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The High Pressure Core Spray (HPCS) system was declared inoperable due to the pump's failure to meet the flow requirement specified in TS Surveillance Requirement 3.5.1.4. This surveillance is normally performed on a quarterly basis in accordance with the plant's In-service Testing (IST) Program. The flow values measured during the performance of this surveillance were below both the normal and alert ranges. This test had also been run on 5/27/04 with results in the alert range; HPCS system instruments had been vented between the two tests to rule out the possibility that the results were due to measurement errors. Upon declaring the HPCS pump inoperable, TS 3.5.1 Action B was entered. In accordance with Action B, the Reactor Core Isolation Cooling (RCIC) system was verified to be operable. With the RCIC system verified operable, Action B provides a 14-day completion time to restore HPCS to an operable status. All other Emergency Core Cooling Systems (ECCS) were operable during this event. This event is being reported as an event or condition that could have prevented the fulfillment of a safety function credited for mitigating the consequences of an accident. The HPCS system is a single train system at Columbia. The licensee notified the NRC Resident Inspector.

• * * UPDATE ON 06/14/04 @1752 BY MIKE BRANDON TO C. GOULD * * * RETRACTION

On May 30, 2004, Energy Northwest provided an 8-hour notification pursuant to 10 CFR50.72(b)(3)(v)(D). This notification reported the apparent failure of the High Pressure Core Spray (HPCS) system's pump to meet the flow requirements of Surveillance Requirement (SR) 3.5.1.4. Upon the apparent failure to satisfy this SR, Energy Northwest entered Action B of Technical Specification (TS) 3.5.1 (14 day completion time) and initiated actions to investigate the cause of this apparent failure. This investigation determined the cause of this apparent failure was due to an anomaly in the processing of the pressure and flow input signals and the instrumentation used for documenting the results of the surveillance. Additional testing using alternative instrumentation determined the HPCS pump was fully capable of providing flow within the existing acceptance criteria of the plant's In-service Testing (IST) Program and thus capable of satisfying the SR. This investigation determined that no actual degradation of the pump existed that would have caused a valid failure of the SR. This was an instrumentation issue only. The HPCS system would have been capable of performing its specified safety function in the as-found condition and was capable of fully satisfying the SR. Therefore, this condition would not have prevented the fulfillment of a safety function and is therefore not reportable under 10CFR50.72. The HPCS system was declared OPERABLE on June 03, 2004 at 22:59 PDT. The NRC Resident Inspector was notified.

During underwater inspection of the Standby Service Water 'C' system, four piping supports were found with considerable degradation. As a result, the Standby Service Water 'C' and High Pressure Core Spray systems were declared inoperable per Technical Specifications (TS). High Pressure Core Spray is a single - train system that performs a safety function." The licensee entered the applicable sections of TS 3.7.2, High Pressure Core Spray Service Water System, and TS 3.5.1, High Pressure Core Spray. The licensee has notified the NRC Resident Inspector.

• * * RETRACTION ON 9/2/04 AT 1610 EDT FROM MICHAEL LARSON TO ARLON COSTA * * *

Reactor Plant Event Number 40952 was reported on August 14, 2004 at 1344 for an inoperable Standby Service Water 'C' and High Pressure Core Spray system due to degraded Standby Service Water 'C' lateral piping supports. This event is hereby retracted. The retraction is based on engineering evaluations and calculations performed that determined that the Standby Service Water 'C' and High Pressure Core Spray System were both OPERABLE and capable of performing their intended safety function. The engineering evaluation and calculations concluded that even without the degraded lateral piping supports, the Standby Service Water 'C' piping maintained its structural integrity and would have performed its intended safety function. The licensee notified the NRC Resident Inspector. Notified R4DO (W. Jones).

