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 SiteStart dateTitleDescription
05000461/LER-2017-010Clinton9 December 2017
5 February 2018
Division 1 Transformer Failure Leads to Instrument Air Isolation to Containment Requiring a Manual Reactor Scram
LER 17-010-00 for Clinton Power Station, Unit 1 Regarding Division 1 Transformer Failure Leads to Instrument Air Isolation to Containment Requiring a Manual Reactor Scram

On December 9, 2017 at 1347 CDT the Main Control Room received annunciators that indicated a trip of a 4160V 1A1 Breaker, the 480V transformer 1A and Al feed breaker. The loss of Division 1 480V power caused the instrument air (IA) containment isolation valves to fail close as designed. The loss of IA affected various containment loads, including the scram pilot air header and containment isolation valves. Another consequence of this event was that secondary containment differential pressure became positive due to fuel building ventilation dampers failing closed by design due to the loss of power. Operations entered Emergency Operating Procedure (EOP) -08, Secondary Containment Control, and Technical Specification (TS) Limiting Condition for Operation (LCO), 3.6.4.1 Action A.1. Division 2 Standby Gas Treatment System was activated at 1350 and restored secondary containment differential pressure within allowable TS values at 1351. The TS LCO and EOP were exited when allowable TS values were restored. Due to the loss of IA, a manual reactor scram was inserted at 1353 when two control rods began drifting in as expected.

A phase to ground fault was identified on 480V transformer 1A (1AP11E). On December 14, the 480V transformer was replaced and the plant returned to Mode 1 operations on December 15. The condition described in this report was determined to be reportable under 10 CFR50.73(a)(2)(iv)(A), 10 CFR 50.73(a)(2)(v)(C) and 10 CFR 50.73 (a)(2)(ii)(B). The cause of the transformer failure is currently under investigation and will be provided in a supplemental report. This event is classified as an unplanned scram with complications due to the loss of the Division 1 480V power.

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).

05000263/LER-2017-006Monticello14 November 2017
12 January 2018
Loss of Reactor Protection System Scram Function During Main Steam Isolation Valve and Turbine Stop Valve Channel Functional Tests due to Use of a Test Fixture
LER 17-006-00 for Monticello Regarding Loss of Reactor Protection System Scram Function During Main Steam Isolation Valve and Turbine Stop Valve Channel Functional Tests Due to Use of a Test Fixture

On November 14, 2017, it was identified that the use of the Reactor Protection System (RPS) test fixture described in some operations procedures would result in the loss of two RPS reactor Scram functions. Technical Specification 3.3.1.1 requires that RPS Instrumentation for Table 3.3.1.1-1 Function 5, Main Steam Isolation Valve-Closure and Function 8, Turbine Stop Valve-Closure, remain operable. It was concluded that a closure of three of four Main Steam Lines or Turbine Stop Valves would not necessarily have resulted in a full Scram during testing depending on the combination of closed valves occurring during the bypass condition. Operations procedures were revised to incorporate the use of the test fixture in December, 2008 for the Turbine Stop Valve Closure Scram Test Procedure and February, 2009 for the Main Steam Isolation Valve Closure Scram Test Procedure. The operations procedures were inappropriately revised to allow use of the test fixture on all RPS functions to prevent a half Scram.

The operations procedures were quarantined until revisions were issued in December, 2017 that removed use of the test fixture.

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.

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.

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.

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.

