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On August 22, 2017 at 2321 hours central daylight time, Grand Gulf Nuclear Station entered Technical Specification (TS) conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal 'A' (RHR A) being declared inoperable. Entergy Operations Inc. (Entergy) made the decision to shut down the plant based on the results of troubleshooting performed on the RHR A pump. The A RHR pump TS differential pressure was out of specification (low) and could not be returned to acceptable limits.

Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on August 29, 2017, due to expected restoration of RHR A exceeding the completion time of 7 days prior to restoring Operability. The shutdown was completed and entry into MODE 3 occurred at 2217 hours CDT on August 29, 2017. The cause is under investigation and this LER will be supplemented upon completion of the causal analysis. Corrective Actions included the replacement of the A RHR pump and the successful retesting of the. A RHR pump and restoration of the pump to operable status. This condition is reportable as a completion of a plant shutdown required by the TS.

(4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

(See NUREG-1022, R.3 for instruction and guidance for completing this form htio://www.nrcoovireadino-rm/dcc-collectionenureosistafffsr1022;r31 APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported lessons learned are incorporated into the licensing process and fed back to Industry. Send comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to 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.

Grand Gulf Nuclear Station, Unit 1 05000 416

3. LER NUMBER

Description On August 22, 2017 at 2321 hours central daylight time (CDT), Grand Gulf Nuclear Station entered Technical Specification (TS) conditions for three Limiting Condition for Operations (LCOs) not met due to Residual Heat Removal (BO) 'A' (RHR A) being declared inoperable.

LCOs not met:

1) TS 3.5.1 for one low pressure ECCS injection/spray subsystem.

2) TS 3.6.1.7 for one RHR containment spray subsystem, and 3) TS 3.6.2.3 for one RHR suppression pool cooling subsystem.

Entergy Operations Inc. (Entergy) made the decision to shut down the plant based on the results of troubleshooting performed on the RHR A pump. Grand Gulf Nuclear Station initiated plant shutdown required by Technical Specifications 3.5.1, 3.6.1.7, and 3.6.2.3 at 1200 hours CDT on August 29, 2017, due to expected restoration of RHR A exceeding the TS completion time of 7 days prior to restoring Operability. The shutdown was completed and entry into MODE 3 occurred at 2217 hours CDT on August 29, 2017.

REPORTABILITY

Entergy completed Event Notification 52936 notifying the Nuclear Regulatory Commission of the commencement of a plant shutdown in accordance with 10CFR50.72(b)(2)(i), due to the anticipated inability to complete the required A RHR Pump repairs prior to exceeding the TS LCO time limits.

The completion of the shutdown reported in Event Notification 52936 is reportable in accordance with 10CFR50.73(a)(2)(i)(A), the completion of any nuclear plant shutdown required by the plant's Technical Specifications. LCOs not met:

1) TS 3.5.1 for one low pressure ECCS (BO) injection/spray subsystem.

2) TS 3.6.1.7 for one RHR containment spray subsystem, and 3) TS 3.6.2.3 for one RHR suppression pool cooling subsystem.

CAUSE

The A RHR pump TS differential pressure was out of specification (low) and could not be returned to acceptable limits prior to exceeding the 7 day limiting condition for operation time.

The A RHR pump was shipped to a vendor for the determination of the cause of the A RHR pump being out of specification limits. This causal analysis is not anticipated to be completed prior to the 60 day report time for this licensee event report (LER). This LER will be supplemented upon completion of the causal analysis.

CORRECTIVE ACTIONS

Replacement of the A RHR pump.

Successful retesting of the A RHR pump and restoration of the pump to operable status.

NRC FORM

(4-2017) 366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

(See NUREG-1022, R.3 for instruction and guidance for competing thIs.form httplAvww.nrc.dovireadino-rm(doc-coRectionsinurectsistaff/sr1022/r3/) APPROVED BY OMB: NO. 3150-0104 EXPIRES: 3/31/2020 Reported lessons learned are incorporated into the licensing process and fed back to industry. Send comments regarding burden estimate to the Information Services Branch (T-2 F43), U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001, or by e-mail to Regulatory Affairs, NEOB-10202, (3150-0104), Office of Management and Budget, Washington, DC 20503. If a means used to impose an information colIection does not display a currently valid OMB con:rol number, the NRC may not conduct or sponsor, and a person is not required to respond to, the information collection.

05000 416

SAFETY SIGNIFICANCE

The event posed no threat to the health and safety of the general public or to nuclear safety as safety-systems performed as designed. No Technical Specification safety limits were violated.

Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR OCCURRENCES

Removal Pump The causes and corrective actions associated with these previous similar events was reviewed and it is believed that the corrective actions could not have prevented the cause of this event.

On December 15, 2016, at 1500 (EST), with the reactor at approximately 22 percent power, the Main Steam Isolation Valves (MSIVs) 2C and 2D were discovered to have steam leaks while performing a steam tunnel walkdown. MSIV 2D, which had a body to bonnet steam leak, was declared inoperable and Technical Specifications (TS) Limiting Condition for Operation Action Statement (LCOAS) 3.7.A.2.b was entered at 1530 on December 15, 2016. Outboard MSIV 2D and inboard MSIV

• 1D both were closed and deactivated to isolate Main Steam Line D. On December 16, 2016, at 1524 (EST) Operations entered TS LCOAS 3.7.A.2.b for outboard MSIV 2C. Actions were also taken to close and deactivate the inboard MSIV 1C, which included a controlled plant shutdown to reduce reactor pressure below the MSIV closure scram bypass setpoint.

