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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).

05000272/LER-2017-001Salem9 November 2017
8 January 2018
Containment Integrity Inoperable for Longer than Allowed by Technical Specifications
LER 17-001-00 for Salem Generating Station, Unit 1 Regarding Containment Integrity Inoperable for Longer than Allowed by Technical Specifications

On November 9, 2017 at approximately 2300, Salem Unit 1 was operating in MODE 3 when operators found steam leaking into the mechanical penetration area outside containment. Operators entered S1.0P-AB.STM-0001, Excessive Steam Flow, and dispatched operators to locate and isolate the leak.

Operators determined the steam was from the 14 steam generator through normally closed valves 14GB47 and 14GB48 steam generator blowdown (WI) line nitrogen supply valves. The steam leak was isolated at 2314 when operators closed normally open manual valve 14GB3.

This report is made per 10CFR50.73(a)(2)(i)(B), Any operation or condition which was prohibited by the plants Technical Specifications.

This was caused by human performance. Procedures will be revised to assure containment integrity exceptions are tracked and open valves are closed while sampling during the sparging process.

NRC FORM 3116 (04-20171

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)

05000395/LER-2017-005Summer22 December 2017
7 January 2017
LER 17-005-00 for V.C Summer, Unit 1, Regarding Automatic Reactor Trip Due to Main Turbine Trip
AUTOMATIC REACTOR TRIP DUE TO MAIN TURBINE TRIP

At 1957 on November 07, 2017, VCSNS Unit 1 was operating. in Mode 1 at 100% reactor power when a turb'ne trip caused an automatic reactor trip. All systems responded as expected, with the exception of 'B' Steani Generator Feedwater Isolation Valve (FW1V) XVG1611B-FW. This valve did not appear to automatically close and was slow to indicate closed from the Main Control Board, however this did not complicate the response. All Control Rods fully inserted and all Emergency Feedwater (Mk') pumps started as required. The Operating crew stabilized the plant, which remained in Mode 3 with decay heat removal via the Steam Dump system to the Main Condenser.

The cause of the turbine trip has been determined to be a loss of Digital Control System (DCS) power to all three Main Feedwater Pumps (FWP), which was caused by the failure of Non-Safety Related Inverter XIT5905.

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.

05000364/LER-2017-002Farley19 December 2017Main Steam Safety Valve Lift Pressure Outside of Technical Specifications Limits
LER 17-002-00 for Joseph M. Farley, Unit 2, Regarding Main Steam Safety Valve Lift Pressure Outside of Technical Specifications Limits

On November 1, 2017, while in Mode 6 and at 0% power level, one of the C Loop Main Steam Safety Valves (MSSV) as-found lift pressure did not meet the acceptance criteria of +/- 3% of the setpoint (1129 psig) as required by Technical Specifications (TS) Surveillance Requirement (SR) 3.7.1.1. The MSSV lifted at 1171 psig which is 9 psig outside of its acceptance range of 1096 to 1162 psig and 3.72°o above its setpoint. The apparent cause of exceeding the MSSV upper acceptance limit is degradation of the valve spring and/or valve spindle compression screw. The as-found settings remained within analytical bounds; therefore, operation of the facility in this condition had no impact on the health and safety of the public.

TS Limiting Condition for Operation (LCO) 3.7.1, IvISSVs, requires five MSSVs per steam generator to be operable in Modes 1, 2, and 3. Since the failure affected the lift pressure over a period of time, it is assumed that the C Loop MSSV was inoperable for a time greater than allowed by TS. Therefore, this occurrence is considered reportable per 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TS.

The C Loop MSSV was replaced on November 5, 2017, while in Mode 5.

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.

05000251/LER-2017-001Turkey Point10 September 2017
7 November 2017
Manual Reactor Trip Due to Lowering Steam Generator Level Caused by Loss of Flow Regulating Valve Positioner Control
LER 17-001-00 for Turkey Point, Unit 4, Regarding Manual Reactor Trip Due to Lowering Steam Generator Level Caused by Loss of Flow Regulating Valve Positioner Control

On September 10, 2017 at approximately 1855 hours, the Turkey Point Unit 4 reactor was manually tripped from 88% power due to lowering level in Steam Generator (SG) C. The reactor was stabilized in Mode 3.

Auxiliary Feed Water actuated as expected on low level in SG C and was secured at approximately 1933 hours. At the time of the event, the Turkey Point site was experiencing high winds with rain associated with Hurricane Irma. The B and C Main Feedwater Regulating Valves (MFRV) had been in manual control when the C MFRV failed closed. The cause of the event was a degraded signal due to water intrusion into the C MFRV valve positioner hand selector switch enclosure resulting from a less than adequate design and installation. Corrective actions include modifications to the Unit 3 and 4 MFRV hand selector switch enclosures and enclosure penetrations, and repair of a failed component associated with the 4C MFRV. Additionally, the terminal/pull box specifications will be revised to improve direction for installation activities. Safety significance is very low because the unit responded as designed to the trip.

