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 Report dateSiteEvent description
05000528/LER-2017-00114 June 2017Palo Verde
Palo Verde Nuclear Generating Station Unit 1

On April 17. 2017, the staff identified a low refrigerant level in the Unit 1 train B essential chilled water (EC) system chiller during inspection. Operations personnel immediately declared EC chiller train B inoperable. On April 17, 2017, the leak was corrected and EC chiller train B was refilled with refrigerant to within the manufacturer's specifications. Operations personnel declared the system operable on April 18, 2017. The chiller had been inoperable since April 11. 2017, when the automatic purge system was placed into service. The direct cause of the low refrigerant level was leakage due to prior installation of a fitting on the automatic purge system filter without a plug.

During the 7-day period that EC chiller train B was inoperable, the supported low pressure safety injection (LPSI) system train B was inoperable. LPSI train A was also inoperable for approximately 17 minutes on April 13, 2017, during the performance of a routine surveillance test. This 17-minute period represented a condition that could have prevented the fulfillment of a safety function.

The cause of the leak was determined to be ineffective work instructions that did not identify the appropriate part number to be used during filter replacement. Corrective actions include revision of the work instructions. This change will ensure that the existing plug remains in place during filter element replacement. A leak test was also added to the work instructions to verify that no refrigerant leaks are present following maintenance.

05000530/LER-2016-00210 February 2017Palo Verde

On December 15, 2016, the Unit 3 "B" train (3B) diesel generator (DG) experienced a failure during the performance of a monthly surveillance test. At 0356 Mountain Standard Time, a master connecting rod mechanically failed and caused significant damage to the 3B DG. Unit 3 control room staff declared the 3B DG inoperable and entered Technical Specification Limiting Condition for Operation (LCO) 3.8.1, AC Sources - Operating, Condition B. To support repairs, Palo Verde Nuclear Generating Station (PVNGS) received two license amendments to extend the LCO 3.8.1, Condition B required action completion time for the 3B DG from 10 days to 62 days. PVNGS Unit 3 continues to operate at 100 percent power.

The preliminary cause analysis indicates that the 3B DG master connecting rod failed due to high cycle fatigue caused by misalignment of the crankshaft bore introduced by a previous failure that occurred in 1986. The failure mechanisms that caused the 1986 and 2016 3B DG failures are not present in any other PVNGS DG.

PVNGS has completed significant disassembly, repair, and reassembly of the 3B DG, and testing efforts are ongoing. The cause investigation is still in progress, and the results will be reported in a supplement to this Licensee Event Report.

No previous similar events have been reported by PVNGS in the last 3 years.

05000530/LER-2016-00110 January 2017Palo Verde

On July 20, 2016, PVNGS received Unit 3 "B" train (3B) control room essential air filtration unit (AFU) carbon sample test results that exceeded the acceptance criteria of the Technical Specification (TS) Ventilation Filter Testing Program. The Unit 3 control room (CR) staff declared the AFU inoperable and entered TS Limiting Condition for Operation (LCO) 3.7.11, control room essential filtration system (CREFS). The carbon filter replacement and testing was completed, and the Unit 3 CR staff declared the 3B CREFS AFU operable on July 24, 2016.

The investigation determined the 3B CREFS AFU was inoperable since December 17, 2015, which exceeded the Required Action Completion Time for Conditions A and C of LCO 3.7.11 on December 24, 2015 and Condition E during movement of irradiated fuel. The direct cause of this event was exposure of the 3B CREFS AFU carbon filter to a high amount of volatile organic compounds (VOCs) during a CR renovation project. The apparent cause was a lack of knowledge and recognition by PVNGS personnel to identify and properly mitigate the effects of the project on the CREFS AFU resulting in inadequate guidance for controlling all potential sources of VOCs. Applicable change process and work control procedures have been revised to ensure flooring and furniture replacements that could impact the CREFS AFU are evaluated as potential sources of VOCs prior to performing work.

No previous similar events have been reported by PVNGS in the last three years.

05000528/LER-2016-00321 November 2016Palo Verde

On September 21, 2016, at 0142 Mountain Standard Time (MST), containment isolation valve SGA-UV-1134 failed to stroke closed from the control room during containment isolation valve testing. The failure resulted in an unplanned entry into Technical Specification Limiting Condition of Operation (LCO) 3.6.3, Containment Isolation Valves. On September 22, 2016, it was concluded the valve was in a configuration that rendered the pneumatic operator incapable of operating the valve, including remote operation and automatic closure in the event of a main steam isolation system signal. The valve had been in this configuration since last operated on June 28, 2016. Therefore, the valve was inoperable longer than the required 4-hour completion time of LCO 3.6.3 Condition C. On September 22, 2016, at 1457 MST, SGA-UV-1134 was properly closed, declared operable, and LCO 3.6.3 was exited.

This event was caused by human error when procedural guidance was not used to return SGA-UV-1134 to its neutral locked configuration following testing on June 28, 2016. Actions have been initiated to ensure proper procedural guidance is used to lock SGA-UV-1134 in the future.

On June, 26, 2015, LER 50-530/2015-002 reported a condition prohibited by LCO 3.0.4 that occurred on May 1, 2015, when Unit 3 entered Modes 4 and 3 while in the applicability of LCO 3.7.4. On May 2, 2015, automatic dump valve, SGB- HV-178, was stroked with steam while in Mode 3 and discovered to be inoperable due to human error incurred during post- maintenance assembly prior to entering Mode 4.

05000528/LER-2016-0024 November 2016Palo Verde

On September 7, 2016, at 2131, with Unit 1 in Mode 1 and 100 percent power, the reactor was manually tnpped and reactor coolant pumps were secured due to a control malfunction which prevented closure of a pressurizer spray valve. This event initiated from an unsuccessful attempt to transfer a non-class 120VAC instrument power bus from its normal source to its emergency/alternate source. The transfer was attempted to facilitate an inspection of an electrical load center which was sprayed with water earlier in the day by a leaking sprinkler head following Fire Protection (FP) Department routine testing of a FP water line.

The cause of the spray valve malfunction was a failed pneumatic volume booster in the spray valve actuator system combined with a current to pressure converter (I/P) calibration offset which resulted from a voltage transient during the unsuccessful electrical transfer. These conditions caused the spray valve to stay approximately five percent open when it received a close demand from the spray valve controller. The I/P converter and pneumatic volume booster were replaced and the spray valve was returned to service. Additional corrective actions will adjust preventive maintenance frequency on the pneumatic volume boosters.

In the past three years, PVNGS has not reported a similar event to the NRC.

05000529/LER-2016-00110 October 2016Palo Verde

On August 9, 2016, Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A was entered for Unit 2 main steam isolation valve SGE-UV-171 (MSIV 171) train A actuator to perform a nitrogen pre-charge check.

