There's an old familiar saying that things aren't always what they seem. Employees at Memphis Light, Gas and Water's (MLGW) Substation Engineering and Electric Operations departments recently found that out while trying to resolve what was thought to be a relay coordination problem.

MLGW, Memphis, Tennessee, U.S., is the nation's largest three-service public utility. MLGW buys electric power from the Tennessee Valley Authority (TVA) and distributes it to more than 350,000 residential, commercial and industrial customers in Shelby County. Within MLGW, Substation Engineering is responsible for the design, engineering and maintenance of approximately 50 electric substations. Electric Operations is responsible for the actual physical work.

In maintaining these facilities, Substation Engineering is also responsible for coordinating protective relays in each substation (Fig. 1). Once the relay settings have been determined, Electric Operations tests the relay and places settings on it (Fig 2). Protective relays detect intolerable or unwanted conditions within an assigned area. These relays generally trip or "open" one or more circuit breakers to isolate the problem area before it can damage or otherwise interfere with the effective operation of the rest of the power system. The difference in operating times between upstream and downstream relays for coordination purposes is called the CTI (coordinating time interval). The goal is to allow enough time for the relay and breaker closest to the fault to clear the fault from the system before the next upstream relay and breaker trip. For example, the feeder relay and breaker should clear a feeder fault before the supply-side relay and breaker trip. The supply-side relay is upstream from the feeder relay. MLGW uses a CTI of 0.35 seconds between feeders and supply points. Most CTIs between feeders and secondaries range from 0.2 to 0.5 seconds with the national average around 0.3 seconds. This CTI takes the following into account: -Breaker fault-interruption time. -Over travel of the induction disk or solid-state relay after the fault current has been interrupted. -A safety margin to compensate for possible deviations in calculated fault currents, relay tap selection, relay operating time, and current-transformer ratio errors.

Of course, this relay coordinating time assumes that all the equipment is functioning properly. Again, a familiar saying comes to mind about what happens when one "assumes" something.

When substation feeder relays and supply-side relays both trip for the same fault, the burden of proof that the relays are coordinating falls on the shoulders of the Substation Engineering and Electric Operations personnel. Over the past few years, there have been several recurring problems where the feeder relay and supply-side relay trip for the same feeder fault. For a feeder fault, this would be considered an overtrip and is usually blamed on poor relay coordination. Typically at MLGW, a supply-side relay and breaker provide power flow to four or five distribution feeders. Therefore, when a feeder fault causes the supply-side relay to trip, not only are the customers on the faulted feeder inconvenienced with an outage, but all the customers that are being served by the other feeder from the same supply-side relay and breaker also experience an outage. The dilemma was that, according to all calculations and good engineering principles, the relays were coordinated properly. And when the Electric Operations personnel went out to test the equipment, they found no problems.

In what was thought to be an unrelated issue, we had several substation fires occur in the wiring of the SCADA (supervisory control and data acquisition) remote interposing relay modules and in the control switch wiring. Although the damage had been minor and limited to the immediate wiring around the burned trip contacts, the potential for major damage was certainly present. In all of the known cases, there had been someone at the station to put the fire out when it occurred. The fires were starting when a breaker failed to trip via SCADA or the control switch in the control house. When the trip contacts were released, they were unable to interrupt the trip circuit current and an arc was produced across them. This arc is very intense and tends to set the wire insulation around it on fire. The arc would generally last until the momentary duty trip coil burned open. All the known cases involved the same type of breaker. The problem was that the breaker was "hanging up."

The relays at these electric substations had not been involved directly with this problem because they were the type of relays that "seal in" when a trip is issued and do not normally break trip circuit current. However, the Substation Engineering and Electric Operations personnel believe that these same type breaker "hang ups" have occurred during feeder faults resulting in what was previously thought to be a relay coordination problem between the feeder and supply-side relays. When the feeder breaker "hangs up," then the supply-side relay and breaker should trip in order to clear the fault. One of three things usually happens when the feeder breaker gets "hung up": 1. The feeder breaker trip coil burns open and the supply-side breaker trips.

2. The supply-side breaker trips before the feeder breaker breaks free and before the feeder breaker's coil burns up. 3. The feeder breaker breaks free and trips, but not before the supply-side breaker trips. 4. The first problem might easily be determined to be a breaker problem. The second one can be determined to be a breaker problem if the feeder breaker is still "hung up" when the field crew arrives to investigate. The third problem might easily be mistaken as a relay coordination problem. Usually, the breaker "hangs up" only momentarily. When the field crews arrive to investigate, the feeder breaker trips with no problem, making this intermittent problem difficult to find.

The definite cause of the breaker "hang up" has not been determined, but the crew found that the recommended mechanism lubricant was not being used on this particular type of breaker. The area responsible for breaker maintenance has now returned to using the manufacturer's recommended lubricant rather than the standard lubricant used on other types of breakers. Since using this recommended lubricant, we have significantly reduced the number of known breaker "hang ups."

So, beware. If you are having an "apparent" relay coordination problem, look to see if there have been any recent changes in the operation of the system. Don't assume anything. Good relaying and engineering principles do work. Things aren't always what they seem.

Michael Ray Russell is a substation protection engineer with Memphis Light, Gas and Water, Memphis, Tennessee, which he joined in 1988. He has the BSEE degree from the University of Memphis and the MBA in finance from Christian Brothers University. His responsibilities include design of substation protection schemes and setting/coordinating relays.

Russ Poteet is a foreman of Electronic Maintenance with Memphis Light, Gas and Water, Memphis, Tennessee, which he joined in 1979. He has the associate of engineering degree in electronics and computers from State Technical Institute at Memphis. His responsibilities include testing, trouble shooting and maintenance of protective relay equipment for electric substation facilities.