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| Entered date | Event description | |
|---|---|---|
| ENS 48506 | 14 November 2012 15:40:00 | This 60-day telephone notification is being made per the reporting requirements specified by 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(1) to describe an invalid actuation of a general containment isolation signal affecting more than one system. On September 18, 2012, at 0045 hours Central Daylight Time (CDT), during performance of surveillance procedure 1-SR-3.3.6.2.3(B), Reactor/Refueling Zone Ventilation Radiation Monitor 1-RM-90-141/143 Calibration and Functional Test, a Primary Containment Isolation System (PCIS) partial Group 6 isolation occurred. The partial Group 6 isolation caused the initiation of Standby Gas Treatment (SBGT) subsystems 'A' and 'B' and Control Room Emergency Ventilation (CREV) subsystem 'A', and the isolation of the Unit 1 H2O2 analyzer and the 1-RM-90-256 Continuous Air Monitor (CAM). Due to the isolation of the 1-RM-90-256 CAM, Operations personnel declared the drywall CAM inoperable and entered Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.4.5 Condition B. Plant conditions which initiate PCIS Group 6 actuations are Reactor Vessel Low Water Level (Level 3), High Drywall Pressure, and Reactor Building Ventilation Exhaust High Radiation (Reactor Zone or Refuel Zone). At the time of the event, these conditions did not exist, therefore, the partial actuations were invalid. The affected equipment responded as designed. On September 18, 2012, at 0123 hours CDT, Operations personnel commenced restoring the affected systems to normal. At 0132 hours CDT, the 1-RM-90-256 CAM was returned to service, the SBGT subsystems 'A' and 'B' were secured, and TS LCO 3.4.5.B was exited. At 0133 hours CDT, the CREV subsystem 'A' was secured and at 0138 hours CDT, the Unit 1 hours analyzer was returned to service. This condition was the result of improper test setup during performance of 1-SR-3.3.6.2.3(B). It was determined that a jumper installed during the performance of 1-SR-3.3.6.2.3(B) to prevent an invalid actuation was not installed correctly. When the detector lead was lifted, an isolation signal was received. The surveillance procedure was stopped and the equipment was restored to pre-test condition. There were no safety consequences or impact to the health and safety of the public as a result of this event. This event was entered into the Corrective Action Program as Problem Evaluation Report 611238. The NRC Resident Inspector has been notified of this event. |
| ENS 48505 | 14 November 2012 15:34:00 | This 60-day telephone notification is being made in accordance with the reporting requirements specified by 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(1) to describe an invalid actuation of a general containment isolation signal affecting more than one system. On September 13, 2012, Browns Ferry Nuclear Plant (BFN) personnel completed the installation of three metal-oxide varistors (MOVs), MOV1, MOV2, and MOV3, on the governor of the 3C Emergency Diesel Generator (EDG) as part of a design change. On September 17, 2012, at 0312 hours Central Daylight Time (CDT), during post-modification testing of the 3C EDG, the Direct Current (DC) control circuit breaker tripped, causing a loss of governor control power for the 3C EDG. This event resulted in the loss of the 3B Reactor Protection System (RPS) Bus. In addition, Primary Containment Isolation System (PCIS) groups 3, 6, and 8 successfully isolated. The Steam Vault Booster Fan tripped and the 3B Steam Jet Air Ejector isolated. Standby Gas Treatment (SGT) Trains 'A' and 'B' and Control Room Emergency Ventilation Train 'A' initiated. The SGT Train 'C' was already in service for BFN, Unit 3, Reactor Zone Ventilation. Plant Conditions which initiate PCIS Group 3 actuations are Reactor Vessel Low Water Level or Reactor Water Cleanup Area High Temperature. The PCIS Group 6 actuations are initiated by Reactor Vessel Low Water Level, High Drywell Pressure, or Reactor Building Ventilation Exhaust High Radiation (Reactor Zone or Refuel Zone). The PCIS Group 8 actuations are initiated by Low Reactor Vessel Water Level or High Drywell Pressure. At the time of the event, these conditions did not exist; therefore, the actuation of the PCIS was invalid. The affected equipment responded as designed. On September 17, 2012, at 0335 hours CDT, Operations personnel restored the 3B RPS Bus. This condition was the result of MOV1 and MOV3 operating due to induced current in their associated ground cables. This resulted in grounds which tripped the DC control power breaker. To address this condition, MOV1 and MOV3 were permanently removed. There were no safety consequences or impact to the health and safety of the public as a result of this event. This event was entered into the Corrective Action Program as Problem Evaluation Report 610091. The NRC Resident Inspector has been notified of this event. |
