IR 05000528/2013003

IR 05000528-13-003, 05000529-13-003, 05000530-13-003; 04/01/2013 - 06/30/2013; Palo Verde Nuclear Generating Station, Units 1, 2 & 3; Integrated Resident and Regional Report; Operability Evaluation, Identification & Resolution of Problems

ML13221A202
Person / Time
Site:	Palo Verde
Issue date:	08/09/2013
From:	Allen D NRC/RGN-IV/DRP/RPB-E
To:	Edington R Arizona Public Service Co
Allen D
References
IR-13-003
Download: ML13221A202 (73)

Text

August 09, 2013

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2013003, 05000529/2013003, AND 05000530/2013003

Dear Mr. Edington

On June 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palo Verde Nuclear Generating Station Units 1, 2, and 3. The enclosed inspection report documents the inspection results which were discussed on July 10, 2013, with Mrs. M. Lacal and other members of your staff and other members of your staff.

The inspections examined activities conducted under your license as they relate to safety and compliance with the Commission=s rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

One NRC identified and two self-revealing findings of very low safety significance (Green) were identified during this inspection.

Two of these findings were determined to involve violations of NRC requirements. Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2a of the Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Palo Verde.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at Palo Verde.

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION IV

1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511

R. Edington

- 2 -

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Donald B. Allen, Chief Project Branch E Division of Reactor Projects

Docket Nos.: 50-528, 50-529, 50-530 License Nos: NPF-41, NPF-51, NPF-74

Enclosure:

NRC Inspection Report 05000528/2013003, 05000529/2013003, and 05000530/2013003 w/ Attachments: 1. Supplemental Information

2. Information Request, dated January 17, 2013 3. Request for Information for Temporary Instructions 2515/182 -

Phase II

REGION IV==

Docket:

50-528, 50-529, 50-530 License:

NPF-41, NPF-51, NPF-74 Report:

05000528/2013003, 05000529/2013003, 05000530/2013003 Licensee:

Arizona Public Service Company Facility:

Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location:

5951 South Wintersburg Road Tonopah, Arizona Dates:

April 1 through June 30, 2013 Inspectors: M. Brown, Senior Resident Inspector M. Baquera, Resident Inspector D. Reinert, Resident Inspector E. H. Gray, Senior Reactor Inspector B. K. Tharakan, Resident Inspector, DRP P. Jayroe, Reactor Inspector S. Graves, Senior Reactor Inspector Approved By:

Don Allen, Chief, Project Branch E Division of Reactor Projects

- 2 -

Enclosure

SUMMARY OF FINDINGS

IR 05000528, 529, 530/2013003; 04/01/2013 - 06/30/2013; Palo Verde Nuclear Generating

Station Units 1, 2, & 3; Integrated Resident and Regional Report; Operability Evaluation,

Identification & Resolution of Problems.

The report covered a 3-month period of inspection by resident inspectors and announced base line inspections by region-based inspectors. Two Green non-cited violations of significance were identified. The significance of most findings is indicated by their color (Green, White,

Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.

The cross-cutting aspect is determined using Inspection Manual Chapter 0310, Components Within the Cross-cutting Areas. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

A self-revealing finding occurred because the licensee did not take action to correct an embedded operator work around in the condensate system.

Specifically, the licensee did not evaluate and develop a plan to correct the practice of throttling the condensate polishing demineralizer bypass valve in manual control mode rather than automatic mode. As a result, a malfunction of the heater drain tank B level controller resulted in a feedwater pump B trip and a subsequent reactor power cutback. The licensee entered the issue into their corrective action program as PVAR 4330504 and revised operating procedures to allow the condensate polishing demineralizer bypass valve controller to operate in automatic control mode during full power operations.

The failure to evaluate and determine corrective actions in accordance with established corrective action program procedures is a performance deficiency.

This performance deficiency is more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the practice of throttling the condensate polishing demineralizer bypass valve in manual control mode rather than automatic mode resulted in a reactor power cutback that upset plant stability. The inspectors used the NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination (SDP) for Findings At-Power to determine the significance. The inspectors determined that the finding was of very low safety significance (Green) because it only contributed to the likelihood of a reactor trip and not the likelihood that mitigation equipment or functions would not be available. This issue did not have a cross-

cutting aspect associated with it because it is not indicative of current performance (Section 4OA2).

Cornerstone: Mitigating Systems

Green.

A self-revealing non-cited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, occurred because the licensee failed to correct and prevent recurrence of a significant condition adverse to quality associated with the emergency diesel generator automatic voltage regulator circuitry.

Specifically, from February 2011 to January 2013, the licensee failed to correct the cause of an induced voltage transient in the automatic voltage regulator circuitry, resulting in the Unit 2 train B diesel generator not reaching rated voltage during a surveillance test. The licensee entered the issue into their corrective action program as CRDR 4329997 and replaced and retested electrical components that could allow a voltage transient on the instantaneous pre-positioning circuit board.

The performance deficiency associated with this finding is the failure of the licensee to correct and prevent recurrence of a significant condition adverse to quality. The performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The senior resident inspector performed the initial significance determination for the train B emergency diesel generator (EDG) failure. The inspector evaluated the significance of the issue under the SDP, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at-Power. The finding screened to a detailed risk evaluation because it involved a potential loss of one train of safety related equipment for longer than the technical specification allowed outage time. A Region IV senior reactor analyst performed the detailed risk evaluation. The exposure period was 43 days. The change to the CDF was 7.2E-7/year (Green). The finding was not significant to the large early release frequency. The dominant core damage sequences included loss of offsite power events that lead to station blackout conditions. The gas turbine generators, train A emergency diesel generator, and the DC battery life extension to six hours helped to limit the risk. The finding has a cross-cutting aspect in the area of Problem Identification and Resolution associated with the corrective action program component because the licensee failed to thoroughly evaluate problems such that the resolutions address causes and extent of condition, as necessary

[P.1.(c)] (Section 4OA2).

Cornerstone: Barrier Integrity

Green.

The inspectors identified a Green non-cited violation of 10 CFR Part 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations and engineering personnel to follow station procedures to perform operability determinations and functional assessments. Specifically, plant personnel did not maintain appropriate controls to ensure that the temperature limit established in the operability determination for the spent fuel pool criticality analysis was maintained. The licensee entered the issue into their corrective action program as PVAR 4380424, began taking more frequent readings of spent fuel pool temperature indicators, and lowered the spent fuel pool temperature alarm setpoint.

