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 SiteStart dateTitleDescription
05000446/LER-2017-003Comanche Peak Nuclear Power Plant, Unit 2
Comanche Peak
25 November 2017
22 January 2018
Manual Reactor Trip due to trip of both Main Feedwater Pumps
LER 17-003-00 for Comanche Peak, Unit 2, Regarding Manual Reactor Trip Due to Trip of Both Main Feedwater Pumps

On November 25, 2017 Comanche Peak, Unit 2 received alarms indicating a trip of both main feedwater pumps. After confirming a decreasing water level in all four steam generators, the control room initiated a manual reactor trip. All safety systems responded as designed including the automatic start of the auxiliary feedwater system. The cause of the trip of both main feedwater pumps could not be positively identified. Causal analysis indicates that a prior plant modification maintained power to abandoned relays in the Solid State Protection System that may have caused both main feedwater pumps to trip. Subsequent actions were taken to remove the fuses that provided power to the abandoned relays on both Unit 1 and Unit 2 to eliminate recurrence from this possible source. Additional corrective actions have been entered into the Comanche Peak Corrective Action Program.

All times below are in Central Standard Time (CST).

05000334/LER-2017-003Beaver Valley4 January 2018
7 November 2017
Beaver Valley Power Station Unit 1 Reactor Trip due to Turbine Trip and Automatic Initiation of the Auxiliary Feedwater System
LER 17-003-00 for Beaver Valley, Unit 1, Regarding Reactor Trip due to Turbine Trip and Automatic Initiation of the Auxiliary Feedwater System

On November 7, 2017 at 05:04 EST Beaver Valley Power Station (BVPS) Unit 1 experienced an automatic Reactor Trip from 100 percent power due to an automatic Turbine Trip. The Turbine Trip was initiated by a Main Unit Generator Overcurrent Protection Trip.

The Reactor Trip was without complications. All control rods fully inserted into the core. The Auxiliary Feedwater System automatically actuated as expected and performed as designed. The plant was stabilized in Mode 3 with the normal Main Feedwater System in service and the Auxiliary Feedwater System properly secured.

The Main Unit Generator trip was caused by foreign material in the isophase bus duct. The isophase bus ducts have been properly inspected and cleared of all foreign material.

This event was reported (EN 53056) as an actuation of the Reactor Protection system 10 CFR 50.72(b)(2)(iv)(B) and a Specified System Actuation (Auxiliary Feedwater System) 10 CFR 50.72(b)(3)(iv)(A).

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) as a condition that resulted in the automatic actuation of the Reactor Protection System (RPS) and the expected automatic actuation of the Auxiliary Feedwater System.

05000364/LER-2017-004Joseph M. Farley Nuclear Plant. Unit 2
Farley
22 December 2017I OF 3
LER 17-004-00 for Joseph M. Farley Nuclear Plant, Unit 2 Regarding Turbine-Driven Auxiliary Feedwater Pump Steam Admission Valve Air Leak Resulted in a Condition Prohibited by Technical Specifications

On October 31, 2017, while in Mode 6 and at 0% power level, the Turbine-Driven Auxiliary Feedwater (TDAFW) pump B-Train steam admission valve from the 2C Steam Generator failed to meet Technical Specification ('I'S) Surveillance Requirement (SR) 3.7.5,5. This SR requires that the valve's associated air accumulator provide sufficient air to ensure operation of the TDAFW pump during a loss of power or other failure of the normal air supply.

During the performance of a flow scan analysis it was identified that the air-operated actuator piston was leaking by the actuator ' o-ring. Although the steam admission valve would stroke open, the 2-hour acceptance criteria could not be met. It is likely that the steam admission valve was inoperable longer than allowed by the Required Action Statement (7 days) following the spring 2016 refueling outage when it passed its last associated surveillance. Therefore, this condition is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

Corrective actions included actuator repair during the outage and further evaluating the preventive maintenance frequency.

NRC FORM 386 (04.2017)

05000286/LER-2017-004Indian Point3 November 2017
20 December 2017
Reactor Trip Due to Main Generator Loss of Field
LER 17-004-00 for Indian Point Unit 3, Regarding Reactor Trip Due to Main Generator Loss of Field

On November 3, 2017, at 2022 hours, with reactor power at 100 percent, Indian Point Unit 3 experienced an automatic reactor trip on a turbine trip, which was in response to a main generator trip. The main generator trip was initiated by actuation of the Generator Protection System due to a main generator loss of field.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The Auxiliary Feedwater System (AFWS) automatically started as expected on steam generator low level to provide feedwater flow to the steam generators. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the loss of main generator field was a failed Thyristor Firing Module drawer which affected proper operation of the redundant Thyristor Firing Module drawer. The root cause was determined to be that the Automatic Voltage Regulator (AVR) Firing Module power supplies have a latent design vulnerability where shared common output nodes are not isolated after a failure. A plant modification is proposed that will eliminate the condition by electrically isolating the AVR Firing Module power supplies upon failure.

This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on November 3, 2017 under 10 CFR 50.72(b)(2)(iv)(B) and 50.72(b)(3)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System when the reactor is critical and a valid actuation of the AFWS.

05000390/LER-2017-016Watts Bar Nuclear Plant. Unit 120 December 2017System Actuations Due to Opening of Feeder Breaker to the 1 B-B 6.9 kV Shutdown Board

On December 20. 2017, at 1040 Eastern Standard Time (EST), the Watts Bar Nuclear Plant (WBN) 1B-B 6.9kV Shutdown Board (SDBD) normal feeder breaker opened. The loss of voltage to the 1B-B SDBD resulted in the start of the 1 B-B Motor Driven Auxiliary Feedwater (MDAFW) pump. the Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) pump. and the start of all four Emergency Diesel Generators (EDGs). Power was restored to the 1B-B SDBD when it loaded on to its associated EDG. Following initial investigation, the 1B-B SDBD was transferred to its alternate offsite power source at 1217 EST. At 1230 EST. the 1 B-B SDBD alternate feeder breaker opened, with a plant response that was similar to the first loss of power.

Restoration of normal offsite power to the 1B-B SDBD was completed at 1654 EST. This event is being reported as a safety system actuation and as an event or condition that could have prevented fulfillment of a safety function related to containment temperature being outside Technical Specification limits.

Both loss of voltage events to the 1B-B SDBD were caused by poor contact of the B and C phases of the protective relay potential transformer drawer secondary connections which supplies the degraded and loss of voltage relays. The mounting block that houses the secondary pins was able to be trimmed, resulting in an improvement of the secondary connection. The mounting blocks for the secondary connections on SDBDs 1A-A, 2A-A, and 2B-B will be inspected and modified. if required, during future equipment outages. The procedure associated with inspection of the secondary connections will be revised.

NRC FORM He :2-2:- APPROVED BY OMB: NO. 3150-0104 EXPIRES: 03/31/2020 comments regarding burden estimate to the Information Services Branch (T-2 F43). U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov. and to the Desk Officer. Office of Information and Regulatory Affairs, used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000266/LER-2017-002Point Beach13 December 2017
29 October 2017
LER 17-002-00 for Point Beach Nuclear Plant, Unit 1, Regarding Operation or Condition Prohibited by Technical Specifications
Operation or Condition Prohibited by Technica Specifications

On October 29, 2017, Unit 1 entered MODE 3 from MODE 4 without satisfying all of Technical Specification 3.7.5, Auxiliary Feedwater (AFW) Limiting Conditions for Operation (LCO) as required by LCO Applicability 3.0.4 for the Turbine Driven Auxiliary Feedwater (TDAFW) pump system.

LCO Applicability 3.0.4 does not permit entry into a MODE of applicability when an LCO is not met, unless the associated actions to be entered permit continued operation in the MODE for an unlimited time or after performance of an acceptable risk assessment and the appropriate risk management actions have been established. After entering MODE 3, it was discovered that components were not operable, contrary to LCO 3.0.4.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(i)(B), for an operation or condition prohibited by Technical Specifications.

05000346/LER-2017-002Davis Besse13 September 2017
27 November 2017
Auxiliary Feed Water Pump Turbine Bearing Damaged due to Improperly Marked Lubricating Oil Sight Glass
LER 17-002-00 For Davis-Besse Nuclear Power Station, Unit 1, Regarding Auxiliary Feed Water Pump Turbine Bearing Damaged due to Improperly Marked Lubricating Oil Sight Glass

On September 13, 2017, with the Davis-Besse Nuclear Power Station operating at approximately 100 percent power, Auxiliary Feed Water (AFW) Pump Turbine 1 experienced high inboard bearing temperature during performance of quarterly Surveillance Testing. The turbine was tripped, and disassembly revealed damage to the journal bearing. The bearirig was replaced, and following successful post maintenance testing, AFW Train 1 was declared Operable on September 16. The cause of the bearing damage was an improperly marked oil sight glass, which allowed operation with improper bearing lubrication. The improper markings were due to the maintenance work instruction for replacing the sight glass not including dimensions or guidance for setting required operational bands.