At 1317 (hrs CST) on December 10, 2004, an automatic actuation of the reactor protection system (RPS) occurred resulting in a reactor scram. The apparent cause of the event was loss of a vital instrument bus due to a fault in a nonsafety related vital inverter. This inverter provides power to selected control room instrumentation and controls. This resulted in the loss of feed water level control. Reactor level is being maintained by the High Pressure Core Spray System. The feed water system is not available. Reactor pressure is being controlled through the main turbine steam bypass system to the condenser. The condenser is available and being used as the heat sink. The residual heat removal system was operated in suppression pool cooling mode to provide a means of rejecting water from the suppression pool (water input from High Pressure Core Spray System minimum flow line). The plant is currently stable, and being maintained in hot shutdown. Systems responded as expected based on the initiating event. Reactor Core Isolation Cooling is not being used pending evaluation of a system alarm that is currently being investigated. Investigation of the initiating fault is being pursued in order to recover the vital bus and feed water level control. It has been preliminarily determined that the loss of instrument power resulted in the Main Feedwater regulating valve failing as-is and the "B" Reactor Recirculation Pump shifting down in speed. The reduction in reactor power with constant feed flow resulted in a high reactor vessel water level, producing a direct reactor scram signal at the High Level 8 setpoint. The licensee has notified the NRC Resident Inspector.

• * * UPDATE FROM G. HUSTON TO M. RIPLEY AT 2025 EST 12/10/04 * * *

At 1657 CST (on 12/10/04), reactor level control was restored to the normal Feedwater and Condensate Systems. The High Pressure Core Spray System was restored to the normal standby lineup. Investigation into the cause of the reported RPS actuation continues. Investigation into the Reactor Core Isolation Cooling System alarms has resulted in declaring this system inoperable. The licensee will notify the NRC Resident Inspector. Notified R4 DO (L. Smith), NRR EO (M. Tschiltz) and IRD Manager (S. Frant)

• * * UPDATE TO W GOTT AT 0016 EST ON 12/12/04 * * *

The final determination of the cause of the scram was determined to be due to the B recirc pump downshift and subsequent power to flow scram on APRM flux. The licensee will notify the NRC Resident Inspector. Notified R4DO (L Smith)

• * * UPDATE TO JOHN MACKINNON FROM HUSTON AT 1332 EST ON 12/16/O4 * * *

The Reactor Core Cooling System was returned to available status at 0343 on 12/11/2004 and was restored to operable status at 2200 on 12/11/2004." The licensee notified the NRC Resident Inspector. Notified R4DO (Kriss Kennedy).

During fact gathering in response to an NRC inspection inquiry, it was determined that documentation does not exist that demonstrates that the Reactor Core Isolation Cooling (RCIC) Electronic Governor Module (EGM) would be able to operate during the required Station Blackout (SBO) coping mission time at the postulated post SBO RCIC room temperature of 206.4F. Current documentation supports operation up to 150F. The EGM is a skid-mounted module that provides speed control signals for the RCIC Woodward Governor. Failure of the EGM would result in a loss of speed control for the RCIC turbine. This could result in an overspeed, underspeed or no change condition. Overspeed of the turbine would result in a mechanical overspeed trip. This device is not in the EQ program but is Augmented Quality. RCIC continues to perform its Technical Specification required functions as defined in the Bases of Technical Specification (TS) 3.5.3. The TS function is to respond to transient events by providing makeup coolant to the reactor. The RCIC Room temperatures for the postulated TS transient events is less than the currently documented component qualification temperature. The RCIC is not an ESF system and no credit is taken in the safety analysis for RCIC system operation but is retained in the TS based on its contribution to the reduction of overall plant risk per Criterion 4 of 10 CFR 50.36. The RCIC system design requirements ensure that the criteria of 10CFR50 Appendix A, GDC 33, are satisfied. Due to the lack of supporting documentation for the EGM, the beyond design basis regulatory SBO rule requirements of 10 CFR 50.63 may not be met. This condition could potentially result in an unanalyzed condition that could significantly degrade plant safety and is therefore reportable under 10 CFR 50.72(b)(3)(ii). An analysis of the RCIC Room Heat Up Rate calculation is being performed as there are conservatisms built into the calculation that when removed will result in a lower temperature than 206.4F. Additional actions in progress include, establishing appropriate protected pathways to minimize the potential for a Loss Of Off-Site Power which could result in a SBO, performance of temperature qualification testing at SBO temperatures for the EGM, and performance of an extent of condition review for remaining RCIC components to ensure temperature qualification is met for the SBO rule. In parallel with temperature qualification testing, a modification to relocate the EGM to an area outside the RCIC room that has a lower SBO profile temperature is being pursued in the event that temperature qualification is not successful. The licensee notified the NRC Resident Inspector.