The check identified low nitrogen pre-charge pressure on the train A accumulator. An engineering evaluation determined that the MSIV 171 train A actuator was inoperable since July 30, 2016 due to a nitrogen leak on the accumulator. This inoperability period exceeded the 7-day required action completion time for one MSIV actuator train. The MSIV 171 train A actuator was restored to operable status and LCO 3.7.2, Condition A was exited on August 9, 2016. The accumulator leak was repaired on October 5, 2016. Insufficient monitoring, trending, and understanding of reservoir hydraulic fluid level trends in relation to the nitrogen pre-charge required for MSIV operability led to the extended inoperability period.

Operator training will be revised to improve understanding of the system and the limitations of the hydraulic fluid level alarm. Additional corrective actions will revise procedures to provide enhanced rigor for the control of operations condition monitoring thresholds for an MSIV to ensure appropriate response times. Maintenance procedures will also be revised to provide more explicit guidance to minimize the potential for leaks. In the past 3 years, PVNGS has not reported a similar event to the NRC.

05000528/LER-2016-0019 June 2016Palo Verde

On April 10, 2016, at 2335, with Unit 1 in Mode 5, during a planned extent-of-condition inspection of the Unit 1 reactor coolant system (RCS), engineering personnel at the Palo Verde Nuclear Generating Station (PVNGS) identified white residue on a one-inch instrument nozzle on the reactor coolant pump 2B discharge pipe. Isotopic analysis confirmed the white residue resulted from leakage of RCS coolant and, at 0535 on April 11, 2016, engineering personnel determined that RCS pressure boundary leakage had occurred resulting in a condition prohibited by Technical Specification 3.4.14, RCS Operational Leakage.

The cause of the event was determined to be primary water stress corrosion cracking of the Alloy 600 instrument nozzle.

To correct the condition, the nozzle was repaired utilizing a Mechanical Nozzle Seal Assembly. A final repair of the nozzle will be addressed in the Corrective Action Program.

PVNGS reported similar events in licensee event report numbers 50-530/2015-001-00 (on June 5, 2015, when RCS pressure boundary leakage was identified on a Unit 3 RCP 2A suction pipe instrument nozzle) and 50-530/2013-001-00 (on December 6, 2013, when RCS pressure boundary leakage was identified on a Unit 3 reactor vessel bottom mounted instrument nozzle).

05000530/LER-2015-0045 February 2016Palo Verde

On August 13, 2015, at approximately 2106, the Unit 3 main steam isolation valve SGE-UV-181 (MSIV-181) B actuator train was declared inoperable and Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A, was entered due to a failed fitting on the air supply line. To correct the condition the failed fitting was replaced and an additional pipe support was installed on the air-line. Following retests, the MSIV-181 B actuator train was restored to operable status and LCO 3.7.2, MSIV-181 B actuator train on May 19, 2015. The investigation of this condition following the second failure determined the MSIV-181 B actuator train air-line configuration was modified in the spring 2015 Unit 3 refueling outage and was inoperable from the time Unit 3 entered Mode 4 on May 1, 2015, at 0258, following the outage because the air-line tubing was not adequately supported following the design change.

The cause of the failure was lack of adequate guidance to perform a walk down during the PVNGS design equivalent change (DEC) process. The lack of a local inspection of actual plant conditions resulted in the latent condition (i.e., vibratory displacement of the affected air-line combined with inadequate tubing support) remaining unnoticed prior to the component failure. Immediate corrective actions to replace the failed fittings and add additional support were completed on August 15, 2015.

An additional corrective action will revise procedural guidance and associated documents.

No similar conditions have been reported by PVNGS in the last three years.

05000530/LER-2015-004, Condition Prohibited by Technical Specifications 3.0.4 and 3.7.2 Due to an Inoperable Main Steam Isolation Valve9 October 2015Palo Verde

On August 13, 2015, at approximately 2106, the Unit 3 main steam isolation valve SGE-UV-181 (MSIV-181) B actuator train was declared inoperable and Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2, Condition A, was entered due to a failed fitting on the air supply line. To correct the condition the failed fitting was replaced and an additional pipe support was installed on the air-line. Following retests, the MSIV-181 B actuator train was restored to operable status and LCO 3.7.2, Condition A, was exited on August 15, 2015, at approximately 1830.

A similar air-line fitting failure had occurred on the Unit 3 MSIV-181 B actuator train on May 19, 2015. The investigation of this condition following the second failure determined the MSIV-181 B actuator train air-line configuration was modified in the spring 2015 Unit 3 refueling outage and was inoperable from the time Unit 3 entered Mode 4 on May 1, 2015, at 0258, following the outage because the air-line tubing was not adequately supported following the design change.

The investigation of the two fitting failures is still in progress. The cause of this condition and any additional corrective actions will be reported in a supplement to this Licensee Event Report.

No similar conditions have been reported by PVNGS in the last three years.

05000530/LER-2015-003, Damaged High Pressure Safety Injection Pump Motor Journal Bearing29 July 2015Palo Verde

On May 30, 2015, emergent maintenance on the Unit 3 train A high pressure safety injection (HPSI) pump motor outboard journal bearing performed under Nuclear Regulatory Commission (NRC) approved notice of enforcement discretion 15-4-01 exceeded the Technical Specification Limiting Condition for Operation (LCO) completion time for LCO 3.5.3, Emergency Core Cooling Systems - Operating, Condition C.1. The HPSI pump had been removed from service on May 27, 2015, at 0628, for planned routine maintenance. During maintenance, it was discovered that the motor outboard journal bearing was damaged. The bearing was replaced and the pump was declared operable on May 30, 2015, at 1710.

The root cause was work instruction weaknesses which resulted in improper reassembly of the HPSI pump motor during planned maintenance in the Unit 3 spring 2015 refueling outage. Immediate corrective actions replaced the damaged outboard motor bearing and properly reassembled the pump and motor. To prevent recurrence, maintenance procedures will be revised to provide enhanced guidance for pump and motor reassembly. An additional action will determine training enhancements needed to address weaknesses with maintenance personnel knowledge.

No previous-similar events have been reported to the NRC by PVNGS in the prior three years.

05000530/LER-2015-00226 June 2015Palo Verde

On May 1, 2015, following completion of refueling activities, PVNGS Unit 3 entered Mode 4 and continued to Mode 3 in preparation for plant startup. On May 2, 2015, when plant conditions needed to test atmospheric dump valves (ADV) with steam were achieved, testing of ADVs was initiated. At 1739 on May 2, 2015, testing determined that ADV SGB-HV-178 (ADV-178) would not stroke more than approximately 13 percent open. Operations personnel declared ADV-178 inoperable and entered Technical Specification Limiting Condition of Operation (LCO) 3.7.4, Atmospheric Dump Valves, Condition A. An investigation determined ADV-178 was inoperable when Unit 3 entered Mode 4.

