Improved Protection and Control Testing utilizing IEC 61850

Authors: Benton Vandiver III, and Bharadwaj Vasudevan, ABB, USA

Digital Substations

Traditional substations have always relied on copper cables for connecting primary equipment like circuit breakers and conventional current and voltage transformers with protection relays and control devices. But digital communication technologies and standards are driving the evolution of something new – digital substations
The defining feature of a digital substation is the implementation of a digital process bus. The IEC 61850 process bus enables the substitution of point-to-point copper connections between Intelligent Electronic Devices (IED), other devices (e.g. instruments transformers, gas monitoring, etc.) and switchgear by means of a safe, standardized optical communication bus. Thanks to the process bus, real-time measurement signals, and status information can be broadcast throughout a substation without complex wiring schemes.
In the late nineties, the world’s first digital substation was commissioned in Australia for Powerlink, a transmission service provider in Queensland. Even though the concept has evolved since then, the basic principles remain the same; substituting heavy and bulky current and voltage sensors with small and integrated sensors and substitute signaling copper wires with fiber optic communication buses. From 2008 onwards, the IEC 61850-9-2 process bus was introduced between non-conventional instrument transformers and protection and control equipment.

Digital substations enable electric power utilities to increase productivity, reduce footprint, increase functionality, improve the reliability of assets and, crucially, improve safety for service personnel. Digital substations exploit the benefits of digital protection, control, and communication technologies, mirroring the trend towards digitalization seen in many other industries. This trend towards digitalization also applies to other areas of the substation.
Within medium voltage switchgear panels, the horizontal exchange of IEC 61850-8-1 Generic Object Oriented Substation Event (GOOSE) and sampled analog values reduces wiring and accelerates the testing and commissioning. Digitalized technology can now continuously monitor mission-critical functions of high and medium voltage switchgear as well as substation transformers, while performing real-time simulation and diagnostics, ensuring that the pro-active management of the assets’ lifecycle is realized. The increasing amount of data in the substation calls for better solutions to turn this data into actionable information, including that the data is secure, accessible, and properly archived. The latest substation data management and asset health management tools provide a power utility a convenient way to take advantage of the latest advances in this area.
The Digital substation concept has also paved the way for innovative switchgear solutions such as the Disconnecting Circuit Breakers with integrated Fiber Optic Current Sensors (DCB with FOCS). (Figure 1).

 Digital Substation Design
The high-level engineering workflow required to design a digital substation is defined as a part of the IEC 61850 standard in the substation automation system process. A very basic engineering workflow is shown in Figure 2.

The design process starts with the system specification. Using the appropriate system specification tool (SST), the engineer begins to create the electrical design for the substation. On top of this, the engineer also defines the requirements for the desired network topology, including all the data exchange and function association (allocation of logical nodes (LNs)) using the same tool. The idea behind this tool is to provide a standard-based document which contains all the information for starting the detailed engineering. The output of such a tool is called a System Specification Description (SSD) file which is used as the input file to start the system configuration.
To complete the system design, we also need individual device descriptions. These files are called the IED configuration description (ICD) files. A vendor-neutral System Configuration Tool (SCT) can be used to import all the SSD and ICD files and build a detailed design. Some of the basic information included in this process are data mapping for Bay level (GOOSE) communication, client-server (MMS) communication, and process level [Sample Values(SV)] communication, etc., that are as per the specifications. The output of this activity is what the standard calls a System Configuration Description (SCD) file. This is the most important file for our topic of discussion in this paper.

Digital Substation Testing

One of the biggest benefits to standard-based engineering is that by the end of such a process we have access to all the engineered information that can be used by other standard compliant tools. Thus, testing such an engineered solution becomes much more simplified than the traditional way of doing testing.

Where to start testing:
1.   The engineered SCD file. As mentioned before, the SCD file is a critical part of the engineering effort in a digital substation. It contains various sections for data handling for multiple services like GOOSE, MMS, SV streams, etc. It's therefore almost inevitable to test the file itself to check the system-wide data consistency before even deploying this file into the individual IEDs
2. Once the SCD file gets deployed, it becomes necessary to test the configuration of individual IEDs to check and compare the system consistency for data exchange. This provides a confirmation that the SCD file deployed is working as designed by the engineer. Usually, this involves capturing the packets of data that is passing in the network and looking at all the information published as a part of each IED service like GOOSE, MMS, SV, etc.

