Substation Automation at a Glance
Substation automation system, or shorten SAS, is not a new term, its been in use for the last 30 years. However, substation automation as a technology has rapidly evolved in the last 10 years and nowadays represents a highly advanced system capable of controlling every single process of a power substation.
In a few years, the next generation of substations will begin to massively appear in many countries worldwide. At that time, the station bus will connect the IEDs that are used for protection, control, and monitoring with the devices that are located at the station level, and the process bus will connect the bay units with the devices that are located in the switchyard.
In addition, because it will be based on the IEC 61850 architecture, conventional wiring will be done away with, and binary and analogue signals will be delivered and received via the communications interface. In addition, the technologies of sensor and traditional instruments transformers are going to coexist in new installations, as well as in an increasing number of secondary retrofit or extension installations. This is going to be the case for both types of installations.
In conclusion, the utilization of Ethernet network architectures would be expanded in order to facilitate communication inside substations as well as between those substations and the control center.
Ok, let’s get into the subject, and that’s the basics of Substation Automation. To begin, let’s discuss the fundamental concepts that underpin such a system. After that, we’ll examine the most important tasks that an SAS completes, and the final section will focus on the primary components of an SAS.
- What Makes SAS
- Substation Automation Functions
- SAS Components
The first one is primary equipment. The term “primary equipment” refers to a bunch of high-voltage components whose individual sizes are determined by the voltages at which the substation operates. In addition, every electric substation is made up of a large number of low-voltage components that are on the smaller side.
The secondary system is the collective name for all of these low-voltage components.
The group of high voltage equipment consists of changing-state equipment or switchgear (circuit breakers, disconnectors, and earthing switches used to maintain or to interrupt the energy flux from/to transmission lines or load feeders connected to the substation), instrument transformers (voltage transformers and current transformers) that reflect voltages and currents present at high voltage terminals of primary equipment, and also, in most cases, power transformers to change the voltage of the primary equipment’s high voltage terminals.
The foundation of substation automation systems, also known as SASs, is a large amount of specialized software that is kept in hardware components that are part of a set of substation secondary components.
Figure 1 – Advanced relay control and protection panel used in SASs
SASs can be built utilizing a straightforward method that makes use of more contemporary technology by integrating three distinct sets of devices together with two local area networks.
The process devices group is comprised of analog-to-digital converters as well as actuator devices, and its primary function is to facilitate the transition between SAS and high voltage equipment. The term “inteface devices” refers to a collection of “Intelligent Electronic Devices“, or “IEDs,” which are able to receive and process signals that are transmitted from high voltage apparatus.
The application devices group is comprised of all of the computers and other components that are necessary to successfully operate control features and interface with both internal and external subsystems.
Figure 2 – Simplified model of a substation automation system (SAS)
*** NCC stands for Network Control Center
The following are the most significant functions that an SAS performs:
- Selecting, opening and closing circuit breakers and disconnectors.
- Commands to block and unblock.
- Giving release information to circuit breakers and disconnectors for securing the opening and closing actions.
- Showing substation configuration with position indication (open or closed) of circuit breakers and disconnectors based on signals coming from their own position contacts.
- Acquiring and process data coming from power transformers and other primary equipment related to condition operation.
- Displaying substation events including information regarding switchgear opening and closing actions due to any external cause, such as the activation/operation of a protective relay.
- Announcing to a substation operator all adverse conditions that may represent a risk to substation integrity.
- Preventing trouble with SAS operation.
- Acquiring and showing current values of electrical or other relevant parameters.
- Giving indications of energy flows through substation primary equipment and transmission lines.
Setting and Monitoring of Protective Relays:
- Allowing changes on operating parameters of protective relays.
- Giving alarm signals when any undesirable condition may affect the right relay performance.
Control and Monitoring of the Auxiliary Power System:
- Displaying screens/drawings showing the configuration of the auxiliary power system.
- Allowing selection and execution of control commands.
- Driving automatic transfer switches.
- Managing interlocking logics.
- Supervising AC/DC power source conditions.
- Giving alarm signals from abnormal conditions.
- Monitoring actual voltage value on the power system.
- Changing the position of the tap‐changer of power transformers.
- Giving alarms and signals.
The operator is presented with control and monitoring information via a graphical interface that displays overview diagrams, control means, alerts, measurement, trends, and event sequences on user-friendly screens.
Figure 3 – Newly installed IED for bay control in a 220 kV substation
The system operator, using the SAS, opens (or closes) circuit breakers and disconnectors situated at the substation to make changes in the primary arrangements essential for power system functioning.
Switching operations can be performed in a hierarchical order from several physical places, the most typical of which are:
- The switchyard itself (process/switchyard level)
- The local control room (bay level)
- The main control house (station level)
- The network control center (remote/network control center level).
The SAS displays various screens with various features. At least one of them includes a control dialog box that allows the substation operator to choose whether to open or close a circuit breaker or disconnector. The switching command is then given as a second phase.
