Semantic search
| Entered date | Event description | |
|---|---|---|
| ENS 45779 | 19 March 2010 14:07:00 | At 12:43 on Monday, March 15, 2010, the 103 Emergency Diesel Generator (EDG) was inadvertently started during standby circuit checks. The standby circuit checks test was a planned evolution that was not intended to cause a start of the EDG. Following the start of the EDG, the standby circuit check test was stopped and the running checks for the diesel were completed satisfactory at 12:50. The EDG was secured at 13:03, after functioning successfully. The EDG was not started by a valid initiation signal. A valid initiation signal is degraded or loss of voltage to the Power Board (PB) 103. Also, the EDG output breaker did not close since the PB 103 was not deenergized. This event is not considered an LER. This report is being made under 10 CFR 50.73(a)(2)(iv)(A) (requires reporting within 60 days when a event or condition that resulted in manual or automatic actuation of the EDG AC Electrical Power Systems, including EDG System occurs.) EDG 103 is the train that actuated. EDG 103 actuation was not complete since breaker did not close. EDG 103 started and remained operable throughout the event; output breaker would have closed and supplied PB 103 if required. The event has been entered into the corrective action program. There are no other adverse impacts to the station based on this event. |
| ENS 44598 | 24 October 2008 00:48:00 | Control Room Operators observed slight (reactor) pressure rise during panel walk down. Investigation of pressure indication led Control room staff to determine that (the) EPR (Electronic Pressure Regulator) was not functioning properly (noise in the output signal). Control Room Staff entered Special Operating Procedure for failed pressure regulator. EPR could not be moved and this was confirmed by operators in the field. Control Room Staff (then) inserted a manual scram. Immediately after the scram reactor water level reached a low of 36", Emergency Operating Procedures for Level (EOP-2) were entered. HPCI initiated on the turbine trip to control water level. After the turbine tripped, all turbine bypass valves failed open; MSIVs (main steam isolation valve) were manually shut to control pressure. (The) EPR eventually disengaged from control, allowing the operator control of the turbine bypass valves. MSIVs were then reopened. (The) Scram has been reset. (The) turbine driven shaft pump did not initially disengage, pump (was) manually tripped after turbine speed reduced to 1500 rpm. All other systems responded correctly. (The) plant is not currently in any SOPs or EOPs and is proceeding to cold shutdown using normal operating procedures. All control rods fully inserted as expected. The plant is in a normal shutdown electrical lineup. At the time of the event, containment spray loop 1-12 was out of service for routine surveillance. The plant is currently cooling down and is at 365 psi. The licensee notified the NRC Resident Inspector. |
| ENS 43710 | 11 October 2007 04:25:00 | The tone alert radio system for Nine Mile point was taken out of service for planned maintenance. Per Site Emergency Planning procedures this constitutes a partial loss of the Public Prompt Notification System (Loss of Communication) and thus is reportable under 10 CFR 50.72 (3)(b)(xiii). The tone alert radio system is installed in Oswego County residences and businesses who can not hear the siren system when activated. The tone alert radio system notifies Oswego County resident of emergency situations. The tone alert radio system is maintained and operated by the National Weather Service (NWS). NWS estimates that the system will be out of service for approximately 6 hours. The county alert sirens, which also function as part of the public prompt Notification System, are operable. The licensee notified the State and local governments. The licensee will notify the NRC Resident Inspector.
The Oswego County Emergency Management Office was notified on 10/11/07 at approximately 1150 by the National Weather Service, NWS (Binghamton, NY) that the Tone Alert System is in service and fully functional. The NWS informed Oswego County that the time the Tone Alert System was out of service from 10/10/07 at 2350 until 10/11/07 at 0013 for a total of 23 minutes. The 23 minutes is less than the one hour criteria for a 10CFR50.72 notification. As such, the initial notification is retracted." R1DO (W. Cook) notified. The NRC Resident Inspector was notified of this retraction by the licensee. State and Local Officials have also been notified of this retraction by the licensee. |
| ENS 41927 | 18 August 2005 11:10:00 | Unit 1 scrammed from 100% power due to a loss of power board 11 coincident with 1/2 scram present already on RPS channel 12 due to (instrumentation and control) (I&C) testing. A loss of power board 11 causes a loss of 11 RPS trip bus which in turn produces a 1/2 scram. Loss of power board 11 is currently under investigation. In addition during the scram, HPCI injected into the reactor vessel on a turbine trip signal to maintain reactor water level. Currently, the reactor is in hot shutdown with reactor water levels being maintained in the normal level band at 74 inches with feedwater in automatic. Reactor pressure is currently 920 psig and being maintained in automatic with turbine bypass valves. Plan is to stay in hot shutdown and complete scram recovery procedures. All control rods fully inserted. No safety relief valves actuated. Electrical busses were being supplied by normal offsite power. Emergency diesel generators are available. The decay heat removal path is currently normal feedwater to the reactor vessel through the turbine bypass valves to the condenser. There was no impact on Unit 2. The licensee is going to suspend any high risk maintenance activities on Unit 2. The licensee notified the NRC Resident Inspector. |
| ENS 41584 | 10 April 2005 11:46:00 | Nine Mile Point Unit 1 received a valid RPS SCRAM signal from high water level in the SCRAM Dump Volume (SDV). While restoring the Hydraulic Control Rod Unit (HCU) for control rod 02-35 to service, the internals to the plug valve for the Instrument Air Supply (116 Valve) to the SCRAM Inlet and Outlet valves failed. This failure caused an approximate 1/2" hole in the SCRAM Air Header, which resulted in the SCRAM Air Header pressure lowering rapidly due to the leak. Operators at the HCU recommended isolating the SCRAM Air Header. The Shift Manager was contacted by the job supervisor and received permission to isolate the SCRAM Air Header. SCRAM inlet and outlet valves opened, SDV vents and drains closed due to the loss of SCRAM Air Header pressure. Approximately 3 minutes after SCRAM Air Header depressurization, a full SCRAM signal occurred as expected due to the water level in the SDV. There was no fuel in the Reactor Vessel (RPV). No Control Rod motion occurred due to all Control Rods being inserted or isolated for maintenance. Immediate (8 Hour Non-Emergency) notification of this event being made as a result of the requirements of 10CRF50.72(b)3(iv)(A). The licensee stated that more information on the event can be found in Nine Mile Point Internal document DER - NM-2005-1565. The license will be notifying the NRC Resident Inspector.