• * * RETRACTION FROM D. COVEYOU TO W. GOTT AT 1427 EDT ON 8/16/05 * * *

A 8-hour notification was made on July 14, 2005, in accordance with 10 50.72(b)(3)(ii)(B), Unanalyzed condition. The report was made because documentation did not support the continued operation of Reactor Core Isolation Cooling (RCIC) Electronic Governor Module (EGM) during the required Station Blackout (SBO) coping mission. Since the initial report, the post SBO room heatup calculation was evaluated and determined that the decay heat removal function during the SBO coping mission was met. The decay heat removal function during SBO coping period is achieved by either High Pressure Core Spray (HPCS) or RCIC systems. In addition, the other RCIC functions (i.e., Remote Shutdown, and Safe Shutdown Fire) were evaluated and determined to be met. Since the RCIC functions and the decay heat removal and vessel inventory functions during the SBO coping mission were maintained, the plant was not in an unanalyzed condition and this issue is not reportable. Since the condition is not reportable EN 41844 is retracted. The licensee notified the NRC Resident Notified R3DO (K. O'Brien)

The Division 3 Emergency Diesel Generator (EDG) was declared INOPERABLE following a trip during a routine monthly surveillance run. As soon as the Division 3 EDG was at full load it tripped off line (output breaker tripped). The Division 3 EDG supplies electrical power to the High Pressure Core Spray System in the event of a loss of offsite power. No problems occurred on the Division 3, 4160 volt, safety related bus. This event is being reported in accordance with 10CFR50.72(b)(3)(v)(B), Event or Condition That Could Have Prevented Fulfillment of a Safety Function for a single-train system failure. The NRC Resident inspector has been notified.

• * * THIS EVENT IS BEING RETRACTED ON 12/20/05 AT 1557 * * *

Subsequent trouble-shooting and testing determined that the cause of the engine trip on 11/21/05 was an invalid high coolant temperature trip signal. This trip is bypassed during a Loss of Coolant (LOCA) initiation of the system, therefore, it was determined that the EDG would have been able to perform its safety function during a LOCA. Following a Loss of Offsite Power (LOOP), reactor water level is expected to reach Reactor Pressure Vessel (RPV) Water Level Low Low (Level 2) within 30 seconds of the initiating signal. Once Level 2 is reached, both the EDG and the LOCA Trip bypass signals are actuated. It was determined that the bypass would have occurred prior to the high coolant temperature trip. Based on the above, it was determined that the Division 3 EDG would have been fully capable of performing its safety function under both LOCA and LOOP. The Division 3 EDG was restored to an operable condition at 0214 on 11/22/05. The NRC Senior Resident Inspector has been notified. Notified R3DO (H. Peterson).

At 0142 on October 24, 2006, while aligning the High Pressure Core Spray system for surveillance testing of the Reactor Core Isolation Cooling System Storage Tank Level instrumentation, 1E22-F015, the Suppression Pool suction valve for the High Pressure Core Spray pump, failed to stroke fully open. High Pressure Core Spray was declared inoperable as a result. This event is considered a loss of a single train system needed to mitigate the consequences of an accident. The High Pressure Core Spray system was restored to an operable condition at 0506 on October 24, 2006 after the suction valve was successfully stroked open and the HPCS suction source was aligned to the Suppression Pool in accordance with Technical Specification Limiting Condition for Operation 3.5.1. The cause of the event is currently under investigation. All other Emergency Core Cooling systems were fully operable during the time period HPCS was inoperable. The Senior Resident Inspector has been notified by the licensee.