The failure to follow Procedure 40DP-9OP26 for performing operability determinations is a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the Barrier Integrity Cornerstone attribute of procedure quality and it adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accident or events. The inspectors evaluated the significance of the finding using Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and IMC 0609,

Appendix AProperty "Inspection Manual Chapter" (as page type) with input value "NRC Inspection Manual 0609,</br></br>Appendix A" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process., The Significance Determination Process (SDP) for Findings At-Power. The inspectors reviewed all Barrier Integrity screening questions in IMC 0609, Appendix A, Exhibit 3 Section D, and all questions were answered No. Therefore, the finding was determined to be of very low safety significance.

The inspectors determined that the finding has a cross-cutting aspect in the area of human performance associated with decision making. Specifically, the licensee did not communicate the administrative limits established in the spent fuel pool criticality operability determination to appropriate operations personnel

H.1(c) (Section 1R15).

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and associated corrective action tracking numbers are listed in Section 4OA7 of this report.

PLANT STATUS

Unit 1 was shutdown at the beginning of the inspection period for the 1R17 Refueling Outage.

Unit 1 completed the refueling outage and returned to essentially full power on May 1, 2013 and remained there for the remainder of the inspection period.

Unit 2 operated at essentially full power during this inspection period.

Unit 3 operated at essentially full power during this inspection period.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Summer Readiness for Offsite and Alternate-AC Power Systems

a.

The inspectors reviewed the licensees preparations for seasonal high grid loading. The inspectors reviewed the licensees procedures and communications protocols to ensure that they included measures to monitor and maintain availability and reliability of both the off-site and alternate-ac power systems.

Inspection Scope

The inspectors performed a walkdown of the switchyard with plant personnel to observe the material condition of offsite power sources. The inspectors reviewed the UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by procedures. The inspectors reviews focused on the following systems:

• Non-essential 13.8kV and 4160V electrical distribution systems

• Essential 4160V electrical distribution system

The inspectors also reviewed corrective action program items to verify that the licensee was identifying summer readiness issues at an appropriate threshold and entering them into its corrective action program for resolution. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample to evaluate the readiness of off-site and alternate-ac power for summer weather, as defined in Inspection Procedure 71111.01-05.

b.

No findings were identified.

Findings

.2 Readiness for Impending Adverse Weather Conditions

a.

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for April 8, 2013, the inspectors reviewed the plant personnels overall preparations and protection for the expected weather conditions. On April 8, 2013, the inspectors walked down the essential spray pond system because its safety-related functions could be affected, as a result of high winds, tornado-generated missiles, or the loss of offsite power. The inspectors evaluated the plant staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant design features and the licensees procedures to respond to tornados and high winds. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the UFSAR and performance requirements for the systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures.

The inspectors also reviewed a sample of corrective action program items to verify that the licensee had identified adverse weather issues at an appropriate threshold and entered them into the corrective action program for resolution. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These activities constitute completion of one sample of readiness for impending adverse weather conditions, as defined in Inspection Procedure 71111.01-05.

b.

No findings were identified.

Findings

1R04 Equipment Alignment

.1 Partial Walkdown

a.

The inspectors performed partial system walkdowns of the following risk-significant systems:

Inspection Scope

• April 12, 2013, Unit 1, spent fuel pooling cooling system

• May 24, 2013, Unit 2, auxiliary feedwater train A and train B

• June 13, 2013, Unit 1, containment spray train A

The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected, while considering out of service time, inoperable or degraded conditions, recent system outages, and maintenance, modification, and testing. The inspectors attempted to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, technical specification requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three partial system walkdown samples as defined in Inspection Procedure 71111.04-05.

b.

No findings were identified.

Findings

.2 Complete Walkdown

a.

On June 12, 2013, the inspectors performed a complete system alignment inspection of the emergency diesel generators to verify the functional capability of the system. The inspectors selected this system based on risk-informed insights from site-specific risk studies together with other factors, such as engineering analysis and judgment, operating experience, performance history, current plant mode, and/or previous walkdowns. The inspectors reviewed plant procedures, including abnormal and emergency, drawings, USAR and vendor manuals to determine the correct lineup and visually inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These activities constitute completion of one complete system walkdown sample, as defined in Inspection Procedure 71111.04-05.

b.

No findings were identified.

Findings

1R05 Fire Protection

Quarterly Fire Inspection Tours a.

The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

Inspection Scope

• April 1, 2013, Unit 1, containment building, all elevations

• April 12, 2013, Unit 1, fuel handling building, all elevations

• May 24, 2013, Unit 2, main steam support structure, 80 elevation

• June 13, 2013, Unit 1, auxiliary building, 51 and 40 elevations

• June 28, 2013, Unit 1, control building, 74 elevation

• June 29, 2013, Unit 3, diesel building, 100 elevation

The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition and verified that adequate compensatory measures were put in place by the licensee for out of service, degraded, or inoperable fire protection equipment systems or features. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six quarterly fire-protection inspection samples, as defined in Inspection Procedure 71111.05-05.

b.

No findings were identified.

Findings

1R06 Flood Protection Measures

a.

The inspectors reviewed the UFSAR, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. The inspectors also inspected the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

• June 13, 2013, Unit 1, auxiliary building 40 elevation

These activities constitute completion of one flood protection measures inspection sample as defined in Inspection Procedure 71111.06-05.

b.

No findings were identified.

Findings

1R07 Heat Sink Performance

a.

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the fuel pool cooling heat exchanger. The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These activities constitute completion of one heat sink inspection samples, as defined in Inspection Procedure 71111.07-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Completion of Sections

.1 through.5, below, constitutes completion of one sample as

defined in Inspection Procedure 71111.08-05.

.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water

Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control (71111.08-02.01)a.

The inspectors observed eleven nondestructive examination activities that included four types of examinations. The licensee did not identify any relevant indications accepted for continued service during the nondestructive examinations.