On September 26, 2017, it was identified that low inboard bearing oil level had likely existed since completion of the previous quarterly surveillance test on June 21, when an oil sample was taken following testing but the bearing was not refilled due to the improperly marked sight glass. This issue is being reported in accordance with 10 CFR 50.73(a)(2)(v)(B) as a condition that could have prevented the fulfillment of the safety function, and in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications.

05000389/LER-2017-004Saint Lucie26 October 2017Automatic Reactor Trip due to Turbine Control System Malfunction

On October 26, 2017, at 0212 hours with St. Lucie Unit 2 in Mode 1 at 100% power, the reactor automatically tripped due to a loss of load following a failure within the turbine control system. The reactor trip was uncomplicated and all control rod assemblies fully inserted. Following the trip, one of the low power feedwater valves LCV-9005, did not properly maintain steam generator level which resulted in an actuation of the A-train auxiliary feedwater system. During the auxiliary feedwater actuation, one main feedwater isolation valve did not reposition closed as expected, but this did not impact heat removal. The main feedwater system remained available.

The failure within the turbine control system was caused by design deficiencies. Planned corrective actions include modifications to improve protective circuits, the addition of coolers and use of conformal coatings on printed circuit boards in the modules.

The problem with LCV-9005 was due to a latent design error that resulted in the setting of an incorrect stroke length for the control valve. This was corrected by adjusting the stroke length of the valve.

This report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) for system actuations of the reactor protection system and the auxiliary feedwater system.

During this event offsite power remained operable and energized. All other equipment responded to the event as expected per the existing plant conditions; therefore, this event had no impact on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Description On October 26, 2017, at 0212 hours with St. Lucie Unit 2 in Mode 1 at 100% power, the reactor automatically tripped due to a loss of load following a failure within the non-safety related turbine control system (TCS) (EIIS:TG:DCC). Based on initial investigation, it was determined that a TCS malfunction affected multiple testable dump manifold (TDM) solenoids (EIIS:TG:PSV). Ultimately, electro-hydraulic (EH) (EIIS:TG) system pressure was lost (i.e., turbine tripped) after two TDM 1 solenoids spuriously operated concurrently. All high pressure turbine governor and throttle valves (EIIS:TA:XCV) and all low pressure turbine intercept and reheat stop valves (EIIS:TA:SHV) repositioned closed as expected upon loss of EH pressure. The reactor trip was uncomplicated and all control rod assemblies fully inserted.

Following the reactor trip, the 15% bypass feedwater regulating valve, LCV-9005 (EIIS:JB:LCV), did not provide the expected feedwater flow to the 2A Steam Generator (EIIS:JB:SG). This resulted in lowering steam generator level and an actuation of the A train auxiliary feedwater actuation system (AFAS) (EIIS:JC). During the auxiliary feedwater actuation, one main feedwater isolation valve (MFIV) (EIIS:JB:ISV), HCV-09-1A, did not reposition closed as expected, but this did not impact heat removal as the redundant MFIV in series isolated main feedwater. The main feedwater system remained available.

Cause of the Event

The failure within the turbine control system was caused by design deficiencies. The TCS incorporates various features for fault tolerance, including the use of three separate trip circuits for each TDM, the 2 out of 3 hydraulic logic of the TDM design, and redundant datalinks provided for Remote I/O communications. The design is intended to ensure a single failure or malfunction will not result in turbine trip. Replaced modules were retained for analysis. Two sets were sent to the original equipment manufacturer. The third set was sent to an independent lab for forensic analysis. Based on the results of the forensic analyses, this report may be supplemented with additional causal factors as appropriate.

The problem with LCV-9005 was due to a latent design error that resulted in the setting of an incorrect stroke length for the control valve. The stroke length of LCV-9005 has been properly adjusted.

The problem with HCV-09-1A was caused by a failed solenoid, and the solenoid was replaced.

Analysis of the Event

This licensee event report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as “Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B).” This event included automatic actuations of the reactor protection system and the auxiliary feedwater system.

Testable Dump Manifolds The TCS has automatic control and trip devices necessary for operation and protection of the turbine-generator.

An automatic trip is provided to prevent any damage to the turbine-generator. The unit trips upon occurrence of conditions which are potentially hazardous to the turbine-generator or to other associated plant equipment. The TCS uses two headers to provide emergency turbine trip and overspeed protection. The emergency trip header has two testable dump manifolds (TDM 1 and TDM 2) and the overspeed protection header has one testable dump manifold (TDM 3). Each triple redundant electronic emergency trip system uses a TDM to interface with the control oil system. The 2-out-of-3 solenoid logic used to provide a protective trip also provides a means to test the system while on-line.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Reviews of EH pressure data at each TDM showed that TDM 1 solenoid B was momentarily spuriously opening during the night prior to the event, and also that TDM 1 solenoid A and TDM 2 solenoid C had momentarily opened over the same time period. Approximately 30 minutes prior to the trip, TDM1 solenoid B opened and stayed open, putting TDM 1 into a continuous half trip state. The trip occurred after a second solenoid on TDM 1 spuriously opened.

Auxiliary Feedwater Actuation LCV-9005 and LCV-9006 are a pair of non-safety related 15% bypass feedwater regulating valves supplying main feedwater flow to the 2A and 2B SGs respectively with a predetermined set point and flow rate post trip. In 1997, LCV-9005 was replaced with what was intended to be a like for like valve replacement. However, the replacement LCV-9005 had different flow characteristics and a different stroke length that was not properly documented; therefore, not properly setup.

Prior to its replacement in 1997, LCV-9005 had a stroke length of 1.5 inches. The replacement valve had a stroke length of 2 inches. Stroke length is used to set up the control of the valve flow rate characteristics.

Therefore, the new model valve was only opening a percentage of a 1.5 inch stroke length instead of 2 inches.

This resulted in less flow than needed to automatically maintain flow to the steam generator without manual operation. A change in the plant conditions following implementation of a low power feedwater digital controller in 2013 compounded the effect of shortened valve stroke length that became apparent during this plant trip.

The opposite train valve LCV-9006 was determined to be operating with the proper stroke length, and main feedwater was used to feed the 2B Steam Generator post trip.

Safety Significance

The digital signals sent by the TCS to the TDMs during this event were reviewed and determined to be invalid and spurious. The turbine was not damaged or exposed to hazardous conditions during this event.

The auxiliary feedwater system is provided with complete sensor and control instrumentation to enable the system to automatically respond to a loss of steam generator inventory. Due to the incorrect setting of LCV- 9005 and the lowering water level in the 2A steam generator, the AFAS-1 actuation was valid. Once the mismatched 15% bypass feedwater regulating valve was isolated by AFAS-1, water level in the 2A steam generator was restored using auxiliary feedwater. 2B steam generator level was maintained post trip via LCV- 9006 and main feedwater.

During the auxiliary feedwater actuation, one of two MFIVs did not reposition closed as expected. There are two MFIVs in series on each feedwater train (A and B). The 2A train of main feedwater was automatically isolated by at least one MFIV. The Unit 2 UFSAR Table 7.3-12 describes failure modes and effects for the auxiliary feedwater actuation system. This analysis bounds the observation of the event described in this LER.

During this event offsite power remained operable and energized. Loss of turbine load events are bounded in the UFSAR as anticipated operational conditions. All other equipment responded to the event as expected per the existing plant conditions; therefore, this event had no impact on the health and safety of the public.

Corrective Actions

The corrective actions listed below are either completed or are being managed under the Corrective Action Program:

1. The three digital output modules controlling solenoids for TDM 1 were replaced, each consisting of an Electronics Module (EMOD), Personality Module (PMOD) and base assembly.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

2. The digital output module EMOD and PMOD for TDM 2 solenoid C was also replaced, as there was evidence that this solenoid had spuriously opened prior to the event.

3. The removed digital output modules were retained for analysis. Two sets (EMOD/PMOD/Base) from TDM 1 were sent to Emerson. The third set from TDM 1 was sent to an independent lab for forensic analysis.

4. Additional countermeasures measures were taken to further protect the TCS remote I/O cabinets from the environment. This included improving the remote TCS cabinets' environmental protection.