Inspection of ADV-178 determined internal sealing rings were improperly installed during maintenance performed in the refueling outage. The valve was repaired and tested and declared operable at 0853 on May 7, 2015. The causes of the event were human error by maintenance personnel and inadequacies with the procedure used to perform the valve maintenance. Corrective actions will revise work instructions to provide detailed guidance for valve re- assembly and to require verifications of proper re-assembly.

A similar event was reported in LER 50-529/2012-003-00 which resulted when testing in Mode 3 following refueling activities identified an inoperable steam supply valve for the steam driven auxiliary feedwater pump.

05000530/LER-2015-002, Condition Prohibited by Technical Specification 3.0.4 Due to an Inoperable Atmospheric Dump Valve (ADV)26 June 2015Palo Verde

in preparation for plant startup. On May 2, 2015, when plant conditions needed to test atmospheric dump valves (ADV) with steam were achieved, testing of ADVs was initiated. At 1739 on May 2, 2015, testing determined that ADV SGB-HV-178 (ADV-178) would not stroke more than approximately 13 percent open. Operations personnel declared ADV-178 inoperable and entered Technical Specification Limiting Condition of Operation (LCO) 3.7.4, Atmospheric Dump Valves, Condition A. An investigation determined ADV-178 was inoperable when Unit 3 entered Mode 4.

Inspection of ADV-178 determined internal sealing rings were improperly installed during maintenance performed in the refueling outage. The valve was repaired and tested and declared operable at 0853 on May 7, 2015. The causes of the event were human error by maintenance personnel and inadequacies with the procedure used to perform the valve maintenance. Corrective actions will revise work instructions to provide detailed guidance for valve re-assembly and to require verifications of proper re-assembly.

A similar event was reported in LER 50-529/2012-003-00 which resulted when testing in Mode 3 following refueling activities identified an inoperable steam supply valve for the steam driven auxiliary feedwater pump.

05000529/LER-2014-00221 April 2015Palo Verde

On November 6, 2014, at approximately 1116 Mountain Standard Time, Unit 2 was in Mode 1, 100 percent power, when control element assembly (CEA) 15 dropped fully into the core while the 88 other CEAs remained fully withdrawn.

Operations entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.1.5, Condition A, for one CEA misaligned from its group which requires a power reduction and restoration of CEA alignment. An initial power reduction was performed in accordance with TSs and attempts to repair the problem were initiated. The CEA could not be aligned within the 2 hour TS time limit and TS LCO 3.1.5, Condition C was entered at 1316 which required entry into Mode 3 within 6 hours. The power reduction was continued and the reactor was manually shutdown at 1636 to comply with TSs.

The direct cause of the event was a failed upper gripper coil on the control element drive mechanism (CEDM) for CEA 15.

The failed coil was replaced and Unit 2 was restarted and entered Mode 1 at 0332 on November 13, 2014. Operation of the coil at elevated temperatures accelerated thermal degradation of the coil insulation. A preventive maintenance strategy for establishing coil voltages and online CEDM coil monitoring, and adjustment, if necessary, was implemented.

In the previous 3 years, similar events related to malfunctions of control element drive mechanism control system equipment that resulted in a plant shutdown were reported in LERs 50-528/2011-004, 50-528/2011-005 and 50-530/2012-001.

05000529/LER-2015-00125 March 2015Palo Verde

On January 11, 2015, at 0024, Unit 2 received a plant computer monitoring system (RJ) alarm on point SASB22, indicating the setpoint for the bistable relay that compares pressures between Steam Generators (SGs) was approaching the technical specification (TS) allowable limit for SG Pressure Difference-High. SASB22 does not alarm to control room annunciators (RK) and went unnoticed until late in the shift. Operators then verified the annunciator for SG differential pressure (DP) was not alarming and SG pressures were normal. The significance of the RJ alarm was not apparent because the value was displayed in units of voltage versus DP.

On January 24, 2015, further questioning determined the setpoint for the bistable that monitors differential pressure between SGs had exceeded its allowable value. Channel B SG Pressure Difference-High was declared inoperable and SG Level 2-Low was placed in bypass per LCO 3.3.5, Condition A.

The direct cause of the event was setpoint drift of the SASB22 bistable relay caused by potentiometers that had not recently been wiped clean. The root cause was the lack of an annunciated alarm for SASB22 and associated alarm response procedure to ensure the alarm condition was promptly acknowledged, understood, and correctly addressed within TS time limitations.

No previous similar events have been reported to the NRC by PVNGS in the prior three years.

05000529/LER-2015-001, Condition Prohibited by Technical Specification (TS) Limiting Condition for Operation (LCO) 3.3.5, Engineered Safety Features Actuation System (ESFAS)25 March 2015Palo Verde

On January 11, 2015, at 0024, Unit 2 received a plant computer monitoring system (RJ) alarm on point SASB22, indicating the setpoint for the bistable relay that compares pressures between Steam Generators (SGs) was approaching the technical (RK) and went unnoticed until late in the shift. Operators then verified the annunciator for SG differential pressure (DP) was not alarming and SG pressures were normal. The significance of the RJ alarm was not apparent because the value was displayed in units of voltage versus DP.

On January 24, 2015, further questioning determined the setpoint for the bistable that monitors differential pressure between SGs had exceeded its allowable value. Channel B SG Pressure Difference-High was declared inoperable and SG Level 2-Low was placed in bypass per LCO 3.3.5, Condition A.

The direct cause of the event was setpoint drift of the SASB22 bistable relay caused by potentiometers that had not recently been wiped clean. The root cause was the lack of an annunciated alarm for SASB22 and associated alarm response procedure to ensure the alarm condition was promptly acknowledged, understood, and correctly addressed within TS time limitations.

No previous similar events have been reported to the NRC by PVNGS in the prior three years.

05000529/LER-2014-00111 August 2014Palo Verde

On June 6, 2014, following planned maintenance on the train A emergency diesel generator (EDG) fuel oil (FO) cooler, essential spray pond (ESP) system water leakage was found on the FO cooler upper cover. The FO cooler upper cover was replaced with a new cover and the EDG and ESP systems were returned to service. A visual inspection of the removed cover identified corrosion related degradation of the cast iron cover. On June 11, 2014, an engineering analysis was completed to determine the required minimum wall thickness for the pressure boundary of the FO cooler upper cover.

Measurements of the FO cooler upper cover wall thickness were found to be below the minimum wall thickness needed to maintain structural integrity for the full range of its design basis requirements. Consequently, it was determined the train A ESP system had been inoperable in excess of the completion time allowed by TS LCO 3.7.8. On June 28 and 29, 2014, the remaining five FO cooler upper covers (trains A and B for Units 1 and 3 and train B for Unit 2) were replaced with new covers.

The root cause of this event was latent design characteristics of the EDG FO cooler that resulted in a localized area in the cooler cover that was susceptible to galvanic corrosion. To prevent recurrence, a design modification will be implemented to remove the EDG FO cooler design function and isolate or remove the related ESP supply piping for the FO cooler.

