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There is an old saying in the industry… “There are bold protection engineers and there are old ones too but there are no old bold ones.” Often emphasis is placed first on economics but in truth safety is always of the utmost importance since we are working in an energized high voltage power system which is a hazardous environment. Being safe is a state of mind and closely following a good set of well-established practices; it is necessary to maintain this state of mind as a constant goal. You must fully understand these practices and be extremely well versed in them.

Introduction This paper provides detailed technical analysis of several catastrophic relay misoperations and demonstrates how to prevent them from occurring. It also provides an example of using data recorded by a relay during onerous conditions to implement a new protection scheme.

This paper is based upon a NERC report released in 2013 that claimed a dramatic rise in the annual number of misoperations—due in large part to the complexity of programming and testing numerical protection relays. This paper illustrates results discussed in the NERC report, as well as provides several interesting examples of actual misoperations and how to mitigate them.

This paper explains how to supervise the transfer of an important load bus from one source to another in less than one half-cycle. This supervision is required for large scale industrial processes such as petroleum refineries.

A numerical generator protection relay provides multiple functions and typically uses algorithms that do not work on the same principles as older electromechanical relays. Often relay test personnel still want to use old test methods developed long ago for electromechanical relays. Test results obtained from these old test methods may not be a good indication of whether or not the numerical relay protection functions properly. One such obsolete technique still often used is referred to as a static test. Fault voltage and/or fault current are injected to see if the selected protection function operates at the setpoint and is in tolerance. Many protection functions have dynamic characteristics and/or hidden features that cannot be properly tested using a static test. This paper demonstrates various techniques how to test numerical protection relays such as dynamic tests.

High magnitude current flows through the conductor and connected equipment to the point of the disturbance when a fault (for example, lightning strike) occurs on an overhead high-voltage transmission line. The heavy current can quickly damage the line conductor and connected equipment (for example, transformer bank).

This paper provides in-depth examples of condition-based monitoring using numerical relays. Condition-based monitoring―which combines both corrective and preventive approaches to maintenance―is more economical and timely, ensuring that the right maintenance work is done at the right time by identifying the root cause(s) of the problems. This proactive managed maintenance approach, a form of asset management, improves utility profitability. This paper details the use of modern numerical protection relays as asset management tools to perform the following tasks: • automatic fault location for transmission and distribution lines • through-fault analysis for transformers • circuit breaker-wear monitoring • voltage transformer failure monitoring

This paper demonstrates how to commission specific protection functions using COMTRADE—an IEEE standard for common format for transient data exchange. The following are required to generate a specific test: • detailed test plan • COMTRADE records 1Each detailed test plan should provide a complete explanation of the test as well as step-by-step instructions on performing the test. Each detailed test plan should also provide an explanation as to why the test is useful to perform, such as preventing a common type of misoperation from re-occurring. Some functional tests may only require a COMTRADE record to inject test signals into the relay. Tests that can be performed using a generic COMTRADE record greatly simplify the test plan and can provide test results based upon actual system conditions.

Numerical transformer differential relays require careful consideration regarding how to test them properly. These relays provide different types of protection such as restrained phase differential, high set phase differential, restrained ground differential and overcurrent protection. All protection elements that are enabled should be adequately tested. A common commissioning practice is to test all the numerical relay settings to verify they were properly entered. Automated testing using computer software to run the test set has made this possible since the overall commissioning for a numerical relay could consist of several hundred tests. While this is a good check, it is still important to ensure that the transformer is thoroughly protected for the particular application.

Conventional methods of protection are not certain due to the intermittent nature of an arcing fault since any single arc may not last long enough to operate time-delayed neutral protection. Arcing faults can occur due to dirty insulators or broken strands in the stator windings. Such faults, if undetected, can lead to overheating along with catastrophic electrical failure. These events typically require extensive repairs with an extended shutdown of the machine. It is highly desirable to detect such faults at an early or incipient stage so that remedial action can be taken before a complete failure occurs. This paper presents a new protection method to detect arcing faults along the entire winding and trip the unit before extensive damage can occur. This paper shows the protection engineer how to properly identify the faulted phase. Faulted phase identification is important since it will greatly aid in locating the source of an intermittent arcing fault.

The first section of the paper analyzes a transformer differential misoperation that dropped a paralleled pair of large distribution transformers serving a sizeable block of contiguous load on the eastern seaboard. This section presents the unfiltered currents measured by the numerical transformer protection relay during the unwanted operation. The misoperation occurred when the faulted distribution feeder CT saturated due to the high magnitude fault current. A recommendation is made how to prevent these types of misoperations. The second section of the paper analyzes two outages that occurred at another distribution substation in less than one month due to the misoperation of the fast bus trip scheme and a defect in the numerical overcurrent relay protecting one of the 23 kV feeders. The paper outlines the modification of the fast bus trip scheme logic to prevent this type of outage from re-occurring.