Based on the evidence found, it was reasonable to conclude that the MSIV 2D valve body to bonnet steam leak and the MSIV 2C packing leak had likely started sometime prior to the event date and both were leaking for a period of time greater than that allowed by TS. Therefore, PNPS is making this submittal in accordance with 10 CFR 50.73(a)(2)(i)(B), any operation or condition prohibited by the plant's TS. In addition, PNPS closed the inboard MSIV 1C in accordance with TS LCOAS 3.7.A.2.b prior to going to Cold Shutdown. However, PNPS is also conservatively making this submittal in accordance with 10 CFR 50.73(a)(2)(i)(A), the completion of any nuclear plant shutdown required by the plant's TS.

The plant was placed in Cold Shutdown and both the outboard MSIV 2C and 2D were repaired and returned to service.

There was no impact to public health and safety from this condition.

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

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

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

On September 4, 2016 at 02:58, Grand Gulf Nuclear Station entered three TS LCO Action Statements because RHR 'A' pump was declared inoperable.

LCO Actions entered:

1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem. All have 7 day Completion Times A decision was made to shutdown the plant to repair the RHR 'A' pump because, based on the troubleshooting and testing plan, the pump could not be repaired and returned to service within the LCO Completion Times. At 0300 CDT on 09/08/16, GGNS initiated the transition to Mode 4.

The pump was removed from service and sent to the vendor facility for decontamination, disassembly and failure analysis.

The 'A' pump was then replaced and tested satisfactorily. RHR 'A' was returned to operable.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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-mail to Intocollects.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 366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

2. DOCKET 3. LER NUMBER 05000 416

PLANT CONDITIONS PRIOR TO THE EVENT

At the time of the event, Grand Gulf Nuclear Station (GGNS) Unit 1 was in Mode 1, at 100% rated thermal power.

All systems, structures and components, with the exception of the RHR 'A' pump, that were necessary to mitigate, reduce the consequences of, or limit the safety implications of the event were available. No other safety significant components were out of service.

DESCRIPTION

On September 4, 2016, GGNS was performing a Residual Heat Removal (RHR) 'A' quarterly Technical Specification (TS) Surveillance Requirement (SR). At 02:58, The RHR pump failed to meet its TS SR Acceptance Criteria for flow and differential pressure (d/p) and was therefore declared Inoperable. Action Statements for TS Limiting Conditions for Operation (LCOs) 3.5.1, 3.6.1.7 and 3.6.2.3 were entered, each having Completion Times of 7 days.

LCO Action Statements entered:

1) 3.5.1 for one low pressure ECCS injection/spray subsystem, 2) 3.6.1.7 for one RHR containment spray subsystem, and 3) 3.6.2.3 for one RHR suppression pool cooling subsystem.

Initial troubleshooting verified that the pump was incapable of meeting the flow requirement of 7756 gpm and d/p of 131 psid simultaneously. The observed pump flow and discharge pressures were verified to be correct via a temporarily installed ultrasonic flow meter and pressure gauge. RHR system valves and lines were verified not to be clogged or leaking. The pump motor was confirmed to be operating at the proper speed.

Further troubleshooting and testing lead station management to the conclusion that RHR 'A' would not be returned to operable status within the 7 day Completion Time. A decision was made to commence an orderly shutdown. On September 8, 2016 at 0300, GGNS began the transition to Mode 4. No other systems were out of service that would have complicated an orderly shutdown to Mode 4.

REPORTABILITY

Event Notification No. 52225 was made to the U.S. Nuclear Regulatory Commission (NRC) Operations Center.

This LER is being submitted pursuant to Title 10 Code of Federal Regulations 10 CFR 50.73(a)(2)(i)(A) for the completion of any nuclear plant shutdown required by the plant's Technical Specifications. Telephonic notification was made to the NRC Emergency Notification System on September 8, 2016, at 03:27, pursuant to 10 CFR 50.72(b)(2)(i) for the initiation of any nuclear plant shutdown required by the plant's Technical Specifications.

CAUSE

Direct Cause: The RHR 'A' pump was unable to provide its required flow at the required differential pressure in order to perform its safety function.

APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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-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

NRC FORM

366A U.S. NUCLEAR REGULATORY COMMISSION

CONTINUATION SHEET

Grand Gulf Nuclear Station, Unit 1 05000 416 Apparent Cause: Subsequent investigation suggests internal pump degradation but the Apparent Cause is ongoing. A supplemental report to this LER will be provided when the Apparent Cause investigation is complete.

EXTENT OF CONDITION

Quarterly surveillance data of similar Emergency Core Cooling System (ECCS) pumps showed no evidence of degradation. Data was re-examined from the following pumps: Low Pressure Core Spray (LPCS), High Pressure Core Spray (HPCS) and RHR 'B' and 'C.' GGNS also performed a partial quarterly surveillance on the RHR 'B' which was completed satisfactorily.

CORRECTIVE ACTIONS

The RHR 'A' pump was replaced and retested satisfactorily. The pump removed from service has been sent to the vendor facility for failure analysis.

SAFETY SIGNIFICANCE

The event posed no threat to the health and safety of the general public or to nuclear safety as safety- systems performed as designed. No Technical Specification safety limits were violated. Industrial safety was not challenged, and there was no potential or actual radiological release during the event.

PREVIOUS SIMILAR EVENTS

Previous similar events. will be discussed in the supplemental report upon completion of the Apparent Cause investigation.

On November 30, 2015, a leak was discovered on Service Water (SW) weld F-1924, which joins a cement-lined carbon steel elbow to a Copper/Nickel (Cu/Ni) Heat Exchanger pipe nozzle on the 21 Component Cooling Water Heat Exchanger. Code case N-513-3 was applied to the pipe defect to justify, continued operability and preparations initiated for a weld repair during the upcoming spring refueling outage (RO) starting March 7, 2016.

