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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).

05000254/LER-2017-004Quad Cities7 November 2017
5 January 2018
Unit 1 HPCI Did Not Trip Due to Wear Debris in the Turbine Stop Valve Oil Resetting Solenoid
LER 17-004-00 For Quad Cities Nuclear Power Station, Unit 1 re: Unit 1 HPCI Did Not Trip Due to Wear Debris in the Turbine Stop Valve Oil Resetting Solenoid

During performance of the High Pressure Coolant Injection (HPCI) Pump Operability Test, the Unit 1 HPCI turbine did not trip when the Remote HPCI Turbine Trip pushbutton was depressed. Operations shut down HPCI by isolating the steam supply valves to trip the HPCI turbine. The Unit 1 HPCI system was declared inoperable, but remained available. The cause was determined to be accumulation of wear debris within the HPCI turbine stop valve oil resetting solenoid valve causing the valve to stick in the energized position. This wear debris was a result of a manufacturing deficiency.

The immediate corrective action was to replace the turbine stop valve oil resetting solenoid valve. Follow-up corrective action is to evaluate the preventative maintenance frequency for the HPCI turbine stop valve oil resetting solenoid valve.

The safety impact of this condition was minimal. The HPCI system was still available to function, despite the issue with the HPCI Turbine Stop Valve oil resetting solenoid. The event is being reported because HPCI is a single train system and the loss of HPCI could potentially impact the plant's ability to mitigate the consequences of an accident.

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.

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.

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.

05000341/LER-2017-005Fermi3 November 2017Non-Functional Mechanical Draft Cooling Tower Fan Brakes Leads to HPCI Being Declared Inoperable and Loss of Safety Function
LER 17-005-00 for Fermi 2 Regarding Non-Functional Mechanical Draft Cooling Tower Fan Brakes Leads to HPCI Being Declared Inoperable and Loss of Safety Function

At 1000 EDT on September 9, 2017, the Division 2 Mechanical Draft Cooling Tower (MDCT) fans were declared inoperable due to loss of output from the over speed fan brake inverter. The MDCT fans are required to support operability of the Ultimate Heat Sink (UHS) and the Emergency Equipment Cooling Water (EECW) system. The Division 2 EECW system cools the High Pressure Coolant Injection (HPCI) system room cooler. As a result, the non-functionality of the fan brakes lead to an unplanned HPCI inoperability.

Since HPCI is a single train system designed to mitigate the consequences of a loss of coolant accident (LOCA), this event could have prevented the fulfillment of a safety function. The cause of the event was the failure of the Division 2 fan brake inverter.

Corrective Actions were taken to replace the inverter and returning the MDCT fans, the UHS, EECW and HPCI to service on September 9, 2017 at 2351 EDT. A failure modes evaluation was performed by the vendor with no direct cause of the failed output determined. The fan brake system is only required for a design basis tornado and there was no credible tornado threat during this event.

The HPCI system is not required to mitigate a design basis tornado. The safety significance of this event is very low and there were no radiological releases associated with this event.

05000220/LER-2017-003Nine Mile Point2 November 2017
6 September 2017
Automatic Reactor Scram due to Reactor Vessel Low Water Level
LER 17-003-00 for Nine Mile Point, Unit 1, Regarding Automatic Reactor Scram due to Reactor Vessel Low Water Level

On September 6, 2017 at 1157, Nine Mile Point Unit 1 experienced an 'automatic reactor scram due to reactor vessel low water level. The automatic Reactor Protection System (RPS) actuation and reactor scram is reportable per 10 CFR 50.72 (b)(2)(iv)(B) and 10 CFR 50.73(a)(2)(iv)(A) as any event or condition that resulted in a manual or automatic actuation of any of the systems listed in 10 CFR 50.73(a)(2)(iv)(B). Following the automatic scram all plant systems responded per design including High Pressure Coolant Injection (HPCI) System automatic initiation.

HPCI is a flow control mode of the normal feedwater systems, and is not an Emergency Core Cooling System.

