Semantic search
| Entered date | Event description | |
|---|---|---|
| ENS 50870 | 7 March 2015 15:05:00 | At 1155 CST on March 7, 2015, a small cooling water leak was identified on the 21 Containment Fan Coil Unit east face u-bend on the north east corner bottom bundle. Unit 2 Containment was declared inoperable, which required entry into Technical Specifications (TS) LCO 3.6.1, Condition A, Containment inoperable, applicable in MODES 1, 2, 3, and 4. Immediate actions were taken to isolate the Fan Coil Unit within 1 hour from the initial identification of the leak. 21 Containment Fan Coil Unit was isolated, Containment was declared operable and TS 3.6.1 Condition A was exited at 1220 CST on 3/7/15. This condition is reportable under 10 CFR 50.72(b)(3)(v)(C) as an event or condition that could have prevented fulfillment of the safety function of structures or systems that are needed to control the release of radioactive material. The plant remains in a safe condition and there was no effect to the health and safety of the public. The licensee has notified the NRC Resident Inspector. |
| ENS 48186 | 14 August 2012 08:52:00 | Prairie Island Unit 1 is currently being shutdown per Tech Spec 3.8.1.F due to both Diesel Generators inoperable for Unit 1. On August 13th at 0939 CDT, a planned entry to Tech Spec 3.8.1.B was performed for one Diesel Generator inoperable, due to the scheduled monthly surveillance run of D1 Emergency Diesel Generator. At 1048 CDT, a small candle sized flame was identified at the exhaust manifold and D1 was subsequently shutdown. Subsequent investigation by maintenance determined that there appeared to be a gasket leak on the turbocharger. D1 was tagged out of service and repairs are currently in progress. Tech Spec 3.8.1 required action B.3.1 requires a determination be made to verify the operable Diesel Generator is not inoperable due to a common cause failure. On August 14th at 0230 CDT, Unit 1 entered the Limiting Condition for Operation to perform the monthly surveillance run to verify no common cause failure existed. At 0312 CDT, the Shift Manager reported a small candle sized fire on the exhaust manifold for D2. Unit 1 entered an event or condition that could have prevented fulfillment of a safety function, a 10 CFR 50.72 (b)(3)(v)(D) report is required due to a loss of both D1 and D2. D2 was subsequently shutdown and declared inoperable. A Technical Specification shutdown was also required and a Unit 1 Shutdown was commenced at 0425 CDT and a 4 hour non-emergency notification is required per 10 CFR 50.72(b)(2)(i). With both Diesels inoperable at 0230 CDT, Tech Spec 3 8.1.E requires one diesel to be returned to operable status within 2 hours. However, as neither diesel generator could be returned to service in this time period, Tech Spec 3.8.1.E requires the plant to be in Mode 3 within 6 hours and Mode 5 within 36 hours. The NRC Resident Inspector has been notified.
A Technical Specification shutdown has been completed at 1025 CDT as planned for Unit 1. It was a normal manual reactor trip with no unexpected equipment issues. As expected due to plant electrical conditions, the Auxiliary Feedwater System auto started. This is reportable per 10 CFR 50.72(b)(3)(iv)(A) as a valid System Actuation, The Auxiliary Feedwater System operated as expected. Unit 1 is currently in Mode 3. The NRC Resident Inspector has been notified. Notified R3DO (Giessner). |
| ENS 46699 | 25 March 2011 17:27:00 | During performance of maintenance to troubleshoot the B feedwater regulating bypass valve, the Thermal Power Monitor (TPM) indication exceeded the maximum thermal power assumed in the Safety Analysis Report. Operators were maintaining 12 Steam Generator (SG) water level in a band from 40 to 48 percent by controlling the B Feed Regulating Valve (FRV) in manual from the Control Room. Operators noted a power increase; adjustments were made via the FRV to reduce SG water level, however the valve response was sluggish and thermal power exceeded 100%. Immediate steps were taken to reduce power to below 100% by reducing 1st stage turbine pressure and inserting Bank D control rods 7 steps. The TPM indication was above the maximum thermal power limit of 100.36% for 1.68 minutes. The TPM indication peak was 100.39%. No concurrent increase in power was observed by the nuclear indication system. NRC Resident had been informed.
