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Power Quality Monitoring Enhances Preventive Maintenance Program: Detecting a Substation Transformer Tap Changer Problem William H. Jones Member IEEE Advanced Micro Devices 5204 E. Ben White Blvd. Austin, TX 78741 USA Abstract-This article discusses a power quality monitoring program underway between a semiconductor manufacturing facility and its serving utility. A description of the sophisticated monitoring program installed and maintained by the utility and a portion of the power quality monitoring installed within the manufacturing site distribution system is included. An incident, where monitoring pinpointed a utility substation transformer Load tap changer problem, is presented in depth. The subsequent investigation and actions that took place to repair the tap changer without impacting the manufacturing facility are discussed. A fault in the tap changer compartment could have resulted if the tap changer problem had gone undetected. Steps taken to correct the tap changer problem averted a possible fault and subsequent transformer differential relay action. Index Terms-Industrial power supply, power quality, power quality monitoring, power system reliability. I. INTRODUCTION Semiconductor wafer fabrication (fab) facilities require both undisturbed and uninterrupted power. In general, fabs are one of the most challenging loads for utilities to serve and, at the same time, one of the most desirable. The high load factor for fab facilities enables a utility to achieve a high utilization factor on the generation, transmission, and distribution equipment invested to serve such facilities. Semiconductor manufacturers and their serving utilities often install sophisticated power quality monitoring devices to quickly pinpoint, analyze, and resolve power system disturbance related problems. Utility voltage sags have shown to cause equipment malfunctions within fab facilities. Correlating power system disturbance data with fab tool malfunctions and process equipment problems is commonly practiced to determine appropriate mitigation measures. Utilities use power quality monitoring data to determine root causes of disturbances, facilitating transmission and distribution system improvements. This paper describes an incident where monitoring pinpointed a utility substation transformer load tap changer problem. Voltage and current waveforms showing the problem increasing with each tap changer operation are included. The utility transformer serves fabs and is not equipped with dedicated primary-side protective devices. Merlin C. Chip Stansbury Member EEE Austin Electric Utility 721 Barton Springs Road Austin, TX 78704 USA Steps taken to quickly identify the tap changer problem and remove the transformer from service averted a possible fault and subsequent transformer differential relay action. A phase-to-ground or phase-to-phase fault in the tap changer compartment could have resulted if the tap changer problem had gone undetected. A transformer differential relay action would have cleared the entire substation and interrupted power to a portion of the manufacturing site. 11. POWER DELIVERY SYSTEM The utility serves the manufacturers site through two substations. One substation is equipped with fully redundant 24/32/40 MVA rated unit transformers. Transformer primary-side connections to two 138 kV utility transmission lines are through circuit breakers into a ring bus. Transformer secondary side switchgear includes a tie circuit breaker. A 138 kV transmission system is networked throughout the utility service territory. The 138 kV transmission system has ties to the 345 kV Electric Reliability Council of Texas (ERCOT) grid through three 345 kV/138 kV, 400 MVA autotransformers. To 1247 kY Svltchgrer Fig 1. I38 kV transmission network connections to substation An older utility substation with redundant transformers that are not equipped with dedicated primary-side protective devices serves a portion of the manufacturers site. The 138 kV transmission network, and the 12.47 kV distribution system for this substation are illustrated in Fig. 1 and Fig. 2, 1 82 0-7803-4509-6/98/$10.00 1998 IEEE respectively. Transformer 45 in Fig. 1 experienced the tap changer problem discussed in this paper. The one-line diagram in Fig. 1 shows that the 138 kV bus does not have breakers on the primary-side of each transformer (or in the primary-side bus section between the transformers). Certain protective devices designed to protect the substation unit transformers have the potential ability to clear the entire substation. The substation in Fig. 1 serves some older fabs at the manufacturing site, as well as an adjacent semiconductor research and development facility. This facility is also a fab facility. No other utility customer loads are served from the substation. Redundant unit transformers are rated 18/24/30 MVA. Dedicated 12.47 kV underground distribution feeders to both facilities are shown in Fig. 2. This feature provides a fully redundant power delivery system in the event that a transformer needs to be taken out of service. The substation is not equipped with a secondary-side switchgear tie breaker. The critical nature of the fab loads connected to this substation demands a preventive maintenance program, which quickly and accurately addresses any suspected transformer problem. Both the utility and the manufacturing site power quality monitors are shown in Fig. 2 and discussed to illustrate the importance placed on power quality monitoring at this site. Fig. 2. Substation secondary-side 12.47 kV one-line diagram 111. UTILITY MONITORING PROGRAM The utilitys power quality program is designed to facilitate information sharing with its customers. Typical shared information includes: 0 0 - digital fault recorder reports, transmission fault reports, breaker operation reports, power quality monitoring system (PQMS) reports, supervisory control