Traditional substations (mechanical relays, limited visibility, first RTUs with IO)
High availability and constant operation of an electrical substation has always been the focus of an electrical company. More faults mean more interruption of service to clients and it translates to less revenue that is not desirable to any company. From the early age of electrical systems, engineers and operators have always been interested in collecting useful information on different devices in a substation so they can better evaluate the health of their system, predict potential problems and – in case of a fault – to analyze and troubleshoot the problem as soon as possible to protect their high values assets and to improve their continuous service to their clients
Early substations consisted of mechanical relays and meters that barely supported recording and had no means of communication. Fault recorders were capturing information mainly in the form of paper charts, so reading and analyzing the information was not a straightforward process.
Lack of communication caused any maintenance or troubleshooting to be costly and lengthy because personnel had to be sent to substations that were often far away and hard to reach.
With the introduction of microprocessor technology, digital protection and control devices became more intelligent. New intelligent electronic devices (IEDs) can collect and record information on many different parameters of a system, process them based on complex logic in a fraction of a second and make decisions on abnormal situations to send control commands to switches and breakers to clear the fault.
In addition to their superior processing capability, modern substation devices can also hold information in their internal storage for a certain period and transfer this information to third-party applications for further study and analysis. IEDs can now send information to a local or remote user via different types of communication. This gives operators more flexibility on how and when to process the information to provide a fast recovery time from an interruption in the substation.
With more information remotely available, new supervisory systems were developed to facilitate the task of a system administrator in the control center. A Supervisory Control and Data Acquisition (SCADA) system can collect information from various IEDs in an electrical system via different methods of communication and then control and monitor them using various visualizing technologies – even automating the supervision task based on predefined parameters and algorithms.
A Human Machine Interface (HMI) is deployed in each substation to provide operators with the local control and monitoring capabilities that are often necessary during the configuration, commissioning or maintenance of the substation.
Digital substation, autoconfiguration and standards
Digital control and protection technology has been evolving since the first introduction of digital devices. The more intelligent and capable the devices became, the more responsibilities that tended to be transferred from human to device. Unlike early digital technologies – where an operator had to work with bits and bytes on a primitive user interface to define every parameter of the system and make sure all elements of the system are correctly configured to make the processing and communication work – new technologies let users focus more on high-level aspects of the system architecture by taking care of the tedious task of defining every single detail in the system configuration.
In the beginning of the digital era, each manufacturer had its own way of interpretation and implementation of different elements in an intelligent system. These various approaches led to lack of interoperability and caused vendor dependency. New standards have been developed to make sure devices from different vendors will function in the same predefined way. This gives users more flexibility and freedom to choose functions that suit them better without having to focus too much on manufacturer.
Although remote access to information provides operators with much more visibility to the system, it also introduces new concerns and challenges. Having information exchanges with remote entities – and often via shared media – makes cyber security one of the most important considerations in any system deployment.
Big data, non-operational data processing
In the earlier years of digital technology, limited data points were available on each device and the high cost of communication – as well as a slow data exchange rate – would render it impractical to collect a high amount of data from each substation. Only necessary operational data was sent to control centers and communication lines were cautiously programmed to minimize the bandwidth and communication cost.
Rapid evolution of communication and process technologies now offers system administrators the luxury of polling more and more operational and non-operational data points from their substations. This information can now be processed in a variety of ways using different software to more efficiently monitor an electrical system. This technology improvement provides for greater sight on overall health and useful information for other applications such as condition-based maintenance and asset monitoring.
A communication protocol defines a set of rules for transmitting data between two or more communication parties. Protocols have been developed to serve various purposes based on specific requirements of that application.
Traditional protocols (DNP3, MODBUS, proprietary)
Most of the early protocols in the electrical automation industry were proprietary protocols developed by device manufacturers. Although proprietary protocols work especially well with devices from the same manufacturer, lack of interoperability – along with vendor dependency – pushed electrical companies toward standard and open-source protocols. Today, device manufacturers have adopted popular standard protocols. As a result, proprietary protocols have been almost completely phased out from the industry. Like other protocols, substation automation communication protocols have evolved along with communication infrastructure improvement. Unlike slow and error-prone older protocols, newer protocols can deal with different communication mediums, recover from communication sever failures and deliver information in a more robust way.
