Coal, O&M

Is Your Investment in Protective Relays Paying Off? Programming Optimum Protection from Relays

Issue 11 and Volume 119.

By Steve Nollette

An experienced protection and integration engineer can help determine the best configurable relay settings to provide maximum system protection and advanced functionality. Photo courtesy: Emerson Network Power

Many electric utilities and power producers today have replaced, or are considering replacing, their aging electromechanical relays with new-generation, microprocessor-based relays. After all, should a fault occur, the new relays afford the best possible protection for electrical systems, equipment, and people. Or do they?

While it’s a well-known fact that new-generation, microprocessor-based relays deliver a host of advantages compared to electromechanical relays, including superior system protection along with cost and efficiency advantages, many of the relays’ capabilities and benefits often go unrealized. Why? Because utilities are not able to configure relay settings and logic to best meet their specific requirements. This is due to dwindling engineering resources and the merging of protection and microprocessor technologies, resulting in ever increasing relay complexity.

Sometimes the lack of configuration is an oversight. Utilities may simply be unaware of the importance and benefits associated with tailoring relay logic, especially since tailored relay configuration has only recently become an option. In other cases, the designers and installing technicians may be unfamiliar with the relays’ capabilities or how to program them properly. Even when utilities do tailor relay logic, if the programming isn’t completed properly, it can lead to a wide range of protection system problems including repeated and unnecessary system shutdowns.

Whatever the reason for failing to tailor logic and settings, the result is the same: the value of the protective relays is diminished. Worse, electrical systems and assets can suffer serious damage in the event of a fault.

Relay Tailoring: Four Good Places to Start

Clearly, the answer to getting the most return from an investment in microprocessor-based relays is to make the effort to properly tailor relay settings and logic. It’s true that most relays come pre-programmed with the manufacturer’s default logic settings, and these settings do provide basic system protection right out of the box. However, the default settings are highly unlikely to be ideal for your utility’s specific protection requirements. Plus, the pre-programmed settings tap into only a fraction of each relay’s potential functionality.

Each and every relay offers literally hundreds of configurable settings that can be tailored to provide maximum system protection and advanced functionality. Some of the built-in programmable logic capabilities include event recording, enhanced communication, arc flash reduction, system monitoring, and continuous self-monitoring. Each of these capabilities can be constructed from hundreds of available digital points within the relays.

So where does one start? With so many options to choose from, it can be a bit overwhelming. But an experienced protection and integration engineer can help. A well-trained, knowledgeable partner is instrumental in understanding your unique project requirements and identifying the specific relay features, capabilities, and configuration for optimum system protection.

The configuration needs of each utility will be unique. However, there are a number of relay features and capabilities that almost always improve protection schemes and add value to the relay system. These features include arc flash mitigation capabilities, lockout settings, event recording capabilities, and generator protection features. All four will very likely be incorporated into your tailored relay plan.

1. Arc Flash Mitigation Capabilities for Advanced System Protection

Arc flash incidents are responsible for one fatality every workday, and the danger of exposure is on the rise due in part to greater overall energy usage, as well as higher system voltages and available fault currents. As a result, organizations like the Occupational Safety and Health Administration (OSHA) and the National Fire Protection Association (NFPA) are becoming increasingly stringent in their requirements for safe working conditions. For the first time, OSHA is mandating and enforcing specific arc flash-related requirements (beyond general hazard awareness) for higher voltage facilities.

One way utilities can enhance arc flash protection, and reduce the potential for worker injury and equipment damage, is by taking advantage of the optional arc flash detection feature built in to many microprocessor-based relays. This feature allows the relays to immediately respond to arc flash incidents by detecting a combination of excess light and current. In locations where the potential for arc flash hazards exists, the integration engineer can program the logic in the protective relays to immediately interrupt the circuit if developing arc flash conditions are detected.

For even greater protection, the engineer can also enable the self-testing capabilities of modern relays to include other components within the protection system, such as breakers, trip coils, and current transformers. This helps ensure that the entire arc flash hazard mitigation system is healthy-giving workers assurance that the system is functional.

2. Lockout Settings for Increased Safety and Security

Protection systems that use electromechanical relays often rely on 86 lockout relays to prevent tripped breakers and transformers from being automatically or remotely re-closed. This is important because re-closing a breaker without first determining the cause of the trip could result in overlooking a major system problem. For example, the lockout relay can keep an operator from unintentionally re-closing into a grounded circuit, which could result in extensive damage and downtime, system failure, and arc flash.

With microprocessor-based relays, the 86 lockout relay function can be moved into the relay logic. The lockout can be configured to require an operator to manually interact with the relay and acknowledge the cause of the fault prior to resetting the lockout and re-closing the breaker. This gives operators the best chance to determine the cause of the trip and take the appropriate corrective action, and it also provides an added level of protection from potential operator error.

The single-line diagram is the first step in preparing a critical response plan, allowing you to become thoroughly familiar with the electrical distribution system layout and design in your facility. Photo courtesy: Emerson Network Power

3. Event Recording Capabilities for Expedited Troubleshooting

Knowing exactly what happened and what the conditions were prior to a fault can go a long way toward helping to identify the root cause of that fault. Microprocessor-based relays can essentially serve as eyes and ears, providing plant personnel with invaluable information on demand.

Each microprocessor-based relay comes with a built-in event recorder capable of capturing and time-stamping event information at one millisecond resolution. The integration engineer can help determine which elements should be recorded in the event of a fault, and then program the event recorder to collect pertinent information such as trip sequence, the amount of time a breaker was open, where the fault occurred, the nature of the fault, pre-fault conditions, and power quality monitoring waveforms.

