|Report date||Site||Event description|
|05000339/LER-2016-001||21 September 2016||North Anna||On July 29, 2016, with Unit 1 and Unit 2 at 100 percent power in mode 1, Unit 2 Reactor Coolant System (RCS) unidentified leakage was noted to take a 0.05 gallons per minute step increase coincident with a similar increase in Unit 2 containment sump in-leakage. Subsequent containment entries identified a through wall leak existed in the controlled bleed-off piping associated with the Reactor Coolant Pump seal for 2-RC-P-1C. Due to the pressure boundary leakage, this event was reported at 1517 hours on July 30, 2016, in accordance with 10 CFR 50.72(b)(2)(i), for "The initiation of any nuclear plant shutdown required by the plant's Technical Specifications" and 10 CFR 50.72(b)(3)(ii)(A) for "Any event or condition that results in the condition of the nuclear power plant including its principle safety barriers, being seriously degraded." While in Mode 5, the controlled bleed-off piping associated with the RCP seal for 2-RC-P-1C was replaced. The health and safety of the public were not affected by this event.|
|05000338/LER-2016-002||5 May 2016||North Anna|
On March 9, 2016, at approximately 1034 hours, with Unit 1 at 100 percent power in Mode 1 and Unit 2 at 0 percent power in Mode 6 for a scheduled refueling outage, 2-QS-MOV-202B failed to stroke open when functionally tested due to excessive unseating thrust. An extent of condition review and engineering evaluation determined that 2-QS-MOV-202A maintained its function. An extent of condition review and engineering evaluation of the Unit 1 valves determined that 1-QS-MOV-102B maintained its function and 1-QS-MOV- 102A did not. Design Changes (DC) (DC NA-16-00023 for Unit 1 and DC NA-16-00021 for Unit 2) were implemented to provide additional valve operating margin prior to returning the valves to service. Based on as- found testing and engineering evaluation, Sodium Hydroxide (NaOH) injection for both units would have been supplied in the event of a Design Basis Accident (DBA) and the safety function of the Chemical Addition System was maintained. The health and safety of the public were not affected by this event.
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|05000338/LER-2016-001||16 March 2016||North Anna|
On January 23, 2016, at approximately 1703 hours, with Units 1 and 2 operating at 100 .
percent power Mode 1, the North Anna 34.5kv Bus 3, offsite power feed to the "C" Reserve Station Service Transformer, was lost due to the opening of the L102 breaker. This resulted in the loss of power to the Unit 1H and Unit 2J emergency buses and the automatic start of the 1H and 2J emergency diesel generators (EDG). The Unit 1H
|05000339/LER-2015-001||2 December 2015||North Anna||On October 7, 2015, at approximately 2147 hours, with Unit 2 operating at 100 percent power Mode 1, a high energy line break (HELB) door between the Unit 1 Turbine Building (TB) and the safety related Unit 2 Emergency Switchgear Room (ESGR) was determined to be slightly open and unlatched. The door was immediately latched closed. Investigation determined the door was unlatched for approximately 46 minutes. On October 8, 2015, at approximately 1647 hours, the Unit 2 ESGR was determined to be outside of the design analysis for a Unit 1 High Energy Line Break. At 1823 hours, an 8-hour Non-Emergency Report was made to the NRC in accordance with 10 CFR 50.72(b)(3)(ii)(B) as an unanalyzed condition and in accordance with 10 CFR 50.72(b)(3)(v)(A) & (D) as a condition that could have prevented the fulfillment of safety functions to shutdown the reactor and maintain it in a safe shutdown condition and mitigate the consequences of an accident. The health and safety of the public were not affected by this event.|
|05000338/LER-2015-002||3 September 2015||North Anna|
On April 2, 2015, at 0426 hours, with Unit 1 operating at 100 percent power, a manual reactor trip was initiated due to the inability to maintain main generator voltage in specification. This also resulted in a turbine trip. The operations crew entered the reactor trip procedure and stabilized Unit 1 in Mode 3 at normal operating pressure and temperature. All control rods fully inserted into the core following the reactor trip. The inability to maintain generator voltage in specification was due to a failure of a component in a firing circuit downstream of the automatic voltage regulator (AVR). The root cause of the event was firing circuit design vulnerabilities in the AVR were not identified during the design change due to lack of rigor. At 0655 hours, a 4-hour Non- Emergency Report was made to the NRC in accordance with 10 CFR 50.72(b)(2)(iv)(B) for "an event causing actuation of the Reactor Protection System when the reactor is critical" and an 8- hour report was also made in accordance with 10 CFR 50.72(b)(3)(iv)(A) for "an event causing actuation of the Auxiliary Feedwater System (AFW)." Two of the AVR gate firing modules (GFMs) were replaced and the third GFM was evaluated to not be required and was disabled.