Although older protocols such as MODBUS are still used in substation automation, most of the systems have already adopted protocols like DNP3 (North America) and IEC 60870 (Europe) as their de facto default protocol.
In addition to the set of rules, control headers and error recovery mechanism, traditional protocols also define the structure of a “point list.” A point list is the list of all data points the communication parties want to exchange as well as additional information such as point address and point type. The point list is defined during the configuration of a communication instance and will be deployed in the devices that will use that communication instance.
The most deployed protocol architecture in substation automation industry is the Master-Slave (server-client) architecture where one or several devices called slave (or server) are polled by a master (client) device or software in some predefined intervals. In some protocols, slaves can also initiate the communication to send information to the master using a mechanism called “unsolicited response.”
Although traditional protocols require more time and effort during configuration and commissioning, they are popular in the automation industry because they are easy to understand, configure and troubleshoot.
Faster and more reliable network infrastructure opened the possibility of implementing higher-level protocols that make the task of configuration, commissioning and testing easier – even though the protocol itself is more complex. These newer protocols tend to move from an IT-oriented paradigm to an OT-oriented paradigm where users focus mostly on “what” a device should do rather than “how” it should do it.
In the early 1990s, parallel efforts were started to develop an object-oriented protocol that focuses more on the actual functions and information of a device, rather than low-level implementation detail such as register addresses and data type.
As utilities tried to move toward vendor-agnostic solutions, interoperability was another main force behind new protocol developments. New protocols should make sure devices from different vendors would be able to exchange information with the least amount of configuration.
The IEC 61850 standard was accepted by most of the utilities as a modern protocol that can address the shortcoming of traditional protocols. Unlike older protocols, IEC 61850 is more a suite of standards that address different aspects of a modern substation, rather than just a communication protocol. It defines in detail a standard model for each function in a substation plus the communication standards to support such a model as well the methods on how the map this model into the lower level communication. IEC 61850 also addresses necessary hardware requirements for a substation-grade device and defines a communication language that can be used to exchange a substation or a device model.
Although traditional protection systems tend to be completely separated from the automation and control system – and are still relying on dedicated hardwire signals between CTs and PTs and relays– IEC 61850 presents a system model where protection data points could be exchanged on a shared Ethernet link. It implements necessary measures to make sure this information will be delivered in a deterministic way within a redefined period of time.
GOOSE and sample values concepts in IEC 61850, define the object models and communication criteria that can be used to exchange protection information (e.g. voltage, current, breaker status) over a dedicated ethernet link called process bus (in less than 4 ms to comply with protection system time constraints). This reduces the amount of wiring in a protection system because all the wires between CTs, PTs and protection relays can now be merged into one ethernet cable.
IEC 61850 also includes testing methods a user can refer to during the commissioning or maintenance phase of a project to make sure all devices are functioning according to the requirement of the project – and to isolate problems during a troubleshooting session.
Being connected to a substation and retrieving vital information from remote devices has always been a challenge for system designers. Not all the substations are of the same size or importance. Many substations are in remote areas where communication could be the biggest challenge when it comes to monitoring a substation.
Early remote monitoring started by using modems on telephones or leased lines. At the time when most of the devices in the field had very limited communication capabilities, these methods of communication were sufficient for most situations. Initial efforts were made using a gateway device in the field that would concentrate information it was receiving from serial devices and send that information to a master station using a modem based on a predefined time schedule. Concentrating information would improve the communication (and reduce the cost) as sending data points in one burst would reduce the communication time – as compared to sending small data packets from different devices over a longer period of time.
In modern substations, most devices communicate via ethernet links. Data from different devices is sent to the control centers via various communication mediums. Utilities generally prefer to install their own inter-sub communication infrastructure using fiber-optic links or radio mesh systems but in some cases, especially in remote areas or smaller substations, using cellular modems becomes more practical.