| ENS 47986 | 1 June 2012 17:26:00 | During NFPA 805 transition reviews, a cable routing error has been identified that would fail the DC control power to credited 4kV Shutdown Board 3EA for an Appendix R fire in Fire Area 23. Cable 3B181 provides alternate DC Control Power to 4kV Shutdown Board 3EA from Battery Board 2. Cable 3B181 is routed in Fire Area 23. However, cable 3B181 is not identified as being in Fire Area 23 in Browns Ferry Nuclear Plant (BFN) calculation EDQ099920030037, Appendix R Computerized Separation Analysis. This error allowed the analysis to credit alternate DC Control Power to 4kV Shutdown Board 3EA. The normal DC Control Power to 4kV Shutdown Board 3EA is not available in the event of an Appendix R fire in Fire Area 23. The routing error results in the credited 4kV Shutdown Board 3EA being unable to perform its function for Fire Area 23 Appendix R fires due to both the associated normal and alternate DC Control Power cables being routed In Fire Area 23. The failure of 4kV Shutdown Board 3EA could result in a loss of power to credited safe shutdown equipment that would challenge the ability to provide adequate core cooling during performance of BFN Safe Shutdown Instructions. Compensatory actions in the form of fire watches to mitigate this condition are in place in accordance with the BFNP Fire Protection Report. This event is reportable as an 8 hour notification to the NRC in accordance with 10CFR 50,72(b)(3)(ii)(B). This is also reportable as a 60 day written report in accordance with 10CFR 50.73(a)(2)(ii)(B). The licensee has notified the NRC Resident Inspector. |
| ENS 47853 | 19 April 2012 20:58:00 | On 04/19/12 at 1430 while performing 1-SR-3.5.1.7, HPCI (High Pressure Coolant Injection) Main & Booster Pump Set developed head & flow rate at rated reactor pressure. The HPCI turbine failed to trip using the manual trip pushbutton. This manual trip pushbutton should have caused the 1-FCV-73-18, HPCI TURBINE STOP VALVE, to go closed. HPCI was secured by taking the 1-FCV-73-16, HPCI TURBINE STEAM SUPPLY VALVE, to close. The 1-FCV-73-18, HPCI TURBINE STOP VALVE, also failed to go closed locally using the 1-XCV-73-18, HPCI TURBINE MECHANICAL TRIP, nor did it go closed when the auxiliary oil pump was secured. With the 1-FCV-73-18, HPCI TURBINE STOP VALVE, open, the HPCI ramp generator is no longer in the circuit therefore, should an initiation occur and cause the 1-FCV-73-16, HPCI TURBINE STEAM SUPPLY VALVE, to open there is the potential for the HPCI turbine to over speed. Therefore, HPCI was isolated using 1-FCV-73-3, HPCI STEAM LINE OUTBD ISOL VALVE. This incident is reportable as an 8-hour ENS notification under 10CFR 50,72 (b)(3)(v) as 'any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident.' It also requires a 60 day written report in accordance with 10CFR 50.73(a)(2)(vii). The NRC Resident Inspector has been notified. |
| ENS 47638 | 5 February 2012 18:06:00 | UNANALYZED CONDITIONS DISCOVERED DURING NFPA 805 TRANSITION REVIEW
During the licensee's NFPA 805 transition review process, several unanalyzed conditions were discovered but determined to be not reportable at that time. During subsequent review, the licensee determined these conditions did meet reporting requirements. The following unanalyzed conditions affect all three Browns Ferry units: "On 5/11/2010, it was determined that in the event of an Appendix-R fire, multiple hot shorts affecting reactor pressure instrument loops, Safety Relief Valves (SRV) overpressure logic or ADS (Automatic Depressurization System) logic could cause 2 to 13 SRVs to spuriously open, for certain fire areas. The current Appendix R safe shutdown analysis only assumes 2 SRVs spuriously open. The issue has significant safety impact due to the potential for one fire scenario to result in spurious opening of multiple SRVs, loss of low pressure inventory makeup, and loss of the condensate system for inventory makeup, which would challenge adequate core cooling during performance of Safe Shutdown Instructions. "On 8/18/2010, it was determined that in the event of an Appendix-R fire, fire induced circuit damage can potentially result in the inability to manually close the following Motor Operated Valves: Residual Heat Removal Heat Exchanger outlet valves and Emergency Equipment Cooling Water pump cross-tie valves. The failure to be able to manually close these valves could result in the loss of decay heat removal function and loss of credited diesel generators to power required safe shutdown equipment. These issues have significant safety impact since the capability to manually close these valves is necessary to ensure adequate core cooling during performance of BFN Safe Shutdown Instructions. "On 9/30/2010, it was determined that in the event of an Appendix-R fire, fire induced multiple hot shorts could cause both Inboard and Outboard RHR test