Testing in the Digital Substation: IEC 61850-based Systems
The transition of the electric power industry toward a smarter grid is characterized with significant efforts to perform all tasks more efficiently and reduce outage duration, including those related to the operation of multifunctional protection IEDs.
By Alexander Apostolov
The transition of the electric power industry toward a smarter grid is characterized with significant efforts to perform all tasks more efficiently and reduce outage duration, including those related to the operation of multifunctional protection IEDs. The widespread implementation of IEC 61850-based substation protection and the increased interest in digital substations (based on the sampled values interface with the substation process) provides an opportunity to develop and implement protection, automation and control systems that can be tested remotely.
Maintenance testing of hardwired protection and control systems often requires a crew to drive to a remote location to perform it. By replacing hardwired interfaces with IEC 61850-based communications interfaces, utilities can have remote access to the substation for remote testing.
The replacement of part or all the hardwired interfaces with communication links requires development and implementation of methods and tools that maintain the same level of security during the testing process, while at the same time take advantage of the benefits that IEC 61850 provides.
It is common for people to use the terms effectiveness and efficiency interchangeably, believing they are more or less the same. The terms are, however, different. Effectiveness is the degree to which objectives are achieved, without consideration of the resources being used. Efficiency, on the other hand, is the extent to which a resource is used to effectively achieve an objective.
Maintenance testing in general is testing performed in an energized substation to diagnose and identify equipment problems or confirm the effectiveness of different actions taken to change settings, upgrade or repair the protection device or another component of the fault clearing system. The tests to be included in the maintenance test will depend on which of these listed measures have been implemented. It is critical to ensure that the testing will not result in any undesired operation, making isolation of the test object from the rest of the energized substation extremely important.
Requirements for Isolation During Testing
Functional testing requirements for devices and distributed functions also determine the methods for testing both types of systems. The order in which system components should be tested are:
1. Functional testing of individual IEDs used in a protection scheme
2. Functional testing of distributed protection functions within a substation
Conventional hardwired protection devices must be physically isolated (Figure 1), using a test switch that completely disconnects the tested device from the substation environment.
FIGURE 1: Physical Isolation for Testing
In an IEC 61850 based digital substation, physical isolation is not possible. It is necessary, therefore, to implement the test related features defined in the standard.
IEC 61850 Edition 2 Testing Related Features
Function elements of a protection IED, such as an inverse time phase overcurrent element, are represented in the IEC 61850 object model by logical nodes (LN) contained in logical devices. The LN or a logical device can be put in TEST mode using the data object Mod LN or LLN0.
In TEST mode, the application is represented by LN works. All communication services work properly and receive updated values. Data objects will be transmitted with quality test. Control commands with quality tests will be accepted only by LNs in TEST or TEST/BLOCKED mode.
FIGURE 2: Mirroring of Control Information
The TEST/BLOCKED mode applies to function elements that have a physical output to the process. In this mode, no output will be issued to the process, allowing, for example, a function element operating the breaker (LN XCBR) to be tested without being energized in the substation.
A command to operate can be either initiated by a control operation or by a GOOSE message that the subscriber interprets as a command. If the command is initiated with the test flag set to FALSE, it will be executed only if the function (LN or logical device) is ON. If the device is set to TEST mode, it will not execute the command.
Control commands or GOOSE messages with quality test set to TRUE will be accepted only by LNs in TEST or TEST-BLOCKED mode.
Another important feature that has been added is the mirroring of control information. This supports the possibility to test and measure the performance of a control operation while the device is connected to the system in TEST-BLOCKED mode.
A control command is applied to a controllable data object. As soon as a command has been received, the device will activate the data attribute opRcvd (Figure 2). The device will then process the command. If the command is accepted, the data attribute opOk will be activated with the same timing of the wired output. The data attribute tOpOk will be the time stamp of the wired output and opOk.
These data attributes are produced independently, whether or not the wired output is produced. The wired output will not be produced if the function is in TEST-BLOCKED mode.
