by Thierry Godart and Farel Becker, Siemens Smart Grid
The distribution grid is experiencing challenges unprecedented in its 100-plus-year history. The need to integrate renewable distributed generation is occurring as baseload power plants are being removed from service-the result of society’s goals to reduce greenhouse gases and reliance on nuclear generation. Existing system assets are aging faster than replacements are being installed. Load continues to grow and change in ways that might make traditional mitigation methods less effective. Never before was substation digitalization and integration required to meet these demands.
Substation automation is integral in building a more intelligent grid and is the nerve center for many utility operations. Managing millions of data points each second, a substation must be able to operate effectively and manage this data to provide information for the utility and end users. Communication technologies make this data management possible. They provide the ability to send and receive data from remote grid locations, and by embedding advanced communications technology in the distribution network, utilities can monitor power networks, manage load usage, improve reliability and reduce operational costs more effectively.
Numerous challenges have forced new approaches:
- Advanced protocols have been developed to disseminate this data required.
- Intelligent electronic devices (IEDs) contain advanced applications to monitor, protect and control these complex networks.
An intelligent agent of the distribution management system (DMS) can be located in the substation to perform distribution network applications such as state estimation, system power flow, optimal feeder reconfiguration, FLISR and volt/VAR control.
Ethernet-based protocols provide two advantages. IEC 61850, especially, is ideal for use inside substations and out on distribution feeders. First, signals are sent in near-real time with closed-loop speeds of about 10 milliseconds. This is the same time frame that power line carrier can send a transfer trip or blocking signal for a high-speed line protection system. The second new feature is the self-describing nature of the information sent. Previous proprietary and industry protocols involved the use of elaborate maps to associate a data bit with previously programmed identification. This limited the ability to route data and share among diverse equipment and systems.
Sharing self-identifying data sets at very high speeds increases the range of information that can be sent from a few bits to virtually anything the IED knows about the distribution system at its location. This information can be used in peer-to-peer, client-server and distribution network applications. Pole-top IEDs can communicate GPS coordinates and distance to the fault location information via IEC 61850 for more accurate outage and work force management at the control center level. A few specific applications have been encouraged and simplified by these communication technologies.
The goal of protection is to isolate and mitigate abnormal operating conditions such as faults, equipment misoperations, overloads and out-of-boundary operating parameters. Traditionally, this means setting a relay and walking away while it does its business. Looking at the changing conditions in the industry and the overall grid, however, means that operating conditions when protection was installed may change by the month or the second. For example, a wind farm on a distribution network sends a signal to the feeder relays, indicating the output level exceeds total feeder load. Now directional settings might shift, fault isolation response might need to change, and fuse coordination overcurrent setting curves might need to be modified. Because this goes beyond a simple preprogrammed contingency, the relay needs an input it can use in an operating equation. IEC 61850 provides the digital and analog messages to enable that change in real time to optimize protection at any instant.
Studies have shown that the IEEE loss of life formulas for transformers based on temperature and loading accurately predict when a given transformer will experience insulation breakdown and failure. This can be detected by gas in oil analysis, but prediction allows scheduling other tests and can reduce costs of false positives and unnecessary tests. Using a relay as a fault anticipation device is beyond traditional application and changes how information is used. Traditionally, relays operate a circuit breaker when problems occur. Now we are using the relay to deliver information to a specific user who can act to avoid a problem. This requires communication outside the normal paths, even to the point of a routable signal to a nonrelay engineer.
Power Quality System
IEDs provide power quality data that is retrieved and archived automatically by the substation data concentrators. After processing, the data concentrator advises the control center operator of adverse conditions. Voltage violation reports automatically are generated and can notify the appropriate individuals by text and email or simply push to the enterprise level moments after each occurrence. Likewise, Common format for Transient Data Exchange for power systems (COMTRADE) and Common Format for Event Data Exchange (COMFEDE) files allow manufacturers to build applications that automatically extract fault and event data from IEDs for remote analysis. Double end fault location calculations are performed in the substation data concentrator. Automatically generated fault location information can be communicated via IEC 61850 messages. These messages can notify the distribution control center the distance to the fault from a specific GPS pole coordinate, as well as which line segment has been faulted.
Substation Intelligent Agent
The most disruptive technology for controlling distribution automation systems uses all previously mentioned technologies with an intelligent agent of the control center DMS into the substation to perform distribution network applications. With the development of the Component Distribution Network Applications (CDNA), it is possible to implement a segment of the DMS network model at the substation level that is specific to the substation and feeders in a specific topological region. This allows the substation to have a self-contained calculation engine. The advantage of this approach is to offload the control center DMS and its operators. In addition, there will be an improvement in the speed, reliability and quality of the decision-making for the distribution automation system if the network model computation and decisions are placed as close to the field devices as possible. The possibility of running a distribution state estimator, system power flow, optimal feeder reconfiguration, volt/VAR control, FLISR and other network software components within the substation is practical because of the modularization of these individual software components and network model management systems that easily segment the network model into smaller topologies.
The figure represents the three layers of distribution automation system hierarchy for a model-based, substation-centric distribution automation system.
The proliferation of challenges in the grid environment has created opportunities to innovate within grid infrastructure, especially substations. IEDs are becoming more powerful as more data is available, and communications within substations and out on distribution feeders is increasing based on Ethernet. The combination of these two areas of technologies has led to applications that achieve the proper monitoring, control and adaptive protection of the distribution network while integrating renewable generation more reliably. For the first time, power quality data retrieval, analysis and reporting can be done in the substation data concentrator as a standard function. Ethernet communications make it possible to automatically push the GPS coordinate and the location of a fault between two coordinates up to the control center DMS, outage and mobile work force management systems.
The most effective use of these technologies would take advantage of recent component distribution network applications development, which allows a utility to place an intelligent agent of the control center DMS in the substation. The intelligent agent runs distribution network applications on a segmented portion of the distribution model for the busses and feeder associated with that substation topology. Network applications such as state estimation, power flow, optimal feeder reconfiguration, FLISR and volt/VAR control are run and executed from within the substation, but under the supervision of the DMS control center. This has the advantage of off-loading the DMS operators and increasing distribution automation speed and reliability.
The growth of these technologies is changing how substations can communicate with utilities. Communication is interactive and two-way with the goal to provide actionable information.
Thierry Godart is president of Siemens Smart Grid, North America. He has more than 20 years of experience in the application of information technology to the power industry. He has managed high-tech and software activities in energy efficiency and demand response, transmission and distribution engineering applications, electricity markets and grid operations, and meters and metering systems.
Farel Becker is product manager for smart substations at Siemens Smart Grid. He has worked in power equipment, relay protection, control, power automation and SCADA for Siemens for 32 years. He serves on industry committees on protection, control and power automation for utilities and industry.More PowerGrid International Issue Articles
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