The root cause of the scram was a failed power supply within the Proportional Amplifier, PAM-ID23E. This power supply failure resulted in the output from the module dropping out causing the #13 Feedwater Pump Flow Control Valve to close. The corrective action taken was the replacement of the failed Feedwater Level Control module, PAM- ID23E.

05000395/LER-2017-003Vc Summer - Unit 1
Summer
28 August 2017
26 October 2017
FAILED LIGHTNING ARRESTER ON MAIN TRANSFORMER CAUSES REACTOR TRIP
LER 17-003-00 For Virgil C. Summer Nuclear Station, Unit 1, Regarding Failed Lightning Arrester On Main Transformer Causes Reactor Trip

On August 28, 2017, at 0837, VCSNS Unit 1 automatically tripped due to a turbine trip. The turbine trip was caused by the Main Generator Differential Lockout due to a fault on the center phase, 230 kV lightning arrester, on the Main Transformer (XTF-1).

The plant trip response was normal. All control rods fully inserted. Balance of Plant (BOP) buses automatically transferred to their alternate power source, Emergency Auxiliary Transformers (XTF-31/32). Both Motor Driven (MD) Emergency Feedwater (EF) pumps and the Turbine Driven EF Pump started as designed.

The cause of this event was the failure of the center phase lightning arrester on XTF-1. The failed arrester, along with the other two lightning arresters that were in service on XTF-1 during the reactor trip, was replaced. The lightning arresters were sent to an independent lab, NEETRAC - Georgia Tech, for testing and evaluation.

The examination results indicate that the most probable cause of the arrester failure was an internal flashover of the metal oxide varistor blocks. The cause of the internal flashover is likely moisture ingress from the upper end seal.

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

05000397/LER-2017-004Columbia20 August 2017
18 October 2017
MANUAL REACTOR SCRAM DUE TO HIGH MAIN CONDENSER BACK PRESSURE
LER 17-004-00 for Columbia Generating Station Regarding Manual Reactor Scram Due to High Main Condenser Back Pressure

On August 20, 2017 at 1605 PDT, Columbia Generating Station was manually scrammed due to a rise in Main Condenser back pressure. The rise in back pressure was due to the spurious closure of the Main Condenser Air Removal Suction Valve (AR-V-1) as a result of the failure of it's associated solenoid pilot valve. Following the reactor scram and depressurization of the reactor a Level 3 actuation occurred. In addition a startup flow control valve failed which necessitated throttling of the Feedwater start-up level control isolation valve to control Reactor Pressure Vessel level. All other safety systems functioned as expected and all control rods were fully inserted. Reactor decay heat was removed via bypass valves to the main condenser.

The apparent cause was the plant modification to address the single point vulnerability of the closure of AR-V-1 was not implemented in time to prevent a plant shutdown. A temporary modification has been installed to maintain AR-V-1 open for the remainder of the operating cycle.

These events are reportable in accordance with 10 CFR 50.73(a)(2)(iv)(A).

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.

05000387/LER-2017-005Susquehanna8 June 2017
4 October 2017
Automatic Reactor Protection System Trip on High Neutron Flux
LER 17-005-01 for Susquehanna, Unit 1 Regarding Automatic Reactor Protection System Trip on High Neutron Flux

On June 8, 2017 at 1527 hours, the reactor automatically scrammed due to a loss of Main Turbine- Electro-Hydraulic Control (EHC) logic power causing a high neutron flux, Reactor Protection System (RPS) trip. The safety systems operated as expected. Secondary Containment differential pressure lowered to 0" WG due to a trip of the normal operation of the Reactor Building Ventilation system. The differential pressure was restored by the initiation of Standby Gas Treatment System.

The scram was caused directly by a DC+ (direct current, positive) test lead (Maxi Grabber) that inadvertently contacted with the grounding screw, causing a short and momentary loss of EHC logic power.

Immediate action was taken to validate that there was no damage to the +30 VDC (volts DC) EHC logic.

