Revolutionising power distribution: unveiling the future of energy with virtual substations
Arnaud Cantin, Senior Vice President of Schneider Electric’s Digital Power Business
The concept of the software-driven ‘virtual substations’ is being pioneered by Schneider Electric as the next evolution of this key infrastructure for the grid of the future.
As digital technologies advance and digitalisation becomes more embedded in the energy sector, new levels of automation and control for system operators are emerging that can hasten the dynamic renewables-based grid of the future.
Electrical substations play a critical function in the energy system, interconnecting the different voltage levels and enabling the two-way flow of power across networks.
To find out how Schneider Electric is evolving the substation and the impacts on network operators and operations, Smart Energy International (SEI) sat down with Arnaud Cantin, Senior Vice President of Schneider Electric’s Digital Power Business.
SEI: What is a virtual substation and how does it differ from the traditional substation?
AC: A virtual substation entails the running of all functions that control a substation within an information technology (IT) environment, with all the time-critical and sensitive functions moved into a pure software space. With this, we are eliminating the traditional IEDs that are the ‘brains’ for functions such as protection, control, and metering, but also those for the networking elements such as cybersecurity, switches, firewalls, and routers. All of these are centralised in software, which also offers the flexibility to adapt and dynamically manage these functions over time. From our perspective, the virtual substation is the next step from a digital substation.
In a primary substation, the actuators and sensors will be outdoors or enclosed in a GIS enclosure while the protection and control space is in a clean room inside the substation. In the virtual substation, the protection and control functions are virtualised into a set of servers or PCs within the substation.
SEI: What are the components of a virtual substation and how does the technology work?
AC: Starting bottom up, sensors are becoming digital, which means we are moving from sensors directly plugged into IEDs to sensors directly linked to a merging unit, which drives the A-D conversion for voltage and current measurements and manage the I/Os input-output that provides the status and the control of the different electrical equipment.
The merging unit is a new element of the digital substation and a must-have for virtualised substations.
From our discussions with customers, the merging unit will also need to host backup protection functions because there is some sensitivity around the centralisation of all protections in a computer.
In addition, we run fibre optics into the servers that host the virtualised ‘brains’ – in our case three servers. This system naturally reduces the physical footprint.
For example, we are doing a test project with French Transmission System Operator, RTE, and can replace 14 metres of protection and control enclosures with a 0.8m rack of servers. This translates to a saving of more than 1,000km of wiring with just two runs of fibre optics and reduces the footprint of the protection and control system by a factor of 10.
SEI: What are the main advantages of virtual substations?
AC: We see three different areas of which one is on the project side, with the simplification at the hardware level.
Typically, in medium-voltage, the bay control units and protection relays are physically implemented within the switchgear, meaning the equipment is highly engineered and complex. Through the virtualisation, we separate the hardware layer from the ‘brains’ which are hosted in the software.
From this point, the switchgear can be standardised with embedded sensors, e.g. voltage and current sensors, by default. In that way it would become a standard item, enabling deliveries to move from typically nine months to a couple of weeks.
It’s a complete transformation of the way one builds a substation.
The second is in the speed and the quality of the work that can be done during the project execution. Today, one can only test the full system at the last hour of the commissioning phase, when the most complex issues are only figured out.
With the virtualised substation, the software application hosting the configuration of the full protection and automation system can be tested in a simulated environment.
Therefore, de-risking project schedules and quality risks from the last-minute changes that are usually done on-site.
The third, and perhaps the most important, is the flexibility it is creating, with the ability for the application schemes to be upgraded dynamically and remotely without interruption of the electrical process.
The grids are evolving faster and faster and the speed at which utilities need to create dynamic grid management schemes in the substation is increasing exponentially with all the renewables and electric vehicles coming online.
But investment is not following and the ability to have a solution that can be installed once and then easily upgraded is highly attractive.
SEI: How does the virtual substation impact the integration of renewables into the grid?
AC: There are two ways. Firstly, adding a renewable generator into an existing substation is made much easier and can be prepared and tested remotely.
Secondly, at the grid management level, protection and automation schemes can be updated to accommodate the new flows of energy, without the hassle of a truck roll to the relevant substations and the associated downtime.
SEI: Are there any notable real-world examples or case studies of virtual substations in action?
AC: It’s too early for any deployments in the field and the development we have done with RTE is in a test facility that emulates the dynamic behaviour of a complete substation. We have implemented full testing in a secondary substation environment to qualify the performance and reliability aspects – and very successfully. While this has not been implemented on the primary substations yet, the secondary substation environment enables us to perform live testing with a reduced level of risk.
SEI: What are the potential challenges or drawbacks associated with implementing virtual substations?
AC: The biggest must be the trust that we and our customers have in the solution; it needs to be proven. We have already done some extensive testing and are running the injection of analog signals into our system to be able to test the end-to-end performance.
We feel that technically speaking, we can reach the level of performance and availability that the system needs, but we need to prove that to our customers.
Then there is the change in operating and maintenance procedures. Field service personnel are used very specific safety procedures in the substation environment. The solution is net positive from that safety standpoint, as instead of having to stand in front of the equipment, the switchgear can be operated from a PC located at its side or even in a separate room.
But that represents a big change of habits, and they also need to get used to having a PC and a touchscreen to operate the switchgear. It will take some time to redevelop safety procedures and train personnel to become familiar with the setup.
SEI: What are the cybersecurity risks in this new approach?
AC: Cybersecurity is already a challenge, whether the protection is implemented in a server or in an electronic device. Moving it to an IT environment makes it easier, as there are more mature tools and methods to ensure security at that level.
But the OT domain isn’t moving as fast so when one moves to an IT environment to run the OT, one benefits not only from the cybersecurity features themselves but also from the ways to deploy and upgrade them.
SEI: What role do data analytics and predictive maintenance play in optimising virtual substations?
AC: Getting data from the substation is already possible and it doesn’t make much difference whether it is hosted in a PC or pushed through a gateway from the IEDs. The virtual substation advances in being able to bridge together the real-time applications of protection, control, automation, metering, etc. with the non-time critical functions such as data management and cybersecurity.
These also become part of the same computer environment as the analytics, which can then be very easily upgraded, without having to wait for a shutdown.
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SEI: Can you expand a bit more on how virtualisation impacts grid management and control?
AC: This is significant. In today’s substations, if one has for example a FLISR scheme and one wants to upgrade it, or the topology of the network is changed, then personnel will need to be sent to the site and a shutdown will be required. With the virtual substation, the scheme can be deployed and managed remotely.
This is where we come back to the flexibility that is offered to adapting the protection and control and other schemes with changes to the grid or new loads on the system – and they must be within the substation to meet the latency requirements.
Another area we are exploring with customers is the dynamic change of automation schemes when an Advanced Distribution Management System is managing the grid operations, i.e. the creation of dynamic interactions between the grid management system and the substation automation.
SEI: What are the long-term implications and trends for virtual substations in the energy sector?
AC: At the low voltage level, most of the substations are not connected and automated today, but with the distributed resources and electric vehicles coming onto the grid, as well as the need to integrate smart metering, the need to digitise them is becoming urgent.
A scheme that is cost-effective to deploy at scale and can ensure that every new substation that is deployed is virtualised by default, would enable to make the integration of renewable generators and large dynamic loads easier and faster.
In the case of the larger substations, of which there are not so many new ones being built, there is the opportunity to virtualise in step-by-step upgrades.
We expect the large-scale deployment of virtual substations to start in the next five to ten years, when the technology has been validated and preparation has been made for the changes in habits that come with them.
At this stage, the most advanced in terms of adoption is the UK and there we expect the first deployments in the coming years.
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