Maintenance testing in cases such as relay mal-operation requires IED testing before putting it back in operation. In typical cases, this requires sending a testing crew to the substation to perform the tests—a time consuming and expensive process.
Sending a crew, especially to remote locations under difficult weather conditions, is not only time consuming, but might be a safety hazard for the team and usually results in a prolonged outage. Some utilities, therefore, are actively implementing the concept of digital substations and seriously considering performing remote testing in IEC 61850 Edition 2 based installations.
Protection systems installed in a digital substation environment allow testing to be performed remotely, however, the use of both sampled values and GOOSE messages is required for the end-to-end testing. For testing only part of a scheme that is affected by the modifications, it is possible to do the remote testing using testing features from IEC 61850 Edition 2. This enables testing a subset of functions and their elements while keeping the rest of the system in operation.
Functions that can be tested remotely depend on the substation communication system’s design and the test equipment’s integration level.
FIGURE 3: Remote Testing Configuration
Remote testing is defined as a testing specialist’s ability to perform testing of a protection, automation and control function, device or distributed scheme from a remote location, without being physically present in the substation.
This means that the testing system must be pre-engineered as part of the substation protection, automation and control system and permanently installed in the substation.
In addition, the test computer and test devices must be substation hardened to withstand the substation environment. Because testing is performed remotely through a wide area communications interface, it is critical that the interface meet cybersecurity requirements.
Testing specialists use remote access software tools to remotely control test computers (Figure 3). Remote desktop software, more accurately called remote access software or remote-control software, allows the user to remotely control one computer from another computer by taking over the mouse and keyboard and using the computer being connected as if it was the local computer.
In addition, cybersecurity measures must be put into place to ensure secure communications between the remote office computer and the test computer located in the substation. Proper assignments of different access rights are necessary to ensure that only people with sufficient knowledge of the tools and test procedures can run the remote tests.
The remote testing concept is currently being defined by a CIGRE B5 working group—B5.53. It is focused on “test strategy for protection, automation and control (PAC) functions in a full digital substation based on IEC 61850 applications.” The working group is considering the methods for configuration and execution of remote testing—the requirements for extensions in the IEC 61850 models that will support it.
This will require some organizational changes to bring testing of the different function types—protection, control, measurements, recoding, etc.—under a single authority. All interested groups must work together when engineering a digital substation to define test plans covering all the earlier mentioned functions to support the possibilities for local as well as remote testing, when necessary.
Even with some challenges and investment in permanently installed test equipment in the substation, the benefits in improving testing efficiency are too big to ignore. They include:
• No travel time
• Improved safety of testing crews due to the elimination of travel to remote locations or during dangerous weather conditions
• Minimum or no setup time
• Independent of weather conditions
• Improved PAC system availability
• Reduced or no outage time
Edition 2 of IEC 61850 introduced many new features that further enhance the standard’s power. These features should make end users’ lives easier—assuming the features are supported by future products. They are designed to support not only automated configuration and execution of test procedures, but also remote testing for some specific test cases.
Interoperability between engineering tools (including testing tools) likely will be improved—something that is urgently needed. New features supporting functional and system testing should facilitate isolation techniques required for IEC 61850 based installations, both during commissioning, in case of maintenance problems, as well as for routine testing.
Even with some challenges, the benefits in improving testing efficiency are too big to ignore. UP
Dr. Alexander Apostolov is principal engineer with Omicron Electronics. He received a master’s degree in electrical engineering and applied mathematics and Ph.D. from the Technical University in Sofia, Bulgaria. He has 40 years’ experience in power systems protection, automation, control and communications. Dr. Apostolov is an IEEE Fellow and member of the Power Systems Relaying Committee. He is also a Distinguished Member of CIGRE, holds four patents and presented more than 480 technical papers. Dr. Apostolov is an IEEE Distinguished Lecturer and Adjunct Professor at the Department of Electrical Engineering, Cape Peninsula University of Technology, Cape Town, South Africa.