The Protective Relay Evolves

By Steven A. Kunsman, ABB Inc.

The need for real-time process data has grown in the past decade. As the appetite for data intensified, the data’s importance has increased dramatically. A changing utility environment has contributed to data importance, along with many technological advances in data collection, data storage and communication infrastructure. Advances have allowed data to be converted into valuable information used to optimize enterprise resources.

Substation data sources are abundant. The ability to convert this data into meaningful information, however, has been complicated by the large installed base of devices utilizing different technologies and communication protocols (vendor proprietary, DNP 3.0, IEC 60870-5-103 and Modbus). Data storage and retrieval, communications networks’ bandwidth restrictions and data access/availability also complicate information utilization. To overcome these issues, today’s substation can leverage multi-vendor interoperability, local storage of mass data and secure remote access to the substation data.

Protection and Control Evolution

The protective relay system provides necessary power system monitoring and protection for abnormal condition detection and mitigation. Such conditions could lead to a fault and result in damage to utility-critical assets such as generators, transformers, breakers, power lines, cables and substation buses.

Years ago, to perform these necessary protection and control functions, relay systems required one or more panels of multiple discrete devices such as electromechanical protective relays, meters, test switches, control switches, indicator lights, etc. Figure 1 illustrates typical electromechanical line protection relay panels. 

Electromechanical Relay Panel


Back then, it was an art to achieve the basic protection principles using electromechanical relays. Based on magnetic fields and an aluminum induction disc—similar to the older residential utility meter spinning to measure the power consumption—the protection application used torque generated in the induction disc and physics related to spring constants opposing the magnetic torque. The relationship between electromagnetic principles and the opposing mechanical spring torque created the necessary protection. Many of these mechanical equations are the foundation for basic protection algorithms emulated and solved by software computation.

To complete the control functions, interconnections required physical copper wires within and between relay panels in the substation control house and into the switchyard apparatus for breaker control and voltage and current transformer measurements. SCADA interfaces were limited by low bandwidth serial connections and the remote terminal unit (RTU) interconnections to breakers and current transformers/voltage transformers (CT/VTs) via digital inputs and analog transducers.

In the 1970s, some relay systems were replaced with solid state protection devices, resulting in smaller footprints and panel-space savings. This technology replaced only the discrete electromechanical devices, however. In the 1980s, the first microprocessor-based protective relays were introduced. Microprocessor protection devices included protective functions, some level of simple programmable logic and varying communications methods. The microprocessor devices were enhanced with programmable logic controllers (PLCs), making advanced protection and control schemes possible. The microprocessor device enabled functional consolidation of discrete protection applications, further reducing panel space. Additionally, integrated communications capabilities enabled RTUs or gateways to communicate directly with the microprocessor device, eliminating the previously required parallel interconnections to breakers and CT/VTs. The SCADA serial interface bandwidth limitations still existed, however.

Technology advances and the introduction of high-speed Ethernet communication architectures make the microprocessor protection and control intelligent electronic device (IED) the cornerstone of the modern substation automation system. To meet real-time actionable information demand outside the substation, gateways and RTUs integrate Ethernet communications, typically wide-area networks, for SCADA and asset management.

Intelligent Electronic Device Capabilities

IED capability is crucial to protection, control, monitoring and automation application advancements. A robust IED platform with high performance microprocessor and Ethernet-based communication technology is essential to any configurable system. Figure 2 shows a modular approach for the IED architecture.

Flexibility and scalability also are essential to meet present and future protection and control requirements. Advancements in processing capabilities enable a single IED to perform multiple protection functions, supporting protection and control of multiple apparatus (breakers, transformers, etc.). The addition of PLC functionality allows applications and control logic to be customized. Multi-function capabilities combined with advanced logic increase functional consolidation and reduce relay panel footprint even more.

The addition of this advanced logic and the emergence of IED configuration tools based on the IEC 61131-3 standard, give protection engineers new design application configuration flexibility. It also allows them to visualize internal connections between protection and control function blocks, control logic and IEDs’ physical inputs and outputs. A relay engineer can customize the IED to meet specific application requirements, and monitor power system health and primary apparatus status.

With electromechanical and other discrete relays, designing, documenting and testing the external control system was cumbersome and required continuous system maintenance to ensure the system was functioning as designed. Now, the IED configuration tool documents the protection and control application configuration. Testing and commissioning, as well as troubleshooting applications are considerably simplified through the debug/diagnostics capability of the IED’s 61131-3 tool suite.

Introduction to IEC 61850

The IEC 61850 standard provides a framework for substation protection, control and monitoring. More than just a communication and data exchange protocol, the standard defines open communication profiles and services, substation communication equipment requirements, functional characteristics, structure of device data, naming conventions, application interaction and control of devices and device conformity testing requirements.

The extensible markup language or XML-based substation configuration description language (SCL) is one of the main differences between IEC 61850 and the traditional substation protocol. SCL describes the configuration of IEDs in terms of functional capability (protection applications, circuit breaker control, measurements and primary equipment status) and communication addresses and services (event and disturbance reporting). It also describes the substation layout and its relationship to the IED functions.

Along with the standard’s logical node definitions, this SCL common language allows IEC 61850 devices to self-describe their functionality and understand peer device configurations and necessary interactions. The substation automation engineering process benefits from the common language with improved efficiency, quality and consistency. Furthermore, maintenance and extension work becomes more efficient and commissioning and testing efforts can be reduced.

The IEC 61850 system architecture enables peer-to-peer communications between devices, reducing the need for hard-wired interconnections and replacing them with “soft” wires. Generic object-oriented substation event (GOOSE) messaging is a special multicast version of peer-to-peer communications unique to IEC 61850. Multicast messages are repeatedly broadcast to ensure timely information is successfully transmitted between IEDs. GOOSE messaging can be used for fast transmission of time-critical information such as status changes, blockings, releases or trips between peer IEDs. The information exchanged between the RTU, gateway, station HMI and the IEDs is achieved via the basic communication services in a client-server relationship.

The standard introduced extending communications architecture to interface the IED with the primary apparatus for sampled measured values and exchange of control/status information. Sampled measured values are digital conversions of current and voltage measurements from either non-conventional instrument transformers (NCIT) or stand-alone merging units (SAMU). The interface between the conventional CTs and potential transformers (PTs), along with communication of the associated sampled values’ measurements to the protection and control IEDs, is defined as process bus communications. The process bus requirements are contained in IEC 61850-9-2 of the standard. Figure 3 illustrates the evolution of protection and control systems where IEC 61850 utilizing station and process bus allow for significant reduction of copper hardwires.

The introduction of the IEC 61850 communication networks and systems in substations standard is an enabler for continued functional consolidation. The main benefits of IEC 61850 architecture include design and operational cost savings, improved reliability and enhanced efficiency. IEC 61850 has a proven track record of delivering benefits to both small and large utilities. Communication infrastructure requires an investment to install, configure and maintain. The savings that an IEC 61850 architecture can deliver in substation design, installation, commissioning and operational efficiencies, however, are significant.

Steven A. Kunsman is ABB Inc.’s vice president and general manager for substation automation products in North America. He has 27 years experience in substation automation, protection and control.

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