5. Actions are planned to install coolers for TCS cabinets.

6. Actions are planned to replace circuit card components in Remote I/O Cabinets.

7. Actions are planned to implement redundancy and diagnostics modifications to the TCS.

8. The stroke length of LCV-9005 was properly adjusted for a 2-inch stroke.

9. The failed solenoid on HCV-09-1A was replaced.

Failed Components Identified Turbine Control System Digital Output Module - Electronics Module (EMOD) Description: Digital Output 5-60VDC EMOD Manufacturer: Emerson Emerson Style Number: 1C31122G01 EMOD Serial Number: 3611019514 Emerson EMOD Module Revision 10 Turbine Control System Digital Output Module - Personality Module (PMOD) Description: Digital Output PMOD Manufacturer Emerson Emerson Style Number: 1C31125G02 PMOD Serial Number: T104316024 Emerson PMOD Module Revision 06 15% Bypass Feedwater Regulating Valve Manufacturer: Fisher Controls Co Inc. (Emerson) Valve Serial Number: 4” - 52A7148 Main Feedwater Isolation Valve Solenoid Description: valve:solenoid,3-way, 1/8" FNPT conn, carbon steel, 120 VDC,90 psi, normally closed Manufacturer: Parker Hannifin Part Number V5H71970 Cat ID322057-1

Additional Information

None

05000389/LER-2017-003Saint Lucie25 October 2017Improper System Realignment Resulted in Loss of Steam Driven Auxiliary Feedwater Pump Flow Indication

On October 25, 2017, St. Lucie Unit 2 was in Mode 1 operation at 100 percent reactor power when the station discovered that both of the required flow transmitters (indication only) for the 2C steam driven auxiliary feedwater (AFW) pumps had been isolated since October 17, 2017. The transmitters were returned to service and extent of condition walkdowns were completed on the AFW pump flow transmitters for both St. Lucie Units 1 and 2; no other anomalies were noted.

This event was caused by human error because the personnel involved in the AFW flow calibration activities on October 17, 2017 did not adequately perform the system restorative steps in accordance with the governing procedure.

Based on the availability of diverse methods to verify AFW flow delivery to the steam generators, this condition had no effect on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Description On October 25, 2017, St. Lucie Unit 2 was in Mode 1 operation at 100 percent reactor power. Maintenance personnel were troubleshooting indication flow ‘spikes' from FT-09-2C1 (EIIS:BA:FT), the flow transmitter for the 2C steam driven auxiliary feedwater (AFW) pump (EIIS:BA:P) discharge. At 1910 hours, the operators declared the 2C AFW flow transmitter FT-09-2C1 inoperable as maintenance reported that the transmitter was isolated. FT-09-2C1 was promptly un-isolated, filled and vented, and restored to service at approximately 1915 hours. During the extent of condition walkdown, maintenance supervision discovered that flow transmitter FT-09-2C2 was also isolated; it was promptly unisolated, filled and vented, and restored to service at approximately 1925 hours.

By 2128 hours on October 25, 2017, the extent of condition walkdowns were completed for the remaining electric driven AFW pumps for Unit 2 and all AFW pumps for Unit 1; no anomalies were noted.

Cause of the Event

Investigation revealed that the individuals that performed an earlier calibration on October 17, 2017 did not properly perform the restoration lineup in accordance with the governing procedure.

Analysis of the Event

This event was reportable under 10 CR 50.73(a)(2)(i)(B) as any operation or condition that was prohibited by the Technical Specifications (TSs).

The AFW system consists of two electric driven pumps and one steam driven pump. Each electric AFW pump is normally aligned to its respective steam generator (SG) (EIIS:SB:SG), and the steam driven AFW pump can feed either SG.

The 2C steam driven AFW pump is provided with two redundant flow transmitters that are used to provide post- accident AFW flow indication. With both 2C AFW pump flow transmitters isolated, the minimum operable channel requirement of TS Table 3.3-10 was not met. Therefore Unit 2 was in the TS 48-hour completion and 6-hour shutdown action statement per TS 3.3.3.6 (Accident Monitoring Instrumentation) action (b). The 2C AFW pump flow transmitters were isolated on October 17, 2017, when maintenance personnel commenced loop calibrations of the Unit 2 AFW flow loops. When the condition was discovered on October 25, 2017, the 54-hour total completion and shutdown time had already been exceeded.

Safety Significance

The subject flow transmitters perform no automatic accident mitigation or control functions; they are used to monitor plant parameters during and following a design basis accident. From October 17 to October 25, 2017, the operators would not have the ability to directly monitor flow from the 2C AFW pump. However, the operators have sufficient diverse means to verify that AFW flow is getting to the SGs, such as SG level and condensate storage tank level trends as well as monitoring the effectiveness of decay heat removal via RCS temperature indication. Loss of the primary method to directly monitor the 2C AFW pump flow would not prevent successful mitigation of any design bases accident. Therefore, this condition had no effect on the health and safety of the public.

Reported lessons learned are incorporated into the licensing process and fed back to industry.

Send comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

Corrective Actions

1. The flow transmitters were immediately returned to service.

2. An extent of condition walkdown identified no other isolated transmitters in the AFW system.

3. The maintenance personnel involved with the earlier calibration that resulted in isolation of the 2C AFW flow transmitters were disqualified pending remediation.

Failed Components

ID: Flow Transmitter for Auxiliary Feedwater Pump 2C Discharge Tag Nos.: FT-09-2C1, FT-09-2C2 Manufacturer: Rosemount Model: 1153DB5

Additional Information

None.

05000483/LER-2017-002Callaway15 August 2017
13 October 2017
Inadequate Protection from Tornado Missiles Identified Due to Nonconforming Design
LER 17-002-00 for Callaway Plant, Unit 1, Regarding Inadequate Protection from Tornado Missiles Identified Due to Nonconforming Design

On August 15, 2017, Callaway Plant was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, Callaway Plant personnel determined that the minimum-flow recirculation lines for the turbine-driven auxiliary feedwater pump (TDAFP) and both motor-driven auxiliary feedwater pumps (MDAFPs) could be damaged if a postulated tornado-generated missile were to penetrate the condensate storage tank (CST) valve house and strike the lines. In response, Operations declared all three auxiliary feedwater pumps inoperable.

Compensatory measures were implemented consistent with Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance." Upon completion of the initial compensatory measures, the TDAFP and MDAFPs were declared Operable but nonconforming.

Subsequent to the condition identified on August 15, 2017, continued investigation of tornado missile vulnerabilities led to discovery that the exposed steam exhaust stacks for the main steam safety valves and atmospheric steam dump valves, as well as the exposed vents for the diesel generator fuel oil storage and day tanks, were also susceptible to tornado missile damage to the extent that compliance with General Design Criterion 2 is not ensured. Compensatory measures were then promptly implemented for these conditions, as well, in accordance with EGM 15-002 such that the affected systems have been evaluated to be nonconforming but Operable.

It has been determined that the identified noncomformances are an original plant design legacy issue. Long-term resolution for establishing compliance is under development and will be completed within the time frame described in the EGM.

05000390/LER-2017-010Watts Bar17 August 2017
10 October 2017
Actuation of Turbine Driven Auxiliary Feedwater Pump Due to Loss of 6.9kV Shutdown Board
LER 17-010-00 for Watts Bar Nuclear Plant, Unit 1 Regarding Actuation of Turbine Driven Auxiliary Feedwater Pump Due to Loss of 6.9kV Shutdown Board

On August 17, 2017, at 1205 Eastern Daylight Time (EDT), the Watts Bar Nuclear Plant (WBN) lost power to the 1B-B 6.9kV Shutdown Board. The loss of power to this safety related bus resulted in an automatic start of the Unit 1 Turbine Driven Auxiliary Feedwater Pump (TDAFWP). Power to the 1B-B Shutdown Board (SDBD) was restored at 1505 EDT on August 17, 2017.

During the loss of power to the 1B-B SDBD, a reduction in containment and control rod drive mechanism cooling occurred. At 1233 EDT, lower containment average temperature exceeded Technical Specification (TS) limits, and TS 3.6.5 Condition A was entered for containment average air temperature not within limits. Lower containment average temperature was restored to within limits at 1525 EDT on August 17. 2017. This is reportable as a potential loss of safety function.

The cause of this event is mechanical vibration while closing a panel drawer resulting in actuation of protective relays that led to a loss of power.

Clearances will require the relays involved in this event to be isolated during drawer movement to prevent a similar occurrence.

05000446/LER-2017-001Comanche Peak5 October 2017
11 August 2017
LER 17-001-00 for Comanche Peak Nuclear Power Plant Regarding Auxiliary Feedwater System Actuation During Unit 2 Turbine Trip
Auxiliary Feedwater System Actuation During Unit 2 Turbine Trip

At 1124 Central Daylight Time on August 11, 2017, Comanche Peak Nuclear Power Plant (CPNPP) Unit 2 experienced an automatic Auxiliary Feedwater System actuation during a Turbine trip. The plant was stabilized at 3 percent reactor power with the Auxiliary Feedwater System feeding all Steam Generators with all levels within their normal bands. The cause of the Turbine trip was high water level in Steam Generator 2-02 related to the mechanical malfunction of a Steam Generator 2-02 flow control bypass valve. The valve '.

malfunctioned due to a loose locknut on the valve hand wheel. Corrective actions included repair of the Steam Generator 2-02 flow control bypass valve. All times in this report are approximate and Central Daylight Time unless noted otherwise.