'On. March 19, 2016, weld repair was performed on the weld F-1924 and satisfactory non- destructive examination was completed. On June 12, 2016, a new leak was discovered in the same SW pipe repair area. During the subsequent repair, cracking was experienced in the ERCuNi filler metal which extended the duration of the repair and forced a Unit shutdown to comply with the TS 72 hour AOT. The direct cause was recurring longitudinal solidification cracks that developed during welding of copper-nickel to carbon steel pipe. The apparent cause was that the team assigned to prepare and execute the weld repair plan failed to ensure all risks and issues were.identified and managed properly. Key corrective actions included weld repair using a new vendor weld procedure and ERNiCu-7 filler material, communication of the lessons learned to all site personnel reinforcing standards and expectations for readiness for critical work.

Incorporate recommendations for improving risk management process effectiveness by incorporating actions taken,in response to INPO IER L2-16-9. The event had no effect on public health and safetY". .. .

Indian Point 2 05000-247 APPROVED BY OMB: NO. 3150-0104 EXPIRES: 10/31/2018 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 Note: The Energy Industry Identification System Codes are identified within the brackets ().

DESCRIPTION OF EVENT

On November 30, 2015, a 1 drop per second leak was discovered on Service Water (SW) (BI) weld F-1924 on SW line #411, which joins a carbon steel elbow to a 90/10 Copper/Nickel (Cu/Ni) Heat Exchanger (HX) pipe nozzle on the 21 Component Cooling Water (CCW) (CC) Heat Exchanger (HX). In accordance with Generic Letter 89-13 program guidance and ASME Code case N-513-3 the weld was evaluated and determined acceptable but required to be repaired prior to start-up from the 2016 spring refueling outage (RO) (2R22). The degradation mechanism leading to the leak was likely crevice corrosion. Leakage was seen to emanate at the weld toe, on the carbon steel side. The leak was recorded in Indian Point Energy Center (IPEC) corrective action program (CAP) as CR-IP2-2015-05358 and repairs scheduled to be performed during the upcoming spring refueling outage (RO) starting March 7, 2016. The copper- nickel to carbon steel weld joints in the CCW to SW piping are the only known welds on site with this configuration. A flaw characterization and full pipe circumference examination of this weld found that the leak was a localized area of corrosion.

Another area of thinning at one other circumferential location on the same weld was identified, but the weld thickness in that area met minimum wall thickness requirements and was designated for continued monitoring with no immediate action necessary.

To support the weld repair plan, from December 17, 2015 to February 8,.2016, a draft Entergy Welding Procedure Specification (WPS) was developed for welding P34 90/10 copper-nickel base material to P1 carbon steel base material. ERNiCu-7 was chosen as the filler metal. Two separate weld test coupons were prepared to qualify the procedure and were shipped to the weld test lab (Lucius Pitkin Inc.) for procedure qualification testing. Test results were obtained on March 3, 2016, which showed one of the four bend tests failed due to inclusions in the root of the weld joint resulting in a failure to qualify the procedure. On March 4, 2016, vendors are contacted to determine if they have a qualified welding procedure for copper-nickel to carbon steel. Only one vendor (Westinghouse PCI) had a qualified procedure using the ERCuNi filler metal. Due to the limited time available to repeat the procedure qualification testing prior to scheduled work, the weld repair was contracted to the vendor with the approved qualified procedure for welding P34 90/10 copper-nickel to P1 carbon steel using the ERCuNi filler metal.

On March 7, 2016, the Unit 2 Refueling Outage (RO) started. Repairs to the 21 CCW Heat Exchanger SW line #411 pinhole leak were scheduled to be performed on March 18 through March 19, 2016. On March 19, 2016, weld repairs, including excavation, weld build-up, and post-repair non-destructive examination (NDE) of the flaw on weld F-1924 was completed. On June 4, 2016, a In-service Leak Test (ISLT) of the SW system was completed satisfactorily. No leaks identified.

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 intemet e-mail to On June 12, 2016, CR-IP2-2016-03818 recorded a new leak that was discovered in the same SW pipe line #411 repair area. The leak was estimated at 1 drop per 5 seconds in the SW System piping supplying the 21 CCW HX. The leak was on the elbow side at the toe of the elbow to inlet nozzle weld of the 21 CCW HX on 20 inch SW line #411, weld number F-1924. This line is the SW supply to the 21 CCW HX. SW line #411 is a standard wall (schedule STD) cement-lined carbon steel pipe having a nominal wall thickness of 0.375 inches. The nozzle/pipe of the 21 CCW HX is 90/10 copper/nickel with a thickness of 0.500 inches. Its function is the inlet pipe to the 21 CCW HX.

SW line #411 is fed from either 20 inch SW line #411 (1-2-3 SW Header), or 20 inch line #407 (4-5-6 SW Header). At the time of discovery, the 1-2-3 SW header was the essential header supplying the 21 CCW HX. Leaking weld F-1924 is a dissimilar metal butt-weld between a carbon steel cement-lined elbow and a copper-nickel heat exchanger inlet nozzle/pipe. The weld location is ASME Section XI Class 3 and is nuclear safety related. The SW pipe with the weld defect is located in the Primary Auxiliary Building (PAB) on the 80 foot elevation downstream of valve SWN-34.

Engineering performed an Operability Evaluation using the methodology and structural margins provide in ASME Code case N-513-3. The pipe weld degradation was determined to be within the Code Case limits. The affected pipe section was considered structurally acceptable therefore Operable DNC. An outage emergent team designated to address the leak determined after discussions with site departments that the leak did not have to be repaired until the next outage (2R23). The Mode 1 hold was removed from the leak repair Work Order and the repair was designated to be scheduled as soon as the work was ready to be performed.

On June 13, 2016, weld repairs were scheduled to be performed beginning June 21, 2016. Work migrated from the refueling outage schedule to the online schedule. The preliminary schedule included 24 hours for the weld repair based on vendor input and time estimates from the original 2R22 outage repair window. A leadership challenge meeting discussed the weld plan because the online weld repair requires entry into a Technical Specification (TS) 72 hour shutdown LCO due to removal of the 21 CCW HX from service.