05000482/LER-2017-003Wolf Creek7 September 2017
2 November 2017
ARV and MSSV Tornado Missile Vulnerabilities Result in Unanalyzed Condition
LER 17-003-00 for Wolf Creek Generating Station Regarding ARV and MSSV Tornado Missile Vulnerabilities Result in Unanalyzed Condition

On September 7, 2017, Wolf Creek Generating Station (WCGS) was in Mode 1 at 100 percent power. During evaluation of protection for safety-related equipment from the damaging effects of tornados, WCGS personnel determined that the non safety-related exhaust lines from safety-related atmospheric relief valves (ARVs) and main steam safety valves (MSSVs) could be crimped by tornado generated missiles. If these are crimped completely, these components may be unable to perform their safety functions. The ARVs and MSSVs were declared inoperable and Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado- Generated Missile Protection Noncompliance," Revision 1 was applied. Immediate compensatory measures consistent with EGM 15-002 were implemented within the time allowed by the applicable Technical Specification Limiting Condition(s) for Operation. The ARVs and MSSVs were subsequently declared operable but nonconforming. These tornado missile vulnerabilities existed since the original plant construction. Actions will be taken to establish compliance for these components either by a plant modification or employing a methodology for addressing tornado missile non-conformances.

On April 5, 2017, WCGS personnel provided a 10 CFR 50.72 notification in Event Notification (EN) 52666 concerning tornado missile protection issues known at that time. As stated in EGM 15-002, the NRC will exercise enforcement discretion for subsequent tornado missile 10 CFR 50.72 notifications. Therefore, no 10 CFR 50.72 notification was made for this condition.

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.

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.

05000323/LER-2017-001Diablo Canyon3 October 2017Relief Valve Leakage Resulting in Inoperable Pressurizer Power Operated Relief Valve
LER 17-001-00 for Diablo Canyon, Unit 2, Regarding Relief Valve Leakage Resulting in Inoperable Pressurizer Power Operated Relief Valve

During an investigation of a nitrogen leak inside the Unit 2 containment, Nitrogen Accumulator Relief Valve (RV) RV-355 was found to be leaking. The leak caused the pressure in the back up nitrogen accumulator supply to Power Operated Relief Valve (PORV) PCV-455C to decrease to a level that made the PORV inoperable. Based on a review of the ti-end data for nitrogen usage in the containment, it is conservatively assumed that RV-355 had been degraded since December 1, 2016, rendering the PORV inoperable for longer than permitted by Technical Specifications.

The presumptive cause was inadequate instructions provided in plant procedures for placing a new nitrogen bottle in service. These instructions did not provide a sequence that assures system pressure transients are mitigated. This may have caused excessive pressure excursions resulting in multiple lifts of RV-355 which resulted in damage to the RV 0-ring seat and a nitrogen leak path.

Corrective actions include replacing RV-355 and revising procedures to provide instructions on placing nitrogen supply bottles in service to maintain back pressure and minimize pressure transients on the nitrogen system.

This event did not affect the health and safety of the public.

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
Branch (T-5 F53), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by
Internet e-mall to Infocollects.Resource@nrc.gov, and to the Desk Officer, Office of Information and
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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.

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)

05000395/LER-2017-002Summer29 June 2017
25 August 2017
Low Feedwater Flow to the 'B' Steam Generator Causes Automatic Reactor Trip
LER 17-002-00 for V.C. Summer, Unit 1, Regarding Low Feedwater Flow to the 'B' Steam Generator Causes Automatic Reactor Trip

1.0 ABSTRACT On June 29, 2017 at 0857. VCSNS Unit 1 automatically tripped due to low Feedwater (FW) flow to the 'B' Steam Generator (SG). The trip was the result of a spurious closure of the Main FW to 'B' Steam Generator Flow Control Valve, IFV00488-FW. The Flow Control Valve's closure resulted in low SG level coincident with the low FW now, which caused an automatic reactor trip. The plant trip response was normal.

The cause of this event was determined to be the inadvertent closure of IFV00488-1'W due to solenoid valve failure. The solenoid valve failure appears to be a result of an inadequate solder applied to the solenoid coil during the manufacturing process.

NIRO FORM 366 (04 2017)

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.

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).