and data acquisitiodsequence of events (SCADNSOE) reports, one line diagrams of transmission and distribution facilities, protective relay settings and coordination, and transmission and distribution system modeling. The PQMS uses monitoring devices to capture steady state and transient power quality data at substations serving utility customers. Seventeen monitors are presently installed and operating at utility substation sites. Password protected reports generated by the PQMS are available to customers via the Internet. The monitors are checked and downloaded hourly via modem. Fig 3 Monitonng device (a) mounted on 12 47 kV switchgear auxiliary compaflment, (b) showing power measurement module, input module, and battery The PQMS facilitates: correlation of system operations data with customer operations data, diagnosis of power quality problems to determine causes and to implement effective, safe, and economic solutions, operations and maintenance improvements in areas such as grounding, lightning protection, surge 2 83 protection, tree trimming, relaying, and capacitor bank switching, characterization and benchmarking of the quality of power supplied by the utility to its customers, e trending of the quality of power supplied to utility customers, * timely dissemination of information, 0 automation of report generation, and * training. Fig. 3 (a) and (b) are photos of a typical monitor installation mounted on a 12.47 kV switchgear compartment. The semiconductor manufacturing site has similar power quality monitors installed in site switchgear served by distribution feeders as shown in Fig. 2. These monitors were installed a few years prior to the utiIitys monitors located at the substation. The site monitors are checked and downloaded daily via modem. The utility also accesses the site monitors via modem to assist in diagnosing power disturbances. IV. MONITORING DETECTS SUBSTATION TRANSFORMER TAP CHANGER PROBLEM A fab site routine power monitoring check on the morning of August 14, 1997 showed a voltage distortion occurred on distribution feeder No. 5 during the evening of August 13h. Fig. 4 shows the voltage distortion in phase B, which appeared as a one cycle sag with some ringing on the first quarter cycle. 2 4 I 8 10 12 0811311QQ7 20 3457 (iocal) Time . Cycles Fig 4 Phase B voltage distortion dunng August 13, 1997 incident Initially, it was suspected that the anomaly could possibly be caused by: 1. 2. Utility capacitor switching on the 138 kV network, or A problem within Transformer 45, such as a tap changer malfunction. A puzzling factor was that the switching only appeared on one distribution feeder from the substation. No reports of any problems resulted within the fabs or other site loads served by the affected feeder. A routine monitoring check on the morning of August 18 showed a similar voltage distortion occurred on the evening of August 17h, where the ringing lasted for almost three quarters of a cycle. The phase B voltage distortion for the August 17 incident is shown in Fig. 5. 1 4 0 8 10 12 WlII!W7 1005.52 (kJ) Time. Cycles Fig. 5. Phase B voltage distortion during August 17, 1997 incident. Again, the August 17* disturbance was apparent on only one distribution feeder, and no reports were received indicating any fab equipment had been adversely affected. However, the magnitude of the voltage problem appeared to be increasing, and the utility was asked to check the condition of their transformer to determine whether a problem was surfacing. In response to the concerns, the utility performed an infrared scan of the transformer equipment and found a 25 F differential between the tap changer compartment and the tank of the transformer. A 20 F differential is considered questionable. Also, sampling and analysis of dissolved gases (methane, ethane, ethylene, and acetylene) in the load tap changer compartment oil showed gas levels were abnormal. Infrared scans are usually performed on transformers three to four times a year, and the last scan at this substation was performed in late June 1997. Oil samples on the main tank and tap changer compartment of transformers are normally taken and tested annually. The utilitys detailed power quality investigation included current and residual voltage waveform analyses for both disturbances. Review of the current waveforms for the August 13 incident uncovered the phase B current anomaly shown in Fig. 6. The phase B current drops to zero for almost one cycle. P 4 1 4 8 8 in D811311887 ZU 3457 (Locd) Time. Cycles Fig. 6. Phase B current distonion during August 13, 1997 incident The phase B current distortion captured during the August 17h incident is shown in Fig 7. Again, the Phase B current dropped to zero for approximately one half cycle. 3 84 n I i 0 i in ii Time - Cycles 081171im7 IO 05 52 (LOCI) Fig. 7. Phase B current distortion during August 17, 1997 incident Based on the above investigations it was suspected that a problem was surfacing with the Transformer 45 secondary- side load tap changer. At this point it was determined that the problem was not serious enough to warrant taking the transformer out-of-service immediately. However, it was agreed to take the transformer out of service in the near future for a tap changer inspection. On the afternoon of August 19h some manufacturing site uninterruptible power supply (UPS) systems supplied by distribution feeder No. 5 annunciated a line voltage problem. The power quality monitor at the substation captured the voltage disturbance shown in Fig. 8. This time the Phase B ringing distortion lasted for approximately one and one half cycles. Phase C voltage, which is also illustrated in Fig. 8, was distorted more severely and almost collapsed for approximately a quarter cycle. 0 . - I 0 2 4 U 8 ID I Time - Cycles 0811011997 15 32 29 (Local) 0 - 0 2 4 B 8 10 I 2 Time - Cycles 08/10/1007 lb 32 IQ (Local) Fig. 8. Phaw B and C voltage di.;torfion during Augut 19. 