The true art of control, monitoring and protection provided by Substation Automation Systems

SAS Control, Monitoring & Protection

The Substation Automation Systems, often known as SASs, are responsible for a tremendous variety of tasks. These include some extremely important actions, such as clearing faults in a timely manner in order to maintain the physical condition of power system components, as well as providing additional visual facilities, such as an office-style remote terminal that is solely for the purpose of displaying the status of substation primary equipment in a commercial setting.

Control, in the context of power systems, refers to the process of monitoring the states of voltages, currents, and frequencies as critically important parameters in order to maintain the system’s stability and safety. As a result, it is necessary to identify instances in which those parameters deviate from the states that are wanted in order to take measures to get them back where they should be.

This control is exercised in a distinct manner, using both manual and automatic modes, and it is carried out in a continuous manner. For the purpose of detecting the variables, instrument transformers, which are a component of the primary equipment of the substation, are utilized.

These resources are integrated in such a way as to accomplish a set of functionalities that are aimed at preserving the integrity of the power system and maintaining the safety and dependability of the flow of electrical power.

The SAS is required to carry out a variety of responsibilities, which will be discussed in the following paragraphs.

Table of Contents:

1. SAS Control Functions:
   1. Primary Switchgear Control:
      1. Depicting Primary Switchgear: Symbols, Colors and Visual Appearance
      2. Implementation of Switching Command
      3. Circuit Breaker Trip Circuit Supervision
   2. Check of Voltage Synchronization (Synchrocheck)
   3. Verifying Operational Limitation:
      1. Checking of Interlocking Conditions
      2. Checking of Blocking Conditions
   4. Voltage Regulation Task
   5. Working of Power Transformers in Parallel
   6. Operation of Secondary Components
   7. Facilities for Operation under Emergency Conditions
2. SAS Monitoring Functions:
   1. Handling Events
   2. Recording of External Disturbances
   3. Alarming Messages for Unexpected Events
3. SAS Protection Functions
4. BONUS (PDF) 🔗 Download Guidelines For Implementing Substation Automation Using IEC 61850

1. SAS Control Functions

At many control levels, control functions can be carried out, including the following:

1. Control from bay level: Through the bay controller screen and associated accessories.
2. Control from station level: Using color monitors and other elements from the Human Machine Interface (HMI).
3. Control from remote control level: By means of a master control unit.

The majority of the time, various control levels do not have the same level of control autonomy because of the practical and technical concerns involved. At bay level, which is located in the local control rooms, each specific bay controller has the capability of managing one or perhaps two high-voltage bays or feeders.

A great deal of responsibility is delegated to the bay controller in order to make it possible for control to be exercised from the bay level. Some examples of this are as follows:

• Monitoring of voltage levels associated with bays.
• Verifying the voltage synchronization for the closing function of circuit breakers.
• Runtime verification of disconnector operations.
• Verify the appropriate level of authority for control (based on the hierarchical control paradigm).
• Supervising the operation of pumps, spring systems, or other components of a circuit breaker’s drive mechanism.
• Monitoring the SF6 gas pressure in circuit breaker interrupting chambers.
• Verify the status of the bay/station interlocking conditions.
• Inhibit the advancement of dual operation orders.
• Confirm the operational mode, whether it is automatic or manual.
• Determine the suitability of the interlock override operating mode.
• Provide visual representations (such as a single-line diagram and dialog methods) for the purpose of controlling.
• Self-supervision involves monitoring the state of the voltage supplies.
• Identification of pole inconsistency in circuit breakers
• Switching commands will be delivered if the necessary safety and operational criteria are met.

Based on that set of facilities and factors, control function is performed through the local control display of the bay controller, following the control concepts shown in Figure 1.

Figure 1 – SAS opening and closing circuit control concepts

At the station level, the operator has the ability to execute the control function in a manner that is comparable to the bay level. This is because the operator has the ability to select control of any of the primary or secondary switchgear.

Additionally, there are some additional control functions that are allocated specifically for the station level. For instance, the operator can change the positions of on-load tap changers.