The health and safety of the public were not affected by this event.
|05000338/LER-2015-001||24 April 2015||North Anna|
On February 26, 2015, at 1511 hours with Unit 1 operating at 96 percent power in an end of cycle coastdown, an automatic reactor trip occurred. The initiating signal was a low-low level on "B" steam generator caused by the closure of the "B" main feedwater regulating valve (MFRV). Closure of the valve was due to a loss of power on the final driver card for "B" MFRV. At 1639 hours, a 4-hour Non-Emergency Report was made to the NRC in accordance with 10 CFR 50.72(b)(2)(iv)(B) for "an event causing actuation of the Reactor Protection System when the reactor is critical" and an 8-hour report was also made in accordance with 10 CFR 50.72(b)(3)(iv)(A) for "an event causing actuation of the Auxiliary Feedwater System (AFW).
Approximately 30 minutes after the reactor trip with AFW flow throttled, the Turbine Driven (TD) AFW pump, 1-FW-P-2, discharge relief valve (RV) lifted and discharged approximately 200 gallons per minute (gpm) to the ground. The RV opened as a result of the inability of the governor valve for the pump to travel an additional 3/16" in the closed direction. An engineering evaluation determined that the loss of emergency condensate storage tank inventory was a condition reportable per 10 CFR 50.73(a)(2)(i)(B) for an "any operation or condition which was prohibited by Technical Specifications." The health and safety of the public were not affected by either event.
|05000338/LER-2014-002||4 February 2015||North Anna||On December 10, 2014, at 1344 hours, two channels of the Unit 1 Refueling Water Storage Tank (RWST) level instrumentation were inadvertently removed from service at the same time during maintenance. Operations personnel responded by entering abnormal procedure 1-AP-3, Loss of Vital Instrumentation. Additionally, Technical Specification (TS) 3.0.3 was entered due to two channels being inoperable that affect Recirculation Spray (RS) pump auto-start logic. Had a Containment Depressurization Actuation (CDA) occurred during this time, accident mitigation may have been impacted. At 1356 hours, both level indications returned to normal. At 1417 hours, Channel II was declared operable and TS 3.0.3 was cleared. At 1439 hours, Channel I was declared operable and TS Actions were cleared. An 8-hour report was made at 1713 hours per 10 CFR 50.72(b)(2)(v)(D) for a condition that could have prevented the fulfillment of a safety function to mitigate the consequences of an accident. The health and safety of the public were not affected by this event.|
|05000339/LER-2014-001||2 April 2014||North Anna|
At 0859 on February 2, 2014, with Unit 2 operating at 100% power, the "A" Math Feedwater (MFW) Pump, 2-FW- P-1A, had a motor lead connection that grounded and caused the power supply breakers for 2-FW-P-1A to trip open. The standby MFW pump, 2-FW-P-1C, auto started, as designed. The Reactor Operator (RO) believed the standby pump did not auto start, since one of the Control Room indicating lights did not illuminate as expected.