The root cause for this event is an insufficient focus on the High Risk Activity of adjusting the EHC power supply, and inadequate risk mitigating actions for that activity.

The condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in an automatic actuation of the RPS, including reactor scram. Although no safety system functional failure occurred, this event is also reportable pursuant to 10CFR 50.73(a)(2)(v)(C) as a condition that could have prevented fulfillment of a safety function. There were no actual, or potential consequences to the health and safety of the public as a result of this event.

I

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.

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.

05000219/LER-2017-003Oyster Creek3 July 2017
31 August 2017
Automatic Scram while Suberitical due to Low Reactor Level
LER 17-003-00 for Oyster Creek Regarding Automatic Scram while Subcritical due to Low Reactor Level

On July 3, 2017 at approximately 10:30 hours with the reactor subcritical after a manual scram, an automatic reactor scram occurred due to low Reactor Pressure Vessel (RPV) water level. Prior to this event, Main Control Room (MCR) Operators established reactor water letdown, reset the manual scram and were placing RPV water level control in automatic using a Low Flow Feedwater Regulator Valve (LFRV). Reactor pressure control was automatically being maintained with turbine bypass valves. A low reactor water level occurred when a bypass valve opened as expected to lower reactor pressure.

Operations personnel had reset the scram signal without fully evaluating other plant conditions. Upon resetting the scram with reactor water level not yet stabilized, an automatic scram was received on low reactor water level. The automatic scram initiation signal occurred with the plant in a shutdown mode.

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-2017-001Indian 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.

05000458/LER-2017-007River Bend Station — Unit 1 05000-458
River Bend
21 August 2017Automatic Reactor Scram due to Failure of Main Generator Voltage Regulator Mode Transfer Relay
LER 17-007-00 for River Bend Station - Unit 1 Regarding Automatic Reactor Scram due to Failure of Main Generator Voltage Regulator Mode Transfer Relay
On June 23, 2017, at 10:18 PM CDT, an unanticipated reactor scram occurred during scheduled testing of the main turbine generator. The plant was operating at 100 percent power at the time, and no safety-related equipment was out of service. A reactor recirculation system flow control valve runback occurred as designed, and the recirculation pumps properly downshifted to slow speed. The main feedwater system responded properly to control reactor water level. The scram signal was initiated by the closure of the main turbine control valves, which was an automatic response to a trip of the main generator. The associated steam pressure increase following turbine valve closure resulted in the actuation of 12 main steam safety-relief valves. A reactor water level 3 signal was received, as expected, following the turbine trip and reactor scram and was promptly restored to the normal reactor water level band. The non-safety related turbine building chillers tripped as a result of the electrical transient caused by the generator trip. One area served by that cooling system is the reactor water cleanup (RWCU) system heat exchanger room. Approximately 20 minutes after the scram, the temperature in that room exceeded the trip setpoint of the area temperature monitors, resulting in the automatic closure of the primary containment isolation valves for the RWCU system.
05000458/LER-2017-00818 August 2017Automatic Reactor Scram due to Failure of Main Feedwater Regulator Transfer Relay

On August 18, 2017, at 8:55 p.m. CDT, an automatic reactor scram occurred while the plant was operating at 100 percent power. The operators promptly established control of reactor water level and pressure, and a controlled plant cooldown was commenced. The initial scram signal was a flow-biased thermal power trip on the average power range monitors.

This action closely followed a planned shift of the master feedwater controller from channel "B" to channel "A.

Troubleshooting discovered that the feedwater level channel select relay had failed such that no signal was present on the "A" channel. When that channel was selected, the feedwater system erroneously sensed that reactor water level was low, and caused all three feedwater regulating valves to move fully open. At the same time, the false low water level signal was sensed in the control circuitry for the reactor recirculation system, resulting in an automatic shift of the recirculation pumps to slow speed. The resultant decrease in core flow caused the flow-biased thermal power trip in the average power range monitors, actuating the reactor scram. The failed feedwater system relay was replaced with an updated model with gold contacts. This condition is being reported in accordance with 10 CFR 50.73(a)(2)(iv) as an event resulting in the automatic actuation of the reactor protection system.