1997 incidrnt Distortions i n the phase currents for the August 19h incidenr are shown in Fig 9 It became apparent that the problem was worsening. since the current was dropping to zero on all phases, and phase B current remained at zero for a longer period than during the two previous incidents. The magnitude of this disturbance incident caused increasing concern that the tap changer problem was magnifying. It was decided to meet at the substation on the afternoon of August 20th, review switching procedures, and plan a course of action for taking the transformer out of service. During the meeting it was agreed to have the utility place the tap changer in manual and lock it in one position to prevent further deterioration of its contacts, until a coordinated switching time could be arranged. Locking the tap changer in one position would not create a voltage problem since fab facilities operate at a high load factor. xrmo Mn -1008 63 : Phase A Current Lkx. 1130.37 2 . :.h.-J-.-a 158681 . , d 2 4 0 8 Ib l i Time - Cycles 08/18/1887 15 31 20 (Local) x 1000 Phase B Cunent .I . . . . . . . . 0 2 i 8 i 10 12 Time - Cycles . . DIIC IS.JI.ZO (LOCII) a XIMO n 4 i-2 9, L - 0 3 0 0 .? 0 a 0 I 4 0 8 IO I 2 Time - Cycles 0811011087 i 5 32.20 (Loczl) Fig. 9. Phase currents during August 19, I997 incident While the August 20th meeting was being held in the substation control house, (and prior to locking the tap changer in one position) a coincidental fourth disturbance occurred. Fab representatives were made aware of the incident after returning to the fab, and receiving reports that UPS systems again annunciated line voltage disturbances on the No. 5 feeder. During this incident, the line voltage ringing lasted for an even longer period. and the current remained at zero 4 85 for a longer time period. voltage and current distortion for this incident. Fig. 10 illustrates the Phase B 2 4 0 8 IO 12 08ROllW7 15.39-19 (local) Time - Cycles 9 U- - 0 2 4 0 8 10 12 08RClllBp? 15 38 19 (heal) Time - Cycles Fig 10 Phase B voltage and current distortion dunng August 20, 1997 incident A closefy coordinated switching effort on August 21 transferred all distribution feeder No.4 and feeder No. 5 loads to the redundant transformer V. UTILITY SUBSTATION TRANSFORMER TAP CHANGER REPAIR Both the utility and the manufacturing site were anxious to complete the transformer repairs as quickly as possible and restore transformer redundancy into the power delivery system. The tap changer problem surfaced during the hottest time of the year. Additionally, the abnormal feeder configuration loaded the single transformer to its rated capacity Utility crews de-energized the transformer, completed repairs, and re-energized the transformer in less than two days. Fig 11 shows the burned contacts found on phases A and B of the oh filled secondary side motor driven load tap changer Tap changer problems of this type (for this vintage of equipment) are not uncommon Similar problems are usually uncovered during the quarterly infrared scanning conducted by substation crews. If the problem grows quickly, customers will often notify the utility of flickering lights or other power quality problems surfacing with their loads The portions of the tap changer that deteriorated were the moving contacts on selector swrtches, which are part of the switching mechanism The switching mechanisms for each phase c o n w of a selector switch, a reversing switch, and two diverter suitches The Lrlector witch 14 a dial type witch with nine stationary contacts and two sets of spring loaded moving contacts. The moving contacts are mounted on the selector drive shaft. The end of the moving contacts nearest the central axis ride on collector rings. The other ends make contact with stationary contacts. In bridging positions, the moving contacts are on adjacent stationary contacts. On non- bridging positions both moving contacts are on the same stationary contact. A pilot project to avoid this type of problem has been initiated by the utility. The project consists of replacing existing tap changer contacts with those that have extremely low resistance and installing a tap changer compartment oil filtration system. VI. POWER DISTRIBUTION SYSTEM RELIABILITY The primary concern with the above described transformer tap changer problem was the possibility of the tap changer faulting and initiating a differential relay action. As can be seen in Fig. 1 , no primary-side breakers exist for either transformer at the substation. The differential relay scheme for either transformer clears the entire substation by tripping and locking out both 138 kV transmission network breakers. If such an incident occurred, restoring service to the manufacturing site would require dispatching a utility crew to the substation, securing the faulted transformer, and re- energizing and switching all distribution feeder loads to the redundant Transformer 12. Under a least problematic scenario, it is estimated these actions would take in excess of two hours. Fig. 1 I . Carbonized and damaged contactr The transformer differential relaying include both percentage and hdrmonic restraint to avoid nuisance tripping problems The percentage restraint enables the relay to discriminate between internal and external transformer faults Harmonic re5traint prevents a nuisance trip fiom the 5 86 magnetizing inrush currents when the transformer is energized. Power quality disturbance monitoring is not installed on the primary side of the transformers. Therefore, data are not available to compare actual primary and secondary currents to differential relay trip settings at the time that the above disturbances were recorded. VII. CONCLUSIONS This tap changer incident provided some satisfying reinforcement that the cooperative power quality initiative between the semiconductor manufacturer and the serving utility is benefiting both parties. It also demonstrated the need for diligent pro-active data retrie