Suggested Guide (PDF) – How to design Bay Control Unit (BCU) in a substation automation system

How to design Bay Control Unit (BCU) in a substation automation system

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1.1 Primary Switchgear Control

The primary switchgear is comprised of high-voltage circuit breakers that are able to connect or disconnect small or large segments of the power system (feeders, bays, transmission lines) under normal or abnormal conditions (short circuits or other types of failure).

Additionally, the primary switchgear includes disconnectors that are required to isolate such segments of the power circuit, thereby providing the necessary safety conditions for activities such as inspection, maintenance, or repair.

The disconnector, in addition to the common open and closed status that can be displayed by both apparatus, also presents as a third status that is referred to in the transit condition that is exhibited during the operation process. This indicates that from an operational point of view, the disconnector acts as a third status.

Suggested Reading – MV switchgear: Important design considerations and applications

Medium voltage switchgear: Important design considerations and applications

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1.1.1 Depicting Primary Switchgear: Symbols, Colors and Visual Appearance

A color monitor for the human machine interface (HMI) and an effective visual display on bay controllers are both very desirable. In order to accomplish this, it is necessary for the contracting departments to work closely together throughout the SAS engineering stage. Despite the fact that the manner in which bays and feeders are displayed on the screen of the bay controller is frequently defined by each IED vendor, prior agreement between the owner of the substation and the SAS designer or integrator may be necessary for a significant amount of detail.

A set of symbols that are utilized to indicate primary switchgear in a variety of settings is one of them. This is done in order to minimize the likelihood of making a mistake during the operational procedure.

This is illustrated in Figure 2, which contains a few examples.

Figure 2 – Examples of symbols to represent devices of a primary switchgear

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1.1.2 Implementation of Switching Command

At the user’s request, for instance by selecting a particular circuit breaker or disconnector on the monitor screen, a control dialog box will emerge. This box is used to issue the command to “go to the control“. Through this approach, the two-step technique that is advocated, which consists of two positive activities that are carried out in succession, is successfully accomplished.

It is necessary to have suitable ways to verify that the person clicking has the appropriate authorization to carry out control orders. This is necessary for reasons of security and to ensure compliance with the rules governing authority levels.

If there is any obstacle that prevents the control command that is supposed to be executed from being carried out, an extra dialog box will display that indicates the reason for the obstacle.

Figure 3 – SCADA screen depicting substation single-line diagram

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1.1.3 Circuit Breaker Trip Circuit Supervision

It is possible that the capability of the SAS to automatically activate particular circuit breakers in the event that a fault arises in the power system (trip order arriving from protective relays) is the most crucial functionality of the SAS.

Due to the fact that this is the case, the trip circuit of circuit breakers is an essential component of the secondary system in terms of its operational availability whenever it is required.

Certain relays that are available on the market are recommended for use in this application.

Further Study – Circuit breaker schematics in a nutshell: Tripping, closing and blocking coil arrangements

Circuit breaker schematics in a nutshell: Tripping, closing and blocking coil arrangements

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1.2 Check of Voltage Synchronization (Synchrocheck)

AC voltage, commonly used in power systems, is a variable that changes over time and is defined by the following parameters:

1. Magnitude: Typically determined by the root mean square (RMS) value of a sinusoidal quantity, such as 115 kV.
2. Frequency: The frequency is the number of sinusoids occurring in one second, typically measured in cycles per second (cps), such as 60 cps.
3. Phase-angle: A relative metric that measures the temporal displacement between various sinusoids. In three-phase electric systems, the three phases have equal magnitudes and frequencies but are displaced by 120° in phase relations.

When a circuit breaker is in the open position, it may have active voltage on one or both sides. When a closing command is given from any control level, the closing action must be effectively performed at the instant when voltages present on both sides of the CB match (with tolerance) with respect to magnitude, frequency and phase‐angle.

The power system will be subject to potentially hazardous transient occurrences if this does not occur. As a result of this, control logic is required to incorporate particular synchronization criteria, such as those that are listed in Table 1. In the past, a separate device was utilized in place of the Synchrocheck task, which is now implemented as a function of the bay controller in a modern SAS.