An eight hour report (EN #46699) per 10 CFR 50.72(b)(3)(ii)(B) was conservatively reported on March 25, 2011 for Thermal Power Monitor indication above the maximum thermal power limit of 100.36% for 1.68 minutes. Subsequent engineering investigation has determined that this specific transient had been previously analyzed. The transient was within the bounds of the safety analysis. The 10 CFR 50.72(b)(3)(ii)(8) report (EN #46699) is retracted. NRC Resident has been informed. Notified R3DO (Peterson). |
| ENS 45952 | 25 May 2010 06:50:00 | During a normal plant power increase following a refueling outage on Unit 2, a reactor trip occurred at approximately 32% power. This reactor trip was the result of a turbine trip. The cause of the turbine trip is unknown at this time, however, a lock out trip occurred on the only running main feed water pump (21 main feedwater pump) at the time of the turbine and reactor trip. An investigation is ongoing. The reactor trip first actuated indication was a turbine trip. An automatic start of both Auxiliary Feed Water pumps occurred following the trip. The operating crew responded to the reactor trip utilizing emergency operating procedures for reactor trip and reactor trip recovery and transitioned into a normal shutdown procedure. All rods inserted as expected and all other systems operated as expected with the exception of a positive displacement charging pump that lifted a relief that failed to reclose. The positive displacement pump relief valve stuck open and the pump was shut down which isolated the relief valve. Decay heat was initially being removed to the main condenser however, steam leak by was causing a plant cooldown therefore the Main Steam Isolation Valves were shut. Decay heat is being removed using the steam generator atmospheric relief valves. There is no known primary to secondary leakage. The plant is in its normal shutdown electrical lineup. The licensee notified the NRC Resident Inspector. |
| ENS 45851 | 17 April 2010 02:19:00 | During a normal reactor shutdown for a refueling outage on Unit 2, a reactor trip occurred at approximately 13% power. This reactor trip was the result of a turbine trip due to high differential pressure between A & B condensers (greater than 2.5 inches). The cause for the vacuum difference between condensers is unknown at this time. The reactor trip first actuated indication was a high flux rate trip and the turbine trip first out indication was not received. The reason for this difference is unknown at this time. The operating crew responded to the reactor trip utilizing emergency operating procedures for reactor trip and reactor trip recovery and transitioned into normal shutdown procedures. All rods inserted as expected and all other systems operated as expected. The licensee notified the NRC Resident Inspector. According to the licensee: The plant is in a normal post-trip electrical lineup. No automatic relief valve operations occurred. The motor driven auxiliary feed pump was manually started. The main steam isolation valves are open and decay heat is being removed by steam through the turbine bypass valves to the main condenser. |
| ENS 44615 | 30 October 2008 16:23:00 | During the performance of 030 (post refueling start-up testing), control rods were being inserted for dynamic rod worth measurement. An urgent failure occurred in the rod control system which caused Group 1 rods in Control Bank A to stop inserting while Group 2 rods continued to insert. Reactor was manually tripped following the receipt of rod control alarms due to rod misalignment within Control Bank A. All rods inserted as expected. The licensee notified the NRC Resident Inspector. |
| ENS 44377 | 31 July 2008 11:03:00 | Unit one (1) experienced a reactor trip during SP-1003 Analog Protection Functional Test. The yellow Tave channel was in test when the red Tave channel bistable failed causing an OTDT reactor trip. Applicable emergency operating procedures were entered and completed. The plant is now implementing 1C1.3, the normal plant shutdown procedure. All systems performed as expected with exception of 11 turbine driven auxiliary feed (AFW) pump auto started and tripped 50 seconds later on low suction / discharge pressure which the plant is continuing to investigate. All rods inserted and all other AFW system components are operating as expected. Decay heat removal is from Main and Auxiliary Feedwater to the Steam Dump system. No safety or relief valves actuated. The plant is in a normal electrical lineup. The licensee notified the NRC Resident inspector. |
| ENS 43592 | 24 August 2007 13:41:00 | On August. 24, 2007, Prairie Island staff completed a past operability evaluation of a condition involving a missing fire barrier, such that the required degree of separation for redundant safe shutdown trains was lacking. The floor trench which transverses the auxiliary feedwater pump (AFWP) rooms has a 12 inch thick concrete barrier at the interface of Fire Areas 31 and 32 (Unit 1 and Unit 2 AFWP rooms). That barrier is required by NRC commitment to prevent the flow of flammable liquid (i.e., oil) and fire suppression water from transferring fire from one AFWP room to the other. That barrier contains penetrations which shall be controlled like any other fire barrier penetration. One of those penetrations is a 4 inch pipe sleeve. When stuffed with fire-retardant wool and capped with provided threaded caps, it is a qualified seal. However, for approximately ten years, the 4 inch sleeve has contained a 3 inch hose. During most of this 10 year period there were hourly fire watches in these two fire areas, which were an acceptable compensatory measure. However; for a period between Sept. 19, 2005 and April 9, 2006 there were no hourly fire watches in place. Prairie Island staff concluded the required degree of separation was lacking with no compensatory measures, thus the as-found condition is reportable per 10 CFR 50.72(b)(3)(ii) as an unanalyzed condition that significantly degraded plant safety. This condition was discovered and corrected on 8/10/07. The licensee notified the NRC Resident Inspector. |
| ENS 43253 | 21 March 2007 20:05:00 | The Prairie Island Nuclear Plant has a turbine building sump that collects water from the secondary side of the plant and this water contains trace levels of tritium. When we normally discharge the water from the sump, it is either sent to the river or to a permitted area on plant property. Earlier today, the discharge was lined up to the permitted area on plant property. The end of the line was frozen, causing approximately 100 - 150 gallons of the water to be diverted to a non-permitted area inside the plant property. This notification is being made due to the notification of offsite agencies (state , local and county). The NRC Resident Inspector was notified of this event by the licensee. |