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

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

05000410/LER-2017-001Nine Mile Point5 August 2017
4 October 2017
1 OF 5
LER 17-001-00 for Nine Mile Point Nuclear Station, Unit 2, Regarding Automatic Reactor Scram due to High Reactor Pressure
On August 5, 2017, at approximately 2235, the Nine Mile Point Unit 2 (NMP2) reactor scrammed on an automatic scram signal during performance of quarterly turbine stop valve surveillance testing. The automatic Reactor Protection System (RPS) actuation and reactor scram is reportable per 10 CFR 50.73(a)(2)(iv)(A). The definitive root cause of the equipment failure was not located but was bound to spurious actuation of load limit relays KL186 and KL187. The spurious action was caused by an intermittent ground and/or an induced voltage within the load limit circuit. This is a result of the non-fault tolerant original design of the Electro-hydraulic Control (EHC) system. The corrective action planned is replacement of the current single point vulnerable NMP2 Turbine EHC system with a fault tolerant Digital EHC system. Interim actions have also been developed to mitigate risk associated with testing of the current system until replacement can be accomplished during the 2018 refueling outage.
05000461/LER-2017-005Clinton30 May 2017
28 September 2017
Automatic Reactor Scram During the Performance of Scram Time Testing As a Result of an Invalid Oscillation Power Range Monitor Growth Rate Trip
LER 17-005-01 for Clinton, Unit 1 Regarding Automatic Reactor Scram During the Performance of Scram Time Testing As a Result of an Invalid Oscillation Power Range Monitor Growth Rate Trip
On May 30, 2017 at 2038 CDT, with the reactor at approximately 28% thermal power Clinton Power Station (CPS) experienced an automatic reactor scram while conducting scram time testing (STT). Plant systems responded as expected and functioned properly following the automatic scram. The automatic scram signal was generated by the Oscillation Power Range Monitor (OPRM) Growth Rate Algorithm (GRA). An evaluation confirmed that the reactor was operating in a very stable core condition and that the event did not occur due to an actual core thermal hydraulic instability. The cause of the event was that the OPRM GRA trip function design is unable to distinguish between plant response to system perturbations and onset of thermal-hydraulic instabilities. Interim actions were implemented to increase operating margin to trip setpoints to support reactor startup and completion of STT. They included a revision to a plant procedure to establish an operating strategy when performing STT in the OPRM enabled region, implementing a monitoring strategy to assess the effectiveness of the operating strategy and monitoring for expected plant response, and raising OPRM Amplitude and GRA set points. Planned corrective actions include working with the industry, as needed, to develop and implement an industry solution for the design of the OPRM GRA to prevent false, spurious trip signals. The automatic scram is reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event or condition that resulted in a manual or automatic actuation of the reactor protection system.
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.

05000287/LER-2017-001Oconee Nuclear Station Unit 3
Oconee
24 July 2017
20 September 2017
Unit 3 Reactor Protection System Actuation - Reactor Trip due to Turbine Trip from Generator Lockout
LER 17-001-00 for Oconee Nuclear Station, Unit 3, Regarding Reactor Protection System Actuation - Reactor Trip due to Turbine Trip from Generator Lockout

On 7/24/17, with Oconee Nuclear Station (ONS) Unit 3 operating at 100 percent power, Transmission Department Relay personnel were in the ONS 525kV Switchyard Relay House performing preventive maintenance on a Breaker Failure Relaying device for Power Circuit Breaker PCB-57. This is a non- safety PCB that isolates a commercial transmission line from the commercial bus in the 525kV switchyard.

The maintenance was intended to actuate the protective relaying for PCB-57. The crew inadvertently connected test equipment to the adjacent relaying for PCB-58. The activation of the PCB-58 relay resulted in a Unit 3 separation from the electrical grid and a generator "Lockout." The lockout generates a turbine trip which in turn trips the reactor via the Reactor Protection System (RPS). This actuation of the RPS is reportable per 10 CFR 50.73(a)(2)(iv)(A).

Post trip plant response was normal and plant conditions were controlled and maintained within the allowances of Technical Specifications with no personnel injuries or safety system actuations.

A cause analysis attributed the cause of this event to human error in that test equipment was inadvertently connected to relaying for the incorrect PCB. The cause analysis corrective actions will address the likelihood of comparable human errors from occurring.

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.