No previous similar events have been reported to the NRC by PVNGS in the prior three years.

05000528/LER-2013-0049 June 2014Palo Verde

On April 10, 2014, a post-event review conducted in response to a proposed NRC non-cited violation concluded the actions to close and deactivate main steam isolation valve SGE-UV-170 (MSIV-170) to address an equipment malfunction on November 6, 2013, did not meet the operability requirements of Technical Specification (TS) Limiting Condition for Operation (LCO) 3.7.2. As a result, the requirement of LCO 3.7.2 Condition G to place the unit in Mode 2 within 6 hours was not completed. MSIV-170 was repaired and returned to service on November 9, 2013.

An 'investigation determined the cause of the condition prohibited by TSs was the operability determination (OD) was overly focused on the ability of the MSIV to perform its specified safety function and did not adequately consider the definition of operability and compliance with the TS. To prevent recurrence, PVNGS OD guidance will be revised to explicitly require evaluation of applicable LCOs to ensure the OD technical conclusions support compliance with the LCOs.

No similar events have been reported to the NRC by PVNGS in the prior three years.

05000529/LER-2013-00231 January 2014Palo Verde

On December 2, 2013, Unit 2 was operating in Mode 1 at 100 percent power. At approximately 1758 Mountain Standard Time a reactor trip was automatically actuated when reactor coolant pump (RCP) 1A speed dropped below 95 percent of rated speed which generated low departure from nucleate boiling ratio and high local power density trips on all four channels of the plant protection system. The reactor trip was determined to be uncomplicated and the reactor trip procedure was implemented to stabilize the plant in Mode 3. Operations personnel subsequently determined the RCP 1A motor circuit breaker tripped on excessive phase differential current.

The probable cause of the RCP 1A motor circuit breaker trip was a high impedance fault within the C phase of the motor stator coil. The faulted RCP 1A motor was replaced with an on-site spare RCP motor and Unit 2 was returned to power operation on December 14, 2013.

The faulted motor has been sent to an off-site facility for disassembly and root cause analysis.

No previous similar events involving an automatic RPS actuation due to a RCP motor failure have been reported to the NRC by PVNGS in the prior three years.

05000530/LER-2013-0016 December 2013Palo Verde

On October 6, 2013, during a scheduled visual examination of the 61 bottom-mounted instrument (BMI) nozzles on the Unit 3 reactor vessel, white residue was identified around the annulus region of BMI nozzle 3. At 0219 on October 7, 2013, engineering personnel determined, based on past and present photographic evidence, that the white residue likely resulted from reactor coolant system (RCS) pressure boundary leakage.

The pressure boundary leakage resulted in a condition prohibited by Technical Specification 3.4.14, reportable pursuant to 10 CFR 50.73(a)(2)(i)(B), and a degraded principal safety barrier, reportable pursuant to 10 CFR 50.73(a)(2)(ii)(A).

Non-destructive examination (NDE) of BMI nozzle 3 identified axial cracking in a near-surface weld flaw in the J-groove weld that extended into the nozzle tube and ultimately resulted in the RCS leak path.

An extent of condition evaluation found no indication of unacceptable flaws or leakage in the remaining 60 BMI nozzle assemblies in Unit 3.

Additionally, no evidence was found that indicated leakage from BMI nozzle assemblies in Units 1 or 2.

The probable cause of the BMI nozzle 3 leakage was a near-surface weld flaw that came in contact with RCS water and allowed initiation of primary water stress corrosion cracking. The flaw was likely caused by a BMI nozzle J- groove weld defect that occurred during reactor vessel fabrication and was undetected by penetrant testing.

An American Society of Mechanical Engineers Code approved weld pad/half-nozzle repair was performed to establish a new BMI nozzle assembly weld configuration.

Corrective actions include increasing the frequency of BMI visual examinations so that one is performed each refueling outage.

No similar events have been reported to the NRC by PVNGS in the prior three years.

1

05000528/LER-2013-0033 December 2013Palo Verde

On October 04, 2013, at approximately 0946 Mountain Standard Time (MST), during review of industry operating experience, PVNGS engineering personnel determined an unanalyzed condition exists related to the Control Room (CR) fire analysis. The original design of ammeter circuits which provide CR current indication for the train B and D class 1E batteries and battery chargers does not include overcurrent protection features to limit fault current. In the postulated event, a fire in the CR could cause a ground loop through unprotected ammeter wiring and potentially result in excessive current flow and heating to the point of causing a secondary fire outside the CR in the cable raceways. The postulated secondary fire could affect the availability of equipment needed to place the plant in a safe shutdown condition during a CR fire event. This scenario has not been analyzed in accordance with 10 CFR 50 Appendix R, Section III.G. Compensatory fire watch measures have been implemented and remain in place for the affected fire zones in the plant.

The cause was determined to be that the original design of the DC ammeter circuits did not adequately address fire protection program requirements. A design change is planned to correct the latent design deficiencies by providing circuit protection on affected CR ammeter circuits.

No similar events have been reported to the NRC by PVNGS in the prior three years.

05000528/LER-2013-0027 June 2013Palo Verde

This LER reports the failure of components caused by a defect in ARD66OUR control relays reported by Westinghouse, pursuant to 10 CFR 21, on April 8, 2013. The defect resulted in the failure of five normally energized control relays at PVNGS in two different systems in Unit 1 and two different systems in Unit 2.

The relays were used in normally energized applications which are de-energized to position associated components to support the related safety function. The relays failed to change state when de-energized during testing.

The five failed relays were replaced. The cause was a change in the manufacturing process that occurred in May 2008. The defect was exhibited only on relays that failed in the manner described in the Westinghouse Part 21 report. An extensive testing program was completed to identify and replace ARD66OUR relays installed at PVNGS that exhibited the described failure mode. Westinghouse has modified the ARD66OUR relay plastic molding process to preclude this described failure mode. LER 05000529 / 2009-002-00 reported ARD66OUR relay failures that exhibited a similar failure mode.

05000528/LER-2013-0017 May 2013Palo Verde

On March 8, 2013, PVNGS engineering personnel determined that certain impacts to the spent fuel pool (SFP) criticality analysis of record (AOR) had not been considered as part of the project to perform a power uprate to 3990 MW thermal in 2003. The power uprate impacted the reactivity of fuel discharged to the SFP but the SFP criticality AOR was not revised to account for the increased fuel reactivity. Therefore, this condition is being reported as an unanalyzed condition in accordance with 10 CFR 50.73(a)(2)(ii)(B).

The cause was procedures and processes lacked adequate rigor to identify impacts to the SFP criticality AOR.

Additionally, the impacts of power uprate relative to the SFP criticality AOR were not well known or understood by personnel involved.