Although using a public infrastructure such as cellular networks can reduce maintenance costs, it also raises concerns about security and availability.
As IEDs improve and implement more functions, new applications can be developed to better leverage these new capabilities. With more accurate and up-to-date information from system elements, IEDs can provide users with better insight on system operation and general health.
Although redundancy is not a new concept, new technology makes it easier to implement and manage redundant devices. In a hot standby configuration, two devices (e.g. a gateway) can be configured in a group where one acts as ‘’active’’ while the other one stays in ‘’standby." The standby device constantly monitors the status of the active device while the active device receives information from other parties, updates both its internal database and the database of the standby unit and sends information to one or multiple clients. If the standby device detects that the active unit is no longer communicating, it assumes (after a predefined period of time) that the active device is no longer functional and takes over the control and continues sending/receiving information.
Sophisticated redundant systems also support virtual addresses. A virtual address will hide physical device addresses, so the transition stays transparent as long as the virtual address is used for the communication.
Time synchronization devices and methods such as GPS clocks and IRIG-B signals have been used in substations for quite a while. The goal is always to keep the internal clock of the devices in a system synchronized so timestamps from different sources can be precisely compared in a system analysis. Time synchronization is also critical in a protection system.
New substation automation technologies offer new methods of time synchronization. Unlike older systems where the time signal was distributed using hard-wired links (IRIG-B wires, serial cables), new time protocols leverage the communication infrastructure to distribute time signals. Some communication protocols (e.g. DNP3 or IEC-104) as well as NTP (Network Time Protocol) and SNTP (Simple Network Time Protocol) can already provide sufficient precision for many applications. However, the high-time precision that is required in mission-critical applications cannot be achieved using these methods.
In recent years, Precision Time Protocol (IEEE standard 1588) was introduced to leverage existing network infrastructure to provide sub-microsecond time accuracy for devices in control and protection systems.
|Time synchronization methods||Typical precision|
< 100 ms
1 ms – 10 ms
1 µs –10 µs
20 ms – 100 ms
System logs, event files
With more processing power and internal storage, IEDs can now produce more information regarding their internal activities. Logging this information and sending it to a control center will provide operators more visibility on what happens in the device and, in case of a problem, gives hints on where to start the troubleshooting. A Syslog server can also be installed in the system to collect these log files from different IEDs and store them in a central repository for further analysis.
Event files can also be generated based on some changes on internal status of a device or data points. For example, an oscillography file captures the value changes on some system parameters (e.g. voltage, current, phase angle) during a fault. Analyzing this file provides system engineers with valuable information on the status of the system right before and after a fault occurs.
Similar to log files, event files can be collected centrally and made available for a wider range of users. This central repository also makes sure information won’t be lost from the devices – as they still have limited storage space as compared to a local server.
Gateway (automation platform)
IEDs (protection relay, smart meters, etc.)
Gateways are initially employed to collect information from serial devices and make this information available for a remote user, but they also include support for more functions that are required in a substation.
A typical modern gateway has a modular design and can host multiple serial and ethernet ports in fiber or copper. Its internal storage has adequate space to collect thousands of files and it supports sophisticated protocols and time synchronization methods.
As a data concentrator, a gateway can collect information via several serial or ethernet ports from the devices in a substation and make them available to remote users. Although the data concentration function is not as important as it previously was, it still adds a lot of flexibility to the system. This is especially so in cases where a cellular modem is used as the link to a remote substation. Concentrating information and sending in a chunk – instead of individually collecting information from the IEDS – reduces modem usage and lowers communication costs. A data concentrator can also offer more storage to maintain log and event files as compared to internal storage of the IEDs.
Using a data concentrator also simplifies system configuration on the SCADA side. Instead of individually setting up the devices in the substation in the SCADA system, only one gateway with one communication link and one set of points is required to be integrated in the SCADA system. When adding, removing or changing a device in the field, the SCADA system only needs to update the point list without changing the communication link parameters.