The RO believed that only one MFW pump was running with two required for operation greater than 70% power. Based on this indication and the perceived loss of MFW, the RO initiated a manual reactor trip as directed in 2-AP-31. Although the remaining control room team members were aware that the standby pump had auto- started, they were unable to intervene in time to prevent the manual trip. Following the manual reactor trip, the unit was stabilized in Mode 3 at normal reactor coolant temperature and pressure. This event was reportable per 10CFR50.72(b)(2)(iv)(B) for actuation of the reactor protection system. Following the reactor trip, the Auxiliary Feedwater pumps automatically started as designed and provided makeup flow to the steam generators. This event was reportable per 10CFR50.72(b)(3)(iv)(A) for actuation of an Engineered Safety Feature (ESF) system. The health and safety of the public were not affected by this event.
|05000338/LER-2013-003||16 January 2014||North Anna|
On November 21, 2013, at 2006 hours with Units 1 and 2 operating at 100 percent power (Mode 1), Engineering personnel determined that the Casing Cooling tank low level setpoint does not account for vortexing. During a review of the Channel Statistical Allowance (CSA), it was identified that the final Casing Cooling tank level would be below the top of the pump suction nozzle when accounting for the full CSA on the low level bistable and closure time for tank isolation motor operated valves. This condition could have allowed air entrainment and caused a reduction in Recirculation Spray system flow during a Containment Depressurization Actuation.
As a result, the Outside Recirculation Spray (ORS) pumps for both units were declared inoperable and Technical Specification (TS) 3.0.3 was entered for each unit. A prompt report was made to the NRC and an Operability Determination was completed with actions to isolate the Casing Cooling tank on a low level at less than or equal to 10% versus the current setpoint of 4%. This change restored operability of the ORS pumps and TS 3.0.3 was exited at 2217 hours, prior to ramping the units. This event is reportable pursuant to 10CFR50.73(a)(2)(v)(D) for a condition that could have prevented the fulfillment of a safety function. The health and safety of the public were not affected by this event.
|05000339/LER-2014-002||1 January 2014||North Anna|
On September 15, 2014, with Unit 2 defueled, debris that had the potential to be fuel fragments was located on the core plate directly below the B11 core location, where fuel assembly 4Z9 resided during Cycle 23.
Video inspection of fuel assembly 4Z9 identified that the top springs of two fuel pins were dislodged. Due to the fact that the fuel damage exceeded expected conditions, at 1454 on September 15, 2014, this event was reported as an eight hour report as per 10 CFR 50.72(b)(3)(ii)(A), any event or condition that results in the condition of the nuclear plant, including its principle safety barriers, being seriously degraded. Detailed video inspections estimated that 15 fuel pellets were dislodged from fuel assembly 4Z9. During efforts to identify and recover the fuel pellets, 7 fuel pellets worth of material were not found and have already or are expected to granulate into fine particles that will dissolve in low flow areas of the primary plant systems, or be removed by normal purification processes. Since the specific location of the 7 fuel pellets is undesignated and because those pellets contain licensed material in a quantity greater than 10 times the quantity specified in App. C of 10 CFR 20, a report was made at 1227 on September 30, 2014, pursuant to 10 CFR 74.11(a) and to 10 CFR 20.2201(a)(ii). The health and safety of the public were not affected by this event.
|05000338/LER-2013-001||20 December 2013||North Anna|
On September 26, 2013, at 1717 hours with Unit 1 in Mode 6, zero percent power, core alterations began with two inoperable emergency diesel generators. One emergency diesel generator (1J EDG), in a two train system, was out of service for maintenance with the second emergency diesel generator (1H EDG) inoperable, but unknown at the time. A subsequent failure of the 1H EDG during a 24 hour run, parallel to the grid, determined prior inoperability.