05000335/LER-2017-003Saint Lucie12 September 2017Inadequate Reactor Protection System Trip Process for Inoperable Channel Results in Operation in a Condition Prohibited by Technical Specifications

During a reactor startup performed on September 12, 2017, the operators noted that the inoperable ‘B' channel reactor protection system (RPS) high startup rate (HSUR) trip did not occur as expected when reactor power exceeded the HSUR bypass removal setpoint. The ‘B' RPS HSUR channel was then manually tripped via the bistable removal method and plant startup continued.

Investigation revealed that the setpoint reduction method process used to implement the RPS HSUR channel trip did not account for subsequent nuclear instrumentation (NI) detector failures. Therefore the ‘B' RPS HSUR channel was not in the required tripped condition since the February 2017 failure of its wide range NI detector.

The setpoint reduction method was subsequently revised to ensure inoperable RPS HSUR channels tripped by the setpoint reduction method generate a trip with reactor power less than 15 percent reactor power. A procedure revision is in progress to implement these new rule-based instructions.

This event had no significant impact on the health and safety of the public based on system channel redundancy and procedural controls.

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 September 12, 2017, St. Lucie Unit 1 was in a reactor startup in Mode 2 operation. The ‘B' channel reactor protection system (RPS) high startup rate (HSUR) (EIIS:JC) channel was thought to be in the reduced setpoint tripped condition in response to earlier unpredictable operation of the ‘B' channel nuclear instrumentation (NI) detector (EIIS:IG:DET). At 1522 hours during the startup, the operators noted that the ‘B' channel RPS HSUR bistable (EIIS:JC) did not automatically trip as expected for the existing plant conditions. The operators placed the ‘B' channel of RPS HSUR in a tripped condition in accordance with procedures by removing the bistable from the trip unit assembly and entered Technical Specification (TS) 3.3.1.1, Table 3.3-1, Functional Unit 11, Action 2 with the ‘B' channel HSUR bistable in trip. The reactor startup continued with the channel in trip as allowed by the Technical Specifications (TSs).

Cause of the Event

This event was caused by inadequate processes used to implement the HSUR reduced setpoint trip method. The instruction used did not evaluate all potential failure conditions when setting the HSUR bistable. Investigation showed that the bistable did not trip because the setpoint reduction method (initially) internally tripped the bistable in the presence of an active NI signal. When the ‘B' wide range NI detector subsequently failed low in February 2017, the input signal to the Hi Rate bistable from the rate circuit changed and the bistable trip conditions were no longer satisfied. During power operation this latent condition was partially masked by the greater than 15 percent power automatic bypass signal applied downstream of the comparator output circuitry. Additionally, the automatic bypass of the bistable trip signal below 10-4 percent power was never automatically removed during the startup due to the NI detector being failed low.

Following this investigation, maintenance and engineering personnel determined that the correct method to internally trip the bistable was to set the setpoint to the maximum negative value. This would ensure a trip would occur regardless of NI detector health whenever reactor power was less than 15 percent. The HSUR bypass for affected channels would also continue to be bypassed above 15 percent reactor power. A procedure revision is in progress to implement these new rule-based instructions.

Analysis of the Event

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

The RPS HSUR trip is developed from the nuclear instrumentation (NI) wide range channels, and the trip signal may be automatically bypassed below 10 E-4 percent and above 15 percent power. When the trip is not bypassed, a reactor trip is initiated prior to the reactor power rate-of-change exceeding 2.49 decades per minute as measured by any two of the four wide-range NI channels.

Plant procedures provide two methods for placing an RPS HSUR channel in the trip condition. The first method pulls the Hi Rate bistable from the trip unit assembly. This method can be implemented quickly by control room operators, but has the disadvantage of sealing in a channel trip signal above 15 percent power. The second method has maintenance personnel reduce the bistable setpoint such that the channel would be expected to generate a trip signal with the automatic removal of the bypass between 10 E-4 percent and 15 percent power. This method has the advantage of preserving the automatic RPS HSUR bypass below 10 E-4 and greater than 15 percent power.