These two tests become the basis for starting the other tests which are traditionally performed during a Factory Acceptance Test (FAT) or Site Acceptance Test (SAT). On a broad scale we can list the activities performed during a FAT or SAT as follows:
1. Functional Tests: Tests performed to validate the settings and the corresponding cor-rect operation of a function
2. Scheme Tests:  Tests performed to validate the engineered scheme. For e.g.: Breaker Failure scheme, Line Protection Pilot schemes, interlocking schemes, etc.
3. SCADA (Supervisory Control and Data Acquisition) Tests:  Tests performed to validate the data sent to the SCADA or HMI system. These tests usually involve checking the me-tered data for scaling issues, testing the alarms and events, switch controls and any outside communication to the Network Control Center (NCC)
In a digital substation, all the above-mentioned tests can be performed in a very fast and efficient manner. In the following sections, it is explained in detail how to accomplish each of the 3 tests mentioned above.

Functional Tests:  In a digital substation, it is very easy to test the individual functions. In an SCD file, we can drill down to any level required and look at the data specific to the function under test. A simple example of looking at the data model of an instantaneous overcurrent protection is shown in Figure 3. From a testing perspective, all the test plans we traditionally build to test individual protection and control functions can still be utilized. The only change affecting the test plan will be the choice of the analog output sources and the trigger condition source used.

In a traditional function testing of a current element, the analog sources were provided by secondary currents generated using a modern relay test set. Today we use SVs published by a standards-based, modern relay test set. In the past, the field personnel would use a binary output coming from the IED under test as the trigger condition to stop a test.
Today we use a GOOSE message published by the IED with the same trigger status to stop the test. The real efficiency comes from the time saved in the preparation for the test and actual time spent to conduct the test and collect the results. Since the test utilizes only the digital signals, there is no need to physically connect, reconnect, or modify individual analog signals as well as trigger signals to the IED. The only connection required is an Ethernet cable connected into the network with proper access for the test set. (Figure 4).

Today the standard provides the ability to logically place any individual IED from the system into Test and Simulation mode. This allows the IED under test to “listen” only to the modern test set publishing the test data, without the need to physically isolate the IED under test. The modern test set for digital substations may even be equipped with features to place an IED into test and Simulation Mode. The entire process of logically isolating the IED, forcing the IED to listen to the test set, perform all the necessary tests within the test plan and then returning the IED to its normal state, can all be engineered into the IED and accomplished quite seamlessly by just a push of a button from the test set.

Scheme Tests: In a Scheme test, more than one IED may be involved. The same methodology mentioned above can be extended to logically isolate all the IEDs involved in the scheme test using a single test plan executed from the same test set. This is possible because an IED in test mode can communicate with any other IED in test mode according to the standard. During commissioning, some IEDs involved in the protection scheme may not be physically available for testing.
Under these circumstances, there are tools available that can simulate missing IED's and can publish all the required GOOSE and SV messages as defined in the SCD file. Consider a breaker failure condition. If the breaker failure initiate signal is not available, the test plan can include the simulated GOOSE message of the missing IED.
Even if the device is available in the network, by putting the subscribing IED in test and simulation mode, the test set can force the IED to stop listening to the actual IED for the GOOSE message and only subscribe to the simulated GOOSE message from the test set. By isolating the individual IEDs from a network, any scheme can be tested within the same test plan without performing major changes to the physical infrastructure. This allows SAT tests to continue without waiting on a piece of equipment to physically be available. The overall time is taken to test and commission a substation can be reduced. (Figure 5).

SCADA Tests: The SCD file which was used to build the communication mapping between the IEDs also contains portions of data mapping required for the SCADA communication. This means SCADA testing can be done in parallel with the relay testing. The same GOOSE messages and SVs that were simulated for the IED testing, can also be simulated to test the SCADA points.
Conversely, on the IED side, the testing tools can be used to act as a SCADA and all the SCADA controls can be tested before deploying the actual SCADA at the substation. The test plan can be automated to test each operational scenario and every data point required for the SCADA system. (Figure 6).

