ML20140A200
| ML20140A200 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 05/19/2020 |
| From: | NRC/RES/DRA/PRB |
| To: | |
| Littlejohn J (301) 415-0428 | |
| References | |
| LER 1992-027-00 | |
| Download: ML20140A200 (5) | |
Text
B-137 B.19 LER Number 327/92-027 Event
Description:
Loss of Offsite Power Date of Event:
December 31, 1992 Plant:
Sequoyah 1 & 2 B.19.1 Summary Shortly after a switchyard tie breaker was installed, it faulted and caused an undervoltage condition in the switchyard. This resulted in the tripping of both units from 100% power after both unit's reactor coolant pumps (RCPs) tripped on undervoltage. Because of the momentary undervoltage condition on the safeguards buses, the emergency diesel generators started and loaded. The conditional core damage probability estimated for this event is 1.8 x 10-1 per unit. The relative significance of this event compared to other postulated events at Sequoyah is shown in Fig. B.40.
[ER 327/92.027 1E-7 156 1E-5 E-1E4 MB-3 1E-2 LTRwj prewsor LOO LOOP 360 h Fig. B.40.
Relative event significance of LER 327/92-027 compared with other potential events at Sequoyah 1 & 2.
B.19.2 Event Description On December 31, 1992, with both units at 100% power, work was progressing on the installation of a 500-kV/161-kV switchyard inter-tie breaker (see figure in LEk 327/92-027). For testing purposes, the primary relay protection for the breaker was disabled. At 2148 hours0.0249 days <br />0.597 hours <br />0.00355 weeks <br />8.17314e-4 months <br />, 11 min after the breaker was placed in service, both units tripped following the loss of the RCPs from an undervoltage signal. The undervoltage was caused by an internal fault in the inter-tie breaker that resulted in decreased voltage throughout the entire switchyard. After the switchyard fault was cleared (in 88 cycles), offsite power was available to the station.
LER NO: 327/92-027
B-138 Following the plant trips and the clearing of the switchyard fault, loads automatically transferred as designed from the unit station service transformers to the common station service transformers.
However, because of the undervoltage sensed on the shutdown (safeguards) buses, the emergency diesel generators started and loaded. At 2313 hours0.0268 days <br />0.643 hours <br />0.00382 weeks <br />8.800965e-4 months <br /> the safeguards buses were realigned to offsite power. By 0013 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> on January 1, 1993, both units were stabilized in hot shutdown.
Due to limited staffing levels, the unit 2 recovery progressed with only one senior reactor operator (SRO) and one reactor operator (RO). During the recovery process, cooling to the RCP seals was placed in a degraded condition. For a period of 20 seconds, all charging pumps and thermal barrier booster pumps (TBBPs) were stopped.
The charging pumps provide RCP seal injection while the TBBPs boost component cooling water (CCW) pressure to the RCP, thermal barriers. During this-20 second time period, the CCW pumps continued to run and supplied approximately 70% of normal CCW flow to the RCP seals. This wal sufficient flow to assure long term seal cooling.
B.19.3 Additional Event-Related Information The Sequoyah switchyard consists of a 500-kV section and a 161,kV section. Unit 1 is directly connected to the 500-kV switchyard and unit 2 is directly connected to the 161-kV portion of the yard. The two sections are joined by the inter-tie transformer. Power circuit breaker (PCB) 5058 connects one of the 500-kV buses to the inter-tie transformer. During startup and shutdown, power to both units is supplied by the 161-kV system via the common station service transformers. Normally, primary relaying will isolate PCB 5058 in 3.5 cycles. Since PCB 5058 was removed from service, the undervoltage relays on the RCP trip actuated instead (in 17.5 cycles). Also, the undervoltage relays on the safeguards busses actuated (in 30 cycles)'before the secondary relaying could isolate the fault (normally, in 88 cycles).
B.19.4 Modeling Assumptions Since the LOOP was caused by a substation fault, this event was modeled as a plant-centered LOOP.
Probabilities for LOOP nonrecovery (short term), failure to recpver ac power prior to battery depletion, and RCP seal LOCA probabilities were revised to reflect values associated with a plant-centered LOOP (see ORNL/NRC/LTR-89/1 1, Revised LOOP Recovery and PWR Seal LOCA Models, August 1989). The event was modeled for a single unit. The event sequence was essentially the same for both units.
B.19.5 Analysis Results The conditional probability of core damage estimated for this event is 1.8 X 10' per unit. The dominant core damage sequence, highlighted on the event tree in Fig. B.41, involves failure of emergency power restoration resulting in an RCP seal LOCA.
LER NO: 327/92-027
B-139 LOOP LOOP EP SSRV SRV HPI HPR PORV SEQ END CHAL IRESEAT LOCA (LONG)
OPEN NO STATE OK OK 41 CD 42 CD OK OK 43 CO 44, CD 45 CD OK 46 CD 47 CD 48 CD OK 49 CD 50 CD OK 51 CD 52 CD 53 CD OK 54 CD 55 CD 40 ATWS Fig. B.41.
Dominant core damage sequence for LER 327/92-027.
LER NO: 327/92-027
B-140 LER NO: 327/92-027
B-141 LER NO: 327/92-027