05000391/LER-2017-004Watts Bar25 September 2017Manual Reactor Trip Due to Inoperable Rod Position Indication
LER 17-004-00 for Watts Bar Nuclear Plant, Unit 2 Regarding Manual Reactor Trip Due to Inoperable Rod Position Indication

On July 25, 2017, at 0428 Eastern Daylight Time (EDT) Watts Bar Nuclear Plant (WBN) Unit 2 was in Mode 3.

commencing a Reactor Startup. While in the initial phase of withdrawing the first of four Control Banks, the two associated group demand position indicators deviated greater than 2 steps from each other. In accordance with Technical Requirement 3.1.7, Position Indication System, Shutdown, with one or more group demand position indicators inoperable, the reactor trip breakers are to be opened immediately. Operations personnel opened the reactor trip breakers immediately by initiating a manual trip of the Reactor Protection System. The Auxiliary Feedwater system was in service and controlling Steam Generator water levels at the time of the event and did not receive any valid actuation signals. No other system actuations occurred as a result of this reactor trip and all systems operated as designed.

The rod demand indication deviation was determined to be caused by a failed logic card, which was replaced.

05000382/LER-2017-002Waterford Steam Electric Station, Unit 3
Waterford
17 July 2017
18 September 2017
Automatic Reactor Scram due to the Failure of Fast Bus Transfer Relays to Automatically Transfer Station Loads to Off- Site Power on a Main Generator Trip
LER 17-002-00 for Waterford, Unit 3, Regarding Automatic Reactor Scram due to the Failure of Fast Bus Transfer Relays to Automatically Transfer Station Loads to Off-Site Power on a Main Generator Trip

On July 17, 2017, at 1606 CDT, Waterford 3 experienced an automatic reactor scram due to a loss of forced circulation, which was the result of a loss of off-site power to the safety and non-safety electrical busses. Prior to the scram, plant operators manually tripped the main turbine and generator due to overheating of the isophase bus duct due to the failure of a shunt assembly connection in the duct to Main Transformer 'B'. The automatic electrical bus transfer did not occur due to relay failures in the fast dead bus transfer system. Both 'A' and 'B' Emergency Diesel Generators started and loaded as designed to re-energize the 'A' and 'B' safety busses. The loss of off-site power caused a loss of both Main Feedwater pumps, resulting in an automatic actuation of the Emergency Feedwater system.

The Root Cause of this event was the design change procedure used for modifications to the fast dead bus transfer circuitry did not include guidance to detect the susceptibility of the relays to DC coil inductive kick. The faulty relays in the fast bus transfer circuit were replaced prior to plant startup.

An Unusual Event was declared at 1617 CDT due to loss of off-site power to safety buses for >15 minutes.

All required safety-related equipment responded as expected during this event.

05000311/LER-2015-002Salem5 August 2015
7 September 2017
LER 15-002-01 for Salem, Unit 2, Regarding Reactor Trip Due to Loss of 4 kV Non-Vital Group Bus
P.O. Box 236, Hancocks Bridge, NJ 08038-0236
PSEG
Nadea, II,C
OCT 0 2 2015
LR-N15-0205 10 CFR 50.73
U.S. Nuclear Regulatory Commission
ATTN: Document Control Desk
Washington, DC 20555-0001
LER 311/2015-002-00
Salem Nuclear Generating Station Unit 2
Renewed Facility Operating License No. DPR-75
NRC Docket No. 50-311
SUBJECT: Licensee Event Report 311/2015-002-00
In accordance with the requirements of 10 CFR 50.73(a)(2)(iv), PSEG Nuclear LLC is
submitting the enclosed Licensee Event Report (LER) Number 2015-002-00, "Reactor
Trip Due to Loss of 4kV Non-Vital Group Bus."
There are no regulatory commitments contained in this letter.
If you have any questions or require additional information, please contact
Mr. David Lafleur of Salem Regulatory Assurance at 856-339-1754.
Sincerely,
John F. Perry
Site Vice President — alem
Attachment
OCT 0 2 2015
10 CFR 50.73
Page 2
LR-N15-0205
CC
Mr. D. Dorman, Administrator— Region 1, NRC
Mr. T. Wengert, Licensing Project Manager (acting) — Salem, NRC
Mr. P. Finney, USNRC Senior Resident Inspector, Salem (X24)
Mr. P. Mulligan, Manager IV, NJBNE
Mr. R. Braun, President and Chief Nuclear Officer — Nuclear
Mr. T. Cachaza, Salem Commitment Tracking Coordinator
Mr. L. Marabella, Corporate Commitment Tracking Coordinator
Mr. D. Lafleur, Salem Regulatory Assurance
NRC FORM 366 U.S. NUCLEAR REGULATORY COMMISSION
01-2014)
t, , .1

'., LICENSEE EVENT REPORT (LER)
'S ree Page 2 or required number of
digits/characters for each block)
APPROVED BY OMB: NO. 3150-0104 EXPIRES: 0113112017
Estimated burden per response to comply with this mandatory collection request: 80 hours.
Reported lessons learned are Incorporated Into the licensing process and fed back to Industry.
Send comments regarding burden estimate to the FOIA, Privacy and Information Collections
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the information collection.
1. FACILITY NAME
Salem Generating Station - Unit 2
2. DOCKET NUMBER
05000311
3. PAGE
1 OF 4
4. TrrLE Reactor Trip Due to Loss of 4 kV Non-Vital Group Bus

On 8/05/15, at 1539, Salem Unit 2 experienced an automatic reactor trip. The cause of the reactor trip was due to a trip of the 21 Reactor Coolant Pump (RCP) causing a 21 Reactor Coolant Loop low flow condition.

The 21 RCP breaker tripped as designed when the 2B Auxiliary Power Transformer (APT) infeed breaker to the 2H 4 kilovolt (kV) Non-Vital Bus opened. The root cause evaluation did not identify a definitive cause.

However the most probable cause of the 2H 4 kV Non-Vital Bus trip was due to a ground fault on the 21 Heater Drain Pump (HDP) motor that was not isolated by its associated neutral overcurrent relay. An automatic start of the Auxiliary Feedwater (AFW) system occurred as expected following the reactor trip due to low steam generator water levels.

Corrective actions include replacement of the 21 HDP motor and its neutral overcurrent relay.

This event is reportable under 10 CFR 50.73 (a)(2)(iv)(A) as an event that resulted in an automatic actuation of the reactor protection system and actuation of the AFW system.

05000311/LER-2016-002Salem4 February 2016
7 September 2017
Automatic Reactor Trip due to Main Turbine Trip
LER 16-002-01 for Salem, Unit 2, Regarding Automatic Reactor Trip Due to Main Turbine Trip

On 2/4/16 at 11:21, Salem Unit 2 automatically tripped from approximately 74% power. Power had been reduced at the beginning of dayshift to support a 500 KV transmission line outage. The reactor trip was due to a Main Turbine trip caused by a Main Generator Protection signal initiated by a main generator automatic voltage regulator (AVR) volts/hertz over excitation protection relay. All emergency core cooling systems and emergency safeguards feature systems functioned as expected. As found calibration data for the generator protection logic relay were found out of specification low. An evaluation determined the cause of the generator protection relay trip was poor manufacturing quality and/or shipping damage to an adjusting rheostat.

This report is being made in accordance with 10 CFR 50.73 (aX2Xiv)(A), "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B)," specifically automatic actuation of the Reactor Protection System and the Auxiliary Feedwater System for this event.

05000446/LER-2017-002Comanche Peak Nuclear Power Plant Unit 21 September 2017Manual Reactor Trip Due to Dropped Rods

On September 1, 2017 CPNPP Unit 2 was manually tripped by Control Room Operators due to two dropped rods. All safety systems responded as designed including the automatic start of the Auxiliary Feedwater System. The proximate cause of the dropped rods was a high resistance condition on a single phase of a three phase fusible knife switch in a Rod Control System Power cabinet. Subsequent third party cause analysis was unable to determine the root cause of the high resistance condition. The defective switch was replaced.

Additional corrective actions to avoid recurrence have been entered into the CPNPP Corrective Action Program.

All times below are in Central Standard Time (CDT).

At time 2140 (CDT) on September 1, 2017, CPNPP Unit 2 experienced two (2) dropped rods, one control, one shutdown. The reactor was then manually tripped. The Auxiliary Feedwater system automatically started as expected.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- Comanche Peak Nuclear Power Plant Unit 2 446

A. REPORTABLE EVENT CLASSIFICATION

The event is reportable under 10 CR 50.73(a)(2)(iv)(A) "Any event or condition that resulted in manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B) of this section." The system which was manually actuated was the Reactor Protection System (RPS). The Auxiliary Feedwater System (AFW) automatically started as designed due to low-low steam generator water level following the trip.

B. PLANT CONDITION PRIOR TO EVENT

At 2140 on September 1, 2017 CPNPP Unit 2 was operating in Mode 1 at approximately 100% rated thermal power.

C. STATUS OF STRUCTURES, SYSTEMS, OR COMPONNETS THAT WERE INOPERABLE AT THE START OF THE

EVENT AND CONTRIBUTED TO THE EVENT

There were no structures, systems, or components which were inoperable prior to the event which contributed to the event. Prior to the actual rod drops, the fusible disconnect switch discussed below was performing its design function.