Inspection Scope

The inspectors directly observed and reviewed documentation of the following nondestructive examinations:

SYSTEM

WELD IDENTIFICATION

EXAMINATION TYPE

Reactor Coolant Pressurizer surge line overlay at lower head nozzle dissimilar metal weld Ultrasonic Reactor Coolant Cold Leg Dissimilar Metal Welds Ultrasonic Shutdown Cooling Austenitic Piping Welds 75-2 Liquid Penetrant Shutdown Cooling Austenitic Piping Welds 75-2 Ultrasonic Shutdown Cooling Austenitic Piping Welds 75-4 Liquid Penetrant Shutdown Cooling Austenitic Piping Welds 75-4 Ultrasonic Reactor Coolant Pipe to Elbow 14-13 Magnetic Particle Reactor Coolant Elbow to Extension Piece 14-16 Magnetic Particle Reactor Coolant Pressurizer Inner radius examinations, upper head, Spray line nozzle 5-10 at the head center Ultrasonic

SYSTEM

WELD IDENTIFICATION

EXAMINATION TYPE

Reactor Coolant Safety valve nozzle side hill nozzle 5-13 inner radius Ultrasonic Chemical Volume and Control Overlay, small dia. 2A Charging line, Tapered welds to nozzles, per Code Case N-770-1, ref APS Report No.:12-UT-2023 Phased Array Ultrasonic

Additionally, while performing the inspections in the plant, the inspectors visually observed the condition of plant components including the containment liner and evidence of boric acid leakage.

During the review and observation of each examination, the inspectors verified that activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspector determined that there were no indications from previous examinations that required re-examination during this refuel outage. The inspectors also verified the qualifications of nondestructive examination technicians performing the inspections were current and were reviewed by licensee staff.

The inspectors observed and reviewed two welds on pressure retaining risk significant systems.

The inspectors directly observed a portion of the following welding activities and reviewed the associated work activity records:

SYSTEM

WELD IDENTIFICATION

WELD TYPE

Main Steam Main Steam Isolation Valve Bypass 1JSGEUV0169 Weld 3779460-1, 3779460-2 Automated Gas Tungsten Arc Welding Main Steam Main Steam Isolation Valve Bypass 1JSGEUV0183 Weld 3779468-1, 3779468-2 Automated Gas Tungsten Arc Welding

The inspectors verified that the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code,Section IX, requirements. The inspectors also verified, through observation and record review, that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements for Section 02.01.

b.

No findings were identified.

Findings

.2 Vessel Upper Head Penetration Inspection Activities (71111.08-02.02)

a.

There were no inspections of the Unit 1 vessel upper head during refueling outage 1R17. The next visual inspection is scheduled for 1R18 in the fall of 2014.

The next volumetric inspection is scheduled for 1R21 in the spring of 2019.

Inspection Scope b.

No findings were identified.

Findings

.3 Boric Acid Corrosion Control Inspection Activities (71111.08-02.03)

a.

The inspectors evaluated the implementation of the licensees boric acid corrosion control program for monitoring degradation of those systems that could be adversely affected by boric acid corrosion. The inspectors reviewed the documentation associated with the licensees boric acid corrosion control walkdown as specified in Procedure 73DP-9ZC01, Boric Acid Corrosion Control Program, Revision 4, and Procedure 70TI-9ZC01, Boric Acid Walkdown Leak Detection, Revision 15. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety significant components, and that engineering evaluation used corrosion rates applicable to the affected components and properly assessed the effects of corrosion induced wastage on structural or pressure boundary integrity. The inspectors confirmed that corrective actions taken were consistent with the ASME Code, and 10 CFR 50, Appendix B requirements. Specific documents reviewed during this inspection are listed in the attachment.

Inspection Scope

These actions constitute completion of the requirements for Section 02.03.

b.

No findings were identified.

Findings

.4 Steam Generator Tube Inspection Activities (71111.08-02.04)

a.

The inspectors reviewed the steam generator tube eddy current (ECT) examination scope and expansion criteria and verified that it met technical specification requirements, EPRI guidelines, and commitments made to the NRC. The inspectors also verified that the ECT inspection scope included areas of degradations that were known to represent potential eddy current test challenges such as the top of tube sheet, tube support plates, Inspection Scope

and U-bends. The inspectors confirmed that only a minimum number of conditions required repairs or analysis by the conclusion of the ECT examinations.

The inspectors observed portions of the eddy current testing being performed and verified that:

(1) the appropriate probes were used for identifying the expected types of degradation,

(2) calibration requirements were adhered, and

(3) probe travel speed was in accordance with procedural requirements. The inspectors performed a review of the site-specific qualifications for the techniques being used, and verified that eddy current test data analyses were adequately performed per EPRI and site specific guidelines.

The scope of the licensees ECT and SG examinations included:

• 100 percent full length bobbin testing using a 0.610-inch-diameter bobbin probe in rows 5 and higher

• 100 percent bobbin testing using a 0.610-inch-diameter bobbin probe from the hot leg tube end to BW1 in Row 1 through Row 4 tubes

• 100 percent bobbin testing using a 0.590-inch-diameter bobbin probe from the cold leg tube end to BW1 in Row 1 through Row 4 tubes

• 100 percent +Point inspection of bobbin flaw-like signals at tube support structures with bobbin indicated depth 15%TW

• RPC boxing of confirmed PLP and observed loose part wear signals

• Special interest +Point testing of non resolved free span bobbin signals

• 100 percent +Point inspection of dent (DNT) signals 2V at tube supports

• 100 percent +Point inspection of free span (DNT) signals 5V

• 100 percent +Point inspection of peripheral tube free span DNT signals 2V within 2 of TTS (Top of Tubesheet)

• 100 percent +Point inspection of NTE sites, tube end to TTS +3

• 100 percent tube plug visual inspection

• Tubesheet periphery and tube lane foreign object search and retrieval

• Steam Drum Upper Internals visual inspection

• In-bundle visual inspection of the TTS region in sludge deposition regions

• Channel head cladding inspection per NSAL 12-1

Secondary side examinations were performed without repairs or complications. Minor cases of tube wear and loose part damage were entered into the corrective action program, evaluated, and adequately addressed.

In summary, the inspectors review selected eddy current test data, and verified that the analytical techniques used were adequate.

These actions constitute completion of the requirements for Section 02.04.

b.

No findings were identified.

Findings

.5 Identification and Resolution of Problems (71111.08-02.05)

a.

The inspectors reviewed 22 condition reports associated with inservice inspection activities, and determined that the corrective actions taken were appropriate. The inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program, and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying inservice inspection industry operating experience. Specific documents reviewed during this inspection are listed in the attachment.

Inspection scope

These actions constitute completion of the requirements of Section 02.05.

b.

No findings were identified.

Findings

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 a.

Quarterly Review of Licensed Operator Requalification Program On May 21, 2013, the inspectors observed a crew of licensed operators in the plants simulator during training. The inspectors assessed the following areas:

Inspection Scope

• Licensed operator performance

• The ability of the licensee to administer the training

• The modeling and performance of the control room simulator

• The quality of post-scenario critiques

• Follow-up actions taken by the licensee for identified discrepancies

These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.

b.

