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On July 25, 2006 during the review of planned maintenance work packages, it was discovered that the Residual Heat Removal (RHR) to Safety Injection (SI) flow transmitters required by the Technical Specification post accident monitoring (PAM) instrumentation have as one of their power sources the opposite diesel generator train as the RHR pump whose flow they monitor. A potential loss of electrical power scenario could have caused a loss of the "A" RHR Pump and flow indication for the "B" RHR Pump. The same condition existed for the "B" RHR Pump and flow indication for the "A" RHR Pump. This condition had been in place since original plant design and construction.

This report is being made under 10CFR50.73(a)(2)(i)(B).

Corrective action to address the potential failure mode is outlined in Section V.

NRC FORM 366 (6-2004) PRINTED ON RECYCLED PAPER (1-2001) R. E. Ginna Nuclear Power Plant 05000244 2� of� 5 ;

On October 3, 2011, during performance of the quarterly surveillance test of the Containment Fan Cooler Unit (FCU) cooling water flow, all five FCUs failed to meet minimum flow requirements with the essential service water (SW) header (1/2/3 header) supplied by the 22 and 23 SW pumps. Operations entered Technical Specification (TS) 3.0.3 per TS 3.6.6.F for 3 trains of FCUs inoperable. In accordance with TS 3.0.3 operations initiated actions to place the plant in Mode 3 within 7 hours. Operations initiated turbine load reduction by approximately 5 MW and swap of the essential SW supply to the 4/5/6 header.

Upon completion of the essential header swap, operations re-performed the quarterly surveillance test on the 4/5/6 header with satisfactory results. Based on successful completion of the test, Operations exited the TS 3.0.3 action statement and commenced power ascension to 100% power. The direct cause was excessive accumulation of silt in the SW Bay that resulted in degraded inlet flow to the SW pumps. The root cause was ineffective barriers established to monitor and remove silt accumulations that would affect SW pump Net Positive Suction Head (NPSH) margin failed to include predictive elements that account for changing environmental conditions. Corrective actions included sonar mapping and de-silting of the SW Bay. The sonar mapping frequency will be increased and the SW System Monitoring Plan will be revised to include alert and action levels for silt buildup. A comprehensive silt monitoring and mitigation plan will be developed to include predictive trending and monitoring methods. The event had no significant effect on public health and safety.

On December 20, 2015, operator investigations identified service water (SW) leakage in containment and on December 22, 2015 discovered a through wall leak on a socket welded elbow for the 21 Fan Cooler Unit (FCU) motor cooler SW 2 inch copper-nickel return line.

The leak was located in a pipe fitting that is within the ASME Section XI Code ISI Class 3 boundary and estimated to be

• approximately-1 gpm.

Since the pipe flaw was through wall and was located within the ASME Section XI boundary, it exceeded the flaw allowable limits provided per IWD-3000. Engineering determined that since the through wall flaw was located on a socket welded fitting, the ASME Code Case N-513-3 did not apply.

The 21 FCU was declared inoperable and Technical Specification (TS) 3.6.6 (Containment Spray and Containment FCU System), entered for one FCU train inoperable and TS 3.6.1 Condition A entered for containment inoperable.

The 21 FCU SW return line was isolated.

The pipe is part of a closed loop system inside containment and is required to meet containment integrity. Since a containment leakage evaluation was not performed, the pipe flaw -was conservatively assumed to result in post-accident containment out leakage in excess of the 10CFR50, Appendix J limits resulting in violation of the containment integrity requirements and therefore is a safety system functional failure.

The direct cause was flow assisted erosion-corrosion. The apparent cause was high SW flow conditions that caused high localized velocities and flow separation at the sharp interior edge of the socket welded fitting.

Corrective actions included replacement of the affected fitting.

The faulted fitting was sent out to a vendor for metallurgical failure analysis.

The procedure for FCU SW flow balanced will be revised to reduce the SW flow in FCU motor coolers. The event had no significant effect on public health and safety.

FACILITY NAME (1) PAGE (3) DOCKET (2) LER NUMBER (6)

Ground test devices (GTD), installed in the Unit 3 startup transformer breaker cubicles during startup transformer maintenance, would cause the Unit 3 emergency diesel generators (EDG) to respond to a loss of offsite power (LOOP) in droop mode instead of isochronous mode. In droop mode, EDG steady state output frequency would be less than that required by Technical Specification (TS) Surveillance Requirement (SR) 4.8.1.1.2; and, therefore, both Unit 3 EDGs are considered inoperable during startup transformer maintenance. It was also determined that, with a GTD installed in the A or B Intake Cooling Water (ICW) pump or the Component Cooling Water (CCW) pump switchgear cubicle, no ICW or CCW pump would be automatically loaded during sequencer loading onto the associated EDG under LOOP conditions. Therefore, the A or B ICW or CCW pump, with the GTD device installed in its associated cubicle,' and the ICW or CCW pump on the swing D Bus switchgear, would both be considered inoperable.