D. NARRATIVE SUMMARY OF THE EVENT, INCLUDING DATES AND APPROXIMATE TIMES

At time 2140 (CDT) on September 1, 2017, CPNPP Unit 2 experienced two (2) dropped rods, one control, one shutdown.

The reactor was then manually tripped by the control room operators. The time difference between the two rod drops was approximately fifteen (15) to thirty (30) seconds. All safety systems responded as designed.

The initial troubleshooting determined the disconnect switch for the Stationary Coils of Rod Control Power Cabinet 2-2BD caused the rods to drop. Further investigation determined the cause of the rod drops was a high resistance connection on the "A" phase of the Rod Control Power Cabinet 2-2BD stationary coil three-phase fusible disconnect switch (EIIS:(AA) (CAB)(JS)). The switch was replaced and and the reactor started up on September 4.

E. THE METHOD OF DISCOVERY OF EACH COMPONENT OR SYSTEM FAILURE, OR PROCEDURAL PERSONNEL

ERROR

Initial indication of rod drop was provided to the Control room operator by an annunciated alarm. Operators confirmed rod drop through Tavg/Tref alarms and lowering of primary pressure. The reactor was manually tripped approximately one minute after the initial rod dropped (times as indicated by the plant computer).

II. COMPONENTS OR SYSTEM FAILURES

A. CAUSE OF EACH COMPONENT OR SYSTEM FAILURE

A third-party failure analysis identified damage to the "A" phase switch knife blade and its associated receiver clip. The "B" and "C" phase knife blades and clips were undamaged and provided no indication as to the cause of the failure of the "A" phase knife blade and clip. All that could be determined was that the "A" phase switch knife blade and clip experienced heat which resulted in a high resistance connection. That high resistance connection resulted in a voltage drop that was sufficient to cause the stationary coils of two control rods to release their control rods, dropping them into the core.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- Comanche Peak Nuclear Power Plant Unit 2 446

B. FAILURE MODE, MECHANISM, AND EFFECTS OF EACH FAILED COMPONENT

The three-phase fusible disconnect switch is used primarily to provide isolation to equipment requiring three-phase electrical power. The disconnect switch is essentially three manual electrical knife switches mechanically linked to operate in parallel. The knife blades are independently fused and provide continuity to one of the three phases of electrical power to which they are connected. Other than the fuses, the disconnect switch has no automatic functions and is open and shut manually. The disconnect switch associated with Rod Control Power Cabinet 2-2BD is normally shut and is operated solely to provide electrical isolation to the cabinet. The disconnect switch was last operated by CPNPP personnel in support of maintenance on Rod Control Power Cabinet 2-2BD during the April 2017 2RF16 refueling outage.

No maintenance activities were performed on the switch at that time.

The stationary coils associated with Rod Control Power Cabinet are part of the Rod Control System and are normally energized, fail safe (de-energized) to result in rod insertion. In the event described herein, the high resistance condition experienced on the "A" phase of the disconnect switch resulted in a low voltage condition at the stationary coils which resulted in the dropped rods.

The cause of the high resistance and overheating of the disconnect switch could not be determined.

C. SYSTEMS OR SECONDARY FUNCTIONS THAT WERE AFFECTED BY FAILURE OF COMPONENTS WITH

MULTIPLE FUNCTIONS

This event did not involve systems or secondary functions which were affected by the high resistance condition identified with the disconnect switch.

D. FAILED COMPONENT INFORMATION

The failed disconnect switch was style no. 55E-5328 (catalogue no. 2528D 46 E01) provided by Westinghouse.

III. ANALYSIS OF THE EVENT

A. SAFETY SYSTEM RESPONSES THAT OCCURRED

The Reactor Protection System responded as designed to the manual trip input by the plant operators. All plant safety systems responded as designed. Automatic start of the AFW system was the expected response and the system responded as designed.

comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000- Comanche Peak Nuclear Power Plant Unit 2 446

B. DURATION OF SAFETY SYSTEM TRAIN INOPERABILITY

The event reported herein did not involve the inoperability of any safety system component or system.

C. SAFETY CONSEQUENCES AND IMPLICATIONS OF THE EVENT

The Rod Control Power Cabinet 2-2BD three-phase fusible disconnect switch has no nuclear safety function; its purpose is to isolate power during maintenance. The high resistance experienced by this disconnect switch resulted in two control rods being dropped and necessitated a manual reactor trip. The analysis contained in FSAR 15.4.3 bounds the condition experienced: one analysis considers one or more rod control cluster assemblies (RCCAs) dropped with a given group, and a second analysis considers a dropped RCCA bank. Both cases are considered ANS condition II events (transients not accidents).

No automatic safety functions were exercised other than the expected automatic start of the Auxiliary Feedwater System and all plant safety systems responded as designed during the resultant transient. This event had no impact on nuclear safety, reactor safety, radiological safety, environmental safety or the safety of the public.

IV. CAUSE OF THE EVENT

The cause of the event was a high resistance condition associated with the electrical connection on the "A" phase of the Rod Control Power Cabinet 2-2BD stationary coil three-phase fusible disconnect switch.

V. CORRECTIVE ACTIONS

The defective switch was replaced. In accordance with the CPNPP Corrective Action Program, phase-to-phase voltage readings will be taken for the Rod Control power supplies three-phase fusible disconnect switches of both Units. A periodic maintenance activity to measure phase-to-phase voltage readings will also be developed. All proposed activities will be tracked and managed under the CPNPP Corrective Action Program.

VI. PREVIOUS SIMILAR EVENTS

There have been no similar reportable events at CPNPP in the past three years.

05000390/LER-2017-004Watts Bar31 August 2017Manual Reactor Trips Due to Failed Reactor Coolant Pump Power Transfer During Plant Startup
LER 17-004-01 for Watts Bar, Unit 1, Regarding Manual Reactor Trips Due to Failed Reactor Coolant Pump Power Transfer During Plant Startup

On May 2, 2017, at 1945 Eastern Daylight Time (EDT) and on May 4, 2017 at 1710 EDT, Watts Bar Nuclear (WBN) Plant Unit 1 reactor was manually tripped due to a failure of the Reactor Coolant Pump (RCP) Board 1C normal feeder breaker to close during the planned power transfer to unit power following plant startup. Concurrent with each reactor trip, the Auxiliary Feedwater system actuated as designed. All control and shutdown rods fully inserted. All safety systems responded as designed for both events.

For the first event. the cause was incorrectly attributed to a high resistance contact resulting in the normal feeder breaker failing to close. In the investigation following the second event, a relay associated with the RCP Board 1C control circuit was found incorrectly configured due to a human performance issue, which resulted in a standing trip signal on the RCP normal feeder breaker. To prevent recurrence, procedures will be revised to address material control of pretested components.

05000286/LER-2017-003Indian Point Unit 3
Indian Point
30 June 2017
29 August 2017
Condensate Storage Tank Declared Inoperable Per Technical Specification
LER 17-003-00 for Indian Point, Unit 3, Regarding Condensate Storage Tank Declared Inoperable Per Technical Specification

Technical Specification 3.7.6. A pinhole sized through wall leak was discovered on the downstream side of CD-123, the 32 Auxiliary Boiler Feed Pump Bearing Cooling Relief Valve, which was unisolable to the Condensate Storage Tank.

The pinhole leak was identified following the performance of 3PT-Q120B, 32 Auxiliary Boiler Feed Pump Functional Test. All Operability and Acceptance Criteria of 3PT-Q120B were sat. The relief valve was removed from the system and sent to a vendor for evaluation. After the vendor evaluation, it was determined that the valve pinhole area leak was due to a casting defect.

This event was determined to be reportable as a Loss of Safety Function pursuant to10 CFR 50.72(b)(3)(v)(B) - 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 remove residual heat.

RC FORM 366 (04-2017)

05000247/LER-2017-001Indian Point22 August 2017
6 February 2017
Manual Reactor Trip Due to Decreasing Steam Generator Levels Caused By Main Boiler Feedwater Pump Turbine Low Pressure Governor Valves Failed Closed
LER 17-001-00 for Indian Point, Unit 2 Regarding Manual Reactor Trip Due to Decreasing Steam Generator Levels Caused By Main Boiler Feedwater Pump Turbine Low Pressure Governor Valves Failed Closed

On June 26, 2017, Operations commenced a downpower from 100 percent to 93 percent reactor power to support performance of the Main Turbine Stop and Control Valve Test. With reactor power at 94 percent, the 22 Main Boiler Feed Pump Turbine (MBFPT) speed control trouble alarm annunciated coincident with pump speed swings of 800 revolutions per minute (rpm). The operators ceased the downpower and placed the 22 Main Boiler Feedwater Pump (MBFP) in Manual speed control to control the rpm swings. This was unsuccessful, and the rpm swings continued. The 22 MBFPT low pressure (LP) governor valves were observed to be cycling from full-closed to full-open. The decision was made to take local pneumatic control of the 22 MBFP to stabilize pump speed. Two minutes after establishing local pneumatic control, the LP governor valves went to full closed. With the rapid reduction in 22 MBFP speed, the pump was no longer delivering feedwater flow to the SGs. An automatic main turbine runback signal should have been generated on a low speed signal; however, there was no turbine runback actuation. In response, the operators commenced a manual runback to reduce main turbine load, but the decreasing SG levels reached 15 percent, and at 1531 hours a manual reactor trip was initiated.