On June 16, 2016, a conference call was held with the weld vendor to discuss the repair approach. The weld vendor and the Indian Point welding engineer concluded the failure of the original weld repair was caused by contamination of the weld and not as a result of any metallurgical issues with the vendor weld procedure.

Subsequent follow-up correspondence with the weld vendor questioned the possibility of hot cracking of the ERCuNi filler metal due to iron dilution from the carbon steel base material. The weld vendor's opinion was that using this process on this configuration would not result in hot cracking. Peer review by another Entergy site made the same conclusion. An Engineering Change was approved to repair the weld defect from both the inner diameter and outer diameter of the pipe using the vendor weld procedure on June 16, 2016. On June 16, 2016, at 23:30 hours, the unit returns to service following an extended refueling outage.

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 On June 17, 2016, a management challenge and critical evolution meeting (CEM) was held for the 21 CCW HX leak repair. At the CEM it was presented that the 2R22 outage repair failed due to weld contamination that occurred because the repair was attempted from the outside of the pipe only and since the cement lining surrounding the repair cavity was not accessible for adequate cleaning around the weld joint, resulting in contaminants becoming trapped in the weld that were not evident in the final exam. In addition, a surface exam of the root pass was not specified to be performed to ensure proper weld integrity below the surface of the finished weld.

Assurance was provided that the new plan would be successful due to a change in work scope (internal access to the defect area, allow proper removal of cement lining, clean affected area, perform a surface exam, weld build-up, adequate access for purging and inspection/repair). The CEM also identified that the contingency Enecon coating of internal piping following weld repairs was an excessive time contributor. Therefore, the plan was altered to use a quick curing waterplug coating repair to the inner piping wall.

On June 21, 2016, the TS 3.7.7 LCO was entered when the 21 CCW HX was declared inoperable for scheduled maintenance. Work to repair the weld commenced. On June 22, 2016, during installation of the remainder of the copper-nickel to carbon steel weld, workers identified repeated cracking problems and could not successfully complete the weld. A leadership team conference was held to discuss the cracking problem and determine a resolution plan. A decision was made to implement a revised plan to grind out the defective copper-nickel to carbon steel weld area, perform a PT exam on the excavated area, weld out the excavated area using a modified transverse technique across the root gap and perform a final PT and UT.

On June 23, 2016, weld repairs were completed in accordance with the revised plan.

During the final inspection of the weld, the qualified inspector rejected the weld based on incomplete weld penetration and appearance on the inside diameter (ID) of the piping in the weld area. CR-IP2-2016-04085 recorded the unsatisfactory condition of poor weld quality. Follow-up engineering discussions with the fleet welding engineer and qualified inspector determined that the internal weld could not be accepted and the weld would have to be removed and re-welded. At 14:30 hours, the outage control center (OCC) issued a schedule update indicating that the 72 hour TS AOT will expire prior to completing the revised plan for weld repairs and restoration of the 21 CCW HX.

On June 24, 2016, at 04:00 hours, the TS 3.7.7 AOT expired forcing a unit shutdown.

The SW System (SWS) is designed to supply cooling water from the Hudson River to various heat loads in both the primary and secondary portions of the plant. The design ensures a continuous flow of cooling water to those systems and components necessary for plant safety during normal operation and under abnormal or accident conditions. The SWS consists of two separate, 100% capacity, safety related cooling water headers. Each header is supplied by 3 pumps to include pump strainers, with SWS heat loads designated as either essential or non-essential.

The essential SWS heat loads are those which must be supplied with cooling water immediately in the event of a Loss of Cooling Accident (LOCA) and/or Loss of Offsite Power (LOOP). The essential SWS heat loads can be cooled by any two of the three SW pumps on the essential header. Either of the two SWS headers can be aligned to supply the essential heat loads or the non-essential SWS heat loads.

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 intemet e-mail to The CCW System (CCWS) is a closed loop cooling system that provides cooling water for systems and components important to safety. The CCWS transfers its heat load to the SWS via heat exchangers. The SWS is a once through cooling system that transfers its heat load. to the ultimate heat sink (Hudson River). The CCWS consists of three pumps and two heat exchangers. These components are divided into two independent, full capacity cooling loops with each loop consisting of one pump and one heat exchanger.

The principal safety related function of the CCW System is the removal of decay heat from the reactor via the Residual Heat Removal (RHR) System during a normal or post accident cooldown and shutdown. The design basis of the CCW System is for one CCW train to remove the post loss of coolant accident (LOCA) heat load from the containment sump during the recirculation phase of a LOCA.

An extent of condition (EOC) review determined that the copper-nickel to carbon steel dissimilar weld configuration is unique to the 21 and 22 CCW HX inlet and outlet SW piping. The 31 and 32 CCW HX inlet and outlet nozzles are rubber-lined carbon steel flanged piping and are not susceptible to the same failure mechanism. CCW HX SW piping weld EOC inspections at five similar locations were completed. No, new problems or degraded conditions were identified.

CAUSE OF EVENT

The direct cause was recurring longitudinal solidification cracks that developed during welding of copper-nickel to carbon steel pipe. The primary degradation mechanism leading to the November '30, 2015 leak Was likely crevice corrosion, caused by small holidays in the internal coating at the field weld that allowed SW to contact the internal piping base metal. The corrosion promoted thinning in the affected area, which resulted in the development of a pin hole at the weakened toe of the carbon steel elbow to copper-nickel inlet nozzle field weld on the carbon steel. Surface exams performed during the RO repairs did not identify any defects. However, potential subsurface flaws would not be detected using the surface exam technique.

During the RO and the June 2016 post outage repair work, repairs to the leaking indication initially used ERCuNi filler metal to restore the weld integrity. This method resulted in strain-induced longitudinal cracking in the highly restrained joint due to the relatively low tensile strength of the material, its thermal conductivity differences with carbon steel, and its susceptibility to iron dilution from steel, which can increase the tendency for brittle fracture.