No findings were identified.

Findings

.2 Quarterly Observation of Licensed Operator Performance

a.

On April 26, 2013, the inspectors observed the performance of on-shift licensed operators in the Unit 1 main control room. At the time of the observations, Unit 1 was in a period of heightened activity due to performing a demonstration test for local operation of the turbine driven auxiliary feedwater pump. The inspectors observed the operators performance of the pre-job brief and the control room oversight and communications of the activity. In addition, the inspectors assessed the operators adherence to plant procedures, including 40DP-9OP02, Conduct of Shift Operations, and other operations department policies.

Inspection Scope These activities constitute completion of one quarterly licensed-operator performance sample, as defined in Inspection Procedure 71111.11.

b.

No findings were identified.

Findings

1R12 Maintenance Effectiveness

a.

The inspectors evaluated degraded performance issues involving the following risk significant systems:

Inspection Scope

• June 3, 2013, Units 1, 2, and 3, main steam isolation valve accumulators

The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• Implementing appropriate work practices

• Identifying and addressing common cause failures

• Scoping of systems in accordance with 10 CFR 50.65(b)

• Characterizing system reliability issues for performance

• Charging unavailability for performance

• Trending key parameters for condition monitoring

• Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)

• Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were appropriately handled by a screening and identification process and those issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one maintenance effectiveness sample, as defined in Inspection Procedure 71111.12-05.

b.

No findings were identified.

Findings

1R13 Maintenance Risk Assessments and Emergent Work Control

a.

The inspectors reviewed licensee personnel's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

Inspection Scope

• April 3, 2013, Unit 1, refueling outage 1R17

• April 19, 2013, Unit 1, reduced inventory operations

• May 24, 2013, Unit 2, auxiliary feed water B air handling unit removed from service concurrent with other train B maintenance

• June 11, 2013, Units 1, 2, and 3, station blackout generator 1 extended outage

The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13-05.

b.

No findings were identified.

Findings

1R15 Operability Evaluations and Functionality Assessments

a.

The inspectors reviewed the following assessments:

Inspection Scope

• April 16, 2013, Unit 1, shutdown cooling suction piping thickness measurement results

• April 18, 2013, Unit 2, essential spray pond pump A high vibrations

• April 23, 2013, Unit 1, voltage regulator transformer elevated temperatures

• April 30, 2013, Unit 1, SI-UV-651 missed post-maintenance testing

• May 7, 2013, Unit 1, instrument air fitting contacting a hydraulic line for the main steam isolation valve 170 nitrogen accumulator

• May 9, 2013, Unit 1, feed water isolation valve 174 following increased leakage in nitrogen accumulator

The inspectors selected these operability and functionality assessments based on the risk significance of the associated components and systems along with other factors, such as engineering analysis and judgment, operating experience, and performance history. The inspectors evaluated the technical adequacy of the evaluations to ensure

technical specification operability was properly justified and to verify the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of six operability evaluations inspection samples, as defined in Inspection Procedure 71111.15-05.

b.

Failure to Follow Operability Determination Procedure for Maintaining Administrative Limits Findings

Introduction.

The inspectors identified a Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of operations and engineering personnel to follow station procedures to perform operability determinations and functional assessments. Specifically, plant personnel did not maintain appropriate controls to ensure that the temperature limit established in the operability determination for the spent fuel pool criticality analysis was maintained.

Description.

On March 8, 2013, the licensees engineering staff identified that the spent fuel pool criticality analysis of record had not been updated as part of the steam generator stretch power uprate modification. The licensee had received a 2.94% power uprate for Unit 2 in 2003 and for Units 1 and 3 in 2005, but the criticality analysis of record dated January 15, 1999 was not revised to reflect the uprated operating conditions. The power uprate was accomplished, in part, by increasing the reactor core exit temperature. Operating at higher moderator and fuel temperatures increases plutonium production in the fuel rods. Consequently, the greater plutonium production increases the reactivity of the spent fuel stored in the spent fuel pools. This condition resulted in Technical Specifications 3.7.17, Spent Fuel Assembly Storage and 4.3.1.1, Criticality, being non-conservative. This issue is described further in section 4OA7 of this report.

The licensee initiated PVAR 4363316 to document the condition and issued an Event Notification to the NRC to report an unanalyzed condition. The licensee also performed a prompt operability determination and evaluated the impact on fuel reactivity due to the increase in fuel and moderator temperatures to show that the spent fuel remained in a safe configuration. The licensee credited several conservatisms in the existing analysis of record that could offset the increased reactivity. One conservative area of the analysis was in the assumed spent fuel pool temperature. The analysis of record was

based on an assumed maximum spent fuel pool temperature of 150 degrees Fahrenheit.

However, the licensee determined that the actual, maximum expected spent fuel pool temperature was lower. Thus, the prompt operability determination assumed the following: The maximum SFP operating temperature is 135 degrees Fahrenheit including instrument uncertainty. This is based upon an alarm setpoint of 125 degrees Fahrenheit with a calculated 9.8 degrees Fahrenheit instrument uncertainty.

During the Unit 1 refueling outage on April 5, 2013, the spent fuel pool temperature reached the alarm setpoint of 125 degrees Fahrenheit and temperature continued to rise to a peak of 130 degrees until the spent fuel pool cooling system was augmented by the shutdown cooling system approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> later. Operators believed that a spent fuel pool temperature of up to 135 degrees Fahrenheit was allowable, and they did not consider instrument uncertainty. During the time with the temperature greater than 125 degrees, Unit 1 was outside the limits established by the prompt operability determination. Operations personnel were not aware that the prompt operability determination limit had been exceeded until questioned by the inspectors. Subsequent licensee analysis of existing margins concluded that exceeding the temperature limit did not result in a violation of Technical Specifications 3.7.17 or 4.3.1.1.

Procedure 40OP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Revision 33, Step 3.2.12 requires that if a operability determination contains specific conditions of limitations for which the assessment remains valid, the shift manager shall ensure that the appropriate controls are in place to ensure monitoring of the limitations. The controls established to maintain the spent fuel pool temperature within limits were not adequate in that the verbiage of the prompt operability determination was not understood by operations personnel.

Additionally, the spent fuel pool temperature monitoring frequency was inadequate to prevent the temperature from exceeding the alarm setpoint. This issue is captured in PVAR 4380424. The licensee initiated corrective actions to lower the spent fuel pool temperature alarm setpoint from 125 degrees Fahrenheit to 115 degrees Fahrenheit and began taking more frequent readings of spent fuel pool temperature indicators.