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.

05000461/LER-2017-007Clinton10 June 2017
9 August 2017
Manual Reactor SCRAM due to Loss of Feedwater Heating
LER 17-007-00 for Clinton, Unit 1 re Manual Reactor SCRAM due to Loss of Feedwater Heating
On June 10, 2017, at 2256 CDT, Clinton Power Station (CPS) experienced a complete loss of the 'A' feedwater (FW) heater string. The operators received numerous FW trouble alarms on FW string 'A' and low pressure heater 1N1B bypass opened (1CB004). The operators entered procedure CPS 4005.01, "Loss of FW Heating," which directs the operators to restore and maintain power at or below the original power level. The operators lowered core flow and inserted all CRAM rods, and then observed that FW temperature had dropped greater than 100°F. As directed by CPS 4005.01, at 2306 hours the reactor mode switch was placed into the shutdown position and procedure 4100.01, "Reactor Scram," was entered. All systems operated as expected following the scram. At 0100 EDT, June 11, 2017; Event Notification 52800 was made. The loss of FW heating transient was caused by a loss of power to Moore trip units caused by a shorted condition on the Moore trip unit associated with the Hi-Hi level in the 4A FW heater. The root cause is that the design of the FW heater level control trip circuitry was not adequate to prevent scrams due to an unevaluated single point vulnerability. Prior to startup, CPS modified the circuit card locations and thereby diversified the power supplies so that the trip units have less dependency on common fuses. Additional corrective actions include performing an engineering evaluation to determine if there are additional single component failures, operator errors, or events for the FW heating system that could result in a drop in FW temperature of greater than 100°F.
05000286/LER-2017-002Docket Number
Indian Point
11 June 2017
9 August 2017
Manual Isolation of Chemical and Volume Control System Normal Letdown to Stop a Valve Leak Resulted in an Exceedance of Technical Specification 3.4.9 Condition A Limit for Pressurizer Level
LER 17-002-00 for Indian Point, Unit 3 re Manual Isolation of Chemical and Volume Control System Normal letdown to Stop a Valve Leak Resulted in an Exceedance of Technical Specification 3.4.9 Condition A Limit for Pressurizer Level

On June 11, 2017, while at 100 percent reactor power, Operations placed Chemical and Volume Control System (CVCS) Demineralizer Diversion Valve CH-TCV-149 in DIVERT to allow the 32 Mixed Bed Demineralizer to be removed from service and align the 31 Mixed Bed Demineralizer for service. Within about two minutes after returning CH-TCV-149 to AUTO, which placed the 31 Mixed Bed Demineralizer in service, Letdown Backpressure Control Valve CH-PCV-135 demand had gone to 0 percent (full open demand) while letdown backpressure had increased, reaching 302 psig.

Operations was alerted to a leak that had developed on 32 Mixed Bed Demineralizer Inlet Isolation Valve CH-352. In an effort to isolate the leak, CH-TCV-149 was placed in DIVERT. Due to the elevated pressure at CH-TCV-149 with CH-PCV- 135 fully open, placing CH-TCV-149 in DIVERT coupled with the elevated line pressure created a pressure transient in the letdown line upstream of the CVCS Reactor Coolant Filter. Reactor Coolant Filter Inlet Isolation Valve CH-305 experienced this pressure transient, which resulted in the valve developing a significant leak at the body to bonnet joint. Abnormal Operating Procedure (AOP) 3-AOP-LEAK-1 was entered, and normal letdown was manually isolated to stop the CH-305 leak. Excess letdown was placed in service to balance reactor coolant inventory at a Pressurizer water level of 61 percent.

This exceeded the 54.3 percent limit of Technical Specification 3.4.9 Condition A, and Operations declared the Pressurizer inoperable. The inoperability of the Pressurizer is reportable as a safety system functional failure under 10 CFR 50.73(a)(2)(v). The direct cause of this event was elevated system pressure due to loading of the Reactor Coolant Filter from materials when the 31 Mixed Bed Demineralizer pathway was aligned. The elevated operating pressure in the CVCS letdown stream challenged the integrity of diaphragm valves CH-352 and CH-305, requiring the isolation of normal letdown.