Prior to this event, the ‘B' channel wide range NI detector signal had been experiencing unpredictable operation, and the ‘B' RPS HSUR channel was placed in trip using the setpoint reduction method in October of 2016. During the 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.

September 2017 plant startup, the ‘B' RPS HSUR channel did not trip as expected when reactor power exceeded the bypass removal setpoint of 10 E-4 percent power. The ‘B' wide range NI detector failed low on February 10, 2017.

The setpoint reduction method (used before the detector failed) was predicated on a baseline NI detector signal not a failed low detector signal; the setpoint reduction method did not account for the static failed detector voltage and its effect on the trip. Additionally, the failed low detector signal did not remove the bypass.

Safety Significance

The high rate-of-change of power trip is not credited in any of the Chapter 15 accident analyses. However, the trip is considered in the safety analysis, in that the presence of this trip function precluded the need for specific analyses of other events initiated from subcritical conditions (e.g., events not discussed in Chapter 15).

Subsequent to the ‘B' wide range detector failure on February 10, 2017, Unit 1 was within the HSUR bypass conditions with power greater than 15 percent. On September 11, 2017, Unit 1 was shutdown due to degrading switchyard environmental conditions caused by Hurricane Irma. The inadequately implemented reduced trip setpoint method had no effect during the evolution because the operating procedure used during this shutdown required that the reactor be tripped above 15 percent reactor power while the HSUR bypass was still in effect. In addition, the inoperative channel trip was detected in the subsequent September 12, 2017 startup and actions were taken as directed by the TSs; therefore the inoperative trip had no effect on the subsequent startup.

As previously stated, the HSUR bistable is required for operation during the reactor power ranges of 10 E-4 percent to 15 percent power. Per the design basis, the RPS has four independent measurement channels that monitor parameters and trip at TS prescribed setpoints. In addition, each RPS channel is required to be demonstrated operable by the performance of a successful monthly functional test. The RPS is designed to initiate a reactor trip when the two out of four coincidence logic is satisfied (i.e. high startup rate). Therefore, even with the ‘B' RPS HSUR channel in a nonconforming condition, there is reasonable assurance that the three remaining healthy HSUR channels would have performed the function of the RPS system to trip if TS prescribed setpoints were exceeded.

Based on the discussion above, this event had no significant impact on the health and safety of the public.

Corrective Actions

1. The ‘B' RPS HSUR channel was recalibrated, placed in trip using the new setpoint reduction method, and the bistable was re-inserted into the cabinet.

2. A procedure revision is in progress to implement the new rule-based setpoint reduction method.

Failed Components

Component: wide range nuclear instrumentation detector JI-002 Manufacturer: Sigma Model: 9222-00ED

Additional Information

None.

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

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

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

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
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 currentlyvaild OMB
control number, the NRC may not conduct or sponsor, and a person is not required to respond to,
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.

05000219/LER-2017-004Oyster Creek31 August 2017Reactor Protection System Channel Disabled During Test Box Use

On August 31, 2017, during a review of industry Operating Experience (FERMI 2, LER 2017-001) for the use of a Reactor Protection System (RPS) test box during main turbine surveillance testing, it was determined that Oyster Creek station procedures failed to implement the required action specified by Technical Specifications (TS) section 3.1,1. note (nn) during testing. The surveillance tests associated with the Turbine Trip and Generator Load Rejection functions were revised in 2013 to use an RPS test box in order to minimize operational risks associated with the receipt of half scram signals during testing. The installation of the RPS test box caused two of the four required instrument channels for the Turbine Trip Scram function to be bypassed during testing.

In accordance with station Technical Specifications, the required action to verify sufficient channels remained operable was not documented as complete within the action time specified in TS Table 3.1.1, note (nn). This issue was identified under normal operating conditions, and is reportable under 10 CFR 50.73(a)(2)(i)(B).