As an interim corrective action, an administrative control was implemented to apply a burnup penalty to low margin fuel assemblies to ensure Technical Specification (TS) reactivity requirements are met under all conditions. Planned corrective actions will revise design change procedures to consider reactivity impacts on the SFP and will revise the SFP criticality AOR using updated methodology and input parameters.

No similar events have been reported to the NRC in the prior three years.

05000529/LER-2012-0025 February 2013Palo Verde

On October 8, 2012, at 13:30, when Unit 2 was in Mode 5 during refueling outage 2R17, Shutdown Cooling System (SDC) Train A was declared inoperable in accordance with Technical Specification 3.4.7 due to a leak on a Low Pressure Safety Injection (LPSI) system Train A drain pipe during SDC operation. The leakage source was a weld defect on the LPSI cold leg 1A injection pipe drain connection upstream of drain valve SIA-V908. The leakage was first discovered on October 7, 2012, at 22:00 when water on the floor adjacent to the LPSI cold leg 1A injection pipe was first found, but not identified as leakage through the drain pipe weld until insulation was removed on October 8, 2012.

A configuration control problem in the early 1990s allowed contact between the drain pipe and a pipe hanger when the SDC system was in operation. This resulted in a weld defect being introduced due to the high cyclic stresses from the pipe/hanger contact. The configuration control problem was corrected in May 1993; but, the weld defect propagated slowly during periods of SDC operations until the leak occurred in the 2R17 outage.

The cause was determined to be inadequate guidance to ensure temporary fittings on safety-related fluid systems were removed prior to placing the system in service. To prevent recurrence, procedures were revised to require that systems with capped pipe ends be returned to their design configuration following maintenance.

05000528/LER-2011-0013 August 2012Palo Verde

On February 21, 2011, at approximately 2001 Mountain Standard Time, a valid actuation of the circuitry that starts the emergency diesel generators (EDG) for Palo Verde Nuclear Generating Station Unit 1 train 'B' and Unit 3 train 'A' occurred due to an undervoltage condition on their respective 4.16 kV safety buses. Both EDGs started and loaded as designed.

The loss of power to the Unit 1 and Unit 3 safety buses was the result of a protective relay actuation on the AE-NAN-X02 startup transformer which de-energized the transformer and the Unit 1 13.8 kV intermediate bus 1E-NAN-S06 and the Unit 3 13.8 kV intermediate bus 3E-NAN-S05. The affected intermediate buses provide offsite power to the Unit 1 safety bus 1E-PBB-SO4 and the Unit 3 safety bus 3E-PBA-S03 respectively.

The cause of the undervoltage was a cable splice failure on the cable for the 'Y' winding of the AE-NAN-X02 startup transformer.

Unit 1 and Unit 3 entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.8.1, Condition A, for one required offsite circuit inoperable. Offsite power was restored to Unit 1 safety bus through the intermediate bus from the altemate supply.

Offsite power was restored to Unit 3 safety bus through the intermediate bus from the altemate supply. The LCO condition was exited by Unit 1 and Unit 3.

No similar events involving a cable splice failure have been reported by PVNGS in the last three years.

05000528/LER-2012-0029 July 2012Palo Verde

On May 9, 2012, a review of the procedural guidance for inoperable essential ventilation equipment by an investigation team concluded that a condition prohibited by Technical Specifications (TS) had occurred in unit 2 on January 22, 2012, when the TS requirements for electrical distribution equipment were not met.

On January 22, 2012, during surveillance testing in unit 2, a control relay did not change state as expected and the essential ventilation dampers controlled by this relay did not change position. Operations declared the affected essential air handling units inoperable. The TSs do not contain specific Limiting Conditions for Operation (LCO) requirements for the affected essential ventilation equipment and no TS LCO Conditions were entered. Operations followed existing procedural guidance for inoperable ventilation equipment. The procedural guidance required operations to verify that there was no loss of safety function and that normal room cooling was available.

The cause of the event was an inadequate procedure that was based on an incorrect understanding of the relationship between essential ventilation equipment that provides a support function to electrical distribution equipment and operability of the electrical distribution equipment. As corrective action, the affected procedure was revised.

Similar reportable events have not occurred in the past three years.

05000529/LER-2012-00126 March 2012Palo VerdeOn January 25, 2012, at approximately 1005 Mountain Standard Time, a reactor power cutback occurred in Unit 2 due to the loss of one main feedwater pump. Main turbine load was automatically reduced and all regulating group 4 and group 5 control element assemblies (CEAs) were automatically fully inserted to lower reactor power to approximately 50 percent. The Reactor Regulating System then automatically inserted regulating group 3 CEAs below the Technical Specification (TS) Transient Insertion Limits to maintain Reactor Coolant System temperature within limits. TS LCO 3.1.7 Regulating CEA Insertion Limits are not applicable for two hours after a reactor power cutback and then require CEA positions to be restored to within limits in the next two hours or be in Mode 3 within the following six hours. Group 4 and 5 CEAs were restored to within TS LCO 3.1.7 transient insertion limits at 1144. The regulating group 3 CEAs were withdrawn to the upper group stop position of 145.5 inches at 1124 but were not fully withdrawn to within limits (greater than or equal to (>/:--) 147.75 inches) until 2030, which exceeded the TS LCO 3.1.7 Completion Time by 25 minutes. The root cause was determined to be inadequate procedural guidance necessary to ensure regulating CEA group 3 was fully withdrawn to comply with the requirements of TS LCO 3.1.7 insertion limits. Corrective actions to prevent recurrence include procedure revisions to provide the needed guidance to ensure CEA insertion limits are met following a reactor power cutback. No similar events have been reported to the NRC in the prior three years.
05000528/LER-2011-0045 October 2011Palo Verde

On August 6, 2011, at approximately 1119 Mountain Standard Time, during the performance of surveillance test 40ST-9SF01, Control Element Assembly (CEA) Operability Checks, the Unit 1 reactor tripped due to an automatic actuation of the reactor protection system. The actuation occurred when CEA 37 of shutdown group B fully inserted causing a deviation of greater than 9.9 inches from other CEAs in its subgroup. This deviation generated a CEA calculator penalty factor and actuated the low departure from nucleate boiling ratio and the high lOcal power density trips on all four core protection calculator channels. Following the reactor trip, plant operators observed CEA 16 of regulating group 5 did not indicate that it had fully inserted. While operators prepared to borate the reactor coolant system, full insertion indication for CEA 16 was received approximately 1.5 minutes following the reactor trip.

The cause for the reactor trip was determined to be a loose terminal lug on the CEA power switch assembly which developed a high resistance connection and led to the improper operation of the control element drive mechanism upper gripper coil. As an immediate corrective action, the terminal lug was replaced and retested satisfactorily. Troubleshooting of CEA 16 did not identify any problems. Unit 1 returned to service and entered Mode 1 at 2140 on August 10, 2011.