return valves, and Drywell Spray and Suppression Pool Spray valves to spuriously open due to damage to the valve control circuit cables. This could result in draining of the Pressure Suppression Chamber Head Tank and the affected low pressure Emergency Core Cooling System loop piping (RHR or CS). Consequently, the discharge pipe in the credited Residual Heat Removal (RHR) loop may not be filled and vented when the Safe Shutdown Instructions (SSIs) call for the RHR pump to be started. The resulting water hammer could result in piping system damage resulting in loss of core cooling and decay heat removal functions and loss of suppression pool inventory. Additionally, single spurious actuation of Core Spray (CS) test return valves due to fire damage to their control circuits could have the same results. These issues have significant safety impact since they would challenge the ability to provide adequate core cooling during performance of Safe Shutdown Instructions. On 8/22/2011, two unanalyzed conditions were discovered: First, "it was determined that, in the event of an Appendix-R fire in certain areas, fault propagation due to loss of the breaker control circuit in conjunction with power cable damage could result in de-energization of the associated 4kV Shutdown Board. This potential exists since some 4kV Shutdown Board load breakers are not equipped with separate fuses for trip circuits extending beyond the board. This condition could result in a loss power to credited safe shutdown equipment that would challenge the ability to provide adequate core cooling during performance of BFN Safe Shut down Instructions. Second, "it was determined that in the event of an Appendix-R fire in certain areas, Multiple Spurious Operations (MSO) could result in the Main Steam Isolation Valves failing to close, or to re-open. This potentially results in a challenge to control inventory loss during performance of Safe Shut down Instructions. The following unanalyzed condition only affects Unit 2: "On 8/18/2010, it was determined that in the event of an Appendix-R fire, fire induced circuit damage can potentially result in the inability to manually close certain Main Steam Drain Line Motor Operated Valves. The current Appendix R safe shutdown analysis credits manual closure of these valves. Failure to close these valves results in loss of suppression pool inventory which could challenge adequate core cooling during performance of BFN Safe Shutdown Instructions." Compensatory actions in the form of fire watches to mitigate all these conditions are in place in accordance with the BFNP Fire Protection Report. The licensee will make the required 60-day written reports in accordance with 10CFR50.73(a)(2)(ii)(B). These events were entered into the licensee's Corrective Action Program. The licensee has notified the NRC Resident Inspector. |
| ENS 45391 | 30 September 2009 04:09:00 | On 9/29/09, at 2323 (hours) Unit 2 was manually scrammed due to loss of one of the remaining two Condensate Booster Pumps due to low pump suction pressure. The cause for the Condensate Booster Pump low suction pressures is unknown at this time, but is under investigation. The operating crew was removing feedwater pump 2B from service when the condensate booster pump tripped. The condensate booster pump 2C was already out of service to support maintenance. After the reactor was scrammed manually, reactor water level lowered below the automatic scram set point (+2 inches) and below the automatic start for HPCI and RCIC (-45 inches). All expected Primary and Secondary Containment Isolation valves operated as required, isolation groups 2, 3, 6 and 8 were actuated. Both reactor recirculation pumps tripped due to the low reactor water level. HPCI and RCIC actuated as expected to restore reactor water level. Reactor pressure control was maintained on the turbine bypass valves, and no Main Steam Relief Valves (MSRVs) were opened as a result of the transient. At this time the unit is stable in mode 3. Reactor water level is being controlled using one Reactor Feedwater pump. HPCI and RCIC have been returned to standby readiness. Reactor pressure is being automatically maintained by the main turbine bypass valves. This event is reportable as a 4 hour non-emergency report due to 10CFR50.72(b)(2)(iv)(A) and (B) (ECCS discharge to the reactor and Reactor Protection System (RPS) actuation) and as an 8 hour non-emergency report due to 10CFR50.72(b)(3)(iv)(A) (specified system actuations). Lowest observed Reactor Vessel Water Level (RVWL) was -50 inches. Following actuation of HPCI level recovered to +51 inches and then returned to the normal operating band of +33 inches. Safety-related equipment out-of-service prior to the scram included Core Spray Loop 1. All control rods fully inserted. Unit 2 is in a normal post scram electrical lineup. The licensee informed the NRC Resident Inspector and does not plan a press release.
