Substation automation is becoming increasingly important as the complexity of the grid increases with the growth in generation in the share of intermittent renewable energy sources, which requires greater coordination, control and protection of the infrastructure. Over the past few years, the number of substations installed at the transmission and distribution (T&D) level has increased exponentially, especially at high voltage levels of 400 kV and above. Given the rapid grid expansion, substation automation technologies help in ensuring system efficiency, security and reliability.
Automation solutions can provide better visibility to the grid and add intelligence to the substation by incorporating communication devices with controls and analytics. Substation automation systems (SAS) provide advanced disturbance management and event recording capabilities in T&D networks, resulting in detailed and faster fault analysis. Smart substations are capable of responding to real-time events, enabling faster restoration of faults and ensuring effective asset management. Besides, certain automation solutions can allow the power system to heal itself during emergencies. As a result, there is better grid monitoring and prevention of blackouts. Further, automation solutions for forecasting are useful for identifying a potential grid security threat. This can help utilities overcome grid instability issues in light of the increasing share of intermittent renewable energy sources in the electricity generation mix.
Substation automation enables users to lower operational costs by reducing the manning needs of substations. It also helps utilities avoid costly downtime of assets by enabling predictive maintenance and planning. Smart technologies help utilities expand their network in remote locations. It can further result in savings, by enabling peak load shaving and demand response.
As per industry estimates, a typical distribution utility with a customer base of 1 million and aggregate technical and commercial losses of over 30 per cent can achieve savings of up to Rs 430 million per annum through substation automation. This is possible through manpower redeployment in strategic functions, controlled load shedding, reduction in overdrawal from the grid, and reduction in the time required for fault detection and correction.
Substation automation entails integrating protection, control and data acquisition functions into a minimum number of platforms to reduce capital and operational costs and panel and control room space, and eliminate redundant equipment and databases. The key components include intelligent electronic devices (IEDs), bay controller units (BCUs), supervisory control and data acquisition (SCADA) systems, human-machine interface (HMI) and communication interface. These devices enable centralised control and monitoring of substations, which reduces installation and maintenance costs, lowers the chances of manual errors and improves equipment reliability.
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. Some IEDs are digital relays, smart meters, reclosers, digital transducers, programmable logical controllers, capacitor bank controllers and load tap changer controllers. Prior to the introduction of IEDs, the data and control signals from relays were sent through a remote terminal unit (RTU) to the SCADA system, which required an extensive network of cables between various bays in the substation and the control room. However, intelligent RTUs allow two-way direct communication between the IEDs and the utility’s SCADA system.
BCU is another key component of SAS, which helps perform functions such as managing close or open commands of the switchgear and the operations of the protective relay equipment. It also undertakes synchronism checks for circuit breakers. Besides, the BCU monitors all other equipment at the substation and records the activity of the substation after a certain time interval.
Substation automation can be structured into three levels: process, bay and station-level automation. At the process level, information from the sensors in the substation is extracted and transferred to an upper-level device called the bay-level device. At the bay level, maintenance work is undertaken only within one bay and devices are usually located close to the switchgear. At the station level, process-related functions include the collection of substation data from bay-level devices, and the interface-related functions comprise interactive interface of the SAS with the local station HMI and control activities of the tele-control interface. There are control points at all three levels and remote monitoring is executed through a router or a modem.
Communication systems form a vital component of SAS, as secondary equipment within a substation should be interlinked with communication buses. In the case of conventional substations with legacy communication, serial communication buses or proprietary communication media with associated protocols are used. For substations with modern communication, data transmission takes place within and between the station, bay and process levels. Various communication protocols including Ethernet-based IEC 61850 as well as vendor-specified Modbus, Ethernet IP, DNP3 and IEC 60870-5-104 have been used at the utility level for SASs.
In addition, 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. It is important that the substation’s user interface is designed intuitively to allow optimal use.
Progress so far
Power Grid Corporation of India Limited (Powergrid) has emerged a clear leader in technology adoption in substation automation, and other utilities at the state level are following suit. Powergrid introduced SAS in India in 2003, establishing its first remote-controlled 400 kV substation at Bhiwadi, Rajasthan. Currently, all new substations set up by the company are being provided with automation technologies.
The company commissioned the National Transmission Asset Management Centre (NTAMC) at Manesar, Haryana in April 2015 at an investment of Rs 1.95 billion. It comprises SCADA, a remote accessibility system and a video monitoring system. The centre enables centralised monitoring, operations and maintenance (O&M) of all substations, and remote O&M of transmission assets. Following the commissioning of the NTAMC, 82 substations are being remotely operated from it, including 36 unmanned substations. Powergrid is currently in the process of setting up nine regional transmission asset management centres.
Powergrid is currently implementing the wide area measurement system (WAMS) technology across India under its flagship Unified Real Time Dynamic State Measurement (URTDSM) project, which is the first such large-scale deployment of phasor measurement units (PMUs) globally. The design of the URTDSM project has been finalised by Powergrid. The survey for PMU locations (substations/generating stations) and for the control centres for phasor data concentrators (PDCs) has been conducted. Further, PMUs are being progressive tested and despatch has started. Prior to the roll-out of the URTDSM, Powergrid had initiated a WAMS pilot project under which 64 PMUs were installed, including three by independent power producers.
In addition, Powergrid is implementing the latest process bus technology using novel sensors (optical instrument transformers) for substation automation using the IEC 61850 protocol. Over the next two to three years, it plans to replace its existing microwave hops with 20,000 km of optical ground wire (OPGW) and add another 20,000 km of OPGW for connecting its substations.
Challenges and the way forward
Going forward, technological advances across various domains of SAS will play a significant role in determining the pace and direction of smart grid deployment in India. However, there are some challenges facing automation that must be overcome. One of the key challenges in substation automation 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. Further, it is important to undertake comprehensive data acquisition as some information may not be important for a particular group of users, but more significant for others.
The demand for automation technologies is also being affected by the poor financial health of state-owned utilities. Despite the operational advantages, utilities, especially in the distribution segment, face challenges in implementing such solutions owing to the huge initial investments and regulatory issues.
The deployment of intelligent automation solutions is expected to witness high uptake given the launch of the National Smart Grid Mission. However, there should be greater focus on research and development to bring down costs and encourage widespread deployment of automation technologies. Further, utilities must 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. Equipment suppliers also need to understand the value chain and provide systems that cater to the entire network. It is crucial to have policies in place that encourage the deployment of advanced automation technologies and solutions for power systems.