platforms? Who will get access to that data? Who will own the data?

“You have multiple parties fighting to own the data and we think that this is a completely ridiculous battle,” Peeters tells Recharge. “You as a consumer own the data.”

The consumer will therefore have to give permission to any entity that wants to use their energy data, he points out, before adding: “Who gets the data? Everybody who needs it, by a real-time, secure, transparent layer.”

This “giant grid communication layer” will provide data to TSOs, DSOs, energy suppliers and service providers “so that we are sure that everybody can do their job in a decent way”, says Peeters. “Building this large network is really a critical asset to make that change in the market.”

Schmitt, however, is not convinced that there should be a single data network responsible for a national or, perhaps, an international grid system.

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“I don’t believe in a single data hub to be honest,” he tells Recharge. “I believe in sets of data-exchange platforms interfacing with each other.

“It’s what we call the power system of systems. What that means is that you don’t have a single system which controls everything. You have a set of systems interacting with each other.

“So the issue is not ‘where do you store the data?’, but the issue is, ‘what are the relevant APIs [application programming interfaces] to exchange information between these players’? Interoperability is key.”

Sander van Ginkel, who leads Accenture Strategy’s European utilities practice, believes it would make sense for two or three data platforms to be rolled out at first in different regulatory areas.

“You need a certain level of competition to get the right platform,” he says. “And then, at a certain point in time — not too early, not too late — it becomes necessary to say, ‘now we’re going to standardise this and award it to one platform’.” In the event of this “winner-takes-all” approach, heavy regulation would be required, he adds.

But the idea of a single entity controlling an entire electricity network is anathema to blockchain advocates such as Ewald Hesse, chairman of the Energy Web Foundation.

“If there will be a party like that, this body would probably be the best energy trader in the world because you’re the best energy trader if you know what’s happening everywhere,” he tells Recharge.

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His organisation is building a decentralised blockchain-based operating system for the electricity sector, the Energy Web, which would be free and “completely open” for anyone to use. This would eliminate the need for a single entity to manage the super-complex energy network as transactions would be processed by computers distributed around the world.

The Energy Web is in the testing phase until the end of 2019, with Hesse explaining that he expects the network, when it is scaled up, to be able to process more than a million transactions per second. It would also be able to manage exchanges of energy as small as a single watt-hour, allowing even laptop computers to potentially provide demand-response services.

Opinions vary greatly in the industry as to whether a blockchain solution would be the best option.

Van Ginkel doubts whether a blockchain would be able to cope with the sheer volume of transactions; Roberto Zangrandi, secretary-general of the European Distribution System Operators’ Association for Smart Grids (Edso), says that the use of blockchain “will be inevitable”; and Christian says that blockchain “would clearly be one option”.

“I think there are big expectations that blockchain will provide more efficiency in the end. I think it is to be seen if this promise holds true in the coming years,” he says.

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Who will manage what?

At the moment, TSOs manage transmission systems and DSOs manage distribution systems. But as transmission and distribution systems become increasingly inter-reliant and operate more and more as a single power system, who will manage what?

TSOs advocate that they should control the system as they are primarily responsible for the balance between generation and consumption. Some DSOs argue that they will have a more complex bidirectional system to manage, so they should take part in this control, at least for managing the congestion in their grids.

In October, the five European electricity sector associations — Entso-E, Edso, Eurelectric, Geode and Cedec — signed a memorandum of understanding “to achieve a common vision on active system management in order to integrate all distributed resources and new service providers in the electricity system and market, to ensure system security and to create value for the customer”.

“DSOs and TSOs increasingly face similar challenges and share common interests: integration of large quantities of renewable energy sources, facilitation of flexibility services (including demand-side response), roll-out of new communication equipment and software, increasing need for data, and the renewal of ageing grids,” says the memorandum.

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Yet the five associations are yet to formally agree on a way forward and common priorities.

“It’s all about what kind of services need to be managed still by the TSO on its own, what has to be managed by the DSO on its own and what needs to be managed together,” explains Schmitt. “So you need to drill down to the various sets of services related to system operation and be able to define what goes where.

“We currently have an existing paper that is getting prepared, which will be released, I think, in the first quarter of 2019. The topic of this paper is called ‘active system management’, which tries to conceptualise the role of the DSOs and TSOs and to define overarching principles of how this coordination needs to be organised. The one-integrated-system approach, where the system is seen as a whole, rather than as subsystems, is the starting point for this work.”

In the end, there may not be a single model for TSO-DSO co-operation in Europe, he adds, explaining that “we try to adapt to various examples and models of collaboration depending on the country”.

“So in the Nordics, TSOs develop the data hubs and do have a mandate from their regulator to further expand into flexibility markets. Of course, creating the right level of interface with the DSOs and so on,” Schmitt says.

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“If I’m looking at another market, such as in The Netherlands, with [TSO] TenneT and three DSOs, my understanding is that they are trying to look at using certain flexibility services together... so that together they can source and buy flexibility in a co-ordinated way that is optimal for the system.”

There are also some European Commission-funded research and innovation projects, such as Smartnet, which showcases potential TSO-DSO co-ordination schemes in Italy, Denmark and Spain; and two that are due to start in January 2019, Interrface and Coordinet, which will further evolve TSO-DSO co-operation and co-ordination for pooling and allocating distributed flexibility

Zangrandi explains that discussions include whether TSOs and/or DSOs should participate in flexibility markets.

“It will take quite a bit [of work] to align the approaches on flexibility management from country to country, provided that the national regulatory authorities will allow, at a certain point, two regulated subjects, DSOs and TSOs to put — along with independent market operators — their fingers into a market product.”

Peeters is adamant that TSOs and DSOs should not participate in flexibility markets.

“We’re system operators. We should not be directly involved in the management of the flexibility itself. Neither in the management of the energy. We should focus on our core task, which is providing the system on which commercial parties can do their job.

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“We should make an open system, taking into account cybersecurity and access rights, etc, but that actually allows the commercial segment to do what it needs to do and that it does hopefully much better than we ever can do it because we’re a regulated business focused on a technical act.”

Challenge of change

Despite all the technical, market and regulatory changes (see panel, above) required, the industry seems confident that all the problems will be overcome.

“The necessity is rising quickly with the emergence of new consumers on the demand side, like electric cars, and newer generation on the supply side, with small solar, medium solar, big solar, same on wind, and the more you get on the grid, the more the necessity is rising,” says Christian. “So, to a certain extent, I think there’s a certain gravity towards these technologies, so it will happen.”