All control rods fully inserted and all required safety systems functioned properly. The plant was stabilized in hot standby with decay heat being removed by the main condenser. The direct cause of the reactor trip was that the shoulder screws used on the 22 MBFPT LP governor valve servomotor linkage had backed out and detached. This caused the LP governor valves to fail closed, shutting off the turbine steam supply. This event had no effect on the public health and safety. The event was reported to the Nuclear Regulatory Commission (NRC) on June 26, 2017 under 10 CFR 50.72(b)(2)(iv)(B), 50.72(b)(2)(xi), and 50.72(b)(3)(iv)(A).

05000247/LER-2017-002Indian Point6 February 2017
22 August 2017
Auxiliary Feedwater Flow Indication Inoperable for Longer Than the Allowed Technical Specification Completion Time Due to Failure of Complete Restoration Following Calibration
LER 17-002-00 for Indian Point, Unit 2 Regarding Auxiliary Feedwater Flow Indication Inoperable for Longer Than the Allowed Technical Specification Completion Time Due to Failure of Complete Restoration Following Calibration

On March 6, 2017, Instrumentation and Control (I&C) maintenance had a scheduled activity to calibrate the 22 Steam Generator (SG) Auxiliary Feedwater (AFW) flow indicator (FI-1201). The tag-out was applied by Operations at 0748 hours on the two flow transmitter root stop valves. l&C personnel began to calibrate FI-1201 at approximately 1000 hours. The calibration Procedure requires isolation of the high and low isolation valves and opening of the equalizing valve to allow venting of any pressure going to the transmitter. The calibration was performed and all as-found readings were within acceptance range. The test equipment was removed. The transmitter restoration was completed with the exception of filling and venting the transmitter FI-1201 and placing it back in service. Due to the root valves being tagged out, the source of water was isolated preventing proper filling and venting of the transmitter. The l&C supervisor discussed the restoration 'of the transmitter with the Operations shift manager, and it was agreed that Operations would complete restoration of the transmitter when the tag-out was removed. The l&C supervisor noted this and marked NA for the steps to return the transmitter back in service. This is a common practice when performing transmitter calibrations as a part of larger work windows because the tag-out must first be removed for a source of water to be available for restoration. However, the l&C supervisor did not obtain the Shift Manager's initials, which is required by Procedure.

ConSequently, Operations did not restore the transmitter to service, resulting in FI-1201 remaining inoperable for greater than the Technical Specification 3.3.3 allowed completion time of 30 days. It should be noted that in spite of inoperability of FI-1201, since FI-1201 is indication only, there was no actual loss or degradation of water flow to the steam generators at any time and thus had no impact on SG heat removal capability.

05000335/LER-2016-003Saint Lucie21 August 2016
15 August 2017
Generator Lockout Relay Actuation During Power Ascension Results in Reactor Trip
LER 16-003-01 for St. Lucie, Unit 1, Regarding Generator Lockout Relay Actuation During Power Ascension Results in Reactor Trip

On August 21, 2016, during Unit 1 restart following a maintenance outage, an unexpected actuation of the Main Generator Inadvertent Energization Lockout Relay caused the main generator to trip, resulting in an automatic reactor trip. The generator lockout prevented the automatic transfer of station auxiliaries to the available startup transformer power, requiring the emergency diesel generators to start and power the safety related buses.

Reactor coolant pumps normally powered through the non-safety buses were deenergized, and decay heat removal was via natural circulation and Auxiliary Feedwater. The lockout relay actuation was caused by a latent error introduced during a 2013 design modification where a wire was inadvertently removed from the circuit.

Corrective actions included restoration of the affected circuit and implementation of procedure guidance to verify the inadvertent energization relay state and to reset as required following Main Generator manual synchronization.

This licensee event report is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) for system actuations of the reactor protection system, the emergency diesel generators and the auxiliary feedwater system.

This event had no effect on the health and safety of the public.

05000528/LER-2017-001Palo Verde
Palo Verde Nuclear Generating Station Unit 1
14 June 2017
11 April 2017
LER 17-001-00 for Palo Verde Nuclear Generating Station, Unit 1 Regarding Essential Chiller B Inoperable Due to Refrigerant Leak Resulting in Safety System Functional Failure
Essential Chiller B Inoperable Due to Refrigerant Leak Resulting in Safety System Functional Failure

On April 17. 2017, the staff identified a low refrigerant level in the Unit 1 train B essential chilled water (EC) system chiller during inspection. Operations personnel immediately declared EC chiller train B inoperable. On April 17, 2017, the leak was corrected and EC chiller train B was refilled with refrigerant to within the manufacturer's specifications. Operations personnel declared the system operable on April 18, 2017. The chiller had been inoperable since April 11. 2017, when the automatic purge system was placed into service. The direct cause of the low refrigerant level was leakage due to prior installation of a fitting on the automatic purge system filter without a plug.

During the 7-day period that EC chiller train B was inoperable, the supported low pressure safety injection (LPSI) system train B was inoperable. LPSI train A was also inoperable for approximately 17 minutes on April 13, 2017, during the performance of a routine surveillance test. This 17-minute period represented a condition that could have prevented the fulfillment of a safety function.

The cause of the leak was determined to be ineffective work instructions that did not identify the appropriate part number to be used during filter replacement. Corrective actions include revision of the work instructions. This change will ensure that the existing plug remains in place during filter element replacement. A leak test was also added to the work instructions to verify that no refrigerant leaks are present following maintenance.

05000261/LER-2017-001Robinson3 April 2017
1 June 2017
Auxiliary Feedwater System Actuation During Surveillance Testing
LER 17-001-00 for H.B. Robinson, Unit 2, Regarding Auxiliary Feedwater System Actuation During Surveillance Testing

At 2155 hours Eastern Daylight Time on 4/3/2017 with the plant in Mode 3 at zero percent power, H. B. Rob.nson Steam Electric Plant, Unit No. 2 (FIBRSEP2), experienced an actuation of the Auxiliary Feedwater (AFW) System during turbine trip logic surveillance testing.

Subsequent investigation determined that the surveillance test was performed without verifying AFW actuation signals were defeated, as required by the test procedure. During performance of the test the AFW system actuated when the only running main feedwater (MFW) pump was tripped as part of the test. Since the AFW defeat switches were not in the defeat position, the AFW system actuated as designed in response to the tripped MFW pump. Main feedwater was restored and the AFW pumps were secured.

The direct cause of the AFW system actuation was inadequate procedure adherence during turbine trip surveillance testing.

05000255/LER-2017-001Palisades29 March 2017
24 May 2017
Inadequate Protection from Tornado Missiles Identified Due to Nonconforming Design Conditions
LER 17-001-00 for Palisades Nuclear Plant Regarding Inadequate Protection from Tornado Missiles Identified Due to Nonconforming Design Conditions

On March 29, 2017, during an evaluation of protection of Technical Specification (TS) equipment from the damaging effects of tornados, nonconforming conditions were identified in the plant design. Specifically, TS equipment did not meet current design basis for protection against potential tornado missile impact. Identified components/systems were declared inoperable and NRC Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado Generated Missile Protection Noncompliance," was implemented. Initial compensatory measures were implemented, per the guidance of NRC Interim Staff Guidance DSS-ISG-2016-01 Appendix A, within the time allowed by the applicable Limiting Conditions for Operation (LCOs) and the associated systems were then declared operable but nonconforming.

The six systems, containing TS required equipment, did not meet current design basis for protection against potential tornado missile impact. Credible tornado missile impacts could affect the following systems; Service Water, Fuel Oil, Emergency Diesel Generators, Auxiliary Feedwater, Component Cooling Water and Control Room Ventilation Filtration.

Comprehensive compensatory measures will be implemented in approximately 60 days of discovery, per the guidance of NRC Interim Staff Guidance DSS-ISG-2016-01 Appendix A.

Due to the historical nature of the issue, a specific cause for the identified vulnerabilities was not determined.

05000391/LER-2017-003Watts Bar23 March 2017
22 May 2017
Automatic Start of Auxiliary Feedwater System Due to Main Condenser Failure
LER 17-003-00 for Watts Bar, Unit 2, Regarding Automatic Start of Auxiliary Feedwater System Due to Main Condenser Failure

On March 23, 2017, at 0014 Eastern Daylight Time (EDT), Watts Bar Nuclear Plant Unit 2 experienced an unplanned trip condition of both Turbine Driven Main Feed Pumps (TDMFPs) following a loss of Main Condenser Vacuum. The trip of both TDMFPs caused an automatic start of both Motor Driven Auxiliary Feed Water Pumps and the Turbine Driven Auxiliary Feed Water Pump as designed.