Standard industry practices to reduce cracking tendencies prior to joining dissimilar metals with filler material were not identified in the repair plan.

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 intemet e-mail to The apparent cause was that the team assigned to prepare and execute the weld repair plan failed to ensure all risks and issues were identified and managed properly.

This apparent cause resulted in this condition because risks were not identified and work planning and scheduling did not include effective contingencies or back-out criteria. Key team members contributing to work preparations did not effectively perform their roles and responsibilities. There was inadequate preparation and lack of rigor during planning and challenge reviews for the critical work activity.

CORRECTIVE ACTIONS

The following corrective actions have been or will be performed under the Corrective Action Program (CAP) to address the causes of this event:

• A vendor (PCI) qualified a new copper-nickel to carbon steel weld procedure using a different filler metal (ERNiCu-7) with better performance characteristics based on industry best practices. An Engineering Change (EC) was developed to eliminate the weld stresses that were contributing to the observed in-process weld cracking. The defective weld and degraded piping section was cut out and replaced with a flush welded patch according to the new EC using the new filler metal (ERNICu-7) and the newly qualified vendor (PCI) welding procedure. All welds were inspected according to the code-required visual and surface examinations. The completed weld was leak tested and the 21 CCW HX returned to service.

• The lessons learned from this event were discussed at the work week critique and were communicated site-wide during all-hands meetings and through distribution of the weekly newsletter. The message reinforced standards and expectations for ensuring readiness.

• A System Outage Critique will be performed in accordance with EN-FAP-WM-003 to communicate lessons learned with individuals involved with the weld repair outage.

• Incorporate recommendations for improving risk management process effectiveness by incorporating actions taken in response to INPO IER L2-16-9 Revision 0.

EVENT ANALYSIS

The event is reportable under 10CFR50.73(a)(2)(i)(A). The licensee shall report the completion of any nuclear plant shutdown required by the plant's Technical Specification (TS). The event meets the reporting requirement because on June 24, 2016, at 04:00 hours, operations implemented actions to commence reactor shutdown to comply with TS 3.7.7 (CCW System).

Indian Point 2 05000-247 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 intemet e-mail to TS 3.7.7 LCO requires two CCW trains to be Operable. TS 3.7.7 Condition A (One CCW train inoperable) required action A.1 is to restore the inoperable CCW train to operable within 72 hours. TS 3.7.7 Condition A was entered on June 21, 2016, at 02:30 hours, when the 21 CCW HX was declared inoperable for scheduled maintenance.

On June 24, 2016, at 04:00 hours, the TS 3.7.7 AOT window expired forcing a unit shutdown to comply with TS 3.7.7 Condition B which requires the plant to be in Mode 3 within 6 hours and Mode 4 within 12 hours. On June 24, 2016, at 7:59 hours, a manual reactor shutdown was completed and the plant entered Mode 3. At 12:58 hours, the plant entered Mode 4. On June 24, 2016, at 04:05 hours, a four hour non-emergency notification was made to the NRC (Log Number 52039) for a TS required shutdown. On June 26, 2016, at 14:11 hours, the 21 CCW HX was declared operable and TS 3.7.7 Condition B exited. Operations commenced plant start-up. Unit entered Mode 1 on June 27, 2016, at 15:01 hours. The event was recorded in the Indian Point Energy Center corrective action program (CAP) as CR-IP2-2016-04118.

PAST SIMILAR EVENTS

A review of the past three years of Licensee Event Reports (LERs) for events that involved a TS required shutdown due to faulty SW pipe repair. No applicable LERs were identified.

SAFETY SIGNIFICANCE

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

There were no actual safety consequences for the event because there were no events impacting redundant components.

There were no significant potential safety consequences of this condition. The CCW System provides a heat sink for the removal of process and operating heat from safety related components during a design basis accident (DBA) or transient. The CCW System consists of three pumps and two heat exchangers. The CCW pumps are connected to a common discharge header that is arranged so that any of the three pumps will supply either CCW heat exchanger and the heat exchangers are connected to a common discharge header so that both heat exchangers supply all CCW System heat loads. Any one of the three CCW pumps in conjunction with any one of the two CCW heat exchangers is sufficient to accommodate the normal and post-accident heat load. For this event one CCW Heat Exchanger was removed from service to perform a weld repair. The remaining redundant CCW HX and associated components were operable and available to perform their safety function.

A risk evaluation was performed to estimate the increase in core damage probability (CDP) and large early release probability (LERP) using a baseline zero maintenance plant configuration and the 21 CCW HX outage time of 5 days. The results of the risk evaluation concluded the risk impact associated with the inoperability of the 21 CCW Heat Exchanger is non-risk significant per NRC Regulatory Guide 1.177 (i.e., the increase in CDP is less than 1E-6/year and the increase in LERP is less than 1E-7/year) Indian Point 2 05000-247 Na

At 2100 hours, on January 23, 2016, the Perry Nuclear Power Plant (PNPP) commenced a reactor shutdown to investigate unidentified leakage in the drywell. At 2122 hours, drywell unidentified leakage exceeded Technical Specification (TS) limits necessitating a plant shutdown as required by TSs. At 0357 hours, on January 24, 2016, while performing the shutdown required by plant TSs, the average power range monitors (APRM) became inoperable due to a calibration setpoint being out of tolerance in the nonconservative direction following a transfer of the reactor recirculation pumps to slow speed. This resulted in a loss of safety function for the APRMs. At 1007 hours, on January 24, 2016, with the plant at 8 percent power, during a feedwater shift to place the motor feed pump in service, reactor water level rose to the level 8 setpoint and the reactor protection system (RPS) automatically initiated, shutting down the reactor. Following the shutdown, a small leak was identified on the reactor recirculation loop "A" pump discharge valve vent line. The recirculation loop is part of the reactor coolant system; this resulted in a degraded condition and a condition prohibited by TS due to pressure boundary leakage.