Table 1 – Example of matrix for voltage synchronization criteria

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1.3 Verifying Operational Limitation

Similar to other control systems, substation control systems have the objective of meeting specific limitation criteria to guarantee that any modifications in the power system design are carried out safely for personnel, equipment, and the environment.

The control system is subject to constraint conditions that prevent the execution of a control command when there is an incorrect switch operation (interlocking logic) or when there are unsafe conditions for performing the intended switch operation (blocking condition).

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1.3.1 Checking of Interlocking Conditions

Autonomous switchgear functioning is hindered by various technical factors. The following items are included:

Disconnector capabilities: These devices lack the capacity to manage standard load or short-circuit currents during operation.
Earthing switch function: The role of the earthing switch is to be occasionally closed for the purpose of inspecting, maintaining, or repairing a specific section of the power circuit. They establish a connection between that particular piece and the earth mesh of the substation. If a segment is energized while the earthing switch is closed, it will result in a serious failure, specifically a short-circuit.

The fundamental interlocking conditions arise as a result of these factors:

1. A circuit breaker must not be closed if an associated disconnector is in the transit condition.
2. A disconnector must remain closed if an associated circuit breaker is closed.
3. A circuit breaker must not be activated if the power circuit it is attached to is grounded.
4. The earthing switch must not be closed if there is voltage present on the power circuit it is connected to.

A few years ago, data transmission between bay controllers began using the GOOSE service that is supplied by the IEC 61850 platform. This occurred despite the fact that substation owners have been cautiously maintaining the means to interchange such signals between different bays by employing hard-wiring. The reasoning behind this decision was based on reliability considerations.

By utilizing this particular method, the station controller will not be required to perform any additional processing on the inter-bay interlocking data.

Further Study – Switchgear interlocking system and arc protection that you MUST consider in the design

Switchgear interlocking system and arc protection that you MUST consider in the design

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1.3.2 Checking of Blocking Conditions

Efficient switching operations necessitate the switchgear to be in excellent condition. If the opening operation of a circuit breaker is performed slowly owing to an anomaly in the functioning mechanism, it can result in an explosive situation. If the opening or shutting time of a disconnector substantially exceeds the average operation time, it might result in significant damage to instrument transformers.

These unfavorable situations necessitate the need to prevent the risk of switching operations that could impact substation workers and unintentionally disrupt the flow of energy. Security is ensured by incorporating blocking signals into the control logic. These signals prevent the switching command (opening/closing) from proceeding if any of the blocking signals are active.

Common blocking signals consist of:

• SF6 gas – low pressure
• Hydraulic/pneumatic/spring – system defective
• Pole discrepancy in circuit breakers
• Motor faulty.

Figure 4 – Operation of Pole Discrepancy in One-and-Half-Breaker Scheme

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1.4 Voltage Regulation Task

The magnitude of voltage is a variable parameter inside the power system. The variation of power flow over transmission lines results in different levels of power consumption at different locations throughout time. For operational purposes, it is crucial that the voltage magnitude at any location in the power system remains within a predetermined acceptable range, such as ± 5% of the rated voltage.

In order to maintain the voltage magnitude within the permissible range, a large electrical system may need to periodically connect or disconnect shunt reactors and capacitor banks. In more complex circumstances, the system may require a continuously active installation such as Static-Var-Compensators (SVC).

The Voltage Regulating Relay (VRR) detects the precise magnitude of voltage on the power circuit, compares it with a predetermined value, and, if necessary, promptly issues a command to activate the tap changer motor. The VRR is connected to the bay controller linked to the power transformer feeder, enabling the adjustment of tap changers through designated control levels.

Good Reading – Voltage Regulation By Transformer Off-Load Tap Changer, On-Load Tap Changer and AVR

Voltage Regulation By Transformer Off-Load Tap Changer, On-Load Tap Changer and AVR

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1.5 Working of Power Transformers in Parallel

HV Power Transformers, whether in the form of three-phase units or arrangements made up of single-phase units, have the capability to manage power loads of several hundred Mega Volt-Amperes (MVA). However, there are situations where it becomes essential to link two or more of these components in parallel, allowing them to collectively bear the electrical load connected with a certain section of the power system.

