SCADA, RTUs, IEDs and PLCs
Electrical distribution systems comprise a large number of remote applications and locations, and it has traditionally been challenging to monitor and regulate these remote applications and sites. Utility companies have been installing remote terminal/telemetry units, often known as RTUs, at substations in order to alleviate this issue.
In the beginning, remote terminal units (RTUs) were initially custom-made equipment; however, later versions depended on conventional hardware like as programmable logic controllers (PLCs) or industrial personal computers (PCs). Intelligent electronic devices, also known as IEDs, can be found placed at the majority of substations.
In most cases, these IEDs interact with the RTU located in the substation.
Switchgear feeders are in charge of controlling the distribution of power to the various electrical loads found in substations and electrical systems. A variety of data, including information on current, voltage, power, and the health of the switchgear, is collected by sensors that are positioned on the switchgear. These data are then sent to the RTU, which is followed by a SCADA system performing a polling operation.
In order to monitor and regulate the activities of the substation and the equipment associated with it, operators look at the information displayed on the HMIs. Modern SCADA systems are exceptionally capable of managing the massive volumes of data that are required to monitor the electrical state of all power lines, connections, and equipment.
Let’s get into the discussion starting with introduction to SCADA systems operating in MV and LV distribution systems.
Medium voltage and low voltage distribution systems can have a number of different configurations, including the major ones, such as standard radial, double-radial, open-ring, and closed-ring. The amount of reliability required and the importance of the loads determine which design is chosen.
Consequently, manual or automatic switching of the system occurs under emergency operating situations, depending on the allowed duration of interruption periods and, of course, the nature of loads. In most cases, automation of the distribution networks serving industrial and commercial loads is required.
How much flexibility do we have in determining the extent to which distribution systems can be automated? That’s a good question, isn’t it?
Figure 1 – Typical regular and emergency power supply for industrial plants
Network scale, load characteristics, and system hardware all play a role. Is it possible to fully automate a distribution system so that it functions reliably, efficiently, and safely even as it expands and becomes more complex?
The following discussion is an attempt to answer this topic.
This sub-switchboard supplies each unit on a floor with electricity as measured by individual utility meters. Standby generators must be installed as a backup to the utility supply to protect against the unpredictability of utility power and the potential for harm in the case of a power outage.
To avoid accidental paralleling, a CB interlock between the generators and the utility feeder is required. In addition, transfer switches must be installed on each level so that the power from the standby generator may be distributed directly to the apartments, bypassing the utility meters.
See Figure 2.
Figure 2 – Schematic drawing of main lines of feeding a commercial building
As a result of these demands, a great deal of apparatus must be dispersed across the building, including an interlock panel for each generator near the main switchboard (utility switches) in the control room, a transfer-switches panel near the sub-switchboard on each floor, and conduits connecting the apparatus to the control room.
The control room, naturally, will need a lot of room, and there will be a lot of wires connecting panels and distant sites. The state of the system during a power loss can be visually assessed by the operator from the control room, where he or she also monitors equipment functioning and functionality.
Traditionally, a considerable number of indication lamps and warning alarms are required for these monitoring functions. Think of all the hassle and uncertainty the operator would feel dealing with all those lines and lights.
Do not discount the time and effort needed for the system’s commissioning and testing, either. However, it may be challenging to implement necessary improvements to the distribution system because the load is always increasing and the nature of the load may vary.
Information regarding the system’s health, economic dispatch, energy interconnection pricing, and the efficiency of the workstation’s various applications can all be gleaned from the data it processes.
The PLC can be instructed to carry out the necessary control commands based on the status data, while the remaining data is put to use in the system’s design, upkeep, and operation.
The workstation’s user-friendly interface through windows allows the operator to graphically display the single-line diagram of the distribution system and any other visual display required. SCADA refers to a system with a focus on data collecting and reporting (and not much in the way of control).
Since the SCADA system can be simply coupled with other systems like the protection system, it can be easily adapted to any change in the application field.
Figure 3 – Protection system equipped with CTs, VTs, test switch, relay and breaker
Take the protective relay-equipped power system depicted in Figure 3 above, for example. In this schematic, the protective relay receives inputs from the current and potential transformers, respectively. In response, the relay trips the CB if the inputs don’t stay within a certain range.
The protective relay must be checked to ensure that this safety device operates correctly. This can be confirmed by simulating the input signals with a generator and measuring the relay’s output.
See Figure 4.
Figure 4 – Testing of relay by using a simulator
Where V = voltage; I = current; f = frequency
Because the utility company cannot interrupt the main power lines to test the relay, a simulator is required. This test is used for protection, but if this relay is to be used as a data source to the SCADA system, the situation changes dramatically. Another test is required to ensure that the data generated by the protective functions is correctly transferred to the SCADA system.
In this scenario, understanding the exact numerical representation of the data delivered by the communication circuit is critical.
The disadvantages of relay systems and the benefits of SCADA systems are as follows:
The disadvantages of relay systems:
- Control systems that are complicated; systems that are expensive;
- More space is required for systems.
- Control relays use more power and generate more heat.
- Relays are exclusively used for on/off control.
- Any change in the control program necessitates relay rewiring; and it is difficult to troubleshoot and detect the fault in complex control systems.
SCADA systems have the following advantages:
- Self-diagnosis and easy maintenance; arithmetic function implementation capability;
- It is simple to program and reprogram;
- Communication with other controllers or a master host computer is possible.