The plant was performing a normal startup, and had just synchronized the main generator to the grid. Subsequent to the event, the plant was transitioned to Mode 3 by inserting all control rods with a manual trip. All plant safety systems operated as expected.

The loss of condenser vacuum was the result of a significant breach of the Unit 2 main condenser - B zone. This failure is attributed to the main condenser neck support structural design being inadequate to maintain integrity within specification. Repairs to the condenser will be completed prior to Unit 2 returning to service.

05000391/LER-2017-002Watts Bar20 March 2017
12 May 2017
Manual Reactor Trip as a Result of a Secondary Plant Transient
LER 17-002-00 for Watts Bar, Unit 2, Regarding Manual Reactor Trip as a Result of a Secondary Plant Transient

On March 20, 2017 at 0813 Eastern Daylight Time (EDT), Watts Bar Nuclear Plant (WBN) Unit 2 operations personnel manually tripped the plant from approximately 91 percent power based on lowering steam generator levels. Prior to the plant trip, the 2A Hotwell pump tripped at 0759 EDT and the 2C Condensate Booster Pump subsequently tripped at 0803 EDT. Operations personnel commenced to lower plant power after the 2A Hotwell pump trip in an attempt to maintain steam generator levels, but were unable to recover level and manually tripped the unit.

All control rods fully inserted and all automatically actuated safety related equipment operated as designed. At 0905 EDT, operations personnel exited the emergency operating instructions after the plant was stabilized.

This event resulted when scaffold crews inadvertently depressed the local trip button for the 2A Hotwell pump, which resulted in the secondary system transient. Bump guard covers were subsequently installed on local pushbuttons for selected pumps in the turbine building.

NRC I ORM TEE :36'01 APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/3112018 comments regarding burden estimate to the FOIA, Privacy and Information Collections Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by internet e-mail to NEOB-10202. (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information collection does not display a currently valid OMB control number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000247/LER-2016-002Indian Point7 March 2016
28 February 2017
Automatic Actuation of Emergency Diesel Generators (EDGs) Due to 480 VAC Bus Undervoltage Condition and Loss of Residual Heat Removal (RHR) While in Cold Shutdown
LER 16-002-01 for Indian Point, Unit 2 Regarding Automatic Actuation of Emergency Diesel Generators (EDGs) Due to 480 VAC Bus Undervoltage Condition and Loss of Residual Heat Removal (RHR) While in Cold Shutdown

On March 7, 2016, while performing set-up activities for 2-PT-R084C, "23 EDG 8 Hour Load Test," the normal supply breaker to 480 Volt AC Bus (ED) 3A tripped on overcurrent. This caused 480 Volt AC Buses 3A and 6A to de-energize since, as part of the test set-up activities, the tie breaker (3AT6A) between Buses 3A and 6A was closed and the normal supply breaker for Bus 6A was opened. This resulted in a loss of both 21 and 22 Residual Heat Removal (RHR) (BP) pumps. As 'designed, all Emergency Diesel Generators (EDGs) (EK) received automatic initiation signals to start. All required 480 Volt AC buses automatically re-energized by design, with the exception of Bus 3A, which had an overcurrent lockout. Operators manually started 22 RHR pump to restore RHR cooling.

However, prior to restoring the normal supply power to Bus 3A, 23 EDG tripped on overcurrent which resulted in a second loss of RIM event. The cause for the Bus 3A supply breaker tripping was inadequate procedural guidance resulting in excessive loads being energized on Buses 3A and 6A. The direct cause for 23 EDG tripping was cracked solder joints on the automatic voltage regulator (AVR). Corrective actions included revising 2-PT-R084C and replacing the voltage regulator. The event had no effect on public health and safety.

05000261/LER-2016-005Robinson8 October 2016
22 February 2017
Reactor Trip and Automatic System Actuation Due to Weather-Related Grid Disturbance
LER 16-005-01 for H. B. Robinson Steam Electric Plant, Unit 2 Regarding Reactor Trip and Automatic System Actuation Due to Weather-Related Grid Disturbance

At 1302 hours Eastern Daylight Time (EDT) on 10 08 2016 with the plant in Mode 1 at 100 percent power, H. B. Robinson Steam Electric Plant, Unit No. 2 (HBRSEP2), experienced a grid perturbation. As a result, HBRSEP2 experienced a reactor trip due to low voltage on the 4kV buses. Plant safety systems responded with the emergency buses separating from offsite power due to emergency bus undervoltage. The emergency diesel generators (EDG) started and powered the 480V emergency buses. 'A' service water pump did not start on the blackout sequencer; however, sufficient service water flow was available from the three operating service water pumps.

This failure did not aggravate this event. The site declared an Unusual Event (UE) at 1317 EDT for loss of power to emergency buses.

At 0011 EDT on 10 09'16, the UE was terminated.

Once the power grid was stable, plant personnel commenced restoration of offsite power to allow shutdown of the the EDGs. During this evolution, at approximately 2323 EDT on 10 . 08 2016, an automatic actuation of the 'B' auxiliary feedwater (AFW) pump occurred due to improper breaker coordination that satisfied the autostart logic for the AFW system.

The apparent cause of the voltage transient in the HBRSEP2 switchyard is a failed fault detection relay, which prevented the grid fault from being immediately isolated. The failed relay has been replaced.

05000455/LER-2016-001Byron12 October 2016
15 February 2017
Manual Reactor Trip due to Circuit Breaker Failure that Caused Actuation of Feedwater Hammer Prevention System with Automatic Isolation of Feedwater to Two Steam Generators and Low Steam Generator Levels
LER 16-001-01 for Byron Station, Unit 2 Regarding Manual Reactor Trip Due to Circuit Breaker Failure that Caused Actuation of Feedwater Hammer Prevention System with Automatic Isolation of Feedwater to Two Steam Generators and Low Steam Generator....

On October 12, 2016 at 1338 hours, Byron Station Operations initiated a manual reactor trip of Unit 2 due to decreasing water levels in the loop B and loop C Steam Generators. A trip of a bus feed breaker resulted in the loss of power feed to multiple normally energized relays associated with the Feedwater (FW) Water Hammer Prevention System (WHPS) circuit, which resulted in automatic closure of related Feedwater Isolation Valves.

The apparent cause of the feed breaker trip was due to a manufacturing defect on the feed breaker amptector circuit board.

The corrective actions planned include revising refurbishment testing requirements for the main feed breaker and performing modifications in subsequent refuel outages to the FW Water Hammer Prevention System to address power supply single point vulnerability.

The Unit 2 Reactor Protection System was actuated by the manual reactor trip and the Auxiliary Feedwater system actuated automatically as expected. This condition is reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A) for any event or condition that resulted in manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B).

05000348/LER-2016-008Farley23 January 2017Manual Reactor Trip Due to Generator Voltage Swings
LER 16-008-00 for Farley, Unit 1, Regarding Manual Reactor Trip Due to Generator Voltage Swings

On 11/26/16 at 2357 while Unit 1 was operating at 100 percent reactor power the main generator began to experience voltage and load swings, which were caused by a problem with the main generator. The unit was manually tripped at 0026 on 11/27/16 to protect the generator from potential damage. All control rods fully inserted and Auxiliary Feedwater (AFW) auto-started as expected. The Turbine Driven AFW (TDAFW) was secured at 0037, with Motor Driven AFW pumps continuing to provide flow to ensure adequate heat sink. The TDAFW auto-started a second time at 0041 on a valid actuation signal when Steam Generator levels decreased to the TDAFW actuation setpoint. The TDAFW system was secured a second time at 0047. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of the reactor protection system and an automatic actuation of the AFW system.

The swings were caused by an intermittent failure of the voltage isolation transducer. The voltage isolation transducer was replaced prior to the plant restarting. The transducer module is being sent off for failure analysis to aid in determination of the cause of this failure.

05000348/LER-2016-006Farley8 November 2016
19 December 2016
Manual Reactor Trip due to Loss of Speed Control on 1A Steam Generator Feed Pump
LER 16-006-00 for Joseph M. Farley Nuclear Plant, Unit 1 Regarding Manual Reactor Trip due to Loss of Speed Control on 1A Steam Generator Feed Pump

On November 8, 2016, Joseph M. Farley Nuclear Plant Unit 1 was reducing power to remove the main generator from service. The 1A steam generator feed pump did not respond to control steam generator levels as expected when the miniflow valve was opened per procedure. Steam generator levels lowered due to lower feed flow, and at 1331 the reactor was manually tripped from 32 percent power to prevent reaching the low steam generator level automatic reactor trip setpoint.

The motor driven auxiliary feed pumps also started automatically, as expected, with the manual reactor trip. The main steam isolation valves were closed to limit the unit cool down, decay heat removal was accomplished with the atmospheric relief valves, and the unit was maintained in mode 3. The controller failure was caused by the speed reference adjust and speed controller (C2) card being out of tolerance due to a failed A2 operational amplifier on the card, which was caused by infant mortality. The C2 card was replaced, and the new card was verified to be within the required tolerance. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to manual actuation of the reactor protection system and automatic actuation of the auxiliary feedwater system.