The cause of the recirculation loop vent line leak was that the weld connecting the root appendage was not performed per the design drawing. The APRM calibration issue was caused by a change to the feedwater flow input to the heat balance. The cause of the reactor level rise and subsequent high water level scram was due to operator error in monitoring and manipulating feedwater system indications and controls.

The safety significance of this event is considered to be small. These events are being reported under; 50.73(a)(2)(i)(A), for completion of any plant shutdown required by the plant's TS; 50.73(a)(2)(ii)(A) for a condition resulting in the plant's principle safety barrier being seriously degraded; 50.73(a)(2)(i)(B) for a violation of Technical Specifications; 50.73(a)(2)(iv)(A) for actuation of the RPS while critical; and 50.73(a)(2)(v)(A) for a loss of safety function.

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

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

The valve was tightened which reduced the leakage to 60 drops per minute. The flange gasket was replaced.

Additional causes and corrective actions are still being determined.

On August 13, 2014, while performing scheduled maintenance on Unit 2 Emergency Diesel Generator (EDG) 2-2, Diablo Canyon Power Plant (DCPP) identified a failed Inlet-to-Fuel-Header capscrew on Engine Cylinder 1L. As part of subsequent inspections to determine whether a similar condition existed on any of the other Unit 1 or Unit 2 EDGs, a degraded capscrew was identified on EDG 2-3 Cylinder 8L.

No capscrew issues were identified on the Unit 1 EDGs or on Unit 2 EDG 2-1. EDG 2-3 was declared inoperable at 1631 on August 14, 2014, resulting in two of three EDGs being inoperable at the same time, which requires ensuring at least two EDGs are operable within 2 hours, or be in Mode 3 within the following 6 hours.

Although the capscrew on EDG 2-3 was successfully replaced within 2 hours, during fuel system fill and vent following corrective maintenance, a fuel oil leak from the belt driven fuel oil booster pump occurred. Because repairs of EDG 2-3 could not be completed within the time permitted by Technical Specification 3.8.1 for two EDGs inoperable, a Unit 2 plant shutdown commenced. On August 14, 2014, at 2351 hours, Unit 2 entered Mode 3.

The cause of the failed capscrew on EDG 2-2, and the degraded capscrew on EDG 2-3, was determined to be high cycle fatigue. The cause of the fuel oil booster pump leak was determined to be a manufacturing defect combined with high seal annulus pressure during fuel oil system priming. Corrective actions include replacement of all capscrews with an improved material design, and incorporation of updated vendor guidance and updated fuel system priming instructions into station procedures.

This event did not adversely affect the health or safety of the public.

On April 2, 2014, at 1228 hours, a Fire Alarm System (FAS) alarm was received for the Unit 2 D heater bay area. Although entry into the room at the time identified only a steam leak, subsequently various spurious alarms and electrical system anomalies occurred.

At 1303 hours, Unit 2 was manually scrammed, the turbine was tripped, and the main steam isolation valves (MSIVs) were closed to ensure the steam leak was isolated. A fire was identified to have occurred in the D heater bay (an area of the plant containing the high pressure (final stage) D feedwater heaters, and several Unit 2 cable trays and risers). The fire was extinguished by the automatic wet pipe sprinkler fire suppression system.

At 1340 hours, due to the manual de-energizing of safety-related motor control center (MCC) 29-1 in the reactor building in response to notification that smoke had been observed, an ALERT level Emergency Action Level classification was declared as HA3 (fire in a vital area affecting safety system equipment). The emergency was terminated at 2132 hours.

The cause of the event was an existing cable flaw that was caused by cable routing that exceeded the required minimum static bend radius.

Corrective actions included repairing impacted cables, replacing the failed steam seal expansion joint, operating procedure revisions, and additional inspections/tests.

The safety significance of this event was minimal. Given the impact on multiple systems, this report is submitted in accordance with 10 CFR 50.73 (a)(2)(iv)(A) for manual or automatic actuation of any of the systems listed in paragraph (a)(2)(iv)(B); in accordance with 10 CFR 50.73 (a)(2)(v)(D) for an event that could have prevented the fulfillment of the safety function of systems needed to mitigate the consequences of an accident; and in accordance with 10 CFR 50.73(a)(2)(i)(A), for the completion of a nuclear plant shutdown required by the plant's Technical Specifications.

On January 30, 2014 at 2313, with Millstone Power Station Unit 2 (MPS2) in MODE 1 and at 100% reactor power, the circuit breaker for the group 1 pressurizer proportional heaters tripped. With the 'B' emergency diesel generator out of service for its maintenance outage and therefore inoperable, Technical Specification Action Statement (TSAS) 3.4.4 action b was entered. TSAS 3.4.4 action b requires MPS2 be in at least HOT STANDBY (MODE 3) with the reactor trip breakers open within 6 hours and in HOT SHUTDOWN (MODE 4) within the following 6 hours, unless one group of proportional heaters is restored to operable status. MPS2 completed the shutdown to MODE 3 at 0457 and restored the group 1 proportional heaters to operable status at 0747 on January 31, 2014. The initiation of the shutdown was reported to the NRC (event number 49779) pursuant to 10 CFR 50.72(b)(2)(i) - The initiation of any nuclear plant shutdown required by the plant's technical specifications.

After troubleshooting, faulty heater leads were lifted to remove a failed heater from service. Following appropriate testing, the group 1 proportional heater and the pressurizer were declared operable and MPS2 was subsequently returned to service.

This condition is being reported pursuant to 10 CFR 50.73(a)(2)(i)(A) - The completion of any nuclear plant shutdown required by the plant's technical specifications.