The inspectors noted this issue is representative of a recent trend involving inadequate administrative controls to maintain operability of degraded and non-conforming conditions, with multiple examples specifically involving management of spent fuel pool operating conditions. In September 2012, the inspectors identified that the licensee did not establish administrative controls to maintain that spent fuel pool heat load and temperature limits related to a non-conforming spent fuel pool transfer canal gate seal.

In April 2013, the inspectors questioned how operators were tracking temperature limits established in response to a licensee-identified inadequate emergency operating procedure. The licensee had initially established a lower spent fuel pool temperature limit as a compensatory measure, but a subsequent engineering evaluation had determined that the lower limit was, in fact, no longer needed. A follow-up evaluation mistakenly re-affirmed this limit without considering the engineering evaluation and without establishing any actions to confirm that the lower limit was being maintained.

These issues are documented as PVARs 4251108 and 3654278 respectively.

Analysis.

The failure to follow Procedure 40DP-9OP26 for performing operability determinations is a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it is associated with the Barrier Integrity Cornerstone attribute of procedure quality and it adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accident or events. Additionally, the inspectors determined the issue is indicative of a significant programmatic deficiency involving controls for maintaining operability of degraded and non-conforming conditions that could lead to worse errors if left uncorrected. The inspectors evaluated the significance of the finding using Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors reviewed all Barrier Integrity screening questions in IMC 0609, Appendix A, Exhibit 3 Section D, and all questions were answered No. Therefore, the finding was determined to be of very low safety significance. The inspectors determined that the finding has a cross-cutting aspect in the area of human performance associated with decision making. Specifically, the licensee did not communicate the administrative limits established in the spent fuel pool criticality operability determination to appropriate operations personnel H.1(c).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings requires in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, Revision 33, required, that if an operability determination or functional assessment contains specific conditions or limitations for which the functional assessment remains valid, the shift manager shall ensure the appropriate controls are in place to ensure monitoring of the limitations.

Contrary to the above, between March 22, 2013 and April 9, 2013, the licensee failed to perform a functional assessment in accordance with documented procedures.

Specifically, the licensee did not maintain appropriate controls to ensure that the temperature limit established in the operability determination for spent fuel pool criticality was monitored. The licensee has subsequently issued a standing order to institute more frequent temperature monitoring and has initiated changes to lower the spent fuel pool temperature alarm setpoint. Because this finding was determined to be of very low safety significance and was entered into the licenses corrective action program as Palo Verde Action Request 4380424, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000528; 529; 530 /2013003-01, Failure to Follow Operability Determination Procedure for Maintaining Administrative Limits.

1R18 Plant Modifications

a.

Temporary Modifications To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modification:

Inspection Scope

• April 26, 2013, Unit 1, demonstration test for local operation of turbine driven auxiliary feedwater pump The inspectors reviewed the temporary modification and the associated safety-evaluation screening against the system design bases documentation, including the UFSAR and the technical specifications, and verified that the modification did not adversely affect the system operability/availability. The inspectors also verified that the installation and restoration were consistent with the modification documents and that configuration control was adequate. Additionally, the inspectors verified that the temporary modification was identified on control room drawings, appropriate tags were placed on the affected equipment, and licensee personnel evaluated the combined effects on mitigating systems and the integrity of radiological barriers.

These activities constitute completion of one sample for temporary plant modifications, as defined in Inspection Procedure 71111.18-05.

b.

No findings were identified.

Findings

1R19 Post-Maintenance Testing

a.

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

Inspection Scope

• May 22, 2013, Unit 1, emergency diesel generator B

• May 24, 2013, Unit 2, containment spray, train B, following preventative maintenance on valves and air handling unit

• June 5, 2013, Unit 2, auxiliary feed water, train A, following preventative maintenance on feed water isolation valves and air handling unit

The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following:

• The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed

• Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate

The inspectors evaluated the activities against the technical specifications, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19-05.

b.

No findings were identified.

Findings

1R20 Refueling and Other Outage Activities

a.

Prior to the refueling outage, the inspectors reviewed the outage safety plan and contingency plans for the Unit 1 refueling outage, conducted April 29, 2013, to confirm that licensee personnel had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense in depth. The inspectors also confirmed that the licensee scheduled covered workers such that the minimum days off for individuals working on outage activities were in compliance with 10 CFR 26.205(d)(4) and (5). During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

Inspection Scope

• Configuration management, including maintenance of defense in depth, is commensurate with the outage safety plan for key safety functions and compliance with the applicable technical specifications when taking equipment out of service.

• Clearance activities, including confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error.

• Status and configuration of electrical systems to ensure that technical specifications and outage safety-plan requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal processes, systems, and components.

• Verification that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor water inventory controls, including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities that could affect reactivity.

• Maintenance of secondary containment as required by the technical specifications.

• Refueling activities, including fuel handling and sipping to detect fuel assembly leakage.

• Startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing.

• Management of fatigue

• Licensee identification and resolution of problems related to refueling outage activities.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one refueling outage and other outage inspection samples, as defined in Inspection Procedure 71111.20-05.

b.

No findings were identified.

Findings

1R22 Surveillance Testing

a. Inspection Scope

The inspectors selected risk-significant surveillance activities based on risk information and reviewed the UFSAR, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:

• Preconditioning

• Evaluation of testing impact on the plant

• Acceptance criteria

• Test equipment

• Procedures

• Jumper/lifted lead controls

• Test data

• Testing frequency and method demonstrated technical specification operability

• Test equipment removal

• Restoration of plant systems

• Fulfillment of ASME Code requirements

• Updating of performance indicator data

• Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct

• Reference setting data

• Annunciators and alarms setpoints

The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• April 22, 2013, Unit 1, containment penetration 42C isolation valve leak-rate testing

• April 22, 2013, Units 1, 2, and 3, diesel fuel oil inventory

• May 8, 2013, Unit 1, diesel fuel oil transfer pump A inservice test

• June 6, 2013, Unit 2, Low Pressure Safety Injection Pump, train A, inservice test

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of four surveillance testing inspection samples, as defined in Inspection Procedure 71111.22-05.

b.

No findings were identified.

Findings

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a.

The inspectors performed a review of the performance indicator data submitted by the licensee for the first Quarter 2013 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

Inspection Scope

This review was performed as part of the inspectors normal plant status activities and, as such, did not constitute a separate inspection sample.

b.

No findings were identified.

Findings

.2 Safety System Functional Failures (MS05)

a.