Technical Specifications 3.8.2 requires one operable qualified circuit between the offsite transmission network and the onsite Class lE AC electrical power distribution subsystem(s) required by TS 3.8.10 and one OPERABLE EDG. Momentary loss of control power to the Digital Reference Unit (DRU) caused it to reset to the 60 HZ setting which unloaded the EDG. A loose fuse holder caused the momentary loss of control power. This event is reportable per 10 CFR 50.73(a)(2)(i)(B) for a condition prohibited by Technical Specifications. One qualified circuit between the offsite transmission network and the onsite Class lE AC electrical power distribution subsystem(s), required by TS 3.8.10, was OPERABLE and the station blackout EDG was also available. Additionally, had a loss of offsite power occurred, the 1H EDG would have been able to supply power in the isochronous mode to the emergency bus. Therefore, the health and safety of the public were not affected by the event.
|05000338/LER-2013-002||6 December 2013||North Anna|
On October 11, 2013, at 1319 hours with Unit 1 operating at 48 percent power (Mode 1), an automatic turbine trip and subsequent reactor trip occurred due to a lockout relay actuation for the 1C Station Service Transformer (1-EP-SST-1C). The lockout occurred simultaneously with the start of the 1C Condensate Pump (1-CN-P-1C). The direct cause of the 1-EP-SST-1C lockout is that current transformer terminal block shorting screws were left installed inside the 1- EP-BKR-15C2 breaker cubicle. The root cause of the event was less than adequate written instructions for documenting the installation and removal of the terminal block shorting screws.
All safety system responded as expected. The Auxiliary Feedwater Pumps actuated as designed following the reactor trip and provided makeup flow to the Steam Generators. 1-EP- SST-1C was inspected and no signs of damage or abnormal conditions were observed. At 1507 hours, a 4 hour report was made to the NRC in accordance with 10CFR50.72(b)(2)(iv)(B) for a Reactor Protection System (RPS) actuation and a 8 hour report in accordance with 10CFR50.72(b)(3)(iv)(A) for a Auxiliary Feedwater system actuation. The event is reportable pursuant to 10CFR50.73(a)(2)(iv)(A) for a condition that resulted in the automatic actuation of the RPS and AFW Systems. The health and safety of the public were not affected by the event.
|05000339/LER-2013-003||30 August 2013||North Anna|
annunciator, 2G-B5 "Station Service Busses 2A-2B-2C UV Relay Trouble" alarmed and locked in. Troubleshooting indicated that the under voltage (UV) relay monitoring B-C phase for Station Service Bus 2A had actuated. The 2A UV channel was placed into trip on July 3, 2013, per Technical Specification 3.3.1 Condition L, but the 2A under frequency (UF) channel was not placed into trip. On July 3, 2013, a multidiscipline team, including the vendor, determined that the UF relay would remain operable with the degraded voltage. An Operability Determination was developed and approved to document the conclusion. However, on July 10, 2013, it was revealed through additional testing that the operability determination contained inaccurate information and the 2A UF relay would not operate within the required time frame. The 2A UF relay channel was subsequently placed in trip on July 10, 2013. A potential transformer blown fuse was replaced and the UV and UF channels were restored to operable on July 22, 2013.
This event is reportable pursuant to 10CFR50.73(a)(2)(i)(B) for a condition prohibited by Technical Specifications (TS) when the inoperable UF channel was not placed into trip within the time limits of TS. The health and safety of the public were not affected by the event.