No similar conditions have been reported by Palo Verde in the past three years.

05000529/LER-2011-0017 June 2011Palo Verdeentered Technical Specification Limiting Condition for Operation (TS LCO) 3.3.9 when the Control Room Essential Filtration Actuation Signal (CREFAS) was declared inoperable due to both Control Room intake radiation monitors being out of service. Irradiated fuel movement was allowed to continue due to an incorrect understanding that the already in-service Control Room Essential Filtration System (CREFS) "B" train air handling unit fulfilled the required action of the LCO. At 2140, the Outage Shift Manager entered the Control Room and noted that the Control Room was not fully pressurized and questioned whether the required actions of LCO 3.3.9 were met. At that time, the Control Room staff recognized that required dampers had not been closed. Re-alignment of the dampers was completed at 2146 to comply with the required actions of the LCO. The root cause was imprecise terminology in LCO 3.3.9 Required Action C.1, which did not specify that CREFS shall be placed in the essential filtration mode required for post-accident emergency alignment. A License Amendment Request will be submitted to provide more specific direction in LCO 3.3.9 regarding alignment of CREFS. The station has not reported any other TS 3.3.9 violations in the past three years.
05000530/LER-2011-00121 March 2011Palo Verde

On January 19, 2011, at approximately 1840 Mountain Standard Time, Unit 3 was at 100 percent power at normal operating temperature and normal operating pressure when the main feedwater pump A minimum flow recirculation valve (mini-flow valve) failed open causing a percentage of feedwater flow to be diverted to the condenser. Subsequently, Unit 3 experienced a reactor power cutback when main feedwater pump B tripped on low suction pressure. The combination of the main feedwater pump B trip and the main feedwater pump A mini-flow valve failure caused both steam generator water levels to lower causing an automatic reactor trip.

Both steam generator levels continued to drop which initiated an auxiliary feedwater actuation signal. The plant was stabilized in Mode 3.

The failed open mini-flow valve was caused by a failed diaphragm in a pneumatic 3-way precision relay within the mini-flow valve control loop. The relay was replaced and Unit 3 was returned to 100 percent power on January 23, 2011, at approximately 0100.

No similar conditions have been reported by Palo Verde in the past three years.

05000528/LER-2011-00317 January 2011Palo Verde

On April 13, 2011, control room essential filtration system (CREFS) outside air intake (OSA) dampers were found to be in the normally closed position instead of the normally open position stipulated in the updated final safety analysis report. This incorrect configuration was the result of procedure changes made in 1986.

Each train of the CREFS system contains two OSA dampers in series, with each damper actuated from one of the two separate channels of the control room essential filtration actuation signal (CREFAS). Upon identification, Unit 1 and Unit 3 entered Technical Specification (TS) 3.3.9, condition A when both channels of CREFAS were determined to be inoperable. In response, both units placed an OPERABLE train of CREFS into operation per required action A.1. Unit 2 was defueled and irradiated fuel assemblies were not being moved; therefore, TS 3.3.9 was not applicable to Unit 2 at the time this condition was identified.

In the three years prior to this event, a similar legacy issue was reported in which station procedures directed system configurations not permitted by the plant design (LER 0500528/529/530/2009-001-00, Safety Injection System Recirculation Alignment Results in Unanalyzed Condition).

05000528/LER-2010-00229 December 2010Palo Verde

On May 7, 2010, Palo Verde discovered that a calculation used for the closing force required for Main Steam Isolation Bypass Valves (MSIBVs) was non-conservative. During the Component Design Basis Review (CDBR), it was determined that the closing force would be inadequate to fully close the MSIBVs upon the receipt of a Main Steam Isolation Signal when Steam Generator (SG) pressure is greater than 700 psi. This condition renders the MSIBVs inoperable when SG pressure is above 700 psi. At the time of discovery, Unit 1 was in Mode 5 and the MSIBVs were not required to be operable; Unit 2 and Unit 3 were in Mode 1, and the MSIBVs were required to be operable. Both Unit 2 and Unit 3 entered the applicable Technical Specification (TS) Limited Condition for Operation (LCO) 3.6.3, Containment Isolation Valves. As an immediate corrective action, Unit 2 and Unit 3 ensured the MSIBVs were closed, with their penetration flowpath isolated to comply with the conditions of TS LCO 3.6.3.

Administrative barriers that existed at the time of the calculation revision (December 2000) were unsuccessful in preventing the error due to ineffective reviews and the lack of a questioning attitude. Calculations with the potential for this error were reviewed and evaluated. The extent of condition evaluation determined the error was limited to safety­ related Air Operated Valve (AOV) gate valves.

No similar events involving a non-conservative calculation for an AOV have been reported by PVNGS in the last three years.

05000528/LER-2009-00313 July 2009Palo Verde

On May 13, 2009, Palo Verde engineers discovered Surveillance Requirement (SR) 3.8.9.1 was not completely implemented in Surveillance Test (ST) procedure 40ST-9ZZ05, "Weekly Electrical Distribution Checks." The procedure did not verify the supply breaker alignment for the Class 1 E 125 VDC distribution panels (PKA-D21, PKB-D22, PKC-D23 and PKD-D24) as required by Technical Specification (TS) Bases Table 3.8.9-1. As a result, all three Palo Verde units entered SR 3.0.3.

Procedure 40ST-9ZZ05 was revised later the same day to include verification of the breaker position for the Class 1 E 125 VDC distribution panels. The revised procedure was performed in all three units satisfying SR 3.8.9.1 and each unit exited SR 3.0.3. Investigation of this event determined the condition has existed since the implementation of the Palo Verde Improved Technical Specifications (ITS) on August 13, 1998, when the Class 1 E distribution panels were added to TS Bases Table 3.8.9-1. The cause of the event was a lack of technical rigor when implementing the ITS.

One similar event was reported by PVNGS in the past three years in LER 50-528/2007-003 where a monthly valve alignment did not adequately meet its intent to satisfy TS SR.

05000530/LER-2008-00226 November 2008Palo Verde

On September 27, 2008, at approximately 21:51 hours, Mountain Standard Time, Unit 3 control room operators initiated a manual reactor trip from approximately 34% rated thermal power in response to high vibrations on the main turbine. The main turbine vibrations were experienced during a required power reduction resulting from a steam generator chemistry excursion. The event was considered an uncomplicated reactor trip. No automatic engineered safety feature (ESF) actuations occurred during the event and none were required. All safety related buses remained energized from normal offsite power during and following the reactor trip.

The cause of the reportable event was the decision by control room operators to initiate a manual reactor trip in response to the main turbine high vibrations. The operators chose to initiate the reactor trip earlier than intended in the planned shutdown in response to the high turbine vibrations. The reactor trip was not necessary to mitigate the consequences of the event.

There have been manual reactor trips in the past at Palo Verde Nuclear Generating Station but none with causes similar to this event. As such, the corrective actions for those events would not have prevented this event.