The inspectors sampled licensee submittals for the safety system functional failures performance indicator for Palo Verde Units 1, 2, and 3 for the period from the second quarter 2012 through the first quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions Inspection Scope

and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73." The inspectors reviewed the licensees operator narrative logs, operability assessments, maintenance rule records, maintenance work orders, issue reports, event reports, and NRC integrated inspection reports for the period of April 2012 through March 2013 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of three safety system functional failures samples, as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.3 Mitigating Systems Performance Index - Emergency ac Power System (MS06)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for Palo Verde Units 1, 2, and 3 for the period from the second quarter 2012 through the first quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period April 2012 through March 2013 to validate the accuracy of the submittals.

The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

Inspection Scope These activities constitute completion of three mitigating systems performance index - emergency ac power system samples, as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

.4 Mitigating Systems Performance Index - High Pressure Injection Systems (MS07)

a.

The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for Palo Verde Units 1, 2, and 3 for the period from the second quarter 2012 through the first quarter 2013. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports for the period of April 2012 through March 2013 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified.

Specific documents reviewed are described in the attachment to this report.

Inspection Scope

These activities constitute completion of three mitigating systems performance index - high pressure injection system samples, as defined in Inspection Procedure 71151-05.

b.

No findings were identified.

Findings

4OA2 Problem Identification and Resolution

.1 Routine Review of Identification and Resolution of Problems

a.

As part of the various base line inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during base line inspection activities and plant status reviews to verify that they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensees corrective action program because of the inspectors observations are included in the attached list of documents reviewed.

Inspection Scope

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b.

No findings were identified.

Findings

.2 Daily Corrective Action Program Reviews

a.

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees corrective action program. The inspectors accomplished this through review of the stations daily corrective action documents.

Inspection Scope

The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b.

No findings were identified.

Findings

.3 Semi-Annual Trend Review

a.

The inspectors performed a review of the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6-month period of January 2013 through June 2013 although some examples expanded beyond those dates where the scope of the trend warranted.

Inspection Scope

The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the licensees corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

These activities constitute completion of a single semi-annual trend inspection samples, as defined in Inspection Procedure 71152-05.

b.

Adverse Trend in Management of Degraded and Non-conforming Conditions Findings and Observations The inspectors concluded that an adverse trend associated with management of degraded and non-conforming conditions existed at Palo Verde through June 2013.

Since the fall of 2012, the inspectors have identified several issues associated with the failure to follow station procedures to provide administrative controls to ensure assumptions and limits established to maintain operability of degraded and non-conforming conditions. The inspectors also identified other issues associated with ensuring corrective actions to correct degraded conditions are properly prioritized and scheduled commensurate with the engineering evaluation that supported equipment operability. Examples of this adverse trend included:

• On September 20, 2012, the licensees engineering staff identified a nonconforming condition involving the spent fuel pool transfer canal gate seals.

The gate seals are designed as non-quality related components. The inspectors identified that plant personnel did not follow station procedures and maintain appropriate controls to ensure that the heat load and temperature limits established in the functional assessment for the spent fuel pools were monitored (NCV 05000528; 529; 530 /2012005-04, Inadequate Tracking of Functional Assessment for Spent Fuel Pool Heat Load).

• On January 8, 2013, the licensees nuclear assurance staff identified that operators did not appear to be tracking spent fuel temperatures in accordance with a functional assessment that was performed after identifying an inadequate emergency operating procedure. The licensee had initially established a lower spent fuel pool temperature limit as a compensatory measure, but a subsequent engineering evaluation determined that the lower limit was, in fact, no longer needed. A follow-up evaluation completed on January 24, 2013 mistakenly re-affirmed this limit without considering the engineering evaluation and without establishing any actions to confirm that the lower limit was being maintained.

(PVAR 3654278)

• On March 1, 2013, the licensee documented non-compliances with Procedure 40DP-9OP26, Operations PVAR Processing and Operability Determination/Functional Assessment, after the inspectors requested documents supporting completion of Sections 4.2 and 4.3, which require Plant Review Board (PRB) and Unit Operations Manager (UOM) periodic reviews of station degraded and non-conforming conditions. The licensee determined that the PRB was not performing a review of causes per Step 4.2.2 and UOMs were not performing the reviews per Step 4.3. (CRDR 4361081)

• On March 22, 2013, the licensees engineering staff completed a prompt operability determination after identifying non-conservatisms in the spent fuel

pool criticality analysis of record. The operability determination contained specific conditions for which it remained valid. Plant operators failed to maintain appropriate controls to ensure monitoring of the spent fuel pool temperature limitations. This issue is documented in section 1R15 of this report.

• On March 28, 2013, the licensee identified significantly elevated temperatures on the Unit 1 Class 1E voltage regulator lower transformer for vital distribution panel 1EPNAD25. A prompt operability determination (POD) was completed and approved on April 16, 2013, that identified a potential for continued degradation until all magnetic components are replaced and established that the POD was only valid until October 10, 2013 based on the age of the transformer and operation at elevated temperatures. The inspectors identified that the corrective action to repair the transformer was originally classified as a Priority 5 action and scheduled for the next refueling outage in October 2014, one year past the assumptions and limits of the POD. The licensee subsequently reclassified the corrective actions as Priority 3 with a due date of October 8, 2013. (PVAR 4374202)

• On May 3, 2013, the licensee identified a declining trend in operability determination/functionality assessment quality during the monthly performance indicators review. The review identified examples of incomplete evaluations/documentation, incorrect codes being entered, and miscellaneous administrative errors. In addition, some of the administrative requirements of Policy Guide 1505-01, Operability Determination Oversight and Monitoring, have been inconsistently met, such as the Shift Technical Advisor (STA) Section Leader documenting the review of the Operability Determination Daily Challenge Board (ODDCB) meeting minutes. (PVAR 4405169)

• On May 24, 2013, Arizona Public Service completed Adverse CRDR 4408625 and initiated a series of corrective actions to address this adverse trend. The corrective actions include procedure revisions; additional training to SROs, STAs, Engineering Fix-It-Now (EFIN) personnel and ODDCB members; and reinstatement of the non-conforming code in Procedure 40DP-9OP26.

The inspectors will continue to monitor this trend and the implementation of the licensees corrective action plan.

.4 Selected Issue Follow-up Inspection

a.