|05000338/LER-2012-001||18 May 2012||North Anna||On March 24, 2012, at 1855 hours, with Unit 1 in Mode 6, refueling, two through-wall cracks were identified after machining the Unit 1 S' Steam Generator (SG) Hot Leg Nozzle.DThe defects were identified after machining approximately 0.7" to 1.1" of material from the Nozzle-to- Safe End weld in preparation of full structural weld overlays (FSWOL).DWork was being performed to support Relief Request N1-14-CMP-001 which permitted the application of FSWOL to mitigate the potential for primary water stress corrosion cracking (PWSCC) susceptibility at North Anna Unit 1. The cracking was determined to be caused by PWSCC and confirmed to be fully contained within the Dissimilar Metal (DM) Alloy 600 weld and butter. Subsequently, the S' Steam Generator and associated Reactor Coolant System piping were drained and the through- wall cracks were seal welded under the provisions of Relief Request N1-14-CMP-001.DThis event is reportable per 10 CFR 50.73(a)(2)(ii)(A) for a condition that resulted in the condition of the nuclear power plant, including its principal safety barriers, being seriously degraded.DOn March 25, 2012, at 0144, a non-emergency 8-hour report was made to the NRC Operations Center, in accordance with 10CFR50.72(b)(3)(ii)(A) for the same condition.DThe health and safety of the public were not affected by the event.|
|05000339/LER-2011-001||23 November 2011||North Anna|
On August 23, 2011, at 1440 hours with Units 1 and 2 offline, as a result of the Central Virgirfa earthquake, the Unit 2 "H" (2H) emergency diesel generator (EDG) was manually tripped due to a coolant system leak forty-nine minutes after its demand start due to a loss of offsite power. A Root Cause Evaluation determined the 2H EDG could have developed a coolant leak during its next operation (i.e., post maintenance or periodic testing or a demand start). On September 28, 2011 a completed prior operability evaluation determined the 2H EDG gasket failure resulted in fault exposure unavailable hours totaling 337.6 hours. During the fault exposure unavailable hours, approximately fourteen days, the limiting action of TS 3.8.1.b was entered three times.
Had a demand start of the 2H EDG occurred during any of these times the gasket failure could have occurred resulting in more than one inoperable EDG. This event is reportable pursuant to 10 CFR 50.73(a)(2)(v)(A), 50.73(a)(2)(v)(B), and 50.73(a)(2)(v)(D) for a condition that could have prevented fulfillment of the safety function of a system required to maintain the reactor in a safe shutdown condition, remove residual heat, and mitigate the consequences of an accident.
The event posed no significant safety implications and the health and safety of the public were not affected by the event.
|05000338/LER-2011-001||1 April 2011||North Anna|
On February 3, 2011, at 0345 hours, with Unit 1 at 100 percent power, Mode 1, annunciator 1H-G4, Annunciator System DC Ground was received in the Main Control Room (MCR).
At 0348 hours annunciator 1B-D3, Boric Acid Tank 1B Hi-Lo Level CH I-II was received which, when acknowledged, locked in and annunciator 1H-G4 cleared. While investigating, an acrid smell was noticeable in the MCR. At 0353, upon entry into the annunciator system cabinet room, adjacent to the MCR, the door of the cabinet, 1-EI-CB-21, was opened and flames approximately 2 - 4 inches long were observed coming from an annunciator circuit card. Operations personnel entered fire contingency action procedure 0-FCA-0, Fire Protection - Operations Response. At 0354 hours, a two second discharge of a portable CO2 fire extinguisher put out the fire and a re-flash fire watch was established. At 0437 hours the fire contingency action procedure was exited. This event posed no significant safety implications since the fire was small, extinguished quickly, did not pose an actual threat to the safety of the nuclear power plant and it did not affect equipment required for safe operation of the plant. Therefore, the health and safety of the public were not affected by this event. This event is being reported voluntarily to share information and lessons learned.
|05000339/LER-2010-003||26 July 2010||North Anna|
On May 28, 2010, at 0004 hours North Anna Unit 2 experienced an automatic Reactor trip from 100 percent power following a lightning strike in the switchyard.DAt 0014 to 0027 hours a primary grade make-up to the blender was performed.DSubsequently, it was determined that the surveillance requirement to ensure valves in the affected flow path are secured closed was not performed.DAt 0104 hours the primary grade (PG) supply valve was secured closed.
