Rapid network expansion has rendered the management of grid operations much more complex. Forecasts made by Cigré, an international council on large electric systems, claim that in the future, electric power systems will be characterised by bidirectional flows as the world adopts more renewable
sources of energy and microgrid or nanogrid models. In such a scenario, digitalisation of substations has gained significance because utilities want to be able to remotely monitor, operate and control their assets to improve system stability, efficiency, security and control.
Substation digitalisation involves the integration of the protection, control and data acquisition functions into a minimum number of platforms by eliminating redundant equipment and databases, thereby reducing capital and operational costs, and panel and control room space requirements.
Key components of a digitalised substation
Some of the key components deployed to monitor, control and configure substations in a single functional array, that is, digitalise them, are intelligent electronic devices (IEDs), bay controller units (BCUs), and equipment condition monitoring (ECM).
IEDs are microprocessor-based devices that are equipped with a communications port to enable the electronic transfer of analog, status and control data of the substation in a standard transmission format. IEDs facilitate the exchange of both operational and non-operational data. In the conventional protection system, the data and control signals from relays are sent through a remote terminal unit (RTU) to the supervisory control and data acquisition (SCADA) system. This requires an extensive network of cables between various bays in the substation and the control room. However, with IEDs, intelligent RTUs allow a two-way direct communication between the IEDs and the utility’s SCADA system, thus eliminating the need for extensive cable networks.
BCUs perform various functions such as managing close or open commands to the switchgear and the operations of the protective relay equipment, and also undertake synchronism checks for circuit breakers. Besides this, BCUs monitor all other equipment at substations and record the activity of substations at regular intervals.
ECM ensures continuous real-time monitoring of all substation assets. It also provides information on both current conditions as well as historic trends, thus helping determine the operational ability and status of the substation equipment through online monitoring and maintaining of records. ECM helps detect abnormal conditions in the working of the equipment and initiates action to prevent failure, thereby significantly reducing downtime and maintenance costs, and improving reliability.
Benefits of digitalisation
Digitalisation allows for detailed and faster fault analysis in the grid, and reduces downtime and operations and maintenance costs. Besides, solutions like ECM allow the power system to heal itself in emergency situations. Further, solutions for forecasting are useful for identifying a potential grid security threat. Of late, cybersecurity concerns amongst utilities have increased, thereby giving prominence to these solutions.
Digitalisation also mitigates the need for comprehensive wiring between the devices found in conventional substations by providing network segmentation and IED reconfiguration. Point-to-point wiring networks entail high capex, are difficult to maintain, and increase the difficulty of fault isolation and detection.
Digitalisation adds intelligence to substations by incorporating communication devices with controls and analytics. While communication is managed by routers, protocol converters and gateways, IEDs control, analyse and monitor the process parameters as well as provide system protection.
As per industry estimates, digitalisation of substations can have the following quantifiable benefits: 60 per cent lower space requirement in the relay house, up to 50 per cent reduction in outage time, up to 80 per cent lower copper cable usage in air-insulated substations, and 40 per cent lower time to install new protection and control systems.
Requirements for digitalisation
The key factors that must be considered for selecting digitalisation solutions for substations are adaptability, distributed architecture and flexibility. The system should be adaptable to any vendor’s hardware. It should have a distributed architecture to minimise wiring. Further, it should be flexible and easy to set up by the utility. The system must interface with each of the IEDs in the substation and data from all the IEDs must be sent to the utility. It is important to note that the data type and substation control mechanism are dependent on the selection of the IEDs in the system, which should be addressed on a case-to-case basis. Further, the entire data required for operational purposes should be communicated to the SCADA system via a communication link from the data concentrator.
Meanwhile, data for non-operational purposes needs to be communicated to a dedicated data warehouse. The utility must establish a uniform communication protocol that allows communication between two devices. Any differences in the protocol of different devices may lead to communication errors. The substation integration and digital architecture must allow devices of different makes to interoperate, using a standard protocol. Also, the substation host processor must align with the relevant standards and specifications, possess strong networking abilities, and support an open architecture. Besides, the local area network of the substation should adhere to the interoperability standards. The substation’s user interface must be designed intuitively to ensure optimal use. There is also a need to develop an interface with the energy management system (EMS) that will allow utilities to monitor and control each substation and the EMS.
Standards and protocols
One of the key challenges for substation digitalisation is interoperability. There is a need to ensure a generic interface for IEDs, which is not proprietary to the supplier. Another critical issue is the inability to efficiently extract the required information from the system, owing to the large quantity of data originating from IEDs. Different devices store data in different formats, such as waveform samples or event reports, which are not easy to compare. Communication networks comprise lower-level data links, as well as physical-layer and multiple application-layer protocols. The addition of automation devices makes the substation architecture and technology landscape highly complex. To mitigate this complexity, standards and protocols are required to define the architecture of digital substation communication systems. Communication protocols determine the manner in which information flows between devices including control stations and IEDs.
Utilities also face the issue of interoperability between IEDs supplied by different vendors during the expansion of an existing electric substation. As a result, substation vendors are moving away from a serial-based to an Ethernet-based IEC 61850 client/server communication standard.
This standard supports interoperability between devices, applications and functions through standardised data models and information exchange, and can be applied at the process level. In the case of IEC 61850, the application model and communication stack remain independent, implying that applications can be modified without changing the communication stack. There are over 50 communication protocols available for legacy substation automation systems. Various legacy communication protocols including Modbus, Ethernet internet protocol (IP), DNP3 and IEC 60870-5-104 have been used at the utility level for digital substation systems.
However, the IEC 61850 standard is a reference architecture for electric power systems, which simplifies the substation digitalisation procedure, optimises device selection, increases efficiency and allows flexible configuration of communication networks. It is a part of the International Electrotechnical Commission’s (IEC) Technical Committee 57 set up during the mid-1990s. The final component of the 10-part IEC 61850 was declared as an international standard in 2005.
A key feature of the IEC 61850 standard is that it provides a set of abstract data models, which can be mapped on to a number of protocols. It also translates substation data into information models in the form of standard naming conventions. Further, it structures and formats data for easy information management, making it possible for applications or databases to remain unchanged, despite changes in communication protocols or media. The data model standardises the substation configuration language to describe substation topology and information models, and it defines the process bus, which is supported by generic object-oriented substation events and generic substation status events.
Conclusion
The need for huge investments in digitalising substations is hampering the implementation of such solutions, particularly in the distribution segment. Utilities need to play a proactive role in defining their automation requirements and selecting the right technology or solution from the plethora of options available in the market.