Best practices call for the engineer to structure the high-speed data capture for trips, abnormal voltage, or currents to aid in event analysis during future trip investigations. Consideration is also given to capturing operator actions within the event recorder. Often times in the heat of the moment, recalling accurately the sequence of events, such as acknowledging a trip, opening, closing, or synchronizing a breaker can be difficult. Having a time-stamped record of these activities is invaluable for reconstructing the events that took place before, during, and after the fault occurred.

If a fault occurs, an operator can use the relay to produce a detailed report showing the sequence of operations prior to, during, and after the event. This information will help system operators clear faults more quickly and safely, ultimately minimizing costs and downtime for the utility.

4. Generator Protection Features for Safeguarding Critical Assets

In many utilities, generators are among the most expensive assets in the facility, making them critically important to protect. Microprocessor-based relays offer maximum protection for generators while helping to prevent nuisance tripping.

One correctly programmed microprocessor-based relay can actually provide better protection for a generator than multiple electromechanical devices. In many upgrades, just one or two microprocessor-based relays can replace 20 or more electromechanical relays.

What’s more, new generation microprocessor-based relays are significantly more sensitive than their older counterparts. They more accurately discriminate between faults within the zone of protection and faults outside the zone of protection, increasing stability of the grid.

Does this necessarily mean that enabling all of the available settings within a relay corresponds to better protection? Imagine sitting with an auditor, checking a generator protection system for compliance with North American Electric Reliability Corporation (NERC) PRC-024, the standard governing voltage and frequency trip set points. The auditor points out that three of six abnormal frequency trips are not compliant. In all actuality, only three of the six elements are used to trip the generator off line, but because all six elements are enabled and have values assigned, it looks to the auditor like they are being utilized for protection. This situation can be avoided by ensuring that the settings are no more and no less than what is needed for the specific application.

Going Beyond Individual Relay Settings

Based on a utility’s specific requirements, an integration engineer will likely program the four settings described above along with many of the other available relay settings that can improve and support a facility’s unique electrical system protection scheme. In addition, an engineering partner can work with a plant’s protection and control system designer to take advantage of a number of the other inherent benefits of microprocessor-based relays. These include the relays’ multifunctional capabilities, ability to self-test and monitor, and capacity to capture large amounts of data.

Using Relays to the Max

Today’s new-generation, microprocessor-based relays can do a lot more than protect an electrical system. They can perform a wide range of functions including automation, metering, and remote control. When a system designer leverages these capabilities, multiple electrical system components can be eliminated from the switchboard, including auxiliary relays, wiring, timers, switches, trip coil monitors, and 86 lockout devices.

This switchboard simplification saves time and money. It also minimizes the potential for additional points of failure or weaknesses in the system. By moving functions to the relays, there are fewer system components to fail, and the reliability of the system automatically increases as a result.

Leveraging Embedded Self-Test Features

One of the greatest advantages of microprocessor-based relays is their inclusion of self-test features that continuously monitor the relay along with all of the embedded inputs, outputs, and logic inside the relay. When relays are programmed to integrate automation, remote control capabilities, and other system components as described above, the relays’ self-test features can be used to protect the entire electrical system. This can do wonders for improving system reliability and availability. But it has positive implications for maintenance and regulatory compliance as well.

As a result of simplifying a system and reducing the number of redundant components, maintenance needs decrease. Plus, relays can accomplish much of the routine and time-consuming maintenance work for themselves, including handling many of the maintenance testing procedures mandated by NERC.

Skilled protection and integration engineers can specifically program the relays to automatically perform NERC-required and manufacturer-specified maintenance activities such as continuous monitoring of the internal health of DC circuits and trip coil circuits, validation of instrument transformer status, and even monitoring of breaker wear. The relays automatically and continuously perform these inspections and testing procedures while the system is operating, reducing the need for scheduled downtime and the burden on maintenance staff.

For those who want to further simplify NERC compliance and reporting, system designers can even configure the relays to work with a communication processor and reporting software. Such a set up allows test results to be automatically communicated and reports to be generated for distribution to regulatory agencies.

Gaining Maximum Value from the Data

Microprocessor-based relays collect a great deal of data about a utility’s electrical system. One way to gain access to this data is to have an integration engineer program a communication processor to work in conjunction with the relays to integrate and concentrate information into usable insights.

Here’s how it works: The processor uses communication and control interface relays to poll protective relays and other microprocessor-based devices in order to collect information in real time. The communication processor can interpret the data and make it accessible to operators in a usable format. Having a wealth of valuable data at hand can dramatically improve control, decision making, and troubleshooting.

Because communication processors typically come as an empty box, the skills and expertise of an integration engineer are critical for taking advantage of the benefits of such a tool. The engineer will build tailored user logic and logic solutions for the processor; do programming to collect data from the connected relays; and assist in distribution of data to operators.

The Importance of the Integration Engineer

A skilled and qualified protection or integration engineer is key to leveraging the full range of microprocessor-based relay capabilities and optimizing system protection. A facility should work with an engineer who is well-versed in new-generation, microprocessor-based relays, as well as one who can further inform and educate a utility about the advantages the technology affords.

An engineering partner will take time to fully understand and define a system’s requirements, such as how the protection system should respond in the event of a fault, how protective relays should communicate with other systems, and what functions (in addition to protection) the relays should perform. The integration engineer should consider the needs of the utility and its operators, along with the requirements and specifications of regulatory agencies and equipment manufacturers. He should also be familiar with a utility’s system requirements, as well as its automation, redundancy, and maintenance needs.

Only by fully understanding these considerations can an integration engineer deliver a solution that offers the highest quality protection for an electrical system and maximizes the value of relay investments.

Author

Steve Nollette is supervising engineer at Electrical Reliability Services, Emerson Network Power.