During a review of items entered in the licensees corrective action program, the inspectors recognized corrective action items documenting issues that warranted further inspection:

Inspection Scope

• January 16, 2013, Unit 2, train B emergency diesel generator failure to reach rated voltage

• January 17, 2013, Unit 3, reactor power cutback due to feedwater pump B trip

The inspectors considered the following during the review of the licensee's actions: (1)complete and accurate identification of the problem in a timely manner;

(2) evaluation and disposition of operability/reportability issues;

(3) consideration of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem;

(5) identification of root and contributing causes of the problem;

(6) identification of corrective actions; and

(7) completion of corrective actions in a timely manner.

Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two in-depth problem identification and resolution samples, as defined in Inspection Procedure 71152-05.

b.

.1 Failure to Prevent Recurrence of a Significant Condition Adverse to Quality

Findings

Introduction.

A self-revealing Green non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, occurred because the licensee failed to correct and prevent recurrence of a significant condition adverse to quality associated with the emergency diesel generator automatic voltage regulator circuitry. Specifically, from February 2011 to January 2013, the licensee failed to correct the cause of an induced voltage transient in the automatic voltage regulator circuitry, resulting in the Unit 2 train B diesel generator not reaching rated voltage during a surveillance test.

Description.

On January 16, 2013, operations personnel conducted a simulated loss of power emergency mode start of the Unit 2 train B emergency diesel generator using the pushbutton located on the local control panel. The generator did not reach its rated output voltage of 4200 VAC. The generator started and stabilized at approximately 2500 VAC. In order to attempt a manual voltage adjustment, the operators switched the generator from its emergency operating mode to test operating mode using the emergency mode defeat switch. The generator output immediately went to its maximum value of 5200 VAC and the engine was emergency stopped.

The output voltage of each emergency diesel generator is controlled by an automatic voltage regulator. In the test mode of operation, the output voltage may be adjusted with a potentiometer by operators in the local or main control room. In the emergency mode of operation, output voltage is automatically set to 4200 VAC by a signal from the Instantaneous Pre-Positioning (IPP) board. The purpose of the IPP board is to instantaneously set the output voltage within one cycle of receiving the emergency start signal, whereas the potentiometer could take up to twenty seconds to adjust the output voltage to the desired setting.

Following the failure, operators declared the Unit 2 train B emergency diesel generator inoperable and entered Technical Specification LCO 3.8.1 Condition B. Troubleshooting identified that the Unit 1 integrated circuit operational amplifier on the IPP board had failed. The licensee replaced the affected IPP board and following additional monitoring of voltage regulator parameters, surveillance test 40ST-9DG02, Diesel Generator B Test was successfully performed and the emergency diesel generator was returned to service on January 18, 2013.

The failure of the Unit 1 operational amplifier was the same significant condition adverse to quality identified during a previous failure of the Train B emergency diesel generator in February 2011. On February 22, 2011, during the performance of surveillance test 40ST-9DG02, the Unit 2 train B emergency diesel generator failed to reach its rated voltage of 4200 VAC after starting in Simulated Loss of Power mode using the local pushbutton. Operations personnel declared the train B emergency diesel generator inoperable. The licensee determined the February 2011 event to be a significant condition adverse to quality and evaluated it under CRDR 3621333. The direct cause was determined to be the failure of the Unit 1 operational amplifier on the IPP board.

The licensee determined the probable cause of the failure to be electrical overstress damage resulting from an electronic static discharge. Corrective actions to prevent recurrence of the significant condition adverse to quality were to revise material handling procedures to improve electrostatic discharge prevention by material handling personnel that could expose the IPP boards sensitive electronic components to static discharge.

The 2011 evaluation did not identify any operational or design characteristics that could have caused the electrical overstress damage.

The root cause investigation for the most recent January 2013 failure was conducted under CRDR 4329997. The root cause of the failure was determined to be an inadequate preventative maintenance strategy for electrical relay VR2, which operates to energize and terminate the 15V supply power for the automatic voltage regulator and IPP board. This resulted in a degraded contact resistance on the relay that allowed a voltage transient to be seen on the IPP board Unit 1 operational amplifier. Furthermore, laboratory analysis also determined that the transient was enhanced by inductive coupling attributed to the configuration of the IPP board power supply wiring.

The licensee replaced and retested the IPP board and VR2 relay and initiated a design change to implement voltage suppression for the power supply to the IPP circuit board on all emergency diesel generators. As an interim corrective action, the licensee is performing all emergency diesel generator surveillance tests in emergency mode to validate operation of the Unit 1 operational amplifier, and is installing temporary instrumentation and monitoring the Unit 2 train B emergency diesel generator IPP board during surveillance tests to identify any indications of transient voltage spikes.

Analysis.

The performance deficiency associated with this finding is the failure of the licensee to correct and prevent recurrence of a significant condition adverse to quality.

The performance deficiency is more than minor, and therefore a finding, because it is associated with the equipment performance attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable

consequences. The senior resident inspector performed the initial significance determination for the train B emergency diesel generator (EDG) failure. The inspector evaluated the significance of the issue under the SDP, as defined in Inspection Manual Chapter 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at-Power. The finding screened to a detailed risk evaluation because it involved a potential loss of one train of safety related equipment for longer than the technical specification allowed outage time. A Region IV senior reactor analyst performed the detailed risk evaluation. To evaluate the train B EDG failure, the analyst used the Palo Verde Standardized Plant Analysis Risk (SPAR) Model, Revision 8.20, with a truncation limit of 1E-11. Based on a SPAR model review, as well as a comparison of the SPAR model against the Palo Verde probabilistic risk assessment (PRA) model, the analyst made the following SPAR model changes.

These changes affected both the nominal and current case calculations.

• Loss of Offsite Power (LOOP) Frequency:

The SPAR model LOOP initiating event frequency was 2.84E-2 per year. This was inconsistent with NUREG/CR 6890, Reevaluation of Station Blackout Risk at Nuclear Power Plants. The NUREG specified frequencies for weather related, switchyard centered, and plant centered LOOP frequencies are the same for all US commercial nuclear power plants. However, the grid related frequency can vary significantly based on the location in the continental United States. Palo Verde is located in the WECC region, which has one of the highest grid related LOOP frequencies, 4.18E-2. The overall LOOP frequency was 5.0E-2. The analyst initiated a change set to implement this change.

• Manual Operation of Turbine Driven Auxiliary Feedwater (TDAFW) Pump without DC Control Power:

The Palo Verde PRA model as well as the NRC SPAR model both contained a basic event that represented manual operation of the TDAFW pump after DC control power expired, approximately two hours. Both models assumed that it was feasible to perform this action for the entire 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time.