05000400/LER-2016-004Harris8 October 2016
7 December 2016
Reactor Trip and Safety Injection During Turbine Control Testing at Low Power
LER 16-004-00 for Shearon Harris, Unit 1, Regarding Reactor Trip and Safety Injection During Turbine Control Testing at Low Power

On October 8, 2016, the Shearon Harris Nuclear Power Plant was reducing power to enter a planned refueling outage (RFO-20). The plant was at approximately 8 percent power in Mode 1 when the unit experienced an unplanned reactor trip with a safety injection (SI) and main steam line isolation (MSLI). A malfunction of the turbine controller during turbine mechanical overspeed trip testing caused an excessive draw of steam flow from the Steam Generators (SGs). This caused the Engineering Safety Features Actuation System instruments to detect a valid change in SG pressure and initiate a rate compensated Low Steam Line Pressure signal. This signal initiated a SI and MSLI, which in turn initiated reactor trip, turbine trip, feedwater isolation, and closed the main steam isolation valves.

Degraded equipment within the turbine controller resulted in excessive opening of the governor valves; this was caused by an inadequate supply of hydraulic oil to meet the increased system demand during testing. Insufficient hydraulic accumulator capacity was available to support system demand. One accumulator was known to be out-of-service; a second was discovered post-event. Also, a hydraulic oil pressure switch used for turbine control was not functioning properly. The equipment deficiencies have been corrected.

Changes have been made to the testing procedure to validate at least four accumulators are in service prior to testing. The Power Operation (Mode 2 to Mode 1) procedure will also be revised to validate at least four accumulators are in service. A new calibration procedure will be implemented for the deficient oil pressure switch to ensure better quality control over verifying switch function.

05000400/LER-2016-005Harris8 October 2016
7 December 2016
Offsite Power Undervoltage Caused Actuation of Several Systems
LER 16-005-00 for Shearon Harris Nuclear Power Plant, Unit 1 Regarding Offsite Power Undervoltage Caused Actuation of Several Systems

On October 8, 2016, at approximately 1310 EDT, while in Mode 4 for a planned refueling outage, Shearon Harris Nuclear Power Plant experienced an undervoltage (UV) condition in the switchyard for about 1.5 seconds. This triggered the UV relays for both emergency 6.9 kV buses and for several of the non-nuclear safety 6.9kV auxiliary buses, resulting in the respective supply breakers opening. At the time of the UV, the site was experiencing high winds and rain from the effects of Hurricane Matthew. Both Emergency Diesel Generators started and loaded as designed. Operations restored offsite power at 2154 EDT after verifying stable grid behavior for an extended period. Additionally, the Containment Ventilation Isolation system and the Auxiliary Feedwater system actuated and performed as designed.

The site declared an Unusual Event at 1328 EDT for loss of offsite power to emergency buses for greater than 15 minutes. At 2049 EDT, the Unusual Event was terminated.

The causes of the UV were determined to be a line fault on the Cape Fear - West End 230 kV line and equipment deficiencies associated with the Cape Fear 230 kV Substation protection relays which prevented immediate clearing of the fault.

05000483/LER-2015-001Callaway23 July 2015
2 December 2016
Completion of a Shutdown Required by the Technical Specifications - TS 3.4.13
LER 15-001-01 for Callaway Plant, Unit 1, Regarding Completion of a Shutdown Required by the Technical Specifications - TS 3.4.13

On July 23, 2015, plant operators became aware of indications of an increase in the Reactor Coolant System (RCS) unidentified leak rate. The indications included containment radiation alarms as well as increasing containment humidity and sump levels. An RCS inventory balance indicated an unidentified leak rate of 1.2 gpm leak which is greater than the Technical Specification limit of 1 gpm for unidentified leakage. Actions were taken to determine the source of the leak. A containment entry was made, and a steam cloud was identified to be coming from the Pressurizer Spray Valve cubicle. The plant was shut down in order to comply with requirements of the Technical Specifications.

It was determined that the leak was due to seat leakage through the RCS Pressurizer CVCS Auxiliary Spray Supply Drain valve BBV0400 and then through the non-safety related pipe flange immediately downstream of the valve.

The valve was tightened which reduced the leakage to 60 drops per minute. The flange gasket was replaced. The root cause of the leak was determined to be that valve BBV0400 was not fully closed at normal closing force in RF20. The valve was replaced in April 2016 during Refueling Outage RF21. Additionally, a plant procedure was revised to require that selected valves (including BBV0400) are closed in MODE 3 using normal force or additional force if leakage is identified.

05000281/LER-2016-001Surry9 October 2016
2 December 2016
Unit 2 Reactor Trip due to Generator Differential Lockout
LER 16-001-00 for Surry Power Station, Unit 2, Regarding Reactor Trip Due to Generator Differential Lockout

On October 9, 2016 at 0254 hours, with Unit 1 and Unit 2 at 100 percent power, Unit 2 experienced an automatic reactor trip initiated by a turbine trip due to generator differential lockout relay actuation. At the time of the trip, high wind and heavy rain conditions existed due to the effects of Hurricane Matthew. All three auxiliary feedwater pumps automatically started on low-low steam generator water level as expected. All plant systems functioned as required, and Unit 2 was stabilized at hot shutdown. The trip response was not affected by any previously inoperable systems, structures, or components.

The direct cause of the generator differential lockout was an electrical ground overcurrent initiated by water accumulation in the "A" phase of the "A" station service transformer leads termination enclosure. Affected electrical enclosures were drained, the system was tested, and modifications to the enclosures to prevent recurrence of water intrusion were completed prior to returning Unit 2 to power operation on October 13, 2016.

This report is being submitted pursuant to 10CFR50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of the Reactor Protection System' and the Auxiliary Feedwater System.

05000348/LER-2016-002Farley1 October 2016
30 November 2016
Automatic Reactor Trip and Safety Injection Due to Closure of Main Steam Isolation Valve
LER 16-002-00 for Joseph M. Farley Nuclear Plant, Unit 1 Regarding Automatic Reactor Trip and Safety Injection Due to Closure of Main Steam Isolation Valve

On 10/1/2016 at 0512 CDT with Unit 1 at 99 percent power the plant experienced a turbine trip and automatic reactor trip as a result of inadvertent closure of the 1 A Steam Generator Main Steam Isolation Valve (MSIV).

This caused a rapid pressure reduction in the remaining two Steam Generators' steam lines, resulting in a Safety Injection (SI). The 1 A MSIV closure was caused by failure of its test solenoid in conjunction with other air system leakage, which vented air pressure from the 1A MSIV actuator. An inadequate technical justification allowed the improper deactivation of the preventive maintenance (PM) task of the test solenoid valve in 2004. Decision making by control room personnel not to strictly adhere to an Annunciator Response Procedure was a contributing cause to the reactor trip being automatic versus manual, and led to the SI.

Following the reactor trip and SI the 1 A MSIV test solenoid was replaced and check valves on the 1 A MSIV steam line were tested and replaced. The technical justifications of a sample of previously extended or deleted PMs strategies will be reviewed and corrected. The PM for the Unit 1 solenoid will be reinstated.

Procedure use and adherence standards have been reinforced with Operations personnel, simulator just-in- time training was conducted for all crews, and further causal analysis is planned to investigate operations fundamental performance gaps. This event is reportable per 10 CFR 50.73(a)(2)(iv)(A) due to actuation of the reactor protection system, Emergency Core Cooling System (ECCS) injection into the Reactor Coolant System, and automatic actuation of the AFW system.

05000346/LER-2016-009Davis Besse10 September 2016
9 November 2016
Reactor Trip due to Rainwater Intrusion and Auxiliary Feedwater Actuation on High Steam Generator Level
LER 16-009-00 for Davis-Besse Nuclear Power Station, Unit 1 Regarding Reactor Trip due to Rainwater Intrusion and Auxiliary Feedwater Actuation on High Steam Generator Level

On September 10, 2016, with the Davis-Besse Nuclear Power Station (DBNPS) operating at approximately 100 percent power, rainwater intrusion into the Main Generator Automatic Voltage Regulator (AVR) cabinet due to an open roof vent caused a lockout of the Main Generator, resulting in a trip of the Main Turbine and Reactor. Following the Reactor trip, the Steam Feedwater Rupture Control System (SFRCS) actuated due to high Steam Generator 1 level and initiated the Auxiliary Feedwater System. The most probable cause of the SFRCS actuation was a failed operational amplifier in the Integrated Control System (ICS), causing the ICS to not reduce Feedwater flow to Steam Generator 1 following the Reactor trip. , Completed corrective actions include closing the roof vents, sealing the top of the AVR cabinet, improved configuration control of the vents, and replacement of the failed ICS module. Scheduled corrective actions include presenting a case study to improve recognition of elevated risk issues, and review of the ICS by a multi-functional team to address system performance concerns.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in automatic actuation of the Reactor Protection System, and an automatic actuation of the Auxiliary Feedwater System.