Application of sound relaying principles helps prevent unwanted tripping during black starts. An unwanted trip during a black start is extremely detrimental since the utility is attempting to reconnect its high voltage grid and restore service throughout its operating region. A black start is the process of restoring a power station to operation without relying on external power sources. Normally, the electric power used within the plant is provided from the station generators. The highvoltage grid provides station service power through the transmission lines if all the main generators are shut down. This off-site power source is not available during a wide-area outage. Therefore, a black start is required in the absence of grid power. Generating plants using steam turbines require station service power up to ten percent of their total load capacity (to bring on-line: boiler-feed water pumps, boiler-forced draft combustion air blowers, and fuel preparation equipment, for example). It is uneconomical to provide such a large standby capacity at each station, so black start power is only provided over the electrical transmission network from specific stations. Often hydroelectric power plants are designated as the black start sources to restore network interconnections since these stations need very little initial power to start and can put a large block of power online very quickly to allow start-up of fossil fuel and nuclear stations. Careful detailed analysis is required to properly apply generator protection at stations with black start capability. Generator relay current inputs are subjected to high levels of dc offset and harmonic current due to energizing transformers during a black start. Proper selection of current transformers for the generator differential protection is necessary to avoid a mismatch. Both the system side and neutral side sets of current transformers should have the same saturation voltage characteristics because if there is a large DC offset present the current transformers can saturate with restraint current significantly less than two times the nominal relay current. The case of a generator differential protection misoperation during a black start at a large hydro station is examined in detail to illustrate what steps to take to prevent these types of nuisance trips without sacrificing relay sensitivity. An unwanted trip occurred because of the particular differential protection operating characteristic. One solution presented monitors the harmonic content of the relay current to momentarily desensitize the differential protection while the transformer draws heavy inrush current. Use of a second generator differential element in tandem with the first to minimize the chance of an unwanted trip from occurring during a black start is also discussed.

The basic concept of redundancy is simple. Instead of relying on a single piece of equipment, there are duplicate or triplicate sets that perform the same function. Consequently, if one piece of equipment fails, the function will still be performed by a redundant device. Redundancy of components plays a major role in elevating the reliability of protection systems. The impact on the power system when a protection device is not functioning when required is much less severe when there is a redundant device that takes over the job. If the redundant devices are of equal performance, there should be no detrimental effect at all on power system operations, and a non-functioning device would just need to be repaired or replaced. While local redundancy is generally applied, it is not the only mitigation that can be used to improve reliability. Remote protection systems may provide adequate protection system reliability in some situations, provided that remote protection can detect faults and provide clearing times that meet performance requirements. Different users have different terminology for referring to the redundant protection systems. They may be called “System 1” and “System 2” or “System A” and “System B” or sometimes “Primary” and “Backup.” This latter terminology, “Primary” and “Backup”, implies, although unintentionally, that one of the two systems serves the main function of protection and the other serves to assist in the case of failure of the first system, analogous to carrying an undersized spare tire in the trunk of a car in case of a flat. In actual practice, the redundant systems are each fully capable, each system is able to detect and clear faults on its own, and each system serves as a backup to the other. Note that this paper is a summary of the full report. The report will be available on www.pes-psrc.org – Published Reports – in May-June of 2010.

This paper covers the application of sound relaying principles to help prevent unwanted tripping during black starts. An unwanted trip can be extremely detrimental to a utility attempting to reconnect its high-voltage grid and restore service throughout its operating region. This paper describes the analysis required to properly apply generator protection at stations with black start capability. A real-life case of a generator differential protection misoperation during a black start at a large hydro station is examined in detail to illustrate what steps to take to prevent these types of nuisance trips without sacrificing relay sensitivity. This paper also shows how to use a second generator differential element in tandem with the first to minimize the chance of an unwanted trip from occurring during a black start.

This paper covers practical considerations for proper application of this protection for a variety of different applications. The total capacitance to ground of the generator stator windings, bus work and delta-connected transformer windings of the unit transformer is a very important factor and must be known to ensure the protection settings are correctly determined. It will be shown that unless special steps are taken in the design of this protection, there are cases when it is hard to distinguish between normal operating conditions and an actual ground fault. The protection must also reject fundamental frequency (50 or 60 Hz) voltage and current signals that are present during ground faults on the stator windings. A real-life example for a back-to-back start at a pump storage facility, captured via relay oscillography, is included.