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On November 11, 2001, a 4160 VAC cable failure de-energized the 1B2 Unit Substation of the 480 VAC system. Due to the equipment which was declared inoperable, it was determined that a reactor shutdown would be required. On November 12, 2001, at 3:33 am, the reactor was placed in the COLD SHUTDOWN CONDITION.

The cause of the cable failure was determined to be a localized insulation weakness aggravated by water intrusion into the cable conduit.

The safety significance of this occurrence was determined to be minimal. Although the 1B2 Unit Substation of the 480 VAC system was lost, the redundant electrical division remained fully operable at all times. At no time during this event did a functional failure of any safety system occur. The plant remained within Technical Specifications limits at all times, and achieved a COLD SHUDOWN CONDITION within the allowed time limits.

The failed portion of the cable was replaced, the plant was restarted and resumed POWER OPERATION. Long term actions include evaluating a new design cable and possible rerouting of the cable run.

On July 17, 2007 at 05:21 while operating at 100% power, an automatic reactor scram occurred due to low reactor water level following a trip of the "C" Reactor Feed Pump (RFP). The cause of the "C" RFP trip is attributed to an electrical fault internal to the motor. This transient led to an automatic scram on

• low reactor water level and subsequent reactor isolation on a low-low reactor level.

There were no safety consequences impacting plant or public safety as a result of this event. .

This event is being reported pursuant to 10 CFR 50.73(a)(2)(iv)(A) due to the automatic reactor protection system and subsequent ECCS actuations.

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 ;

2008, (SI) unit shutdown for a refueling outage, a 480 V breaker (BKR) on Safeguards Bus 2A (ED) did not close during a surveillance test.

On March 27, during Safety Injection and Black Out testing, with the Troubleshooting discovered that SI Logic Train A, contact 17-21, when closed had high contact resistance. relay 3-2, Relay 3-2 is part of the Engineered Safety Feature Actuation System (ESFAS), whose design function is to actuate safeguards equipment required to mitigate an accident. On March 28, 2008, troubleshooting discovered relay 3-2 did not have wires associated with 23 Fan Cooler Unit (FCU) Breaker connected to it in accordance with plant design. The wires were found landed on an adjacent SI Logic Train A relay 3-3. Subsequently equivalent wires on the SI Logic Train B relays, 3-12 and 3-13, were discovered to be similarly mis-wired. The incorrect wiring associated the 23 FCU with Bus 5A rather than its assigned Bus 2A. If power was lost on Bus 5A during an SI, the mis-wiring would prevent the automatic start of the 23 FCU even though its assigned Bus 2A was energized. The apparent cause of the circuit anomaly was an improperly implemented design change by the original plant installer in 1973. The design schematic was properly revised by the design change but the wiring lists and plant were not.

The specific cause can not be determined due to the passage of time.

Corrective actions included re-wiring of relay contacts in accordance with re-verified design documents. An extent of condition was performed and no additional wiring anomalies were identified. The event had no effect on public health and safety. ,

On August 11, 2015, during operator investigations inside the reactor containment building, a through wall leak was discovered on the 24 Fan Cooler Unit (FCU) motor cooler service water (SW) return line. The leak was in a 2 inch copper-nickel pipe near a brazed joint upstream of containment penetration SS. The leak was located within the ASME Section XI Code ISI Class 3 boundary and estimated to be approximately 2 gpm.

Since the pipe flaw was through wall and was located within the ASME Section XI boundary, it exceeds the flaw allowable limits provided per IWC-3000.

The weld leak was evaluated and determined to meet the structural requirements of ASME Code Case N-513-3.

The condition was determined to have no impact on SW cooling safety function or adverse impact on piping structural integrity. The pipe is considered a closed loop system inside containment and required to meet containment integrity.

An engineering evaluation was performed to determine the potential air leakage out of containment based on the observed SW leakage into containment.

This evaluation concluded that the leaking defect could result in post-LOCA air leakage out of containment in excess of that allowed by Technical Specification 3.6.1 (Containment) which requires leakage rates to comply with 10 CFR 50, Appendix J.

The direct cause was corrosion. The apparent cause was the length of time to implement a modification to replace the FCU motor cooler copper-nickel piping identified in 2009 per the SW mitigation strategy.

An engineered clamp was installed over the pipe defect. The pipe and affected elbow were replaced in accordance with the requirements of ASME Section XI Code during the spring refueling outage in 2016. A modification to replace piping will be processed for funding. The event had no significant effect on public health and safety.

On November 21, 2016, as a result of investigating an increased level rise in the Waste Hold-Up. Tank (WHUT), Operators identified a corresponding rise in containment sump level. A containment entry was made to investigate the source of the sump level rise and determined the source was a through wall leak in a Service Water (SW) supply pipe elbow to the 24 Fan Cooler Unit (FCU). The leak constituted a breach of a closed system within containment. Technical Specification (TS) 3.6.1 (Containment) was entered and containment declared inoperable. TS 3.6.6 (Containment Spray and Fan Cooler System) was entered when the 24 FCU was secured and SW to the 24 FCU was isolated. Inspections identified a through wall leak on .a SW supply pipe elbow to one of the 24 FCU water boxes.