As a protocol translator, a gateway can receive information from different devices via different protocols, translate the inputs in another protocol and send it to local or remote users. Although growing use of standard protocols reduces the need for a protocol translator there are situations where utilities still have installations with legacy devices, but they need to upgrade the outbound protocol for performance or security reasons. A protocol translator can facilitate such an upgrade by keeping the legacy devices intact.
Once data points are concentrated in the gateway, they can be available to various remote and local users via different protocols. This feature of the gateway is especially useful in cases where a device has limited outbound communication. Different users with varying interests may want to access the same device at the same time.
Since a gateway collects data points from different devices in a substation, it is the ideal place to implement some logic for control and operation purposes. By using a well-known programming language such as IEC 61131, input points can be created, and output commands can be issued based on some predefined logic. These points can also be sent to a control and monitoring system in the master station.
Although the terms RTU and gateway are used interchangeably these days, first-generation RTUs were devices with limited communication capabilities that were used to convert hardwired signals into digital binary or analog data points. These devices generally had high I/O capacities as most of the system parameters were not yet available in digital format and they communicated over serial links.
With the evolution of digital relays, most system parameters became digitally available directly from relays and meter-over-ethernet links and via new protocols – and the demand for high-capacity RTUs was reduced. However, there are still some hardwire signals (e.g. breaker monitoring and control, cabinet door safety switch, transformer oil gauge) that need to be monitored or controlled by remote users – sometimes even separately from the protection system.
A distributed I/O device can convert a limited number of Input/Outputs into digital values and communicate those values via a standard protocol through serial or ethernet links.
An IED (Intelligent Electronic Device) is a microprocessor-based device with some processing and communication capabilities. The biggest category of IEDs in a substation is protective relays. This device can receive information from CTs, PTs or other type of sensors, make control or protection decisions based on some algorithms and issue commands to other devices such as breaker and switches. Although sensor signals are still mainly in hardwired form, modern IEC 61850-based substations can communicate digital information between sensors and relays using sample values or GOOSE protocols. A digital relay can also generate and save log, event and oscillography files.
Digital meters are another type of IED that can measure and record main system parameters and communicate them to a control center.
A Supervisory Control and Data Acquisition (SCADA) system is an enterprise-level software whose main task is to monitor and control an electrical grid system based on the information it collects from the substations within that system. A SCADA system is normally installed in a control room where operators can consistently monitor the overall health and function of the electric system. To provide enough information for an operator, a SCADA system supports a range of features and functions such as a single-line diagram and a historian.
A single-line diagram is an interactive graphical representation of the grid system via which an operator can monitor different parameters of the system and issue commands as necessary. A SCADA single-line diagram generally consists of an overview of the system plus multiple detailed pages for different components of the system to which an operator can navigate.
Unlike single-line diagrams that show the components and connection of the system, the real-time trending function provides the operator with a real-time chart that monitors the values it receives from devices in the substation. An operator can add one or several points to the chart and follow the real-time value changes for better analysis of the system.
Recording information is another important function in a SCADA system. Except for some buffering capabilities, most IEDs and gateways have insufficient internal storage to maintain a record of real-time value changes for an extended period of time. One of the main tasks of a SCADA system is to record the real-time values it collects from the devices in the field. This information is saved in a relational database and can be surveyed based on various filters using the historian function. The recorded information can also be accessed directly from the database using a third-party application for further analysis.
Event and alarm management
Event and alarm management is also part of the standard functions offered by a SCADA system. An alarm can be raised by the SCADA system in an alarm window based on predefined criteria. The operator can then acknowledge the alarm and clear it when the value of the point the alarm was created on goes back to its normal status.
Like alarms, events can also be generated based on the status of the data points collected from the field. Contrary to an alarm management system, an event management system doesn’t require an operator’s intervention – as generally events are not considered critical.