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.

05000265/LER-2017-001Quad Cities15 May 2017
13 July 2017
High Pressure Coolant Injection Minimum Flow Valve Failed to Open
LER 17-001-00 for Quad Cities, Unit 2, Regarding High Pressure Coolant Injection Minimum Flow Valve Failed to Open

On May 15, 2017, at 19:18 hours, station Operations personnel were performing a High Pressure Coolant Injection (HPCI) Pump Operability Test which ensures the HPCI Minimum Flow Valve opens as pump flow decreases. When the HPCI Turbine was tripped, the Minimum Flow Valve did not open as expected when system flow was reduced to the low flow setpoint. Operators took steps to open the valve manually, but upon release of the control switch, the valve returned to the closed position.

The valve was then left in the closed position.

The HPCI system was declared inoperable and Technical Specification 3.5.1 Condition G was entered.

The cause of the Minimum Flow Valve failing to open was attributed to the HPCI Pump Discharge Flow Indicating Switch, specifically, intermittent failure of the high side micro switch caused by residual material from the manufacturing process.

The Flow Indicating Switch, which had been installed for three months, was replaced and the HPCI Pump Operability Test was successfully re-performed. The failed switch was then sent to Exelon's Power Labs for failure analysis.

The safety significance of this event was minimal. Given the impact on the HPCI system, this report is submitted for Unit 2 in accordance with the requirements of 10 CFR 50.73(a)(2)(v)(D), which requires the reporting of any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident. The HPCI system is a single train system and the loss of HPCI could impact the plant's ability to mitigate the consequences of an accident.

05000461/LER-2017-004Clinton12 May 2017
10 July 2017
Main Steam Isolation Valve Local Leak Rate Test Limit Exceeded During Refueling Outage
LER 17-004-00 For Clinton Power Station, Unit 1 Re: Main Steam Isolation Valve Local Leak Rate Test Limit Exceeded During Refueling Outage
During the Clinton Power Station (CPS) Refueling Outage (C1 R17) on May 12, 2017 at 0045 (CDT), CPS tested its Main Steam Isolation Valves (MSIV) and discovered the as-found leakage for main steam line (MSL) `D' exceeded the Technical Specifications (TS) 3.6.1.3, Primary Containment Isolation Valves, Surveillance Requirement (SR) 3.6.1.3.9 limit placed on an individual MSL and total leakage from all four MSLs. During Modes 1, 2, and 3, TS SR 3.6.1.3.9 requires MSIV leakage for a single MSL to be less than or equal to 100 standard cubic feet per hour (scfh) (47,195 standard cubic centimeters per minute (sccm)) and requires the combined leakage rate for all MSLs to be less than or equal to 200 scfh (94,390 sccm) when tested at 9 psig. The as-found leakage for the 'D' MSL was 53,921.61 sccm for the 'D' inboard MSIV (1 B21 F022D) and 59,698.8 sccm for the 'D' outboard MSIV (1B21F028D). The as-found combined min-path leakage for all four MSLs was 102,463 sccm. An event investigation determined the as found condition of MSIVs 1B21F022D and 1B21F028D did not reveal any damage, only normal wear indications. Thus, the apparent cause for the excessive leakage past all affected MSIVs is expected wear. Valves 1621F028A, 1B21F022D, and 1B21F028D were repaired so that as-left leakage values complied with limits established by TS SR 3.6.1.3.9. This event is reportable due to principle plant safety barriers being seriously degraded, under the provisions of 10 CFR 50.73(a)(2)(ii)(A) and a condition prohibited by TS under 10CFR50.73(a)(2)(i)(B).
05000461/LER-2017-003Clinton9 May 2017
3 July 2017
Implementation of Enforcement Guidance Memorandum (EGM) 11 - 003, Revision 3
LER 17-003-00 for Clinton Power Station, Unit 1 Regarding Implementation of Enforcement Guidance Memorandum (EGM) 11-003, Revision 3
The condition reported by this LER is the result of planned activities in support of Refueling Outage C1 R17 at Clinton Power Station (CPS). As described in the LER, the NRC provided enforcement guidance, applicable to boiling water reactor licensees, that addresses the reported condition. Although this allowance is provided by the NRC's enforcement guidance, the planned activities are still considered reportable in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS). On May 9 through May 28, 2017 CPS performed Operations with the Potential for Draining the Reactor Vessel (OPDRV) activities while in Mode 5 without an operable Secondary Containment. These activities were performed within the guidelines of NRC Enforcement Guidance Memorandum (EGM) 11-003, Revision 3 which allows the implementation of interim actions as an alternative to full compliance, provided several conditions are met. The OPDRV activities were planned activities that were completed following the guidance of the EGM and are considered to have low safety significance based on interim actions taken. Since these actions were preplanned, no cause determination was necessary. As required by the EGM, a license amendment request was submitted on May 1, 2017 which follows the guidance in Technical Specifications Task Force traveler TSTF-542 which is the agreed-upon generic resolution of this issue.
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.