Troubleshooting in a Digital Substation environment
The data model in IEC 61850 has all the information pertaining to the current state of every function modeled within an IED. Many of today’s modern relay test sets, make it possible to obtain the current state of any function in an IED. In the standard, it’s called the ‘Behavior of the logical node.’ Consider the scenario mentioned under functional testing above. An IED can be put into test mode by a test set without any physical isolation or modifications. It’s also equally necessary to validate before starting any test to physically check if the ‘behavior’ of the function has changed. Positive feedback can be used to verify that an IED is in the correct test or simulation mode before proceeding with the detailed test plan.
Every message engineered using IEC 61850 has a quality information bit associated with it. There are methods and/or tools within the test software that can verify this quality bit according to the standard’s definition and provide visual cues to diagnose the actual validity of the data. This way the testing personnel can focus on the real application problems rather than interpreting bits and bytes to their actual meanings.

Typical Use Case
Consider a typical 138/13.8kV substation. Assume it has 5 feeders. Each feeder will have a breaker controller, feeder protection, plus transformer protection and overall bus protection for the substation. Typically, it would take about 3 days to test and commission the whole substation using traditional secondary injection methods. In the overall time spent for testing these protection panels, a third of it is spent on preparation. This involves choosing the right sources to be isolated for testing, isolating the correct trips/interlocks and connecting the right cables to the test set. In a digital substation, most of the preliminary work can be done even before arriving at the site. The SCD file for the substation can be used for the test plan preparation which will provide information on what SV streams need to be simulated and what functions are to be tested and what GOOSE messages need to be monitored. Another one-third portion of the time is spent on running the actual tests which include all the functional and scheme tests. With the techniques mentioned above for conducting the scheme and SCADA test, it is possible to reduce this time by half. The final one-third of the time is spent on troubleshooting and documentation. By automating test plans to document the results and by using all the techniques mentioned above for troubleshooting, it is possible to document every step of the test plan with detailed checks and feedbacks from all the IEDs and complete all the tests in half the time required traditionally.

Conclusion
The intent of this article was to clear some initial misconceptions around the standard that usually lingers with first-time users. Most of the existing accepted processes used for testing and commissioning a typical substation can be easily adapted for a digital substation. By using automated test scripts, the whole test plan can be automated, and a report can be prepared and published much faster than through a traditional test procedure. Only a few tools have been showcased in this paper to help with troubleshooting. the standard itself has evolved over the last few years and has provided a lot of new features like the LGOS, LSVS, and LTRK to online monitor GOOSE, SV streams and all the MMS based services respectively. There are also logical nodes available today to monitor the error statistics of the IED and switch communication ports which help with communication supervision for any network topology. There are many tools available today which utilize the built-in features from the standard and provide the users with options to test, commission, diagnose and maintain a digital substation. For details and the latest information on this subject, please refer to Brochure 760 (March 2019) developed by the CIGRE working group B5.53 who investigated and reported on the state of the art related to test strategies for protection, automation and control functions in a fully digital substation based on IEC 61850 applications. To fully utilize the benefits of the standard, strong importance must be given to the engineering of the digital substation and resulting SCD file using a standard conformant system engineering tool. Today the standard provides enough conformance guidelines to verify tool compliance. Enough has not been said about the benefits of IEC 61850 and in this article, we attempt to highlight the usability of the standard itself. It’s a proven global standard that can benefit any utility design.

Biographies:

Benton Vandiver III received a BSEE from the University of Houston in 1979. He is currently the Technical Sales Engineer for ABB in the South & Central Regions located in Houston, TX. A registered Professional Engineer in TX, he is also an IEEE senior member, PSRCC member, PSCCC member and Vice-chair of the P0- Protocols and Communication Architecture Subcommittee, and IEEE-SA member. He has been in the power industry for 40 years and worked previously with Houston Lighting & Power, Multilin Corp., and OMICRON electronics. He has authored, co-authored, and presented over 100 technical papers and published numerous industry articles.

Bharadwaj Vasudevan graduated from North Carolina State University with a master’s degree in power systems and joined ABB as an Application Engineer for Protection, Control and Auotomation systems. He started his career in power systems with Areva T&D India Ltd. He has worked on various EHV substation de-sign projects throughout India.Currently he is working out of New Jersey as the Regional Technical Manager (ABB Power Grids – Grid Automation) for North East US. In the last 6 years he has been invloved in numerous IEC 61850 projects accross the United States.

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