05000247/LER-2017-003Indian Point Unit 2
Indian Point
27 June 2017
23 August 2017
Technical Specification Violation of Section 3.3.1 RPS Instrumentation
LER 17-003-00 for Indian Point Unit 2, Regarding Technical Specification Violation of Section 3.3.1 RPS Instrumentation

' On June 27, 2017, during reactor startup, power was raised from Mode 3 to Mode 2 and above the P-6 (Intermediate Range Neutron Flux) interlock with the P-6 Switches in the wrong position. With P-6 inoperable this was a violation of the requirement of Technical Specification (TS) Limiting Condition of Operation (LCO) 3.3.1 and resulted in a 60 Day Licensee Event Report (LER). LCO 3.3.1, Table 3.3.1-1, Item 17 states that the Intermediate Range Neutron Flux, P-6 shall be operable.

On June 27, 2017, during performance of 2-PT-V63A, Reactor Protection System (RPS) Logic Train 'A' Partial Functional Test, Instrumentation and Control (I&C) Technicians left two Intermediate Range P-6 switches in the wrong position, which resulted in an unplanned entry into'LCO 3.3.1, due to inoperable RPS instrumentation. This inoperable RPS instrumentation resulted in a TS LCO 3.3.1 violation when reactor power was raised from Mode 3 to Mode 2.

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).

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.

05000416/LER-2016-009Grand Gulf27 March 2016
16 August 2017
Entry into Mode of Applicability with the Oscillation Power Range Monitor Upscale Settings Incorrectly Set
LER 16-009-01 for Grand Gulf, Unit 1, Regarding Entry into Mode of Applicability with the OPRM Upscale Settings Incorrectly Set
On March 27, 2016, the Entergy, while returning the GGNS Unit 1 to power operations at the conclusion of Refueling Outage 21, reactor thermal power was allowed to exceed 16.8 percent without first fully calibrating the Oscillation Power Range Monitor (OPRM) to include the new limits required by the adoption and implementation of the Maximum Extended Load Limit Line Plus (MELLLA+) operating range. Specifically, the OPRM Upscale setting requirements specified in Technical Specification 3.3.1.1, Reactor Protection System (RPS) Instrumentation, Table 3.3.1.1-1, Reactor Protection System Instrumentation, Function 2, Average Power Range Monitors, Sub-Function f. OPRM Upscale were not fully met. The direct cause of this event was the failure to ensure the required procedure changes were incorporated and performed prior to the unit entering the mode of applicability. Corrective actions included the addition of the condition to Limiting Condition for Operation tracking system to ensure resolution prior to a mode of applicability. This event is reportable as a licensee event report (LER) in accordance with 10CFR50.73(a)(2)(i)(B) as an operation or condition prohibited by Technical Specifications and 10CFR50.73(a)(2)(v)(A) for the loss of safety function.
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.

05000374/LER-2017-003LaSalle
Lasalle
11 February 2017
9 August 2017
High Pressure Core Spray System Inoperable due to Injection Valve Stem-Disc Separation
LER 17-003-01 for LaSalle County Station, Unit 2 Regarding High Pressure Core Spray System Inoperable due to Injection Valve Stem-Disc Separation

On February 11, 2017, Unit 2 was in Mode 5 for a planned refueling outage. While attempting to fill and vent the Unit 2 High Pressure Core Spray (HPCS) system, no flow was observed from the drywell vent valves or downstream of the HPCS injection valve. The HPCS system was already inoperable to support scheduled surveillances performed on February 8, 2017 in which the HPCS injection isolation valve had been cycled five times satisfactorily. Troubleshooting determined the cause of the valve malfunction was due to stem-disc separation. The valve internal components were replaced prior to restart of the unit from the refueling outage. The root cause of the valve failure was insufficient capacity of the shrink-fit stem collar, combined with multiple high-load cycles, which resulted in loosening and eventual shear failure of the wedge pin and threads.