05000263/LER-2017-001Monticello15 April 2017
13 June 2017
Reactor Scram and Group II Isolation Due to 11 Reactor Feed Pump (RFP) Removal from Service with 12 RFP Isolated
LER 17-001-00 for Monticello Regarding Reactor Scram and Group II Isolation Due to 11 Reactor Feed Pump (RFP) Removal from Service with 12 RFP Isolated
On April 15, 2017 at 0436 hours, the 11 Reactor Feedwater Pump (RFP) was removed from service and the discharge valve closed. With the discharge valve closed and 12 RFP previously isolated no flow path was lined-up for the Condensate pumps to supply water to the vessel. Reactor water level lowered resulting in valid Reactor Protection System (RPS) actuation and Primary Containment Group II Isolation signals. The 11 RFP discharge valve was reopened to reestablish a flowpath to restore level. The RPS and Group II isolation logic was reset when cleared. Two apparent causes were identified: 1) Failure to identify and address the unusual Feedwater System configuration prior to execution of the 11 RFP shutdown. 2) Guidance for shutdown of the RFP did not take into account the state of the other train when shutting down a RFP. The corrective actions were: 1) Revise plant startup and shutdown procedures to ensure abnormal equipment lineups are addressed to avoid unexpected interactions. 2) Revise the Feedwater System operation procedure to maintain a flow path when the opposite train Reactor Feed Pump is isolated
05000313/LER-2016-003Arkansas Nuclear24 August 2016
9 June 2017
Tornado Missile Vulnerabilities Resulting in Unanalyzed Condition
LER 16-003-01 for Arkansas Nuclear One, Unit 1 Regarding Tornado Missile Vulnerabilities Resulting in Unanalyzed Condition

On August 24, September 11, and September 15, 2016, during performance of an extent of condition evaluation related to the protection of Technical Specification (TS) equipment from external flood hazards, Arkansas Nuclear One, Unit 1 (ANO-1), identified non-conforming plant design conditions such that specific ANO-1 TS equipment was considered to not be adequately protected from tornado missiles. These are legacy design issues.

On August 24, 2016, at 0945, September 11, 2016, at 1504, and September 15, 2016, at 0958, Operations declared the affected components inoperable, implemented Enforcement Guidance Memorandum (EGM) 15-002, "Enforcement Discretion for Tornado-Generated Missile Protection Noncompliance", along with necessary compensatory measures, and subsequently declared the affected equipment operable but non-conforming.

The cause of this issue was unclear and changing regulatory requirements during original plant licensing that led to an inadequate understanding of the regulatory guidance with respect to tornado missile protection design requirements.

Interim corrective actions include implementation of compensatory strategies. Plant modifications and license basis changes are being evaluated to resolve outstanding issues.

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.