Substations have been equipped to perform automatic reclosing, bus sectionalising, load transfers, capacitor switching, etc. for many years. In the past, these and other functions were implemented using a combination of control panels, auxiliary relays, switches, lights, meters, transducers and extensive wiring and cabling. In many applications today, this perception is probably because developments in substation equipment have expanded the potential capabilities of substation.
Substation automation (SA) is not a new concept. People started adopting the changes in the technology to substation. SA term refers to obtaining information or data from intelligent electronic devices, control and automation capabilities within the substation, and control commands from remote users to control power system devices. This enables the electric utility to remotely monitor, control and coordinate the distribution components installed in the substation.
The use of substation supervisory control and data acquisition (SCADA) is one of the key points on the power grid automation, as well as on the utilities asset management, improving its monitoring and control capabilities, because of collected data by the whole substation automation system, like the intelligent electronic devices (IEDs), Remote Terminal Units (RTUs) and SCADA.
IEDs are installed in strategic locations to collect data and automatic protection of substation equipment. It includes microprocessor-based controllers of power system equipment, such as circuit breakers, transformers and capacitor banks. IEDs receive data from sensors and power equipment, and can issue control commands, such as tripping circuit breakers if they sense voltage, current, or frequency anomalies, or raise or lower voltage levels in order to maintain the desired level. Common types of IEDs include protective relaying devices, On Load Tap Changer controllers, circuit breaker controllers, capacitor bank switches, recloser controllers, voltage regulators etc. SA has to perform many functions and in IEC 61850, the functions are divided into sub functions. Each sub function is performed by the IED installed in the substation and it can perform one or more functions. A set of sub functions is integrated together to perform a substation automation function. Thus, data communication between the control center and IED remote points and among the IEDs is very important for real time operation.
SCADA is a computer system for gathering and analysing real time data. These systems are used to monitor and control a plant or equipment in industries such as telecommunications, water and waste control, energy, oil and gas refining and transportation. In addition, SCADA systems are needed to monitor and control a large geographical displacement where an organisation may not have enough manpower to cover. Thus, reliable communication and operability of these areas or sites is critical to profitability. The system is a common industrial process automation system which is used to collect data from instruments and sensors located at remote sites and to transmit data at a central site for either monitoring or controlling purpose.
RTU is a high-speed microprocessor controlled electronic device that interfaces objects in the physical world to a distributed control system or SCADA system by transmitting telemetry data to a master system, and by using messages from the master supervisory.
Advances in communications technology are used within the substation; a single high-speed Local Area Network (LAN) is used to transmit data and control commands. Presently, a number of different LAN techniques and protocols are in use. The industry is actively working on development of a new standard LAN definition that will be based on the use of Ethernet and Manufacturing Messaging Specification and will be compatible with the Utility Communications Architecture. There are already many techniques for moving data out of the substation to a master station or to other substations. These include the use of leased or dedicated telephone lines, dial-up phone lines, cellular telemetry techniques, satellite transmissions, various flavours of radio techniques and fiber-optic networks. Basically, this variety of communications methods results in the ability to transmit large amounts of information at a rapidly declining cost per bit. The combination of PLC based devices and communications technology creates the ability to obtain more information about the power system and the equipment being used. Power system variables include magnitude and angle of voltages and currents, real and reactive power, frequency, power factors etc. Information is available regarding the initiating event for relay operation, the location of faults, and fault analysis. Specialised sensors and transducers are used to build a database relating to equipment condition and use; so that analysis techniques can be used to determine equipment condition and base maintenance activities on actual condition rather than time schedules. Within the substation, the use of PLCs or other types of computers opens up a vast array of automation possibilities. Complex schemes for dead bus and dead line re-closing can be implemented with the sequence being based on actual power system conditions that exist at the time. Re-closing of circuits can be modified based on cold load pickup requirements. Load transfers between buses and transformers can be made to protect against transformer overloads. Bus voltages and power factors can be tightly controlled to minimise losses or voltage variations. Supplementary measurements and inputs can be used to initiate automatic equipment re-energizing after a transformer or bus differential.
Components of Substation Automation (SA)
The electrical substation is of prime importance to the electrical generation, transmission, and distribution system and has four major types.
- Switchyard substation at a generating station connects the generators to the utility grid and also provides offsite power to the plant. Generator switchyards tend to be large installations that are typically engineered and constructed by the power plant designers and are subject to planning, finance, and construction efforts different from those of routine substation projects.
- Customer substation functions as the main source of electric power supply for one particular business customer. The technical requirements and the business case for this type of facility depend more on the customer’s requirements than on utility needs.
- System substation involves the transfer of bulk power across the network. Some of these stations provide only switching facilities (no power transformers), whereas others perform voltage conversion as well. These large stations typically serve as the end points for transmission lines originating from generator switchyards and provide the electrical power for circuits that feed transformer stations. They are integral to the long-term reliability and integrity of the electric system and enable large amounts of energy to be moved from the generators to the load centers. System stations are strategic facilities and usually very expensive to construct and maintain.
- Distribution substations are the most common facilities in electric power systems and provide the distribution circuits that directly supply most customers. They are typically located close to the load centers, meaning that they are usually located in or near the neighborhoods that they supply, and are the stations most likely to be encountered by the customers.
The substation roles clearly indicate that it can be considered as critical infrastructure, especially for substations in the transmission grid, interconnecting many systems. As such, it requires proper physical and cyber protection to ensure uninterrupted and smooth operation.
SA System Components: The SA system uses any number of devices integrated into a functional array for the purpose of monitoring, controlling, and configuring the substation. The components of the SA system include VT, CT, and PT stand for voltage, current, and power transformer, accordingly. According to IEC 61850, the SAS layout is structured in three levels:
- Station level: A redundant PC based Human machine Interface (HMI) enables local station control through the software package that contains an extensive range of SCADA functions. The station level contains the station-oriented functions, which cannot be realised at bay level, e.g. alarm list or event list related to the entire substation, gateway for the communication with remote control centers. A dedicated master clock for the synchronisation of the entire system shall be provided.
- Bay level: A bay comprises of circuit breaker and associated isolators, earth switches and instrument transformers. At bay level, the IEDs provide all bay level functions such as control (are directly connected to the switchgear without any need for additional interposing or transducers. Each bay control IED is independent of the others and its functioning is not affected by any fault occurring in any of the other bay control units of the station. command outputs), monitoring (status indications, measured values) and protection.
- Process level: It consists of all the switchyard devices which are hardwired using copper cables and use fibre optic cables to connect the bay level IED’s used for control and protection.
The SAS shall contain the following main functional parts:
- Human Machine Interface (HMI) with process database includes Operation and supervision of equipment, Data presentation,
- Separate gateway for remote supervisory control via SCADA.
- Master clock (e.g. GPS receiver)
- Collection of the relevant data concerning the substation and distribution of the data where needed and monitoring of Gas density, Switchgear and Transformer.
- Data exchange between the different systems components via serial bus.
- Bay and station level devices for control, monitoring and protection.
- Bay-oriented local control panels with mimic diagram.
The salient features of SAS are protection for all applications, control with flexible system functions, communication with fibre optics, self-supervision and diagnostic, support of hardware and software, state-of-the-art microprocessor technology, user-friendly workplaces, high performance and availability, step by step possible implementation, user friendly software tools. In the future, more components will facilitate the adoption of the architecture of the SAS system and permit the better physical distribution of the primary equipment, providing the full advantage of the process bus.