05000530/LER-2007-0017 April 2008Palo Verde

During an extent of condition review for events that could have led to the obstruction of the Containment Spray (CS) system, Arizona Public Service (APS) identified an April 21, 2007, event where nozzles in the Unit 3 CS system may have become obstructed. On December 5, 2007, while performing a Surveillance Test of the Unit 3 CS spray nozzles, APS personnel discovered one obstructed nozzle on each of two separate Containment Spray (CS) train 'A' lines. The evaporation of borated water from a header overfill event caused boric acid residue to accumulate and obstruct the two CS nozzles for a period greater than allowed by Technical Specification 3.6.6 limiting condition for operation. The nozzles were cleaned and restored to service on December 18, 2007.

The cause of the CS overfill event was determined to be leakage by the containment spray train 'A' discharge valve seat. The cause of the Unit 3 CS system nozzles blockage was from inadequate consideration of the consequences of overfilling the CS system with borated water.

There have been no previous similar events in the past three years that had a similar failure mechanism or that should have prevented this event as a result of previously implemented corrective actions.

05000528/LER-2008-0011 April 2008Palo Verde

On February 1, 2008, during performance of the Component Design Bases Review initiative, engineering personnel determined that surveillance test procedure (STP), "Remote Shutdown Disconnect Switch and Control Circuit Operability," was not adequate to meet the Technical Specification (TS) Surveillance Requirement (SR).

TS SR 3.0.3 was entered for the affected components, and risk assessments were performed which supported continued operability until such time as the components could be adequately tested.

The direct cause of this condition was that the STP did not ensure that each circuit was verified to meet the requirements of the TS SR. The preliminary root cause analysis is that 10 CFR 50, Appendix R experienced personnel did not provide input during the development of the STP. Corrective actions include performance of new and revised STPs to adequately demonstrate compliance with the TS SR within the schedule permitted by TS SR 3.0.3.

There have been two previous similar occurrences of failure to meet TS SRs due to inadequate STPs in the past three years. Corrective actions taken as a result of those conditions would not have prevented this condition.

05000528/LER-2007-00722 January 2008Palo Verde

Control Room. Shortly after this unexpected alarm, other unexpected alarms were received and the essential spray pond pump started automatically. The Balance of Plant (BOP) Engineered Safety Feature Actuation System (ESFAS) Train "A" load sequencer was declared inoperable, and troubleshooting to identify the cause of the event commenced.

Troubleshooting and corrective maintenance were not completed in time to restore the train to operability within the 24 hours permitted by TS Limiting Condition for Operation (LCO) 3.8.1, Condition F, and Unit 1 was shut down as required by TS LCO 3.8.1, Condition H.

The direct cause of the BOP ESFAS failure was the failure of a relay coil suppression diode. The failed diode was replaced and no failures of other noise suppression diodes were identified. Following corrective maintenance and successful retest of the Train "A" BOP ESFAS load sequencer, the affected equipment was declared operable on November 25, 2007. ' There has been one previous Licensee Event Report submitted in the past four years reporting an Engineered Safety Feature actuation and the subsequent unit shutdown required by TS; however, the cause of that event was distinctly different from this event.

  • NRC. FORM 366A U.S. NUCLEAR REGULATORY COMMISSION (7-2001)
05000528/LER-2007-00410 October 2007Palo Verde

On August 11, 2007, Palo Verde Units 1, 2 and 3 were in Operating Mode 1 (Power Operations), at approximately 100 percent rated thermal power, when a void was discovered in the Unit 1 Containment Spray (CS) "B" header, which was not in compliance with Technical Specification (TS) Surveillance Requirement (SR) 3.6.6.2.

The direct cause of the void in the CS header was that the Unit 1 "B" CS Header was not properly vented during the fill and vent process on July 1, 2007. The root cause of this condition was ineffective use of operating fundamentals during the pre-job briefing, resulting in failure to identify the potential for air entrapment during the fill and vent process on July 1, 2007.

Subsequent investigation determined that the Surveillance Test Procedure (STP) forall three units did not adequately satisfy the requirements of the TS SR to demonstrate that the CS headers were full of water.

The direct cause for the identified failure to properly meet the TS SR to verify the CS header is full was a procedural deficiency in that STP 40ST-9S113, "LPSI and CS System Alignment Verification" did not adequately demonstrate compliance with TS SR 3.6.6.2. Ultrasonic Testing (UT) was performed on all CS headers in all three units to verify that they were full of water, and a small void in Unit 3 "B" header was detected and filled and vented. UT was subsequently added to the affected STP to ensure compliance with TS SR 3.6.6.2.

System containment sump piping due to a failure to translate the design intent to have the line filled with water into start-up, surveillance, and operating procedures.

05000528/LER-2007-00311 September 2007Palo Verde

On July 13, 2007, with Unit 1 in Operating MODE 3, and Units 2 and 3 both in Operating MODE 1 at approximately 100 percent rated thermal power, during performance of a Component Design Basis Review (CDBR), station personnel determined that Surveillance Test Procedure (STP), 40ST-9AF07, "Auxiliary Feedwater Pump AFA-P01 Monthly Valve Alignment," did not adequately meet its intent to satisfy Technical Specifications (TS) Surveillance Requirement (SR) 3.7.5.1 for position verification of the steam admission bypass valves to Auxiliary Feedwater Pump AFA-P01. Specifically, the STP did not provide adequate verification of the position of valves SGA-UV-134A and SGA-UV-138A.

The STP was revised to include the affected valve position verification and was subsequently successfully performed. The root cause investigation is in progress.

steps in an STP. The actions taken as a result of that event would not have prevented this event from occurring.

05000529/LER-2007-00120 April 2007Palo Verde

On February 16, 2007, Unit 2 was In Mode 1 at approximately 100 percent rated thermal power, running the High Pressure Safety Injection (HPSI) 2A pump in support of activities to determine the leak rate of oil from the pump bearings. The oil leak rate was found to be greater than acceptable and at approximately 13:01 Mountain Standard Time (MST), Operations personnel declared the HPSI 2A pump inoperable and entered Technical Specification (TS) Limiting Condition for Operation (LCO) 3.5.3, Condition B, placing the plant in a 72 hour action. Corrective actions could not restore the pump to an operable status within the TS LCO allowed time. On February 19, 2007, at approximately 14:56 MST, Operations commenced a plant shutdown and at 16:45 MST, the reactor was manually tripped from approximately 20 percent power and the unit entered Mode 3. No TS LCO allowed action times were exceeded.

The oil leaks were corrected and on February 22, 2007, at approximately 05:02 MST Unit 2 declared HPSI 2A operable. The corrective actions were also implemented in the other five HPSI pumps on site.

In the past three years, there were two events reported for a TS shutdown that became necessary when attempted repairs could not be performed within the completion time for the TS LCO required action.