One of the main tasks of a SCADA system is to provide the necessary information to the right people in a timely manner. In a new SCADA system, the software administrator can assign notifications for different alarms and events to specific users or a group of users and send them email or text message notifications based on that list.
A Human Machine Interface (HMI), is a stripped-down version of a SCADA system that is used locally in a substation – especially during commissioning and maintenance. Unlike a SCADA system, an HMI only monitors local devices and generally doesn’t have a historian capability. An operator can use a HMI system for operating the devices in the system or to verify the current status of the system.
A HMI could run on a local computer substation, but a better solution would be to use a modern gateway that supports a built-in HMI function. The HMI function on such a gateway would be locally accessible via a touchscreen monitor directly connected to the gateway or locally/remotely through a web connection. This approach eliminates the use of a substation computer – resulting in less hardware and software maintenance considering that a computer running on Windows OS needs regular patch management.
The concept of the single-line diagram in a HMI system is the same as in a SCADA system. A graphical representation of the system helps the operator to visually investigate the current state of the substation and to send commands to the control. A HMI has fewer single-line diagram pages as it only needs to represent its own substation.
Except for the fact that HMI alarm management only takes care of local alarms and events, the rest of the functionality is similar to a SCADA system alarm management system.
Another function of a HMI system is to show some form of a summary on the general health of a substation. Information such as the number of successful and failed communications, gateway CPU and memory usage and the software version can be shown in a graphical form, so an operator can evaluate the overall condition of the system at a glance.
Commissioning tools is a set of tools on a HMI system that offer an operator various functions that can improve or speed up the process of testing and commissioning during a substation installation or troubleshooting session.
Showing real-time value of the points received by a gateway, the ability to simulate some values and other functions such as reading logs or events can provide better insight into the current status of the system and potential faults that may occur during the operation.
In the early years of digital communication, substations were either connected through low-bandwidth links or not connected at all. Only a small set of information was sent to the control center due to the communication limits and this information was only used in real-time control systems. Devices in the substation had limited processing and communication capabilities and only provided the necessary information required by the control system.
The rapid growth in communication and processing technologies changed digital devices into intelligent units capable of sending information at a fairly high speed. Communication links between control centers and substations can now carry a large amount of information with a lower cost, so control systems have access to a rich set of operational and nonoperational data they can use in many different paradigms.
Unlike early digital control systems, control centers are no longer only interested in operational data. The nonoperational data collected from the substations can now be fed into many different applications to predict and prevent future errors, provide improved insight into the fleet of devices, manage devices in a more secure way and limit operator direct access to the devices – or decrease maintenance on-road time.
Increased device connectivity provides better device visibility. Utilities can leverage this visibility to do many tasks remotely and save time and money by limiting the number of times they need to send a crew to a substation.
New standards and guidelines such as NERC CIP increasingly demand higher visibility of devices, so every change can be traceable back to its originator.
Unlike old mechanical devices, digital device health is highly dependent on its firmware health. IED firmware changes over time – as new features or bug fixes become available, so utilities may need to update the firmware version of their IEDs. Updating firmware on a big fleet of devices from various manufacturers is a challenging task. An application that can automatically monitor firmware and do batch updates in case of a new release saves a lot of time and effort and prevents errors.
Secure remote access
These days, most digital devices can be remotely accessed by an operator during a maintenance or programming session. Utilities also need to track and log these accesses, especially for security auditing or troubleshooting. Native Vendor Tools (NTV) provided by IED manufacturers often have limited log capability (if any) – and that doesn’t meet the requirements for an enterprise-level system.
A central remote access system provides secure remote access to a device while it logs every exchange between the user and the device and saves this log in its internal database for further investigation, if necessary. This type of system can also leverage a central authentication system such as MS Active Directory to authenticate and authorize users before they can access a device.
Keeping track of the configuration of the devices in a small substation is fairly easy. On the other hand, keeping track of all devices in a utility with many (often remote) substations is quite a big challenge. With standards such as NERC CIP that require every configuration change to be reported, companies need an enterprise-level application that can automatically monitor the configuration of each device in the system and notify the right people in case of a change. A user should also be able to compare two configuration files to better investigate the changes and to spot unauthorized modifications, if any.