The cause of this event was due to a misunderstanding of the effect of the GTD used in the 4 kV cubicles on associated EDG and 4 kV switchgear control circuits, and a procedural deficiency that did not include this precaution. Procedures have been revised to install appropriate jumpers, when GTDs are installed in associated 4 kV cubicles, prior to the next maintenance or test.

I

On March 8, 2006 at approximately 1553, a loss of the Unit 3 3A 4 kV electrical distribution bus occurred during restoration of the 3C load center (LC) following outage maintenance. The 3A load sequencer performed bus load stripping and a loss of offsite power to the 3A bus occurred due to a degraded voltage 1 condition that was sensed on the 3C LC. This was caused by a misaligned auxiliary switch contact on the newly refurbished 3C 480V LC feeder breaker (30302). The 3A emergency diesel generator automatically started and restored power to the 3A bus; however, the 3C LC 4 kV supply breaker (3AA14) failed to close due inadequate contact wipe on normally closed relay contacts. Core cooling was reestablished at approximately 1600 utilizing the 3B residual heat removal (RHR) pump. The cause was vendor human error during breaker refurbishment of the 3C LC breakers (30302 and 3AA14) which went undetected by the vendor test and inspection programs and Turkey Point pre-installation checks. Corrective action includes:

For breaker 30302, the breaker refurbishment standard revised the final test and inspection procedure to record as left auxiliary switch contact configuration and compare it to the as found configuration (checks to be independently verified). For breaker 3AA14, the procurement specification and applicable receipt inspection procedure for HMA relays have been revised to verify adequate contact wipe by vendor and receipt inspection personnel, respectively. The increase in risk due to loss of core cooling is judged to be very small given the availability of the redundant RHR pump and power source, and the short period for restoration of cooling.

NRC FORM 966 (6-2004) PRINTED ON RECYCLED PAPER v.(�

On February 8, 2016 at approximately 0147 hours, during a surveillance test, control room indications identified that 3B Emergency Containment Cooler (ECC) fan tripped. Troubleshooting found the control power fuse for the fan's power supply breaker was loose in its fuse holder. Investigation revealed that the fuse holder clips had been widened during work activities associated with the installation of the new breaker during the prior Unit 3 refueling and maintenance outage. The most probable cause of the loose fuse was improper insertion.

The installation procedure did not validate fuse holder gap, fuse alignment, and fuse tightness after its last removal and insertion prior to placing the new breaker in service. Inadequate contact during the surveillance test caused the fan trip. The 3B ECC would not have reliably met its safety function mission time and so was determined to be inoperable for approximately 72 days exceeding the 72 hour Technical Specification allowed outage time. In addition, on several occasions during the 72-day period one of the other two ECCs was inoperable concurrently for testing. Corrective actions include: 1) The fuse holder clips were adjusted to provide a tight fit. 2) A review determined additional similar breakers will be inspected for fuse tightness. 3) Future installation and preventive maintenance of similar breakers will check for fuse tightness and correct if necessary. Safety significance is considered low based on a risk assessment showing - Incremental Conditional Core Damage Probability and Incremental Conditional Large Early Release Probability are below the NRC acceptance criteria for minimal risk impact.

On July 20, 2005, Unit 4 4C Emergency Containment Cooler (ECC) fan failed to start during a scheduled monthly surveillance test. The 4C ECC fan tripped due to thermal overload during two start attempts.

Inspection during a subsequent containment entry revealed a rubber shoe cover with evidence of having been lodged between the fan stationary vanes and rotating blades. The rubber shoe cover was removed and further inspection and test operation showed no resulting damage. Three ECCs are provided in each reactor containment building to remove decay heat during a maximum hypothetical accident. The most likely cause of the rubber shoe cover entering the 4C ECC outlet ductwork is human error during the recent refueling outage which concluded on June 13, 2005. It is postulated that an individual failed to pay adequate attention when ascending or descending erected scaffolding above the 4C ECC and to report the loss of the rubber shoe cover.

The containment closeout inspection procedure will be revised to require inspection inside such components as the ECCs that have outlet areas with a potential for foreign material intrusion. In addition, enhancements to procedure 0-ADM-730, Foreign Material Exclusion Controls, will be evaluated. Since no actual event occurred which relied on the ECCs to perform their safety function and the remaining two ECCs were operable, the health and safety of the public and plant personnel were not affected.

NRC FORM 366 (6-2004) PRINTED ON RECYCLED PAPER 11-20011 WIC FORM 366A U.S. NOCIBUI BECULATOBY COMMISSION LICENSEE EVENT REPORT (LER) FACILITY NAME DOCKET CUMBER 121 LER NUMBER 161 PACE 131 Turkey Point Unit 4 05000251

On June 4, 2009 (Discovery Date) at 2010 hours, while in Mode 1 at 100% power after startup from Forced Outage 01 F59, the MO 1-1001-37B, torus (NH) spray shutoff valve (SHV) was found inoperable, in that it would not open while using the control switch (HS) during the performance of the Residual Heat Removal (RHR) (BO) Power Operated Valve Test surveillance procedure.