05000395/LER-2017-001Vc Summer.- Unit 1
Summer
7 April 2017
24 July 2017
C MAIN FFFDWATER PUMP FAILURE '1'0 TRIP RESUI,TS IN LOSS OF EMERGENCY FE,EDWATER AUTO START ACTUATION SIGNAL
LER 17-001-00 for V.C. Summer, Unit 1, Regarding C Main Feedwater Failure to Trip Results in Loss of Emergency Feedwater Auto Start Actuation Signal

On June 16, 2017, the station completed a past operability review and determined that an IsAnergency Feedwater Auto Start Actuation Signal was inoperable from November 12. 2016 until April 7. 2017. Technical Specification (TS) 3.3.2 Limiting Conditions for Operation (J,C.0) was entered due to having less than the minimum number of channels operable for Motor Driven Emergency Feedwater Pump (NIDE:MVP) actuation per TS Table 3.3-3 Functional IJnit 6.g.

'Ibis event was caused by the Low Pressure (LP) and High Pressure (HP) steam inlet valves not closing because the Secondary Operating Cylinder and associated Pilot Valve were corroded. Water intrusion into the 'C' Main Feedwater Punip (MFP) oil system had caused the corrosion of the carbon steel components within '1.1)P0022C such that the Secondary Operating Cylinder and Pilot Valve were not functional.

This condition is reportable under 10CFR50.73(a.)(2)(i)(B), an operation or condition which was prohibited by the plant's Technical Specifications.

05000443/LER-2017-001Seabrook27 June 2017Manual Reactor Trip in Response to a Feedwater Isolation due to High Level in Steam Generator '13'
LER 17-001-00 for Seabrook Station Regarding Manual Reactor Trip in Response to a Feedwater Isolation due to High Level in Steam Generator 'B'

On April 29. 2017 at 18:44. the Reactor was manually tripped by the operators at approximately 12% power in response to a feedwater isolation caused by I ugh Steam Generator (SG) Level on the 'B' SG. The feedwater isolation signal P-14 was automaticall) actuated at 18:43 when the 'B' SG level reached the setpoint 0 r 90.8?..o narrow ranue level. The plant was being started up following the major work perlbrmed for Refueling Outage 18. No adverse consequences resulted from this event.

Post-trip investigation revealed that FW-LT-502-V 1 L (the Variable leg pressure isolation for FW-LT-502) had not been restored to the required open position during routine instrument line filling and venting. On April 26. 2017. l&C' performed hacklilline of the reference legs on multiple steam generator level channels. including FW-1.T-502. the '13' SG wide range level instrument.

1:W-LT-502- VII. not being restored to the open position caused the 'B' SG wide range indication to respond slowly to level changes resulting in overfeeding the 'B' steam generator. The cause of the event was determined to be failure of the l&C technician to properly implement maintenance fundamentals during the performance of restoration of FW-LT-502. Individual perlbrmance was corrected. A contributing cause was determined to be improper characterization or SG level hack fill activity as skill-of-the-craft. Planned corrective actions include development of a maintenance procedure to provide specific step-by-step instructions.

05000313/LER-2017-001Arkansas Nuclear
Arkansas Nuclear One – Unit 1
26 June 2017
26 April 2017
Automatic Start of an Emergency Diesel Generator Due to the Loss of Offsite Power due to Severe Weather
LER 17-001-00 for Arkansas Nuclear One, Unit 1, Regarding Automatic Start of an Emergency Diesel Generator Due to the Loss of Offsite Power due to Severe Weather

On April 26, 2017, Arkansas Nuclear One, Unit 1 (ANO-1), was operating normally at 100% rated thermal power.

The 500kV transmission line to the substation at Pleasant Hill, Arkansas was out of service for planned maintenance.

The area around the plant was experiencing severe weather from thunderstorms and tornado warnings had been issued from the National Weather Service for the four county area.

At approximately 1002 CST switchyard breakers for 500kV lines opened on fault current. High winds had damaged the transmission towers approximately 16 miles away from ANO and caused phase to ground faults. This resulted in a loss of all offsite power lines to the 500kV bus. The autotransformer also locked out as designed when the 500kV transmission lines faulted.

The Reactor Operator initiated a manual reactor trip about 8 seconds after the 500kV lines tripped and prior to the reactor protection system initiating an automatic trip. During this time both emergency diesel generators (EDGs) (EK) started as expected. EDG #2 re-energized one Engineered Safeguards bus. EDG #1 ran unloaded until shutdown.

The plant was stabilized in Mode 3 with Emergency Feedwater (EFW) pumps supplying the steam generators, maintaining the water level at the natural circulation setpoint.