- PLCs’ ability to progress from simple control schemes to more complicated schemes such as proportional/integral/derivative (PID) control;
- SCADA in an industrial facility can be considered as a distributed control system (DCS) with graphical user interface (GUI) and visual display of system status.
More information on SCADA, terminology, components, communication, and other topics can be found in the this article.
Suggested Guide (PDF) – Design guidelines for substation and power distribution systems of buildings
The distribution substation can be controlled and monitored locally or remotely from a centralized control center, with the trend toward “unmanned substations“. Substation operations are being entirely automated these days as a result of the presence of sophisticated computers and clever devices.
These linked devices (IEDs) are designed to collect data and regulate substation processes. The SCADA system, on the other hand, allows the substation operator to view and control the status of various aspects of the substation.
Of course, improved control systems, system protection, and communication applications, in conjunction with the SCADA system, have the potential to dramatically improve the capacity and reliability of existing distribution networks. This entails lowering operating and construction expenses as well as optimizing distribution system utilization.
See Figure 5.
Figure 5 – Substation with distributed SCADA and automation systems
The dominant trend in SCADA and automation system architecture is toward distributed architecture due to its efficacy and compatibility with the nature of distribution systems, as well as the following:
- Increased modularity and availability
- There is no requirement for a master controller.
- Peer-to-peer communication, high performance, and the single-failure condition.
Figure 5 depicts a schematic representation of a distribution substation control and monitoring system. This advanced system achieves numerous advantages over the usual control method, including:
- Hardware savings.
- There is no separate local control board, nor is there a separate local sequential event recorder.
- There is no separate RTU.
- There are no separate cross-connection cubicles for bay- and station-level equipment.
- There are no transducers.
- Reduced signal cabling,
- Simple to use.
- Vibrant colors.
- Microsoft Windows operating system.
- Important information is automatically displayed.
- When information is required, it is made available.
- Preventive maintenance information.
- Reports and listing, as well as application support for distributed architecture.
Further Study – Inside the Modern Digital Low Voltage Switchgear: Devices and Communications
A SCADA system can operate and monitor the example of a commercial office building discussed at the beginning of this article and represented in Figure 1 as follows:
An IED represents the condition of the reverse switch for each apartment on each floor. An RTU gathers data from a collection of IEDs (for example, one RTU per level). When there are a lot of RTUs, they are separated into groups, and each group connects with a remote station, which communicates with an Ethernet bus (LAN).
An IED defining the interlock state is attached to a specialized RTU that connects with the Ethernet bus in the basement where the main switchboard is located.
As shown in Figure 6, a central control station and a SCADA master station are linked to the LAN to control and monitor the system, respectively.
Figure 6 – A SCADA system for a commercial office building
It’s important to acknowledge that shunt capacitors are used to implement power factor adjustment in the system. As an example, in this application, zone compensation is assumed, which means that the shunt capacitors are linked to the MV bus bars of the distribution switchboard, which is responsible for distributing power to the loads located in that zone as a sub-switchboard.
Traditionally, shunt capacitors are divided into stages, with each stage containing a collection of capacitors (capacitor bank) with a specified quantity of kvar as a rating. Each stage may have a rating that is equal to or different from the ratings of the previous stages. It is determined by the planner’s analysis of the load and its type of change.
As a result, the controller sends a control signal to each stage’s switch to turn it “on” or “off” in order to reach the preset power factor value. The power factor correction system is safeguarded against overcurrent, overvoltage, and overheating by employing appropriate relays.
To avoid switching-over and restriking voltages, no stage can be reenergized in less than a set time (a few minutes).
Figure 7 – Application of SCADA system to power-factor correction system
When the SCADA system is applied to the power-factor correction system, the total system, as shown in Figure 7, will include the following:
Position switch: It allows each capacitor bank to be manually or automatically inserted into the system or disconnected (man/off/auto).
The Auto/SCADA switch: It allows the system to run automatically or with the SCADA system.
The central control station (system controller): It regulates the capacitor banks based on the system’s voltage and power factor. When SCADA is turned off, the control station is activated.
Instrument transformers, CTs, and VTs: They function as sensors (IEDs), sending samples of system parameters (phase currents, phase voltages, line voltages, active power, reactive power, and so on) to both the protection and measuring systems.
The protection system: It incorporates many types of relays that protect the system from abnormal operating situations. When necessary, a temperature sensor can be added to safeguard the system from ambient temperature rise.
Measuring system: It measures all required parameters based on sensor signals and communicates the measured values to a PLC.
SCADA master station: This station transmits control signals to the PLC. Furthermore, it handles all indicator, alarm, reporting, and graphical display functions. Actual power factor, connected steps, pending processes, capacitor loss, load and reactive currents, and voltage total harmonic distortion (THD) are all displayed by the SCADA.
PLC: It manages the functional requirements of both the system controller and the SCADA, determining which capacitor bank stages are “on” and which are “off.” The inputs from the measurement system, protection system, position switch, auto/SCADA switch, controller, and SCADA master stations are used to make this decision.
Suggested Article –
- Power Distribution Systems by Abdelhay A. Sallam, Om P. Malik
- V.K. Mehta ,Rohit Mehta, PRINCIPLES OF POWER SYSTEM
- ABB Substation Automation Systems
- John D. McDonald, Electrical Power Substation Engineering
- Nicholas Honeth, Substation Automation Systems