Investigation into the event determined that the valve motor actuator (84) declutch lever had been inadvertently bumped into the manual mode of operation during previous outage related work activities in the vicinity of the valve. When given the open signal from the control room the valve actuator did not return to the motor mode of operation from the manual mode of operation due to increased friction caused by degraded lubricant/grease in the area of the clutch return spring and clutch keys, and possible degradation/wear of the clutch keys.

The failure of the MO 1-1001-37B valve to open, although impacting the ability to achieve flow for RHR suppression pool spray, did not create any actual plant or safety consequences, since Unit 1 was not in an accident condition requiring RHR suppression pool spray during this event. Furthermore, the containment spray (NH) function (which consists of drywell spray and suppression chamber spray) is not required for proper performance of the containment pressure suppression system. This issue was, however, determined to have resulted in a past operation or condition prohibited by the plant Technical Specifications (TS), and is reportable per 10CFR 50.73(a)(2)(i)(B), because on May 30, 2009 (Event Date) while in Mode 2, at 0225 hours during startup from 01F59, the activity of having changed modes to enter Mode 2 resulted in not meeting TS LCO 3.6.2.4 for two required operable RHR suppression pool spray subSystems while in Modes 1, 2 and 3.

At 0027 on May 5, 2013, the safety injection/refueling water (SIRW) tank was declared inoperable in accordance with the operational decision-making issue (ODMI) process. Water leakage from the tank had exceeded the pre-established limit of the ODMI process that directed the tank be declared inoperable.

Leakage from the tank was quantified at approximately ninety gallons per day. Technical Specification (TS) 3.5.4.B requires restoration of an inoperable SIRW tank within one hour. If the tank is not returned to an operable status within one hour, TS 3.5.4.0 requires the plant be placed in Mode 3 within six hours and in Mode 5 within the subsequent thirty-six hours.

Due to the inability to repair the leak within the required one-hour time frame, a plant shutdown was initiated at approximately 0100 hours on May 5, 2013. The plant entered Mode 3 at 0457 hours on May 5, 2013. At 2358 hours on May 5, 2013, the plant entered Mode 5 to execute repairs.

Testing identified an approximate 3/16-inch through-wall crack in a nozzle reinforcing collar to floor plate weld of the tank. Follow-up analysis determined there was significant lack of fusion in the weld that resulted in the failure of the weld and subsequent water leakage. The welder that fabricated the weld did not ensure adequate fusion at the weld root.

The entire SIRW tank floor was replaced with the exception of an annulus ring around the perimeter.

Several initiatives were implemented to preclude potential weld issues during the fabrication of the new tank floor, including welder proficiency training on revised welding techniques and utilization of several types of weld testing methods.

At 1611 hours EDT on June 29, 2009, with H. B. Robinson Steam Electric Plant, Unit No. 2, operating at approximately 100% power, Technical Specifications (TS) Limiting Condition for Operation (LCO) 3.0.3 was unknowingly entered based on failure to meet the required actions of TS LCO 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation." The condition prohibited by the TS was in effect for approximately two minutes and posed no adverse effect to the health and safety of the public. The required actions in effect at the time were associated with TS LCO 3.3.2, Conditions D and E, Required Actions D.1, D.2.1, E.1, and E.2.1, which provide actions for inoperability of one containment pressure channel.

The cause of this event was determined to be insufficient work instructions to describe the impact of the repair activities for the containment pressure channel.

During the repair, the channel was removed from the tripped condition due to interruption of power when the comparator was removed from the circuit. The channel was returned to the tripped condition within about 2 minutes by replacement of the comparator and subsequently returned to operable status. Removing the channel from the tripped condition resulted in a failure to meet the required actions associated with TS LCO 3.3.2, which is a condition prohibited by the plant's Technical Specifications.

Therefore, this condition is reportable under 10 CFR 50.73(a)(2)(i)(B), for any operation or condition which was prohibited by the plant's Technical Specifications. .

This report describes the discovery on January 12, 2001, while conducting procedural reviews for the implementation of the Improved Technical Specifications, that testing of the power range low power trip logic and the intermediate range high flux trip logic was not being conducted within 24 hours after reducing power below 10% after having operated in excess of 10% power for greater than the monthly surveillance frequency specified in TS Table 15.4.1-1, Item 44.

Although the surveillance testing of these trip logics was being accomplished prior to the next unit start up, and thus established the operability of the trips, a more conservative interpretation of the TS would have been to complete this surveillance within 24 hours of proceeding below 10% of full power. However, since the power range low power trip logic and intermediate range high flux trip logic testing can be accomplished at power, our corrective action will be to revise the plant procedures to require the monthly logic testing. The event had no impact on the health and safety of the public or the plant staff.