On January 11, 2014 at 14:53 CST, Farley Nuclear Plant (FNP) Unit 2 completed a shutdown from 100 percent power to Mode 3 to comply with Required Actions of Technical Specifications 3.3.1 (Reactor Trip System Instrumentation) and 3.3.2 (Engineered Safety Feature Actuation System Instrumentation). These Required Actions had been voluntarily entered on January 10, 2014 at 0919 CST in order to perform periodic logic surveillance testing on the B-Train Solid State Protection System (SSPS). FNP was unable to rectify logic testing failures encountered during the testing within the time requirements of the Required Actions, necessitating the shutdown. This shutdown is reportable under 10 CFR 50.73(a)(2)(i)(A). Subsequent troubleshooting identified the direct cause of the logic test failures to be due to foreign material causing an intermittent short between two logic card connector pins. Following removal of the foreign material the SSPS was restored to operable status and Unit 2 was restarted on January 14, 2014. The root cause of this event was determined to be that station leadership did not appropriately manage the risk associated with past indeterminate SSPS failures. Corrective actions include an intensive inspection of both units' SSPS cabinets for foreign material, to revise troubleshooting procedures to include component validation during troubleshooting and to establish a practice of timely issue resolution when the direct cause of a failure was not validated during initial troubleshooting.

RC FORM 366 (01.2014) 05000 364

On October 18, 2013 at 1141 Central Daylight Time (CDT), the Class 1E electrical equipment air conditioning unit, SGKO5A, was declared nonfunctional due to low lube oil pressure on the SGKO5A compressor. As a result, Technical Specification (TS) Limiting Condition for Operation (LCO) 3.0.3 was entered and a plant shutdown was commenced. Mode 3 was entered on October 18, 2013 at 1735 CDT.

The cause of the SGKO5A failure was a loss of lube oil pressure sensing to the pressure switch of the SGKO5A compressor. Contaminates in the system caused the loss of lube oil pressure sensing to the pressure switch. An inadequate flush and restoration of the system in May 2013 allowed contaminates to remain in the system.

SGKO5A was returned to a functional status on October 21, 2013 at 1915 CDT. Wolf Creek Generating Station returned to Mode 1 on October 27, 2013 at 2007 CDT.

On September 5, 2013, Unit 2's Control Element Assembly (CEA) #27 dropped to the fully inserted position while the CEA was being operated as part of a surveillance test. Operators entered applicable Technical Specifications for the dropped CEA. When operators were unable to restore the CEA to its proper alignment within the required Completion Time, operators commenced a reactor shutdown in accordance with Technical Specification Required Action 3.1.4.F.1. The unit was shutdown at 1735 on September 5, 2013. Troubleshooting identified Control Element Drive Mechanism (CEDM) #27 lift coil lead wire was grounded internally to the coil housing due to a chafed wire. The root cause for the dropped CEA was determined to be a manufacturing defect that resulted in circumferential displacement of the coil within the coil housing-and the misalignment of the lift coil lead wire within the coil housing nipple. Corrective actions included replacement of the CEDM coil stack with one that includes a change in design featuring a protective heat shrink wrap at the point where the lead wire penetrates the coil housing nipple. All other Unit 2 CEDMs were meggered with satisfactory results. A detailed plan to replace the remaining Unit 2 CEDM coil stacks is being developed.

Replacement of the Unit 2 coil stacks is expected to begin during the 2015 refueling outage.

On May 6, 2013 at 1733 Central Daylight Time (CDT), the Class 1 E electrical equipment air conditioning unit, SGKO5A, was declared nonfunctional due to an increasing temperature trend in the 'A' train safety related electrical equipment room. As a result, Technical Specification Limiting Condition for Operation 3.0.3 was entered and a plant shutdown was commenced.

Wolf Creek Generating Station (WCGS) entered Mode 3 on May 7, 2013 at 0009 CDT.

Damage to the liquid line filter drier assembly was caused by over tightening of the wing screw that holds the assembly together. This caused the partial blockage of the thermostatic expansion valves feeding the SGKO5A evaporator coils resulting in the temperature increase in the 'A' train safety related electrical equipment room.

The thermostatic expansion valves and filter drier assembly were replaced and WCGS returned to Mode 1 on 5/13/2013 at 0832 CDT.

On April 27, 2013, LaSalle Unit 1 was in Mode 2 (Startup) following a forced outage. At 1800 hours CDT, during a walk down of the drywell, a steam leak was observed coming from the Reactor Core Isolation Cooling Steam Supply Inboard Isolation Bypass/Warm up Valve (1E51-F076), a normally-closed, one inch, motor operated valve. The leak was determined to be on the valve bonnet extension-to-bonnet upper seal weld. At 2124 hours CDT the leak was classified as reactor coolant pressure boundary leakage, and Technical Specification (TS) 3.4.5 Condition C was entered. TS 3.4.5 Required Actions C.1 and C.2 require that the unit be in Mode 3 within 12 hours, and Mode 4 within 36 hours.

Unit 1 entered Mode 4 at 0841 hours on April 28, 2013, as required by TS 3.4.5 to allow for repair of the leak on 1E51-F076.

The apparent cause was a weld defect or discontinuity from the original weld construction (i.e., manufacturing, installation/construction errors, etc.) of the upper seal weld that propagated through wall as a result of system loading and conditions (i.e., high pressure steam) during normal plant operations. Corrective actions included repair of the defective seal weld area.

At 13:46 on August 12, 2012, Millstone Power Station Unit 2 (MPS2) completed a controlled plant shutdown from Mode 1 to Mode 3 (Hot Standby) as required by plant Technical Specification (TS) 3.7.11 Ultimate Heat Sink. TS 3.7.11 stipulates the ultimate heat sink shall be operable with a water temperature of less than or equal to 75 degrees F. TS 3.7.11 Action a. allows continued plant operation when ultimate heat sink (UHS) temperature is between 75 degrees F and 77 degrees F, provided UHS temperature averaged over the previous 24 hours is verified to be less than 75 degrees F once per hour. Otherwise, be in Hot Standby within the next 6 hours and in Cold Shutdown within the following 30 hours.