• * * RETRACTION FROM SIMPSON TO HUFFMAN AT 1534 EST ON 11/10/06 * * *

Upon further review of this event, the High Pressure Core Spray (HPCS) system remained operable. Based upon valve motor operator thrust verification testing data and troubleshooting, the cause of the suppression pool suction valve for the HPCS pump stopping in mid-position was determined to be tripping of the open-direction torque switch prior to the open limit switch setpoint. Normally, the condition of the open-direction torque switch has no safety-related consequence since the torque switch is bypassed during design basis events and the valve's motor gearing capability is sufficient to open the valve when the torque switch is bypassed. During this event, as directed by the surveillance test procedure, operators placed the HPCS Motor Operated Valve (MOV) test switch to the test position which resulted in the open-direction torque switch not being bypassed (i.e., was in the circuit) during repositioning of the HPCS suppression pool suction valve. Due to placing the HPCS MOV test switch to test, operators entered the action of Operational Requirements Manual section 2.5.2 (Motor Operated Valves Thermal Overload Protection). The action requires operators to return the MOV test switch to normal (removing the torque switch from the circuit) if an emergency condition occurs requiring valve repositioning. As operators were opening the HPCS suppression pool suction valve for testing, suction for the HPCS pump was aligned from the RCIC storage tank. When the HPCS suction valve from suppression pool stopped in mid-position, the HPCS suction valve from the RCIC storage tank was still fully open (per design, stays full open until the HPCS suppression pool suction valve is full open). Therefore, if an accident occurred requiring HPCS to initiate and inject water into the reactor pressure vessel during this event suction would have initiated from the RCIC storage tank. The HPCS system can take suction from either the RCIC storage tank or the suppression pool, and a HPCS initiation signal does not automatically swap HPCS pump suction from the RCIC storage tank to the suppression pool or vice versa. The operators immediately recognized the HPCS suppression pool suction valve did not fully open. If an accident condition occurred, operators would reposition the HPCS MOV test switch to Normal (to bypass the open torque switch). In the event a condition requiring a HPCS suction transfer to the suppression pool occurred, the suppression pool suction valve would fully open and the RCIC storage tank suction valve would fully close, completing the required suction shift. On this basis, the HPCS system was capable of performing its function to mitigate the consequences of an accident and this issue is not reportable under 10 CFR 50.72(b)(3)(v)(D). The NRC Resident was notified of this retraction. R3DO(Cameron) notified.

On December 3, 2006, at 0858 hours, control room operators received a Division 3 Emergency Diesel Generator (EDG) Carbon Dioxide (CO2) (Fire Protection) system initiation signal. The CO2 system for the Division 3 EDG room was out of service at the time and so no CO2 was released into the room. At 0905 hours, a first responder notified the control room operators that there was no indication of a fire in the Division 3 EDG room. A walkdown of the associated EDG room ventilation system confirmed the ventilation system tripped with the CO2 initiation signal locked in. At 0919 hours, the Division 3 EDG was declared inoperable and Technical Specification (TS) LCO 3.8.1 Condition B was entered. The required TS actions were implemented. The Division 3 EDG is available with restoration of the ventilation system using the CO2 Override switch. The CO2 initiation signal is currently locked in, and the Division 3 CO2 Fire Monitoring Panel, with associated equipment has been quarantined for further investigation. The Division 3 EDG provides emergency AC electrical power to the High Pressure Core Spray system. This event is being reported as a condition that could have prevented the safety function of structures or systems required to mitigate the consequences of an accident. The Resident Inspector has been notified.

* * * EVENT RETRACTED AT 1324 ON 12/14/06 FROM C. ELBERFELD TO P. SNYDER * * * 

The purpose of this call is to retract Event Number 43021. On December 3, 2006, at 1520 hours, a notification, Event Number 43021, was made to the NRC Operations Center by the Perry Nuclear Power Plant (PNPP) in accordance with 10 CFR 50.72(b)(3)(v)(D) as a condition that at the time of discovery could have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident. A spurious Carbon Dioxide (CO2) Fire Protection system initiation signal resulted in a tripped condition for the Division 3 Emergency Diesel Generator (EDG) room ventilation system. Operators declared the Division 3 EDG inoperable and took the appropriate Technical Specification actions. The Division 3 EDG provides emergency AC electrical power to the High Pressure Core Spray system. The High Pressure Core Spray system is a single train safety system. After further evaluation, it was determined that operators could promptly restore the ventilation system, with the CO2 initiation signal locked in, if the Division 3 EDG was needed, and that the safety function of the system could still be fulfilled during the time in question. Because the condition reported in Event Number 43021 would not have prevented the fulfillment of the safety function of a system that is needed to mitigate the consequences of an accident, the condition is not reportable, and this notification is retracted. The evaluation (i.e., Reportability Review) for this condition is documented in Condition Report 06-10843. The NRC Resident Inspector has been notified. Notified R3DO (Lara).