The concept of asset monitoring began to sound practical when new technologies made feeding various nonoperational data to the control centers easier and more affordable. Asset monitoring can cover a wide range of applications, but the general idea is to use the nonoperational data from IEDs in the field and process them using predefined algorithms to produce or predict new information on various aspects of the system – such as health, potential problems or upcoming maintenance.
Event and oscillography files
Immediately before and during a fault, data fault recorders generate event and oscillography files. These may help a protection engineer to better investigate the cause of a fault and take necessary measures to readjust the system to prevent future similar faults.
These types of files are internally stored in a protection device and normally need to be manually downloaded from the device. Even if the device is remotely accessible, a user should take time to go through the files to find the new ones and then download and share them in case more than one person requires access to these files.
A better approach would be to have an automated system monitor the protection devices and download the new files when they become available. This type of system can also send notifications to the stakeholders with the files attached to the message or a link to the folder where they can find a copy of the files. This system can cut operational costs by automating the download process and decreasing the time it takes for the information to become available to the operators.
By analyzing information coming from devices in the field, an application can be used to predict when and why a particular device or equipment may need maintenance. Condition-based maintenance can eliminate sudden and unpredictable substation shutdowns that could happen when a piece of equipment fails abruptly. It can also help utilities to lower maintenance costs by planning maintenance in advance and combining multiple maintenance sessions into one based on the information they get from a condition-based maintenance system.
During the early years of digital control systems, cyber security was not a concern. Most of the communication was done using dedicated methods such as telephone lines and modems that where not visible to outsiders. Security was not even an issue in the initial design of the internet infrastructure. As the internet became available to the public, more vulnerabilities were detected. Newer technologies have attempted to address the problems caused by a shared link accessible to anonymous users.
Security threats can be categorized into two main types:
A good security infrastructure should make sure the right information will be accessible only to the right people at any time using proper authentication, authorization and access control.
The North American Electric Reliability Corporation (NERC) developed a suite of standards for Critical Infrastructure Protection (CIP). This suite includes nine different standards that cover various areas from physical security to electronic and cyber security. Its main purpose is to limit access and grant it only to authorized people, to secure connections and to log every access to an element in the system – while documenting any changes.
A major requirement in a secure system is to make sure users can only access or modify the assets they are given permission to by a system administrator. This type of system can leverage a corporate-level access management system (such as MS Active Directory) and adopt it in a substation automation environment to grant granular access to the operators, system engineers and other users that need to access the devices in the system.
A user management system should also log and timestamp every access to the system and make sure access privileges are revoked once a user leaves the company.
To eliminate travel time to a substation, utilities will use a remote access system that works in conjunction with user access management tools. The main drawback of a remote access system is that security may be compromised, especially when shared links such as cellular modems or internet connection are used to establish communication. In addition to various encryption methods, a Virtual Private Network (VPN) can also be used to secure a communication link and to hide it from unauthorized users that may use the same shared connection.
Digital devices are normally password-protected to prevent unauthorized people from accessing and modifying a device. Security standards require a device password to be routinely changed. Managing passwords on hundreds of devices cannot be done manually, so an automated system is required to keep track of password changes.
Logging user interaction with a device can provide system administrators or other users with valuable information – especially in case of a failure. Logs and traces can be investigated to spot any potential mistakes during a commissioning or maintenance session. An automated system can collect this log information and save in a central database for future use.
Although firewalls and antivirus software are generally part of the IT infrastructure in a substation control system, more sophisticated devices also support some of these security features. As a gateway can sometimes be used as the single point of access to a substation, it needs to support security measures that block an unauthorized access.
A gateway firewall will block all communication ports, except those necessary for normal operation. The malware protection system on a gateway uses a whitelisting approach to constantly monitor the codes run on the gateway. Codes that are not digitally signed by a trusted source are blocked and gateway operation is halted if suspicious code is detected.