This component failure is reported in accordance with 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented fulfillment of the safety function of structures or system that are needed to mitigate the consequences of an accident. This condition could have prevented the HPCS system, a single train safety system, from performing its design function if the valve failure occurred during an actual demand. This component failure is also reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by Technical Specifications (TS) 3.5.1 "ECCS - Operating," since the HPCS system could have been 1 inoperable for greater than the TS 3.5.1, Required Action B.2, Completion Time of 14 days to restore HPCS system to operable status. There were minimal safety consequences associated with the condition since HPCS was not required to be operable at the time of the failure, and other required emergency safety systems remained operable. There were no actual demands for Unit 2 LHPCS, other ECCS systems, or the reactor core isolation cooling (RCIC) system during this period.

- --- ------- - NRC FORM 366 (04-2017) - 01 003 2017

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.
05000255/LER-2017-002Palisades19 May 2017
17 July 2017
Reactor Protection System Actuation While the Reactor was Shutdown
LER 17-002-00 for Palisades Regarding Reactor Protection System Actuation While the Reactor was Shutdown

On May 19, 2017, at 0206 hours, an unexpected Reactor Protection System (RPS) actuation occurred during pre-startup testing. The reactor was shutdown at the time, with all control rods inserted. The portion of the test that was in progress is designed to actuate the RPS from a loss of load input signal. To facilitate this part of the test with the reactor in a shutdown mode, one of two conditional steps in the procedure is to be taken. The generator motor operated disconnect 389 (MOD-389) is required to be in the open position, or protective trip circuity for the generator is required to be bypassed.

Due to a conditional step of the test procedure being misinterpreted by a Nuclear Control Operator (NCO), MOD-389 was left in the closed position and the generator protective trip circuity was not bypassed. This resulted in the RPS actuation occurring prior to the preplanned sequence. The RPS responded as designed. All components operated as expected for the plant conditions.

The cause of the unexpected RPS actuation was human performance errors during procedure performance, e.g., lack of self-validation/verification, misinterpretation of information, and lack of peer check verification.

Corrective actions from the event include the removal of the NCO's licensed operator qualifications until remediated and initiation of a standing order requiring peer check verification for all procedure conditional steps until the applicable administrative procedure is revised. Additionally, a case study of the event will be included in a 2017 operations high intensity training session.

05000366/LER-2017-004Edwin I Hatch Nuclear Plant Unit 230 June 20171 OF 3On June 30, 2017, Unit 2 was at 100 percent rated thermal power (RTP) when "as-found" testing results of the 3-stage main steam safety relief valves (SRVs) indicated two of the eleven Unit 2 SRVs experienced a setpoint drift during the previous operating cycle which resulted in their failure to meet the Technical Specification (TS) opening setpoint pressure of 1150 +/- 34 5 prig as required by TS Surveillance Requirement (SR) 3 4 3 1 The test results showed that two SRVs were slightly out of specification low due to setpoint drift The SRV pilots were disassembled and inspected while investigating the reason for the drift SNC has determined that the abutment gap closed pre-maturely The pre-mature abutment gap closure is most likely due to loose manufacturing tolerances leading to SRV setpoint drift NRC FORM 368 8:14-2017)
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.

05000440/LER-2017-002Perry27 June 2017Loss of Safety Function Due to Main Turbine Bypass Valve Opening
LER 17-002-00 for Perry Nuclear Power Plant Regarding Loss of Safety Function Due to Main Turbine Bypass Valve Opening

On April 30, 2017, at 1818 hours, while the plant was at 100 percent rated thermal power, main turbine steam bypass valve number 1 partially opened. Power was subsequently lowered in an attempt to close the bypass valve. While lowering power the bypass valve would shut and then reopen and power would again be lowered. When power was lowered to approximately 74 percent the bypass valve remained closed. During the transient the reactor protection system (RPS) trip functions for the main turbine stop valve closure and turbine control valve fast closure scram were declared inoperable due to the opening of the bypass valve, which changes the bypass setpoint for those RPS trips. With the loss of RPS trip capability. a loss of safety function existed intermittently for approximately 37 minutes. The manual reactor trip function and other RPS functions remained operable.