05000348/LER-2016-007Farley17 November 2016
7 June 2017
Plant Shutdown Required by Technical Specifications due to Inoperable Steam Flow Transmitters
LER 16-007-01 for Joseph M. Farley, Unit 1, Regarding Plant Shutdown Required by Technical Specifications due to Inoperable Steam Flow Transmitters

On 11/17/2016 at 1859 with Unit 1 in Mode 1 at 99 percent power, the plant initiated a shutdown in accordance with Limiting Condition for Operation (LCO) 3.0.3 for having no operable steam flow channels for the C Steam Generator (SG). The two steam flow channels did not meet acceptance criteria for Technical Specification (TS) 3.3.2. The shutdown was completed and the plant entered Mode 3 as required by LCO 3.0.3. This is reportable as a plant shutdown required by Technical Specifications in accordance with 10 CFR 50.73(a)(2)(i)(A). This is also reportable as an event or condition that could have prevented fulfillment of a Safety Function needed to mitigate the consequences of an accident, in accordance with 10 CFR 50.73(a)(2)(v)(D).

This condition was discovered during an engineering verification of beginning of cycle full power scaling values for steam flow normalization. New scaling data was calculated and the channels were rescaled and restored to operable status. The cause of this event has not yet been determined. A supplemental LER will be submitted upon the completion of the causal analysis, and the cause and corrective actions will be provided at that time.

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.

05000250/LER-2017-001Turkey Point16 May 2017
18 March 2017
LER 17-001-00 for Turkey Point, Unit 3, Regarding Loss of 3A 4kV Vital Bus Results in Reactor Trip, Safety System Actuations, and Loss of Safety Injection Function
Loss of 3A 4kV Vital Bus Results in Reactor Trip, Safety System Actuations and Loss of Safety Injection Function
On March 18, 2017 at approximately 1107 hours, the Turkey Point Unit 3 reactor tripped from 100% power as a result of an electrical fault on the 3A 4kV vital bus. The Auxiliary Feed Water System actuated as expected, and the 3A Emergency Diesel Generator started but did not load, as designed, due to the lockout of the 3A 4kV bus. The 3A 4kV bus remained de-energized and the reactor was stabilized in Mode 3. Both Unit 4 High Head Safety Injection (HHSI) pumps were out of service for maintenance. The 3A HHSI pump was unable to be powered from the 3A 4kV bus resulting in a loss of the Safety Injection safety function for approximately 2.5 hours on both Units 3 and 4. The safety function is achieved by operation of two of the four pumps which are shared by both units. The loss of the 3A 4kV bus was caused by an electrical fault created by a conductive foreign material that had entered the current-limiting reactor cubicle that bridged an air gap between an uninsulated bus bar and the cubicle wall. The foreign material was a carbon fiber mesh used to reinforce a Thermo-Lag installation taking place in the 3A 4kV switchgear room. Corrective actions include: 1) The Thermo-Lag installation procedure will be revised to incorporate additional precautions for handling Thermo-Lag materials, and 2) the Engineering product risk and consequence assessment process will be revised to ensure a review is conducted of Safety Data Sheets for material being considered in the design. This event had no effect on the health and safety of the public.
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.

05000382/LER-2017-001Waterford8 March 2017
4 May 2017
1 of 5
LER 17-001-00 for Waterford, Unit 3 Regarding Both Trains of Emergency Core Cooling System Inoperable due to Inadvertently Performing Maintenance on Train 'B' Resulting in Event or Condition that Could Have Prevented Fulfillment of a Safety Function

On March 8, 2017, at 1627 CST, it was identified that Low Pressure Safety Injection (LPSI) train ‘B' was inoperable due to SI-135B, Reactor Coolant Loop 1 Shutdown Cooling Warmup Valve, being found open, which is not the required position. At the time of discovery, LPSI train ‘A' was inoperable for maintenance and the station was in compliance with Technical Specification (TS) 3.5.2 action ‘a' which requires that an inoperable LPSI train be restored within 7 days. The shift operating crew entered TS 3.5.2 action ‘c' due to both trains of the Emergency Core Cooling System being inoperable. Action ‘c' requires that with both LPSI trains inoperable, at least one train must be restored within one hour.

SI-135B was subsequently closed and tested to verify operability. TS 3.5.2 action 'c' was exited at 1705. The station remained in compliance with TS 3.5.2 action ‘a'.

It was determined that the SI-135B valve was opened inadvertently. It was planned to perform work on SI-135A, Reactor Coolant Loop 2 Shutdown Cooling Warmup Valve. The workers incorrectly began work on SI-135B and manually opened the valve. This was caused by personnel not performing proper component verification to validate that they were on the correct component, contrary to station procedures. Corrective actions are being performed to improve station work practices related to component verification.

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.

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).