Practical guide to smart substation automation in electric energy distribution

The substation automation system

The substation automation system (SAS) is characterized by its ability to replace manual operator operations with automated functions, as implied by its name. Automated operations are essential for ensuring the safe and dependable functioning of electric power transmission and distribution. The functions encompassed in this list include, but are not restricted to, monitoring, data collecting, protection, control, and remote access communications.

Previously, Remote Terminal Units (RTUs) were only used as intermediaries between the electric power switchgear at the process level in substations and the network management system of utilities for long-range surveillance purposes (see Figure 1 below).

These units are equipped with several inputs and outputs that serve as communication interfaces to the remote network control centers. Both the Remote Terminal Units (RTUs) and the Network Control Center (NCC) combined to create the Supervisory Control and Data Acquisition System (SCADA), as shown in Figure 1.

There are several specific functions of the substation automation system worth mentioning:

1. Voltage transformation control (Load Tap Changer Control)
2. Equipment protection for buses, lines, feeders, transformers, generators, and other equipment.
3. Implementing automated interlocks and switchgear switching mechanisms,
4. Transmitting monitoring data to the control center,
5. Resolving power system faults either locally or remotely,
6. Establishing communication with other substations (intra) and regional control centers.

For instance, numerous functions in SAS are synchronized to automatically recover from equipment failure or short-circuit failures. These functions utilize several devices, with their responsibilities divided between primary equipment (such as circuit breakers, transformers, instrument transformers, etc.) and secondary equipment (such as protective relays, merging units, intelligent electronic devices).

Figure 1 – The substation Automation System, an architecture of classical SCADA systems

Therefore, the cabling and wire connections between these devices and equipment become intricate, resulting in significant efforts and extended time when performing maintenance, repair, extension, or modification operations. Efforts have been made to reduce the quantity of cabling and wiring by implementing serial communication networks at various levels of the substation hierarchy. These endeavors indicated exclusive solutions that are created by providers of substation equipment.

Major corporations, a non-profit group consisting of suppliers of substation equipment and utility users like the Utility Communication Architecture (UCA), are actively enhancing substation communications. They are doing so by actively participating in the development of international standards to enhance functional compatibility and proposing architectures that offer greater network bandwidth.

The objective is to improve the reliability of communication between substations, both within and between them.

In general, IEDs facilitate the flow of information that can be collected and stored either locally or remotely for the purpose of thorough analysis and logging. This data assists utilities in improving reliability and facilitating asset management initiatives, including as predictive maintenance, extending the lifespan of assets, and advanced planning.

Communication architecture of Substation Automation Systems

SAS The substation automation hierarchical architecture is classified by technological implementations. The substation automation system consists of three levels: the station level, the bay level, and the process level (as shown in Figure 2). These levels can be utilized to achieve various functionality. In terms of technical specifications, the dimensions of a substation automation system (SAS) will be greater in extra high voltage transmission substations compared to high voltage distribution substations.

In modern substations, the bay level is a common feature, although in the early days of SAS, the concept of bay level was not acknowledged.

Usually, the sensors gauge exceedingly large current and voltage magnitudes. Current and voltage transformers (CTs/VTs) are used to convert large amounts of current and voltage into standardized values that are then sent to relay inputs. The scaled figures typically correspond to 5A (1A in Europe) for the current and 120 Volts for the voltage.

In simple words, protective relays or modern intelligent electronic devices execute the protective logic.

Figure 2 – The structure of a Substation Automation System representing station, bay and process levels

These devices detect and measure electrical current and voltage levels to calculate certain values that are monitored by the protective logic, such as the electrical current in two distinct sides of an Extra High Voltage (EHV)/High Voltage (HV) transformer. When a parameter exceeds a specified value (pickup setting), the protective logic will respond based on a predetermined sequence of steps or a programmed control algorithm.

Typically, a trip signal is transmitted to the corresponding circuit breaker to disconnect a line or bus when a problem is present.

These gadgets will be powered by either a battery or a direct current (DC) source. Essentially, a contemporary substation design consists of three tiers, each of which is further divided into subsections.

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