The scram event that occurred on April 10, 2005 was not initiated from a "valid" scram initiation signal (i.e., none of the instrumentation signals identified in Technical Specification Table 3.6.2a triggered the scram). To the contrary, a valve on a CRD hydraulic control unit (HCU) failed and Operations took action to isolate instrument air from the scram air header. This operator action had the identical effect that a scram signal would have had - the scram air header completely vented through the broken valve and caused the scram inlet and outlet valves on the HCUs to open and the scram discharge volume vents and drains to close. At the time, the reactor was defueled and all control rods were either already inserted or properly removed from service for maintenance, thus, the event did not result in any control rod movement (i.e., the system had been properly removed from service and the safety function had already been performed). Subsequent to the initiating event, as per the design of the CRD and RPS systems, the scram discharge volume filled and a full RPS scram signal was generated. Conclusion: The scram event that occurred on April 10, 2005, resulted from an invalid scram initiation signal. At the time, the reactor was defueled, the CRD system had been properly removed from service and the safety function had been properly performed (no control rods moved). Thus, pursuant to the guidance in NUREG-1022, it is appropriate to conclude that the event is not reportable under 10CFR50.72(b)(2)(iv) or 10CFR50.73(a)(2)(iv). As such, the 8-hour ENS notification that was made at 11:46 on 4/10/05 (reference Event Number #41584) is being retracted The licensee notified the NRC Resident Inspector. R1DO (Bellamy) was contacted. |
| ENS 40749 | 14 May 2004 15:45:00 | Nine Mile Point has been informed of a change in its vendor's calculation of Peak Cladding Temperature (PCT) and local cladding oxidation that is based on a reanalysis of the oxygen available for injection into the reactor vessel that would then recombine with hydrogen produced during the postulated zinc-water reaction. Based on 10CFR50 Appendix K inputs and assumptions the additional heat released from this increased reaction rate would result in an estimated increase of 25 degrees F in PCT and 1.73% in maximum local oxidation during five reactor recirculation loop operation, with containment inerted. The increased oxidation results in the analysis of record being non-conservative to the 17% limit as specified in 10CFR50.46(b)(2). Maximum Average Planar-Linear Heat Generation Rate (MAPLHGR) limit adjustments will be applied to bring the oxidation limits below the 17% limit. Notification is being made as a result of the 10CFR50.46(a)(3)(ii) requirement to report this issue in accordance with 10CFR50.72 and 10CFR50.73. Background During a Loss of Coolant Accident (LOCA), oxygen is available in the fuel bundles due to evaporation of the Emergency Core Cooling System (ECCS) water and release of the dissolved oxygen. In addition, oxygen can also be drawn into the reactor vessel later in the LOCA when the vessel pressure has dropped to the Primary Containment (Drywell) pressure. Condensation of the steam in the reactor vessel upper plenum due to the injection of sub-cooled ECCS water causes a reduction in pressure that will result in drawing the non-condensable gases (including oxygen) from the Drywell. Hydrogen is generated, within the fuel bundles during a LOCA due to Zirconium metal - water reaction caused by high cladding temperatures. It has been postulated that, at the pressure and temperature conditions in the reactor core during a LOCA, free hydrogen and oxygen could combine and release heat that will increase the steam temperature. Since steam is the heat sink when the core is uncovered, an increase in the steam temperature can result in an increase in the PCT for non-jet pump plants. The LOCA scenario for a BWR/2 designed plant is different since the core remains uncovered and there is no period of reflooding for large breaks. The cladding will still be heating up when the oxygen from the containment gets into the vessel. This phenomenon also results in an increase in local oxidation. The change in the allowable MAPLGHR limit for five loop operation with the containment inerted results in the offsite dose for this scenario being still bounded by our current safety analysis. Therefore, this event is not significant with respect to the health and safety of the public. Corrective Action(s): Reactor Engineering has implemented the 2% MAPLHGR Limit reduction through imposition of a .98 MAPRAT to restore compliance to the 10CFR50.46 limits. Operations will place administrative controls/ procedure changes to preclude operating without containment inerted at or above 25% power to limit oxygen available for this postulated phenomenon. In accordance with 10CFR50.73, a LER will be submitted with a more detailed discussion of the nature of this change in the ECCS evaluation model, its estimated effect of the limiting ECCS analysis, and a proposed schedule for providing a reanalysis or taking other action as may be needed to comply with this regulation. The licensee notified the NRC Resident Inspector. |