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All times listed in this event report are approximate and Mountain Standard Time (MST) unless otherwise indicated.

On October 26, 2006, at approximately 23:53 MST, a valid actuation of the Palo Verde Nuclear Generating Station Unit 1 Train B Emergency Diesel Generator (EDG) and Unit 3 Train B EDG occurred as a result of under-voltage on their respective safety buses. Both EDGs started and loaded as designed. No Emergency Plan declaration was made and none was required.

The loss of power to the two safety buses was the result of an apparent protective relay actuation of Startup Transformer X01 output breakers to Unit 1 NAN-S06 and Unit 3 NAN-S06 electrical distribution busses. Unit 1 NAN-S06 bus was being supplied by its Alternate breaker (1ENANSO6F) and Unit 3 NAN-506 was being supplied by its Normal breaker (3ENANSO6C). Prior to the event, maintenance personnel were restoring potential transformer (PT) fuses at Unit 1 breaker 1ENANS06, Cubicle G.

Current belief is that the two simultaneous LOP conditions occurred when the cubicle door was closed on 1ENANS06, Cubicle G. This condition apparently caused the output breakers of Startup Transformer X01 to open. There was no electrical fault or damage to any electrical components.

In the past three years, Palo Verde reported Emergency Diesel Generator Actuation on Loss of Power but none associated with the same root cause.

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.

On August 21, 2007, with Palo Verde Units 1, 2 and 3 in Operating Mode 1 (Power Operations), at approximately 100 percent rated thermal power; during performance of a Component Design Basis Review of the Auxiliary Feedwater (AF) System, station personnel determined that the existing Surveillance Test Procedures (STP) did not verify that Technical Specification (TS) Surveillance Requirement (SR) 3.3.5.4 was met for certain AF valves. TS SR 3.3.5.4 requires that the Engineered Safety Feature response time be verified every 18 months. The existing STPs did not include the response times of certain valve actuation relays and did not account for full valve stroke time.

Subsequent investigation for extent of condition identified similar issues with" response time testing STPs for the Main Steam Isolation Valves (MSIV), the Feedwater Isolation Valves (FWIV) and'the steam admission valves to the AF System turbine driven pump. All affected valves were assessed and, when the expected additional time associated with all relay actuations and the full valve stroke were accounted for, the total response time did not exceed the TS SR limits for any of the valves. Control Room personnel entered TS SR 3.0.3 to allow a delay in the requirement for declaring the LCO not met.

The cause of this event was inadequate oversight of TS required testing where testing requirements are satisfied by sequential or overlapping STPs. STPs have been revised to test the actuation and buffer relays for the affected valves. A review of TS SRs that are met through the performance of more than one test has been conducted to ensure that the TS SRs were met.

There have been two previously reported conditions within the last three years where existing STPs did not verify that existing TS SRs were met.

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.

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.

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.

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).

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.

On December 21, 2012, PVNGS discovered that previous revisions of surveillance test (ST) procedures to conduct safety injection system (SI) injection line check valve testing allowed system alignments that could have resulted in less than the minimum required emergency core cooling system (ECCS) flow described in the safety analysis and licensing bases. The ST procedures directed closure of the manual discharge isolation valve for the train B high pressure safety injection (HPSI) pump and directed opening of a manual drain valve on one of the four SI injection headers which created a potential for diversion of a portion of the ECCS flow provided by the train A HPSI pump.

The latent procedure deficiencies existed since 1983. The root cause was the procedure review process failed to identify the latent procedure deficiencies affecting both ECCS trains. The ST procedures were revised so that system alignments for SI injection line check valve testing ensure availability of at least 100 percent of ECCS flow equivalent to a single operable ECCS train. To prevent recurrence, the procedure process will be revised to identify and resolve common train impacts on design and licensing bases involving safety systems during procedure reviews.

A similar event has not occurred in the prior three years that required reporting.

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.

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.

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.

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.

On December 31, 2004, at approximately 1042 Mountain Standard Time (MST), Units 2 and 3 were operating in MODE 1, at approximately 100 percent power, when Arizona Public Service Company (APS) Transmission and Distribution (T&D) personnel inadvertently tested a relay for the 525 kilovolt (kV) Westwing #2 transmission line that resulted in the Westwing #2 line relaying out and disrupting power to the PVNGS NAN-X01 startup transformer.. - 7 . .

Disruption of power to the NAN-X01 startup transformer resulted in the loss of offsite power to the Unit 2 train "A" engineered safety features (ESF) 4.16 kV class electrical buss and Unit 3 train "B" ESF 4.16 kV class electrical buss. The loss of power to the Unit 2 and 3 ESF 4.16 kV class electrical busses caused auto-starts of the associated diesel generators to supply power to the Unit 2 "A" Train PBA-S03 class bus and the Unit 3 "B" Train PBB-SO4 class bus. All equipment responded satisfactorily. By 1107 MST, power to the Westwing #2 transmission line and startup transformer NAN-X01 had been restored. Previous similar events have been reported in LERs 50 528/2004-006 and 50-530/2003-004.

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).

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.

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.

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.

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.