Both channels of the rod withdrawal limiter (RWL) and the end of cycle reactor recirculation pump trip (EOC-RPT) function were also declared inoperable. These functions are credited in accident analysis and this also resulted in a loss of safety function in accordance with the plants Technical Specification bases.

The direct cause of the bypass valve opening was degradation of the Primary Low Value Gate (PLVG) card in the main turbine speed control circuit.

The safety significance of this event is considered to be small. This event is not considered a safety system functional failure as the specific functions were maintained and never bypassed during the event. This event is being reported under 50.73(a)(2)(v)(A) and 50.73(a)(2)(v)(D) for a loss of safety function.

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.

05000219/LER-2016-002Oyster Creek16 March 2016
23 June 2017
Control Rod Drive Cooling Water System Isolation Scram Time Testing Was Not Performed
LER 16-002-01 for Oyster Creek Regarding Control Rod Drive Cooling Water System Isolation Scram Time Testing Was Not Performed

On 03/16/2016, it was identified that isolating or reducing cooling water to the Hydraulic Control Units (HCUs) for three control rods should have been considered a modification since it had the potential to impact the scram times of the control rods. Even though scram time penalties were applied for the three control rods where the cooling water flow was either isolated or reduced, failing to identify the isolation of cooling water to the control rods as a modification as described by the Technical Specifications resulted in the Plant not taking the action to scram time test the affected rods.

By not completing scram time testing for the control rods, whose cooling water was isolated or reduced, the station was in violation of the requirements of Technical Specifications Section 3.2, since the issue was not identified previously and the affected control rods were not declared inoperable and isolated.

  • This event resulted in an Operation or Condition that was Prohibited by the Plant's Technical Specifications (TS) and is therefore being reported under 10CFR50.73(a)(2)(i)(B).
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
05000458/LER-2016-003River Bend19 January 2016
8 June 2017
Operations Prohibited by Technical Specifications Due to Reactor Control Rod Drift During Core Alterations
LER 16-003-01 for River Bend Station, Unit 1, Regarding Operations Prohibited by Technical Specifications Due to Control Blade Drift During Core Alterations

On January 19, 2016, at 5:28 a.m. CST, while conducting core alterations, an alarm was actuated in the main control room alarm indicating that a reactor control rod had drifted out of the fully inserted position. At the time, a fuel bundle was being raised out of the core, and the control rod in the same cell drifted out one notch with no "withdraw" command present. This condition actuated a corresponding alarm on the refueling platform, and system interlocks stopped the platform hoist with the fuel bundle partially withdrawn. When the control rod moved from the fully inserted position, the Technical Specification applicability for the intermediate range neutron monitoring system was inadvertently entered, while a certain function of those instruments was not operable. This event constituted operations prohibited by Technical Specifications, and is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B). After a detailed assessment of the situation, the fuel bundle and the control rod were returned to their original positions. The drive mechanism for the control rod has been disabled, and the control rod will remain fully inserted for the remainder of the current fuel cycle. The causal analysis for this event will be completed when the control rod can be removed for inspection during the next refueling outage.

The results of that investigation will be provided in a supplement to this report.

05000397/LER-2016-004Columbia8 June 20171 OF 3
LER 16-004-01 for Columbia Generating Station Regarding Automatic Scram Due to Off-site Load Reject

On December 18, 2016 at 11:24 hours, an automatic scram occurred due to a fault on an off-site transmission network. A reactor scram was automatically initiated by the plant response to the transient.