Figure 4 – SAS Communications Network Overview
A previous check synchronization process occurs when the switching command is for the closing activity of a circuit breaker. This procedure verifies the voltage values on both sides of the specified circuit breaker, as well as the voltage differential across it and the phase shift between voltages.
The following requirements must be met before one or more of the following operations on a circuit breaker can be authorized:
- Voltage is only present in the substation busbar; that is, the feeder is dead.
- Voltage is only present in the feeder; that is, the substation busbar is dead.
- Voltages are present in both substation busbar and feeder and lie within permissible ranges for the conditions.
In addition, when no blocking condition is present, all switching commands are permitted. These blocking situations may originate from both high voltage equipment (such as low gas pressure on the chosen circuit breaker) and the SAS itself (e.g., disregard for the control hierarchy).
Figure 5 – Sample Interlocking Screen
Figure 6 – Sample 380 kV Bay View
The SAS includes a collection of mimic diagrams that represent different areas of the substation. These diagrams include color-coded symbols and information regarding the position of principal equipment and secondary pertinent components. In this substation, there is a provision for displaying lists of messages and alarms, as well as lists of events that are happening in the substation and are related to the transmission lines.
Single-line diagrams provide the substation operator with a simplified representation of the current state of all of the switchgear in the substation, allowing for a more rapid comprehension of the following topics:
- Which feeder is connected to which busbar
- The actual busbar configuration
- Those feeders that are generating signals.
The position of the switchgear can be effectively depicted visually by ways such as the following examples:
- Switchgear in the closed position: Steady light in symbol filled out.
- Switchgear in the open position: Steady light in symbol empty.
- Circuit breaker tripped by a protective relay: Flashing light, symbol empty.
- Disconnector in motion: Flashing light, symbol empty or filled out according to direction of movement.
- Disagreement in position information: Steady light, symbol half filled out.
Figure 7 – Sample single-line overview screen
In addition to this, SAS diagrams will typically include all of the data pertaining to the feeders at each voltage level, such as the following:
- Switchgear and auxiliary power system
- Related signals
- Change of status
The following variables’ values are also displayed:
In addition to this, self-monitoring and diagnostic tools for essential parameters and functions are built into SASs. The following are the minimum things that are monitored:
- Auxiliary supply voltages
- Availability of the various assemblies
- Circuits to transmission and execution of control commands
- Serial data communication links
- Software procedures
- Memories capabilities
- Timing periods
- Agreement of actual switchgear status and displayed status.
At the very least, event messages must include the following information:
- Event description
- Date and time of event
- Related voltage level
- Supplementary information.
All occurrences with the potential to significantly impact the substation and associated transmission lines must be recorded in chronological order on the event list.
Suggested Guide (PDF) – Substation automation and communications for controlling primary equipment (switches, breakers, etc.)
In addition to controlling the substation from a local control room and the main control house and processing the return confirmation signals from the switchgear, the SAS processes and displays defect signals and other anomalous condition signals that require acknowledgment.
It also serves as the basis for the substation operator’s decision regarding what additional action should be taken, and it processes the return confirmation signals from the switchgear.
Typical alarm signals include:
- Switchgear operational unavailability.
- Overloading or overrunning of the circuit breaker operating mechanism.
- Excessive oil and/or winding temperature of the power transformer.
- The power transformer protective relay has been triggered.
- Voltage readings that are too high or too low.
- Voltage loss or drop.
- Communication links fail.
- Station/bay controller failure.
- Protection relays fail.
This component improves alert perception and recognition by the substation operator.
Figure 8 – Typical alarm annunciator in substation
The ability to measure is another important aspect of substation automation systems. This supplies the most up-to-date information that is required for the efficient operation of the power system. The following are the primary parameters that are subjected to measurement:
- Active powers
- Reactive powers
- Temperatures on power transformers.
In most cases, the values are displayed in measurement dialog windows that are specifically devoted to each voltage level of the substation.
Further Study – SCADA applications in thermal power plants (TPPs)
The operation of protective relays that are tailored to specific applications (such as busbar protection, protection for transmission lines, protection for power transformers, and so on) is dependent on reference parameters, which determine when the relay is prepared to send a selective trip command to a circuit breaker.
The operator of the power system can use the facilities provided by SAS to either fix or alter those reference parameters.
Figure 9 – An example of setting of control and protection relays in a substation
Internal electrical loads at substations include things like motors for circuit breakers and power transformers, lighting circuits, and air conditioning equipment. These loads require alternating current (AC) power service. In addition to this, DC power sources are required so that IEDs and other secondary devices can be supplied with electricity.
A well-configured low voltage network that is comprised of distribution transformers, transfer switches, LV cubicles, batteries, and sometimes diesel generators is used by the auxiliary power systems to meet these internal power requirements.
In today’s world, the functions for control and monitoring of such systems are wholly incorporated into the solutions provided by SAS.
Suggested Course – Relay Circuitry and Understanding Control and Protection Schematics
Electrical equipment is designed to function in a steady state at nominal voltage plus or minus a particular percentage of the nominal voltage, for instance 5%. If the applied voltage is higher than the limit value, there is a possibility that damage will occur; this damage will primarily harm the internal insulation.
