Utilities globally are realising that digitalisation is the way forward to cope with the rapid changes and challenges in the industry, given the growing number of consumers, prosumers and renewable energy integration. In a recent interview with Power Line at ABB’s Zurich headquarters, Massimo Danieli, managing director, grid automation, ABB, spoke about the digitalisation trends in the power industry as well as the solutions and technologies enabling the digital transformation. Excerpts…
What does digitalisation of the power grid really mean?
Today, many people speak of digitalisation of the grid with reference to the digital substation. Digital substations that utilise the 61850 protocol have now become a widespread technology. However, the market, including us, is taking the next step in digitalisation. The focus is now on utilising digital communication and digital sensing technologies. This step is essentially to bring technology to the process bus concept. We use digital sensing and digital communication technologies in order to make the design of the substation linear. At the same time, these technologies are being used to collect more information from the sensing devices in the substation. This helps to achieve two objectives. First, this helps design substations that are more compact and hence have a smaller footprint and lower capex and civil works costs, and allow faster commissioning.
The other benefit is that through digital technologies, a lot more information about the status of the main components, whether it is a transformer, breaker or any other component, is now made available, which makes it a smart digital substation. While this may seem adequate, it does not really provide a lot of benefits unless software analytics capabilities are added, particularly asset performance management. With analytics, a complete picture of what happens at the component level becomes available and this helps implement newer strategies for operations and maintenance. Typically, utilities have been more operational technology (OT)-oriented and have looked more towards deploying assets that are controllable and reliable. However, now with cost pressures, they are looking at analytics to optimise costs.
Apart from substations, another key area for digitalisation is the maintenance of power quality in the network with the rise in renewables and distributed generation. Solutions like distributed energy resource management system (DERMS) are being used by operators to keep the grid balanced and optimised in real time while maintaining system reliability and power quality.
When was the first truly digital substation commissioned? How many such substations have been commissioned since then?
ABB commissioned the first digital substation in Australia in 2012. A few dozen have been set up by ABB since then. The majority of these have been in the pilot phase since utilities tend to be quite conservative in their technological approach and substations are a delicate part of the network. However, we now see a big momentum with many utilities wanting to move from the pilot phase to implementation.
What have been the challenges so far in deploying digital substations?
We do not really see any technological challenges since the solutions that are available today are at a good stage of maturity. However, one of the main challenges is changing the mindset and competency of people, which requires them to move away from a conventional, wired type of environment. So far, engineers, users, engineering, procurement and construction (EPC) contractors and vendors have felt safe with a certain architecture, which they have used for a long time. To move to a digitised network, with vast amounts of information and cybersecurity concerns requires a different type of knowledge of design, implementation and maintenance. This is not very different from what happened 15 years ago with process automation moving to field bus.
How does the cost compare?
One of the biggest components of cost for the end user is land. If a substation is built in a desert, the costs are lower as compared to a substation that is built in a city like Mumbai or New York. With digital substations, there is a huge reduction of about 50 per cent in footprint. This significantly reduces civil works costs. There is also a reduction of up to 80 per cent in cabling costs. The overall capex is much lower. Another key factor impacting capex is the reduction in commissioning time by up to 40 per cent. This is possible since pretesting can be done through software as opposed to conventional technologies for which testing needs to be done on the field. On the operations and maintenance front, the cost reduction comes in once software and analytics technologies like asset performance management are utilised. By monitoring the behaviour of key components like transformers, it can be detected if the transformer is deviating from the optimal performance; it is also possible to predict when the transformer will enter a critical situation. So, instead of practising routine maintenance, utilities can start managing predictive and risk-based maintenance. This also helps reduce downtime.
What has been the utility experience in using such data?
There are some forward-looking utilities that are implementing not only the software but also the processes from which they derive various advantages. For instance, one of the large utilities in the US has implemented a system from which they are able to monitor more than 8,000 transformers and a few thousand breakers. They now run maintenance on a risk basis. Their savings are significant on the opex side.
How has been the uptake of DERMS so far?
ABB is quite strong in the network control business and is one of the leaders in the market. We are very strong, especially in the US and European markets, in advanced distribution management systems (ADMS). What we have started seeing is that utilities are now asking for expanding ADMS to DERMS, which would allow them to better control the network with the growing number of prosumers.
Today, the business is getting better defined because the main issue is the stability of networks, and utilities are looking for a method or tool to support it. ABB has decided to invest in Enbala Power Networks and we are working together to integrate DERMS into the ADMS platform so that we can provide our customers with complete solutions from controlling the grid to managing outages. However, the kind of business model that is adopted will ultimately depend on the regulatory framework in different countries and the incentives offered for controlling the grid, the storage solutions, etc.
What is the big difference between ADMS and DMS? What is the advanced part of it?
The definition may vary by company, but we define DMS as mainly the set of applications needed to run the electrical network. So, power flow, optimisation, stability and power control are what comprise the electrical control part. The advanced part has to do more with outage management – so we look at how a certain feeder that gets out of service can be managed along with all the processes from service shutdown to re-establishment of the connection.
With increasing complexity and a growing number of consumers, the distinction between electricity transmission and distribution systems is getting blurred. What are the big risks that utilities have to watch out for?
Cybersecurity remains one of the biggest threats with more access points and connectivity. There is an exponentially increased risk of penetration intrusion and potential of dramatic incidents. From a technical point, we do not really see big risks because of the blurring of the segments compared to a more segmented grid. However, there are definitely challenges. Planning becomes more complicated as grid stability issues arise with greater injection of renewables. Bulk renewables can be managed; however, with distributed renewable resources, it becomes more difficult to control power and, therefore, we have started using technologies like DERMS. For solar parks, the challenge is more about planning the right interconnections to make the grid stable.
What work is being done by ABB in the area of smart cities?
We are working in many areas of smart cities. One area where we see great momentum is connectivity and communications. The underlying concept of a smart city is that there are a lot of smart devices. However, there is a need to connect all these devices on a common platform. So, deployment of wireless IP technologies is one area where we see momentum, whether it is to connect meters, to carry out distribution automation, or do more intelligent management of street lighting. In the end, a common platform is needed where all these activities can be channelled.
Other areas where we are working are related to connected asset life cycle management, which combines an asset management system with collection and analysis of asset performance data and a comprehensive workforce management solution for dispatching crews, and helps companies adopt a proactive approach to enterprise-wide management of assets, people and processes. This is an area where we see a lot of potential in smart cities because there are a lot of distributed assets.
Are you looking for a platform to integrate all of these?
ABB has a whole set of components and software solutions. For Enterprise Asset Management, we have a solution called Ellipse and also AssetSuite; for asset performance management, we have a solution called Asset Health Center; and for workforce management, we have a solution called Service Suite. At the group level, we have now launched an initiative called ABB Ability, which is unifying cross-industry digital capability – extending from device to edge to cloud with devices, systems, solutions and services, and a platform, so that we can provide flexible functionality to customers.