All rods fully inserted, Main Steam Isolation Valves (SB,V) automatically closed due to loss of pow er to both Reactor Protection Sy stem (JC) busses. All safety sy stems operated as designed. Two Safety Relief Valves (SB,V) were initially cycled automatically, then several manually to maintain Reactor Pressure Vessel (AC) pressure. Reactor water level was maintained with Reactor Core Isolation Cooling (BN), Control Rod Drive (AA) flow, and High Pressure Core Spray (BG).

The cause analysis for the loss of off-site power is being performed by the entity responsible for the off-site transmission network, Bonneville Power Administration (BPA). BPA took immediate corrective actions to restore the off-site transmission network. The root cause evaluation addressing the plant response is being performed by plant personnel. A supplemental LER will be issued when the cause analyses are completed.

05000260/LER-2017-003Browns Ferry29 March 2017
30 May 2017
Manual Reactor Scram Initiated During Startup Due to Multiple Rods Inserting
LER 17-003-00 for Browns Ferry Nuclear Plant, Unit 2 Regarding Manual Reactor Scram Initiated During Startup Due to Multiple Rods Inserting

On March 29, 2017, at 1842 Central Daylight Time (CDT), during Unit 2 start-up, Operations personnel received annunciators for an Intermediate Range Monitor (IRM) Downscale and a Control Rod Withdrawal Block.

Operations personnel noticed that IRM `G' was reading downscale and adjusted the range down one position with no immediate reaction. At 1844 CDT, an upscale spike on IRM `G' caused a half scram on Reactor Protection System (RPS) 'A' trip system. After verifying that the IRM `G' High-High trip signal was cleared, Operations personnel reset the half scram on RPS 'A'. An immediate, concurrent trip signal from IRM 'F' was then received on the RPS '13' trip system, resulting in multiple rods inserting into the core. When Operations personnel identified multiple rods inserting, a manual reactor scram was inserted at 1844 CDT.

The root cause was determined to be a lack of performing electromagnetic and radio-frequency interference noise testing to detect nuclear instrumentation abnormalities.

Corrective Action to Prevent Recurrence is to perform routine pre-outage and outage-related preventive maintenance tasks for noise-induced cable tests to verify the noise has been removed.

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.

05000458/LER-2017-003River Bend10 March 2017
9 May 2017
Manual Reactor Scram Initiated in Response to Increase in Steam Pressure During Steam Leak Troubleshooting
LER 17-003-00 for River Bend Station, Unit 1, Regarding Manual Reactor Scram Initiated in Response to Increase in Steam Pressure During Steam Leak Troubleshooting

On March 10, 2017, at approximately 7:14 a.m. CST, the reactor operator manually actuated a reactor scram in response to an abnormal increase in steam pressure. Reactor power was approximately 15 percent at the time. The turbine generator had been synchronized to the grid at 5:13 a.m. on March 10, and was being closely monitored by engineers and operators since a major modification to the turbine electro-hydraulic control (EHC) system had been installed during the recent refueling outage.

Approximately 45 minutes prior to the manual scram, a main control room alarm actuated indicating a problem with the EHC system.

A few minutes later, it was reported from the turbine building that there was a steam leak in the area of the EHC steam pressure transmitters. Shortly thereafter, reactor pressure began to increase with no demand signal present, at which time the reactor operator initiated the scram. The main feedwater system remained in service, and reactor water level control performed normally as designed. No reactor safety-relief valves actuated. The main turbine bypass valves did not open following the shutdown, and engineering review determined this condition was consistent with the response to the abnormal configuration of the EHC system pressure transmitters created by efforts to isolate the leak locally. Approximately five minutes after the scram, the outboard main steam isolation valves were manually closed to limit the reactor cooldown rate. This event resulted from the incorrect installation of a new compression fitting in the steam pressure instrumentation tubing for the main turbine control system. This event is being reported in accordance with 10 CFR 50.73(a)(2)(iv)(A) as a manual actuation of the reactor protection system.