The initial notification made at 0409 hours ET on September 30, 2009, reported that the RCIC system actuated as expected in conjunction with the HPCI to restore Reactor Pressure Vessel (RPV) water level. However, during a review of plant data, BFN (Browns Ferry Nuclear) determined that after receiving a valid actuation signal, RCIC failed to inject to the RPV. The cause of the failure is under investigation. The licensee informed the NRC Resident Inspector of the update and does not plan a press release. Notified R2DO(Ernstes). |
| ENS 48724 | 6 February 2013 16:31:00 | On July 28, 2009, TVA identified, in the Corrective Action Program, the potential to overtop and fail earthen embankments at Cherokee, Fort Loudoun, Tellico, and Watts Bar Dams. Prior Browns Ferry Nuclear (BFN) analysis did not consider the potential to overtop and fail the earthen embankments at Cherokee Dam. This condition could have resulted in an increase in the probable maximum flood (PMF) level at Browns Ferry Nuclear Plant Units 1, 2 and 3. TVA initiated immediate actions to address the condition by conducting additional analyses and developing contingent actions. Additional actions were developed including the installation of modular flood barriers (which were) completed in December 2009. The barriers increase the effective height of the affected embankments preventing their overtopping and failure. Additional details regarding the modular flood barriers and the results of TVA's subsequent hydrologic analyses were discussed in a public meeting between TVA and the NRC staff on July 7, 2010. This report addresses a condition as described in 10 CFR 50.72(b)(3)(ii)(B). Subsequent analyses, completed in November 2012, determined that there are no past operability concerns with this condition at BFN. The NRC Resident inspector has been notified of this condition. See related event notifications from Watts Bar (EN #48723) and Sequoyah (EN #48725). |
| ENS 43092 | 11 January 2007 13:16:00 | Unit 2 reactor scrammed due to a main turbine trip. PCIS (Primary Containment Isolation Signal) groups 2, 3,and 6 isolated, CREV (Control Room Emergency Ventilation) A, SBGT (Standby Gas Treatment) trains A, B, and C started as expected. All control rods fully inserted, eight main steam relief valves lifted and no ECCS actuations occurred. This event is reportable within four hours according to 10CFR50.72(b)(2)(iv)(B) and eight hours according to 10CFR50.72(b)(3)(iv)(A). The turbine trip was the result of the 500kV main output breaker opening causing the generator output breaker to open. All relief valves fully seated during the scram recovery. The reactor water level is being maintained using normal feedwater and decay heat is being removed using the steam dumps. The plant is using the startup transformer for electrical power. The cause of the 500kV breaker opening is under investigation. The licensee will notify the NRC Resident Inspector. |
| ENS 42867 | 29 September 2006 15:02:00 | This 60-day telephone notification is being made under reporting requirements specified by 10 CFR 50.73(a)(2)(iv)(A) and 10 CFR 50.73(a)(1) to describe an invalid actuation of an emergency service water system component that does not normally run and which provides an ultimate heat sink. At 0951 hours CDT on August 9, 2006, with Unit 1 defueled and Units 2 and 3 operating at 100% power, the B3 Emergency Equipment Cooling Water (EECW) pump was tripped when an undervoltage relay was manually operated during functional testing of relaying associated with the 1B Core Spray (CS) pump breaker. While operations personnel were responding to the pump trip, but before the testing activity could be halted, performance of subsequent steps in the functional testing activity resulted in an automatic start of this same pump and then another trip when a companion undervoltage relay was manually operated. Auto-starting of associated EECW pumps upon CS pump starts is part of the equipment logic and had been anticipated, and the B3 EECW pump had been placed in service prior to beginning the relay functional testing to avoid an automatic start. The potential for tripping loads other than the 1B Core Spray pump breaker was discussed in the pre job briefing, however, the actual test instruction steps did not provide detail sufficient to ensure only specific undervoltage relay contacts were operated. Rather than operating only specific relay contacts, test personnel operated the entire relay, resulting in the unplanned trip, restart, and trip of the B3 EECW pump. The logic downstream from the manually operated undervoltage relays and the B3 EECW pump responded in accordance with the plant design. No other plant equipment was affected during this event, though the 2B Core Spray pump would have also tripped had it been running at the time the undervoltage relays were operated. The B3 EECW pump was secured, and the testing activity was suspended. Other operating EECW pumps were not affected and no degradation of EECW system function occurred. There were no safety consequences or impacts on the health and safety of the public. The event was entered into TVA's corrective action program for evaluation and resolution. Reference corrective action document PER 108425. The licensee notified the NRC Resident Inspector. |
| ENS 41861 | 22 July 2005 08:01:00 | During performance of 2-SR-3.8.6.2(I-A) QUARTERLY CHECK FOR SHUTDOWN BOARD A BATTERY, the DC subsystem was declared inoperable due to cell voltage not meeting Technical Specification (TS) acceptance criteria. Concurrently a second DC subsystem was inoperable in support of scheduled maintenance activities. As a result of these subsystems being inoperable, Unit 2 entered TECHNICAL SPECIFICATION LCO 3.0.3. at 0220 and commenced a shutdown at 0316. In accordance with 10CFR50.72(b)(2)(i) this notification is being made. Plant conditions are stable at this time and no other plant systems were affected. At 0450 one DC subsystem was returned to an operable status. As a result of this, Unit 2 exited LCO 3.0.3, shutdown activities were terminated and unit 2 has been returned to 100 % power. The licensee notified the NRC Resident Inspector. |