05000247/LER-2010-009, Regarding Automatic Reactor Trip Due to a Turbine-Generator Trip Caused by a Fault of the 21 Main Transformer Phase B High Voltage Bushing
| ML110280013 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 01/18/2011 |
| From: | Joseph E Pollock Entergy Nuclear Operations |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| NL-11-005, FOIA/PA-2011-0066 LER 10-009-00 | |
| Download: ML110280013 (7) | |
| Event date: | |
|---|---|
| Report date: | |
| Reporting criterion: | 10 CFR 50.73(a)(1), Submit an LER, Invalid Actuation 10 CFR 50.73(a)(2)(iv)(A), System Actuation |
| 2472010009R00 - NRC Website | |
text
-Entergy Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, N.Y. 10511-0249 Tel (914) 734-6700 J. E. Pollock Site Vice President NL-1 1-005 January 18, 2011 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Mail Stop O-P1-17 Washington, D.C. 20555-0001
SUBJECT:
Reference:
Licensee Event Report # 2010-009-00, "Automatic Reactor Trip Due to a Turbine Generator Trip Caused by a Fault of the 21 Main Transformer Phase B High Voltage Bushing" Indian Point Unit No. 2 Docket No. 50-247 DPR-26 Entergy letter NL-10-132, "Licensee Event Report # 2010-009-00," J. E.
Pollock to NRC Docket Control Desk, dated December 21, 2011.
Dear Sir or Madam:
Pursuant to 10 CFR 50.73(a)(1), Entergy Nuclear Operations Inc. (ENO) hereby provides Licensee Event Report (LER) 2010-009-00. The attached LER replaces the LER transmitted previously on December 21, 2010 per the reference letter with a correction to the LER report date. This LER identifies an event where the reactor was automatically tripped, which is reportable under 10 CFR 50.73(a)(2)(iv)(A).
As a result of the reactor trip, the Auxiliary Feedwater System was actuated, which is also reportable under 10 CFR 50.73(a)(2)(iv)(A).
This condition was recorded in the Entergy Corrective Action Program as Condition Report CR-IP2-2010-06801.
There are no new commitments identified in this letter. Should you have any questions regarding this submittal, please contact Mr. Robert Walpole, Manager, Licensing at (914) 734-6710.
Sincerely, JEP/cbr cc:
Mr. William Dean, Regional Administrator, NRC Region I NRC Resident Inspector's Office, Indian Point 2 Mr. Paul Eddy, New York State Public Service Commission LEREvents@inpo.org
Abstract
On November 7, 2010, an automatic reactor trip (RT) was initiated as a result of a turbine-generator trip due to actuation of the main generator primary and back-up lockout relays. All control rods fully inserted and all primary systems functioned per design except for the 138 kV Station Auxiliary Transformer tap changer. The plant was stabilized in hot standby with decay heat being removed by the main condenser {SG}.
Based on reports of two explosions an Alert was declared in accordance with the emergency plan which was terminated at 22:18 hours. There was no radiation release. The Emergency Diesel Generators did not start as offsite power remained available. The Auxiliary Feedwater System automatically started as expected due to SG low level from shrink effect. The direct cause of the RT was due to actuation of the 86P and 86BU relays that sensed a fault from the failure of 21 main transformer (MT) as a result of a low impedance fault of the 345 kV Phase B bushing. The root cause could not be determined because the catastrophic failure of the phase B bushing destroyed most of the evidence.
The most probable cause is an internal failure of the phase B bushing due to a design/manufacturing deficiency.
Corrective actions include replacement and acceptance testing of the 21 MT, external visual inspections of the 22 MT HV bushings, Unit Auxiliary Transformer (UAT),
Iso-phase bus and 345 kV feeder W95, testing of the 22 MT, UAT, Iso-phase bus and HV components.
Damaged HV components were replaced. An equipment failure analysis of the failed bushing will be performed.
An evaluation will be performed on the need to revise the maihtenance frequency for bushing and transformer testing. The event had no effect on public health and safety.
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There were no significant potential safety consequences of this event under reasonable and credible alternative conditions.
The RPS is designed to actuate a RT for any anticipated combination of plant conditions including a direct RT on a turbine trip (TT).
The analysis in UFSAR Section 14.1.8 concludes an immediate RT on TT is not required for reactor protection.
A RT on TT is provided to anticipate probable plant transients and to avoid the resulting thermal transient.
If the reactor is not tripped by a TT, the over temperature delta temperature (OTDT) or over power delta temperature (OPDT) trip would prevent safety limits from being exceeded.
This event was bounded by the analyzed event described in UFSAR Section 14.1.8 (Loss of External Electrical Load).
The response of the plant is evaluated for a complete loss of steam load from full power without a direct RT.
The analysis shows that the plant design is such that there would be no challenge to the integrity of the reactor coolant system or main steam system and no core safety limit would be violated.
For this event, rod controls were in Auto and all rods inserted upon initiation of the automatic RT.
The AFWS actuated and provided required FW flow to the SGs.
RCS pressure remained below the set point for pressurizer PORV or code safety valve operation and above the set point for automatic safety injection actuation.
Pressurizer level remained on scale.
Following the RT, the plant was stabilized in hot standby.
Although the SAT tap changer hang-up resulted in one offsite power circuit being declared inoperable, adequate offsite power remained available to power safeguards buses.
Offsite power is supplied from the offsite transmission network to the plant AC electrical power distribution system by two offsite circuits: a 138 kV circuit and a 13.8 kV circuit, each of which has a preferred and backup feeder.
All offsite power to the safeguards buses enters the plant via 6.9 kV buses 5 and 6 which are normally supplied by the 138 kV circuit but may be supplied by the 13.8 kV circuit.
During plant operation, 6.9 kV buses 1-4 receive power from the main generator via the UAT.
Following a unit trip, 6.9 kV buses 1-4 will auto transfer (dead fast transfer) to 6.9 kV buses 5 and 6 in order to receive offsite power.
6.9 kV buses 2, 3,
5, and 6 supply power to the 480 volt safeguards buses (2A/3A, 5A, 6A) using 6.9 kV/480 volt station service transformer's.
The 138 kV offsite circuit satisfies the requirement of 10CFR50, Appendix A, General design Criterion 17 that at least two required circuits can, within a few seconds, provide power to safety related equipment following a Design Basis Accident.
The 138 kV offsite circuit has a dedicated SAT that can be supplied by either the preferred feeder (95332) or the backup feeder (95331).
Adequate offsite feeders were available.
The SAT automatic tap changer is operated under load to maintain secondary voltage to properly power the 6.9 kV buses.
In automatic the tap changer utilizes a voltage regulator to maintain proper voltage by automatically selecting the appropriate tap.
The tap changer position is monitored by a limit switch and~a hang-up relay.
When the limit switch fails to open within a specified time limit, the SAT Tap changer hang-up alarm actuates in the CCR.
Upon a unit trip the tap changer immediately begins raising voltage until a specified voltage is reached or the bus tie breakers are closed.
Once the tie breakers close and the transformer is loaded, any additional tap changer motion is unnecessary.
In this event the SAT tap changer stuck at high voltage side thereby providing adequate voltage to power the 6.9 kVand 480 volt buses.