The leak is on a 3 inch carbon steel epoxy-lined elbow.

The pipe fitting is in an ASME ISI Code Class 3, nuclear safety related piping system.

The direct cause was failure of the interior coating allowing brackish river water to corrode the carbon steel fitting. The root cause was the maintenance coating procedure requirements for post-coating inspections were inadequate. Key corrective actions included removal of the defective elbow and weld repair, recoating and re-installation.

Maintenance procedure 0-SYS-409-GEN will be revised to mandate detailed inspections and/or testing of surface preparation and applied coatings to ensure proper coverage and adhesion. The event had no effect on public health and safety.

NO:

Indian Point 2 05000-247

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.

On October 23, 2010, during a refueling outage for Browns Ferry Nuclear Plant (BFN) Unit 1, the Tennessee Valley Authority (TVA) discovered that a Residual Heat Removal (RHR) Loop II low pressure coolant injection (LPCI) flow control valve failed to open while attempting to establish shutdown cooling (SDC) while in Mode 3. Operations personnel declared RHR Loop II inoperable for ECCS and placed RHR Loop I in service for SDC.

Unit 1 Technical Specification (TS) limiting condition for operation (LCO) 3.5.1, Emergency Core Cooling System (ECCS) - Operating, requires both RHR loops of LPCI to be operable in reactor Modes 1, 2, and 3. Investigation of the valve failure to open determined that the root cause was a manufacturer's defect resulting in undersized disc skirt threads at disc connection. Based on causal analysis information, the stem-to-disc separation occurred sometime before November 2008. Thus, RHR Loop II was inoperable for a period longer than the 7 days allowed by TS 3.5.1. This condition is reportable as both operations prohibited by TS and as an event or condition that could have prevented fulfillment of a safety function.

This report constitutes a Part 21 notification.

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.

response to NRC Generic Letter GL 98-04. Two significant errors were involved:

1. A correlation for head loss across a mixed fiber and particulate debris bed on a screen was improperly applied to a debris bed consisting only of coatings chips, and 2. While interpreting the resulting calculated head loss, the total submergence depth of the screens was used rather than the average submergence depth. This resulted in an erroneous conclusion that the available submergence would be sufficient to ensure adequate flow to the residual heat removal (RHR) pumps.

Since the screens would be only partially submerged, air intrusion and loss of RHR pumping function would have been the correct conclusion reached.

Further investigation found that the flow path created by a partially blocked strainer had not been considered I and that the increase in expected head loss created an additional challenge to RHR pump operability. These I errors and deficiencies in modeling and interpretation of results impact the analytical basis for demonstrating , compliance with the acceptance criteria in 10 CFR 50.46 (b)(5), 'tong-term Cooling." This condition was ' reported to the NRC via the Emergency Notification System on November 8, 2005 (EN# 42129).

An operability analysis of this condition demonstrated that adequate net positive suction head (NPSH) would be available to the emergency core cooling system (ECCS) pumps to ensure long-term cooling pending final 1 resolution of generic PWR sump screen issues.

LER NUMBER (6 „ � SEOUENTIAL

On April 13, 2013 at 23:39 PBNP Unit 1 entered Mode 4 during start up from a refueling outage. On April 14, 2013 at 0620, approximately 6 hours after entering into MODE 4, the Unit 1 sodium hydroxide tank outlet valve (1S1-831A) was found to be closed. This valve isolated the flow path for both trains of spray additive equipment and resulted in not meeting LCO 3.6.7, Spray Additive System. That mode change resulted in a violation of LCO 3.0.4.

The incorrect valve position was discovered when a senior reactor operator identified a caution tag on the 1S1-831A valve. Operations investigated the unexpected condition then immediately placed the valve in its proper position to meet the Technical Specification requirements.

This event is being reported pursuant to 10 CFR 50.73(a)(2)(v)(D) and 10 CFR 50.73(a)(2)(i)(B).

On 09/13/2008, while Oconee Unit 1 was operating in Mode 1 at 100% rated power, an examination being performed in response to Generic Letter (GL) 2008-01 detected a gas bubble (void)A in the suction piping to the High Pressure Injection (HPI)A At 13:46 hours,Asuction header. Engineering completed a calculation of the void volume and initiated a Problem Investigation Process report.A At 15:12 hours, Engineering and Operations concluded that the void could render the 1A HPI pump and 1A HPI train inoperable.A Operations declared lA HPI pump and lA HPI.train out of service and entered Technical Specification (TS) 3.5.2, Conditions A and C. The line was vented, and, at 16:43 Operations declared the pump and train Operable and exited the TS conditions. Additional examinations confirmed that the equivalent locations on the Unit 1B HPI train and on Units 2 and 3 did not contain voids.

No specific source or cause could be found for the void.ADuke Energy responded to GL 2008-01 by letter dated 10/13/2008 and committed to actions which are expected to permanently resolve this issue.

This event is considered to have minimal significance with respect to the health and safety of the public.