DHowever, the fifteen minute isolation requirement of Technical Specifications (TS) 3.1.8 was not met.DDue to the high volume of activities associated with the automatic reactor trip and loss of power Operations personnel failed to secure the PG supply valve within the required time.DThis event is reportable pursuant to 10 CFR 50.73(a)(2)(i)(B) for a condition prohibited by TS.DThis event posed no significant safety implications since the dilution flow path was isolated. Therefore, the health and safety of the public were not affected by this event.
|05000339/LER-2008-001||1 April 2008||North Anna|
On February 8, 2008, Unit 2 was in Mode 3, zero percent power, preparing for restart following a planned maintenance outage. At 1759 hours, a rod control urgent failure alarm was received while withdrawing the "A" Shutdown Bank control rods. Rod withdrawal was stopped and it was noted that the Group Step Counters deviated by three steps.A As a result, at 1812 hours a manual reactor trip was initiated by opening the reactor trip breakers in accordance with Technical Requirement 3.1.3. This is a valid actuation of the Reactor Protection System. Four suspect cards were replaced in Power Cabinet 2AC.
Following card replacement the reactor trip breakers were closed.A Shutdown Banks "A" and "B" were fully withdrawn with no concerns. On February 8, 2008, at 1959 hours, a non- emergency 8-hour report was made in accordance with 10 CFR 50.72(b)(3)(iv)(A) due to actuation of the Reactor Protection System. This event is reportable pursuant to 10 CFR 50.73A (a)(2)(iv)(A) for aA condition thatA resulted inAA manualA actuationA of theA Reactor Protection System. This event posed no significant safety implications because the reactor was subcritical when the reactor trip breakers were opened. Compliance with all Technical Requirements was maintained. Therefore, the health and safety of the public were not affected by this event.
|05000339/LER-2007-001||27 April 2007||North Anna|
On February 27, 2007, at 1620 hours, with North Anna Unit 2 operating at 100% power (Mode 1), Unit 2 Safeguards exhaust bypass dampers 2-HV-AOD-228-1 and 2-HV-AOD-228-2 were found to have leak-by during the performance of Periodic Test (PT) 0-PT-77.14A, Emergency Core Cooling System (ECCS) Pump Room Exhaust Air Cleanup System (PREACS) Train A Filter In-Place Test (1-HV-FL-3A). This condition rendered both trains of Safeguards exhaust inoperable. This placed Unit 2 in Technical Specification (TS) Limiting Condition of Operation (LCO) 3.0.3. Operations personnel began a unit ramp-down at 1947 hours and a 4-hour Non- Emergency Report was made to the NRC at 2215 hours, in accordance with 10 CFR 50.72(b)(2)(i), for the initiation of any nuclear plant shutdown required by the plant's Technical Specifications. At 2220 hours, with Unit 2 at 32% power, the TS action was cleared after installation of a temporary modification that restored the system to OPERABLE. The cause of the event was improper linkage adjustment and actuator preload that resulted in less than full damper closure.) This event is reportable pursuant to 10 CFR 50.73(a)(2)(i)(B), 10 CFR 50.73(a)(2)(v)(C), and 10 CFR 50.73 (a)(2)(vii). No significant safety implications existed because the ECCS PREACS ventilation filters were not called upon to perform their safety function and the unfiltered ECCS leakage limit was not being challenged.
|05000338/LER-2005-001||29 November 2005||North Anna|
On October 3, 2005, with Unit 2 in Mode 5 for a scheduled refueling outage it was determined that all required actions for Low Temperature Overpressure Protection (LTOP) System controls were not implemented. A second independent means to prevent more than one low head safety injection (LHSI) pump and charging pump from being capable of injecting into the Reactor Coolant System (RCS) was not being performed. The procedures controlling the LHSI and charging pumps operations only required the pumps to be placed in pull to lock.
The Technical Specifications (TS) Bases states two independent means are required to prevent a pump start such that a single failure or single action will not result in an injection to the RCS. This condition was applicable to Units 1 and 2. This event is reportable pursuant to 10 CFR 50.73 (a)(2)(i)(A) for a condition prohibited by the TS. This event posed no significant safety implications since the LTOP System design basis pressure and temperature limit curve were never violated. Therefore, the health and safety of the public were not affected by this event.