In addition, malfunction may occur if the voltage that is applied is lower than the value that is permitted.
The following list includes examples of control instructions and signals that are associated with such a subsystem and managed by the SAS:
- Control commands to adjust the position of the tap-changer.
- Indication of tap-changer position.
- Alarms caused by electrical or mechanical failures along the voltage regulation process chain.
Further Study – Instructions for making specifications and selecting the main components of an HV substation
Speaking using simple words, SAS servers are the secure computers running SCADA software that talk to IEDs to monitor and operate the power grid. The block diagram for a transmission SAS is depicted in simplified form in Figure 10.
Figure 10 – Block Diagram of SAS
The main SCADA application software is installed on the database (DB) server. It interfaces with field IEDs to collect data and deliver control commands. Real-time analog values, indications, alarms, controls, and set points comprise data.
This data are shown on the SCADA HMI by the computer. Because the servers are critical, the optimal setup is to have them redundant inside a master-standby (hot-cold) arrangement. Furthermore, dependent on the number of voltage levels and IEDs, the number of redundant sets of database servers can be raised.
Figure 11 – SCADA server
The gateway (GW) server is in charge of communicating outside of the substation (for example, to a master station) in order to supervise the operation of all substations in a certain geographical area. The gateway server also has the SCADA application database configured.
The primary function of this machine is to act as a protocol converter between IEC 61850 and numerous other substation protocols and the protocols used in the master station (primarily IEC 60870-5-101 and IEC 60870-5-104).
Figure 12 depicts a typical SAS database and gateway server configuration.
Figure 12 – Database and Gateway Servers in an SAS Network
An SAS’s two primary network components are industrial-grade controlled Ethernet switches and a redundancy box. Let us mention a few words about each.
Managed ethernet switches are network-switching devices that link all SAS components to a network and transmit/receive data according to the defined and necessary functionality. These are multiport devices that can be configured at each port level.
A controlled Ethernet switch has two distinguishing features: VLAN awareness and support for the Rapid Spanning Tree Protocol (RSTP).
Further Study – Ethernet in substation automation applications – Issues and requirements
Redundancy boxes are found in substations where a communications network based on IEC 62439-3: Parallel Redundancy Protocol is established (PRP). IEDs and devices with only one network interface that are not PRP compatible are linked to a PRP-based network via a redundancy box, which offers a redundant communication line.
An IED is a smart device in power system automation that may perform both basic and advanced activities relating to protection, automation, monitoring, and control. Any IED in an IEC 61850 context can connect independently with SCADA, which acts as an intelligent interface for field devices.
Bay control units, protection relays, transformer tap changer control modules, smart metering devices, and IEC 61850 compliant I/O modules are examples of IEDs used in transmission substations to integrate outdated devices into the SAS.
Figure 13 – IEDs – Intelligent Electronic Devices
Grid operators are provided with two main workstations to execute routine maintenance and undertake operational duties. These are operator and engineering workstation.
The operator workstation machine includes a graphical user interface (GUI) that is linked to the database servers. The operator workstations (OWS) are not linked to field-level IEDs; instead, the IEDs rely entirely on the integrity of the database servers for proper data representation.
The operator workstation is set up to only communicate with the master database server.
Figure 14 – SCADA interface in operator’s workstation
The engineering workstation (EWS) communicates with all substation devices. The EWS is responsible for configuring or modifying IED configuration parameters and Substation Configuration Description (SCD) files for all IEDs in the substation. It is not responsible for any SCADA functions.
This computer must be extremely secure because it has access to any IED in the substation.
In SCADA applications, time synchronization is critical for properly analyzing data acquired via any distributed control system or network. Installing a dedicated Simple Network Time Protocol (SNTP) server that can obtain proper, precise time via Global Positioning System (GPS) and Global Navigation Satellite System (GLONASS) satellites allows for time synchronization.
There are benefits to installing an SNTP server. It lowers the cost of physical layer implementation and makes use of the same local-area network (LAN) over which IEDs interact. Inter-Range Instrumentation Group (IRIG)-based protocol is also utilized in critical applications needing great accuracy.
Further Study – Protocols applied for time synchronization in a digital substation automation
The SAS used in modern substations is built with the capability to connect with each remote-control center using either a serial or an Ethernet-based protocol. This gives the SAS greater flexibility.
To protect the option of using Ethernet-based communication, security gateways that are up to date with the latest cybersecurity standards are set up according to the specifications of the customer.
Suggested Video – 170kV HV GIS Substation, Automation Protection Communication & Cybersecurity
- Substation Automation by E. Padilla
- Modern Power System Automation for Transmission Substations by G. M. Asim Akhtar, Muhammad Sheraz, Ali Safwan, M. Akhil Fazil, and Firas El Yassine at Schweitzer Engineering Laboratories, Inc.
- Emerging Technologies and Future Trends in Substation Automation Systems for the Protection, Monitoring and Control of Electrical Substations by Bruno Tiago Pires Morais
- Substation Integration and Automation by Eric MacDonald