The optimal method would involve installing transformers that had identical internal characteristics and adjusting the different voltage regulator relays (VRRs) to the same reference voltage. Practically speaking, even when transformers are made by the same manufacturer, slight variations in internal impedances result in imbalances when operated in parallel.

In addition, the module must also obtain the precise values of magnitude and phase angle of the current from each transformer from VRRs. The module computes the circulating reactive current of each transformer based on these parameters. A control signal obtained from these circulating reactive currents is transmitted to one or more VRRs, which regulate the corresponding tap changer to either increase or decrease the tap position until a minimal circulating reactive current is achieved at each power transformer.

Learn more – Principles of Transformers in Parallel Connection

Principles of Transformers in Parallel Connection

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1.6 Operation of Secondary Components

In addition to managing primary switchgear, SASs are also valuable for controlling secondary components, such as:

1. Operating MV circuit breakers to close and open electrical circuits.
2. Operating low voltage automatic transfer switches.
3. Activating and deactivating diesel generators.

Medium voltage circuit breakers, typically utilizing SF6 gas or vacuum isolation, are primarily employed for protecting auxiliary power transformers against internal malfunctions. The methods of controlling these devices are comparable to those used for primary switchgear, utilizing the LCD of an IED placed in a local control room and the HMI at the station level.

The diesel generator serves as a contingency power supply in the event of a complete failure of other alternating current (AC) power sources, such as those derived from the tertiary winding of power transformers or external feeders. The controls necessary to initiate and establish a connection for that equipment are typically included as components of an automatic transfer scheme.

Figure 5 – Schematics of LV automatic transfer switch  between three power sources

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1.7 Facilities for Operation under Emergency Conditions

Facilities for Operation under Emergency Conditions are SAS systems specifically designed to carry out control actions in situations that deviate from regular substation operation.

Two such facilities are:

1. A set of accessories to be added to the bay controllers for override interlocking logic. This facility shall be provided with a safety device in order to prevent its use by unauthorized personnel.
2. The second is a highly visible push‐button recommended to be installed near the HMI at the main control house. That button is used to open the circuit breakers associated with power transformers only in extreme situations, for example when smoke or fire are present around power transformer.

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2. SAS Monitoring Functions

Understanding what is happening in the controlled process is critical for control function. In HV substations, there are several characteristics and circumstances that require constant operator attention. Even if nothing unexpected is happening in the power system, it is important to examine, display, and record a large number of variables that indicate power system behavior and the operational status of substation components.

Of course, if an unusual condition develops at the substation, it must be quickly reported to the proper management levels. SAS facilities are organized to provide information to power system actors and provide timely warnings of potential risks.

Figure 6 – Engineer observing SCADA HMI of a substation automation system

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2.1 Handling Events

Common events in power substations include the following:

1. Switchgear status changes (open/closed)
2. Local/remote selector position changes
3. Manual/automatic selector position changes
4. MCB trip
5. Protective relay activation
6. Alarm status changes (acknowledged, non-acknowledged, blocked)
7. Extraction of metal enclosed switchgear
8. Diesel generator start/stop
9. Automatic transfer switch actuation
10. Alarm activations
11. Failures in switching commands.

Event handling encompasses the various techniques employed during the SAS engineering phase to achieve the objective of providing the operator with a concise, user-friendly, and dependable list of events.

These include:

1. Time stamping: Each event must be clearly labeled with the precise time of its occurrence and as closely as feasible to the location where it is detected.
2. Reliable event collection: Bay controllers are typically equipped with an event buffer to guarantee the collection of events without any loss, especially in situations where there is a large number of events occurring simultaneously.
3. Event texts: Event texts are named by creating an event list in collaboration with the substation owner. The event names are defined at various control levels in a customized manner, utilizing the native language.
4. Event presentation: The event list requires that all events be listed in a precise chronological order.
5. Storage capacity: Bay controllers must possess sufficient memory to hold a minimum number of events, such as 15,000.

Figure 7 – SCADA application that includes a powerful pre-configured alarm database that can support an unlimited number of process alarms and events

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2.2 Recording of External Disturbances

For big transmission substations, electrical utilities often necessitate the installation of a sophisticated Disturbance Recording System. This system provides ample data and additional capabilities to evaluate significant failures and other disturbances. Typically, these systems are set up in a distributed configuration, which includes multiple bay units and a master unit.