At 2003 on 6/10/07, the division 3 Nuclear System Protection System (NSPS) inverter power supply failed for unknown reasons. As a result of this failure, the High Pressure Core Spray (HPCS) system has been declared inoperable. This is a failure of a single train safety system and is reportable under 10 CFR 50.72(b)(3)(v)(D). Troubleshooting has been initiated to determine the cause of this failure. The licensee notified the NRC Resident Inspector.

• * * RETRACTION ON 07/6/07 AT 1639 EDT FROM TOM CHALMERS TO MARK ABRAMOVITZ * * *

This event is being retracted. An evaluation was performed and it was determined that no loss of safety function occurred following the failure of the Division 3 NSPS Inverter. The investigation determined that a circuit board failed on the inverter causing a blown fuse. The inverter was found in the reverse transfer position and AC power was automatically transferred to its alternate source, supplying its Division 3 loads. The High Pressure Core Spray system remained fully capable of performing its safety function to start and inject under both LOOP and LOCA conditions. The licensee will notify the NRC Resident Inspector. Notified the R3DO (Lanksbury).

On 4/2/12 at 1511 (CDT), GGNS (Grand Gulf Nuclear Generating Station) received a valid ESF actuation for emergency AC power to Division 3 4160V bus due to degraded voltage.

One of the two 500KV offsite feeders (Tech Spec Offsite Power Source) tripped causing a drop in grid voltage which resulted in a trip of the ESF feeder breaker for 4160 Volt Division 3 bus. The HPCS (High Pressure Core Spray) Diesel Generator automatically started and energized the bus. The HPCS system was not running and no ECCS initiation occurred during this event. The plant was in Mode 5 with RHR A in shutdown cooling. Divisions 1 and 2 ESF power monitoring instrumentation responded to the grid voltage transient but no actuation setpoints were reached. Division 1 and 2 ESF 4160V buses remained energized and shutdown cooling remained in service. The 500KV offsite feeder (Tech Spec Offsite Power Source) and additional 115 KV feeder (Tech Spec Offsite Power Source) remained in service. The 500KV feeder that tripped was restored by the dispatcher at approximately 1515 CDT. The Division 3 bus was subsequently transferred back to offsite power and the HPCS Diesel Generator was secured. This event is reportable per 10 CFR 50.72(b)(3)(iv). A lightning strike resulted in a voltage transient on the GGNS electrical distribution system. Due to this transient, the 'A' Control Room Air Conditioning Unit (CRAC 'A') tripped and had to be manually restarted. CRAC 'A' was not running for approximately two minutes. During this timeframe CRAC 'B' was tagged out of service. This was evaluated and determined to not be a loss of safety function. The licensee has notified the NRC Resident Inspector.

LaSalle Unit 1 and LaSalle Unit 2 have both experienced an automatic reactor scram, in conjunction with a loss of offsite power. This was caused by an apparent lightning strike in the main 345kV/138kV switchyard during a thunderstorm. 138kV line 0112 has been inspected in the field, and heavy damage has been noted on the insulators on two of the three phases on a line lightning arrestor line side. The plant systems have all responded as expected. All five diesel generators started, and have loaded on to their respective buses as designed. All rods went full in on both units during the respective scrams. HPCS (High Pressure Core Spray) system was started on each unit and automatically aligned for injection for initial level control. The MSIVs (Main Steam Isolation Valves) are shut on both units with decay heat being removed via the safety relief valves. Suppression pool cooling is in progress. The licensee will notify the NRC Resident Inspector and has notified the State. Notified DHS, FEMA, USDA, HHS, DOE, NICC, EPA, and Nuclear SSA via email.