4.

05000529/LER-2007-0024 April 2007Palo Verde

On February 3, 2007, Unit 2 was in Mode 1 at approximately 100 percent power performing a surveillance test (ST) to demonstrate the operability of full strength Control Element Assemblies (CEA) by moving each CEA five inches. While performing this test, Shutdown Group B, Subgroup 6 failed to withdraw after it was successfully inserted five inches. This left the CEA Subgroup at 144 inches, which is below the limit as required by Technical Specification (TS) Limiting Condition for Operation (LCO) 3.1.6. Unit 2 entered TS LCO 3.1.6, condition A and TLCO 3.1.204 condition A at approximately 12:32 Mountain Standard Time (MST). At approximately 13:15 (MST), Unit 2 Operators entered LCO 3.0.3 due to more than one CEA inserted beyond the TS limit.

At approximately 16:16 (MST) on February 3, 2007, following corrective maintenance to replace a phase synchronization card, CEA Subgroup 6 was restored above the TS 3.1.6 insertion limit and Unit 2 exited LCO 3.0.3. The cause of the failed phase synchronization card was determined to be the random failure of a ceramic capacitor.

In the past three years, there were no similar events reported for multiple CEAs being inserted beyond TS Limits.

05000529/LER-2006-00622 March 2007Palo Verde

On December 22, 2006, the Palo Verde Nuclear Generating Station (PVNGS) received a Final Significance Determination letter from the Nuclear Regulatory Commission (NRC) for Apparent Violations received during an NRC Heat Exchanger Performance inspection. The NRC concluded in the letter that the Unit 2 Essential Cooling Water, Train B heat exchanger was Inoperable and a Technical Specification (TS) 3.7.7 violation for a period of 78 days occurred, ending on September 27, 2003 when Unit 2 was shutdown for a refueling outage (U2R11). The subject heat exchanger was restored to Operable during the refueling outage. Essential Cooling Water, Train A heat exchanger was functional for the 78 day period that EW 2B was considered inoperable.

As a result of other heat exchanger problems, in May 2006, Arizona Public Service (APS) initiated an investigation of the Essential Cooling Water heat exchangers and the chemistry controls for the Spray Pond System. The APS investigation identified system problems with chemistry control, equipment maintenance and organizational weakness which allowed the problems to develop and remain uncorrected for an extended period. A number of corrective actions were implement or are being implement which include restoring effective chemistry controls of the system, procedure changes, personnel training, and equipment modification.

In the past three years, there were no similar events reported.

05000529/LER-2006-00428 September 2006Palo Verde

On July 27, 2006, station personnel discovered that the hydraulic accumulator for Feedwater Isolation Valve #174 (FWIV #174) would not recharge because a failed four-way valve became lodged in the center blocked position.

Further evaluation concluded that the condition would have prevented fast closure of the FWIV upon receipt of a main steam isolation signal and had existed since approximately 21:09 Mountain Standard Time (MST) on July 13, 2006. This exceeded the technical specification required action time. The four way valve was replaced and the FWIV was declared operable on July 28, 2006.

The preliminary cause of exceeding the technical specification action time was that the failed condition of the four­ way valve was not known to operators until the accumulator failed to recharge on July 27, 2006. Corrective action included revision of the depressurizing procedure to verify the respective four-way valve returns to its required position and is not lodged in the blocked position.

A non-reportable failure of FWIV #174 occurred in Unit 2 on May 13, 2003 when the four-way valve became lodged in the standby position which did not adversely impact the FWIV operability.

NRC POW 366A U.S. NUCLEAR REGULATORY COMMISSION (7-2001)

05000529/LER-2006-00214 September 2006Palo Verde

On July 16, 2006 at approximately 14:52 Mountain Standard Time (MST) Unit 2 was operating at 100 percent power, Model (power operations), when an Area Operator (AO) notified the control room that door C-A-06 was found open with no compensatory measures established.

Door C-A-06 is a watertight fire door that functions as the train separation barrier between Auxiliary Feedwater (AF) pump rooms 'A' and 'B.' When door C-A-06 is open with the unit operating in Mode 1, compensatory action must be taken in order to maintain both trains of AF operable. The AO who discovered door C-A-06 open and unattended, closed the door immediately. Based on a review of security computer transaction logs, control room personnel determined that door C-A-06 was open with no compensatory actions in place for approximately 4 hours and 20 minutes. As such, AF trains 'A' and 'B' were considered inoperable between 10:32 and 14:52 (MST). Based on further review and personnel interviews, an investigation concluded that a Fire Department Emergency Services Officer (ESO) had failed to close C-A-06 after leaving the AF pump room.

In the past three years, there were two similar events reported (LER 50-529/2005-003-00, and 50-530-2006-001-00).

05000529/LER-2005-0041 July 2006Palo Verde

On August 22, 2005 at approximately 1750 Mountain Standard Time (MST), Unit 2 completed a reactor shutdown required by the Technical Specifications. The shutdown was required due to all four channels of the Core Protection Calculators (CPC) being declared inoperable on August 22 at 1326 MST based on information from the CPC vendor that software changes that had previously been implemented in Unit 2 CPCs changed the way the CPCs would operate for a failed sensor.

The direct cause of the Unit 2 CPC software issue was a 2002 revision of the software requirements specification led to an inconsistency with the system requirements specification.

The root cause was determined to be that no formal communication plan existed within the internal Westinghouse users of the reactor trip function in the CPCs.

The Unit 2 software has been corrected. Unit 1 had the correct software installed when the software change was made. Unit 3 has not installed the new software at this time.

Although other Technical Specification required shutdowns have been reported in the last three years none were due to similar causes or equipment.

05000528/LER-2005-0047 October 2005Palo Verde

On August 12, 2005 at 0019 Palo Verde Unit 1 was in Mode 1 (Power Operations), operating at approximately 94 percent power, when Control Room personnel commenced a reactor shutdown required by Technical Specification 3.8.1.

Prior to the event, on August 9, 2005, Emergency Diesel Generator "B" failed to maintain proper steady state output voltage during the performance of a routine monthly surveillance test.

Engineering and Maintenance personnel were unable to identify and correct the cause of the fluctuating generator output voltage within the 72 hour required action completion time associated with Limiting Condition for Operation 3.8.1 which would have expired August 12, 2005 at 0420. At 0216 on August 12, 2005 Control Room personnel manually tripped the reactor from 23 percent reactor power. At 0217, Palo Verde Unit 1 entered Mode 3 (Hot Standby), completing a reactor shutdown required by Technical Specification 3.8.1. At 2237 on August 12, 2005, Unit 1 entered Mode 5 (Cold Shutdown) and exited LCO 3.8.1.

All times in this report are approximate and Mountain Standard Time unless noted otherwise.

In the past three years, Palo Verde reported reactor shutdowns required by Technical Specifications but none associated with the same root cause.