While the system operates autonomously, it is primarily connected to the rest of the SAS to monitor the status of various components.

Figure 8 – SAS screen of analysis of fault events

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2.3 Alarming Messages for Unexpected Events

Alarm messages are an essential and vital function provided by substation automation systems. It is imperative to ensure that the operator is informed of any unforeseen circumstance or condition that may necessitate prompt response. Alarm messages generally pertain to the following:

• Inconsistencies in the number of circuit breaker poles.
• The pressure of SF6 gas.
• The duration of disconnector operations was surpassed.
• Conditions of overvoltage.
• Conditions of undervoltage.
• Switching blocking conditions.
• Monitoring the oil levels in power transformers.
• Voltage absence in secondary circuits.
• Excessive operation of hydraulic pumps.
• Excessive burden on driving mechanics.
• Malfunctions in the trip circuit.
• Temperature measurements in power transformers.
• The Buchholz relay has been triggered.
• Excessive pressure during valve operation.
• Cooling system for transformers.
• Malfunctions in protective relays.
• Malfunctions in the parallel operation of power transformers.
• Malfunctions on SAS components.
• Disruption of communication at HMI facilities.
• Disruption of communication with the remote control center.

The alarm management features encompass:

1. Message texts: The process of naming each alarm message involves creating an alarm list in collaboration with the substation owner. This ensures that alarm messages are defined at various control levels in a personalized manner.
2. Alarm classification: A widely accepted convention is to distinguish between distinct alarm messages by assigning them priority levels based on the significance of the underlying cause.
3. Alarm grouping: These alarm messages are created from a specific source and are used to send alarm signals to the NCC.
4. Display means: Refers to methods that present various devices in messages or produce an audible indication, such as LCD screens, color monitors, external alarm annunciators, and loudspeakers.
5. Message presentation: The alarm messages are assigned multiple attributes to optimize the processing and management of information. These techniques encompass the utilization of color combinations and flashing effects.
6. Handling tool: Encompasses all methods for selecting handling options, including presentation mode, acknowledgement and inhibition capabilities, and filtering operations.

Figure 9 – Alarm annunciators in substation control room

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3. SAS Protection Functions

The protection role is carried out by a specific group of IEDs, also known as protective relays, which are connected to the station bus in conjunction with bay controllers. The actual voltage and current levels on primary circuits are monitored by these relays so that they can be continuously compared to the limit values that have been specified. The relay enters an active condition at the first stage when real values begin to deviate from the permitted range. This condition remains in place until a trip-condition is reached, which occurs if the anomaly continues to exist.

The segment of the power system in which the anomaly (failure) occurs is isolated from the rest of the system by use of trip orders, which are addressed in a coordinated manner to open specific circuit breakers. This is done in order to ensure that the power system continues to function normally. The following are examples of typical protection methods that are based on the segment-oriented principle:

1. Busbar protection
2. Line protection
3. Transformer/shunt reactor/capacitor bank protection.

With the advent of digital technology a few decades ago, the first generation of substation IEDs were created. Nowadays, the majority of protective relays are IEC 61850 compliant.

Recommended Course – Mastering Power Substations: Electrical Equipment, Busbar Schemes and Relay Protection

Mastering Power Substations: Electrical Equipment, Busbar Schemes and Relay Protection

Recommended Course – Transformer Differential Protection Course: Understanding Schematics, Relay Settings and Testing

Transformer Differential Protection Course: Understanding Schematics, Relay Settings and Testing

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4. BONUS (PDF): Guidelines For Implementing Substation Automation Using IEC 61850

Download Guidelines For Implementing Substation Automation Using IEC 61850 (for premium members only):

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References:

1. Substation automation systems : design and implementation by Evelio P.
2. 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. 
3. Emerging Technologies and Future Trends in Substation Automation Systems for the Protection, Monitoring and Control of Electrical Substations by Bruno Tiago Pires Morais
4. Substation Integration and Automation by Eric MacDonald