• * * UPDATE FROM DON PUCKETT TO VINCE KLCO AT 2113 EDT ON 4/17/2013 * * *

In addition to information (previously provided), LaSalle Unit 2 received a high drywell pressure signal (1.77 psig) due to loss of containment cooling from the loss of power. At the time of this high drywell pressure signal, high pressure core spray pump and 2B residual heat removal (RHR) pump was already in operation, the low pressure core spray system and 2A residual heat removal system was secured and (placed) in pull to lock. When the signal was satisfied the ECCS (Emergency Core Cooling Systems) signal was processed but only the 2C RHR pump would have started. In this case, the 2C RHR pump tripped when the signal was received. There is no evidence of reactor coolant leakage. There was no additional ECCS systems discharging into the RCS (Reactor Coolant System). As (initially stated), level was controlled using High Pressure Core Spray and level control is now being maintained using the Reactor Core Isolation Cooling (RCIC) systems. The 2C RHR pump trip is under investigation. Due to the initial loss of offsite power for both Unit 1 and Unit 2 reported at 1511 (CDT), multiple containment isolation valves isolated and closed as expected. Once initial containment isolations were verified, two Unit 2 primary containment vent and purge valves were opened to vent the Unit 2 containment. Once Unit Two containment pressure reached 1.77 (psig), these two vent valves isolated as expected. Due to the loss of offsite power, the Station Vent Stack Wide Range Gas Monitor (WRGM) and the Standby Gas Treatment Wide Range Gas Monitor (VGWRGM) also lost power. Manual sampling has been implemented and power is restored to the VGWRGM, however the VGWRGM has not been declared operable yet. Normal radiation levels have been reported from the manual sampling. (This is being reported in accordance with 10CFR50.72(b)(3)(xiii).) The licensee notified the NRC Resident Inspector and the State of Illinois. Notified the R3 IRC, NRR EO(Skeen), IRD MOC (Grant).

• * * UPDATE AT 0057 EDT ON 04/18/13 FROM MIKE LAWRENCE TO S. SANDIN * * *

After the Unit 2 primary containment vent and purge system isolated on the Unit 2 containment High Pressure signal, Venting of the Unit 1 primary containment was commenced. At 2005 CDT, Unit 1 primary containment pressure reached the Group 2 primary containment isolation system setpoint (1.77 PSIG) causing the primary containment vent and purge valves being used to vent the Unit 1 containment to isolate. Unit 1 primary containment venting was being performed through the Standby Gas Treatment system which is a filtered system. In addition to the primary containment isolation signal on high drywell pressure, an ECCS initiation on high drywell pressure also occurred. The ECCS signal resulted in an auto start of the 1C RHR system. The 1B RHR system was already running in suppression pool cooling mode. 1A RHR and LPCS had been secured to prevent overloading the common diesel generator for division 1. The common diesel generator supplies both Unit 1 and Unit 2 division 1 ESF busses. The licensee informed the NRC Resident Inspector. Notified NRR EO (Skeen), IRD MOC (Grant) and R3IRC (Louden).

• * * UPDATE AT 0947 EDT ON 04/18/13 FROM JUSTIN FREEMAN TO PETE SNYDER * * *

LaSalle has terminated the unusual event which was initiated at 1511 on 4/17/13 and reported under EN 48939. This unusual event has been terminated based on meeting the following established criteria. This report is being made in accordance with 10CFR50.72.(c)(1)(iii). 1) Off-site power has been restored to all ESF busses 2) Fuel Pool Cooling has been restored on both units 3) Primary Containment Chillers have been restored on both units 4) Drywell pressure is less than ECCS initiation setpoint 5) ECCS signals cleared to allow diesels to be placed in stand by Recovery of remaining plant systems will be managed through the Outage Control Center (OCC)." The licensee informed the NRC Resident Inspector. Notified R3DO (Orth), NRR EO (Chernoff), IRD (Grant), DHS, FEMA, USDA, HHS, DOE, NICC, EPA, and Nuclear SSA via email.

• * * UPDATE AT 1711 EDT ON 4/21/2013 FROM GREG LECHTENBERG TO MARK ABRAMOVITZ * * *

In addition to the 10 CFR 50.72 Sections initially identified, the Loss of Offsite Power was also reportable under 10 CFR 50.72(b)(3)(v)(D) as an event or condition that could have prevented the fulfillment of the safety function of systems needed mitigate the consequences of an accident. This event is considered a safety system functional failure for both Units 1 and 2. The licensee will notify the NRC Resident Inspector. Notified the R3DO (Orth).