The UHS for MPS2 is Long Island Sound. The UHS temperature had initially gone above the temperature limit at 16:30 on August 11, 2012, but had cooled below the limit based on environmental factors. At 00:44 on August 12, 2012 the UHS temperature again rose above the TS limit and operators initiated a plant shutdown as required by plant TS 3.7.11. At 02:55 the Shift Manager directed that power be stabilized at 65% power since UHS temperatures had cooled below the TS limit. Plant power was held at approximately 65% power until 08:35 on August 12, 2012 when temperature again rose above the UHS limit. The Shift Manager directed completion of the plant shutdown from Mode 1 to Mode 3, completed at 13:46 on August 12, 2012. The UHS temperature continued to cycle above and below the TS limit. The plant entered Mode 5 Cold Shutdown at 22:31 on August 13, 2012. This condition is being reported pursuant to 10 CFR 50.73(a)(2)(i)(A) "the completion of any nuclear plant shutdown required by the plant's technical specifications".

On July 17, 2012, Reactor Coolant System pressure boundary leakage was determined to exist on Unit 1 11A Reactor Coolant Pump differential pressure transmitter tubing. Operators commenced a Technical Specification required unit shutdown. With reactor power at 10 percent a containment entry was made to isolate the leak. This effort stopped the steam emanating from the insulated tubing. Unit 1 returned to full power. Unit 1 leak rate data was monitored for the next several days. It was determined conditions did not improve as expected.

An additional containment entry was made on July 21, 2012 which identified that Reactor Coolant System pressure boundary leakage existed past the previously shut isolation valves.

Operators conducted a Technical Specifications required shutdown of Unit 1 to MODE 5. The source of the leak was a crack in the tubing side weld of the pipe to tube adapter. The cause of the leak was high cyclic fatigue. The cyclic fatigue was caused due to a vertical support for the tubing that was not connected. Corrective actions included replacement of the adapter, the affected portion of tubing, and the connection of a re-engineered vertical support. The similar welds on the other Unit 1 reactor coolant pump differential pressure transmitter tubing runs were inspected with no issues identified. Unit 1 returned to full power on July 25, 2012.

On December 9, 2011, at 0908, Nine Mile Point Unit 2 (NMP2) was operating at 100 percent of rated thermal power when alert alarms were received for containment monitoring particulate channels. These alarms were accompanied by a rise in unidentified drywell leakage and drywell pressure. At 1046, a manual shutdown of Unit 2 was initiated due to exceeding the Technical Specification (TS) Limiting Condition for Operation for unidentified leakage in the drywell. TS 3.4.5 requires action to be taken if unidentified leakage increases > 2 gpm within a 24 hour period while in Mode 1. Peak drywell floor drain leakage was 3.7 gpm. Entry into the drywell revealed a packing leak from the Reactor Coolant System (RCS) "A" blocking valve 2RCS*MOV18A.

The valve stem packing leak occurred due to a score in the packing material created by a burr on the valve stem. The burr was created during packing replacement in August 2011 when the plant was shutdown due to high unidentified drywell leakage from the packing of this same valve.

The root cause of this event was that Nine Mile Point leadership did not exhibit a questioning attitude toward potential error likely situations. Leadership did not appropriately identify situations where precursors, such as lack of adequate procedure details and environmental conditions, were challenges to workmanship.

On September 26, 2011, at 0158 hours, the unit 1 startup transformer was taken out of service to perform scheduled maintenance. The unit 2 startup transformer and the manual unit 1 backfeed lineup were OPERABLE and were considered to be the two qualified offsite circuits required by Technical Specifications (TS). Further review of this configuration determined that the backfeed lineup could not be credited as a qualified offsite circuit. This review also revealed that required TS actions were not completed when the startup transformer was declared inoperable on September 26, 2011. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(B) as an operation or condition which was prohibited by the plant's TS.

Transformer maintenance was secured and the unit 1 startup transformer was returned to service.

Subsequently the transformer tripped due to an internal fault.

On October 2, 2011, at 0100 hours, a planned shutdown was commenced to repair the unit 1 startup transformer. On October 2, 2011, at 1614 hours, plant shutdown was completed by manual actuation of the Reactor Protection System. This event is being reported in accordance with 10 CFR 50.73(a)(2)(i)(A) for completion of any nuclear plant shutdown required by the plant's TS. Corrective actions for these events include approval of a License Amendment to clarify the use of a delayed access circuit as a qualified offsite circuit and installation of a replacement startup transformer. The safety significance of these events is considered to be small.

At 0152 on August 6, 2011, the containment gaseous radiation monitors went into alarm and it was identified that Reactor Coolant System (RCS) unidentified leakage was increasing. At 0205, a Technical Specifications Condition was entered for RCS unidentified leakage increase above the specified limit. The RCS unidentified leakage peaked at 11.35 gpm, which resulted in an Unusual Event being declared due to reaching an Emergency Action Level (unidentified leakage greater than 10 gpm). At 0227, commenced lowering reactor power. Reactor power was reduced to 20% and, at 0941, the Reactor Protection System was manually actuated by placing the reactor mode switch in the Shutdown position. The unidentified leakage was due to a packing leak from the "A" RCS pump discharge blocking valve. The cause of the packing leak was determined to be vibration/turbulent flow that caused packing relaxation and failure. The valve packing was replaced, torqued and the gland follower nuts were secured in place. The packing for other similar valves was re- torqued and the gland follower nuts were secured in place.

A Preventive Maintenance Surveillance Test (PMST) activity will be created to re-torque the packing for RCS pump blocking valves every two years. Additionally, a modification will be implemented to install a live loading design on the RCS pump blocking valves in an upcoming outage.

There have been two other similar LERs involving RCS valve packing leakage: Nine Mile Point Unit 1 LER-2006-001 and Nine Mile Point Unit 2 LER-2001-007.