The licensee provided an analysis that demonstrated that battery power to the TDAFW pump would be available for six hours, versus two. In addition, during a site visit, the licensee demonstrated that it was possible to manually operate the TDAFW pump using valve handwheels, a tachometer, local discharge pressure indication, system flow indication from the control room, steam generator level indication in the control room, as well as reactor coolant system temperature monitored in the control room. While the local indications would be available continuously, the control room indications would only last as long as the train A or train B batteries that powered them, approximately six hours. Collectively, the analyst considered that the licensee had a reasonable expectation of TDAFW operation for up to six hours during station blackout scenarios.

The analyst failed the TDAFW pump manual action in the SPAR model but adjusted the LOOP and EDG non-recoverabiltiy probabilities to account for the six hour TDAFW capability. This modification is detailed in the next section.

• Offsite Power and EDG Recoveries:

The analyst replaced the two hour offsite power and EDG recovery values with the seven hour non-recovery probabilities. The NRC SPAR model used 1, 2 and 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite power and EDG recoveries, no other recoveries appeared in the cutsets. The use of the two hour recovery was based on the TDAFW pump two hour DC control power battery life. The licensee, however, estimated that an additional one hour would be available following battery failure before core damage would occur. If a recovery could be completed within that time, core damage could be averted. The analyst added an additional six hours because of the extended TDAFW pump operation. The total time to recover the noted equipment was therefore seven hours.

• Gas Turbine Generator (GTG) Failure Probability:

The analyst determined that the value in the SPAR model GTG failure probability was too conservative. The original failure probability was 3E-1. This would fail the GTGs 30% of the time. The analyst reviewed the existing SPAR-H evaluation and noted that some assumptions were overly conservative. For example, the SPAR-H stated that there was barely adequate time to start the GTGs, when there was extra time. In addition, stress was extreme and complexity was moderate. The analyst noted that the licensee performed surveillances on the GTGs, using plant procedures, and periodically placed the units into operation. Operators were trained on the task and control room operators knew that they needed to start the GTGs if both EDGs on any of the units were unavailable during a LOOP. Based on the revised SPAR-H analysis, the analyst calculated the failure probability from operator error at 2E-2 (about 2%). The analyst used a change set to accomplish this modification.

• GTG Cable Failure:

The SPAR model used an overly conservative probability for underground cable failures, 3.19E-2. This value appeared to have no reference. This would infer an approximate 3% failure rate just from the underground cables. Palo Verde had no history of GTG cable failures. The analyst reviewed the licensees justification for the same event in the Palo Verde PRA model. The probability was 2.9E-3 and this appeared conservative. The analyst updated the NRC SPAR model with a change set and used the licensees failure probability.

• Early TDAFW Pump Failures:

The analyst reduced the TDAFW pump failure to run probability for the early time dependent failures. The licensee used two different failure probabilities for the

TDAFW pump, an early failure and a later failure. The NRC SPAR model used a compound event that had an early component and a late component. However, the compound value was used in all cases. This led to overly conservative failure probabilities for the early time dependent failures. To remedy this situation, the analyst wrote a post-processing rule that changed the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> sequence TDAFW pump failure to run probability. If the failure occurred in the first hour, the failure to run probability was changed from 3.95E-2 to 4.42E-3.

The rule appears below:

If (EPS-XHE-XL-NR01H

• AFW-TDP-FR-AP01);then Delete Event = AFW-TDP-FR-AP01; Add Event = ZT-TDP-FR-E; endif

Internal Events: The analysts performed simplified calculations to determine the change to the core damage frequency (delta-CDF) for the EDG failure. The analyst made the following influential assumptions:

• Exposure time is equal to 43 days

• Normal EDG recoveries were permitted

Since the exact time of the voltage regulating subsystem failure was unknown, the NRCs Risk Assessment of Operational Events Handbook, Volume 1, Internal Events, Revision 2.0, Section 2.4, specified that a T/2 + repair time exposure period should be used. The train B EDG suffered a voltage regulating system failure on January 16, 2013 during integrated systems testing. The last time that this portion of the circuit was tested was on October 26, 2012. The T exposure period was therefore 82 days, so the T/2 exposure portion was 41 days. The repair time was 2 days. The EDG was returned to service on January 18, 2013. The total exposure period was 43 days.

The analyst allowed the normal EDG recoveries, part of the SPAR model, to occur. The train B EDG required a repair to return to service, so no recovery of this particular EDG was warranted. The train A EDG, however, could be recovered in the failure scenarios.

The SPAR model only attempts to recover one EDG. The analyst noted that allowing the normal recoveries to occur had little impact on the final results.

The analyst then calculated the change in core damage frequency (delta-CDF), solving only the LOOP sequences. The current case core damage probability (CCDP) was 8.3E-6 for an entire year of exposure. The nominal case CCDP was 2.3E-6/year. The incremental CCDP (ICCDP) for a one year exposure period was 6E-6/yr. Adjusting for a 43 day exposure period, delta-CDF was:

delta-CDFinternal events = 6E-6

• 43/365 = 7E-7/year.

External Events: There were two potential external events that could contribute to the CDF. Those were seismic events and fire initiators:

The RASP Manual, Volume 2, External Events, Revision 1.01, Appendix 1, Frequencies of Seismically-Induced LOOP Events, specified a seismic induced LOOP frequency for Palo Verde as 5.4E-5/yr. Seismic LOOP events are considered non-recoverable. The analyst used the SPAR model and failed the off-site power recovery events. The analyst also set the LOOP frequency to 1.0 to derive the nominal case CCDP. The resultant CCDP, given a non-recoverable LOOP, was 1.2E-4. Next, the analyst added the failure of the train B EDG by setting the basic event failure probability to 1.0. The resultant CCDP was 2.7E-3. The delta-CDF for the seismic initiator was therefore:

delta-CDFseismic = 5.4E-5/yr * (2.7E-3 - 1.2E-4)

• 43/365 = 1.6E-8/yr Seismic was not a significant contributor to Delta-CDF and was not considered further.

The analyst referenced the Palo Verde Individual Plant Evaluation of External Events (IPEEE), dated June 30, 1995 and utilized more recent information from the licensees current Fire PRA to evaluate the condition. The licensee provided a list of 12 fire sequences that could result in a LOOP. The analyst used this list as a basis for the following analysis. The analyst reviewed the sequences and eliminated two sequences because they involved the failure of train B equipment. Since the train B EDG was affected by the condition, there would be no change to the core damage frequency associated with these two sequences.

Six sequences were associated with the corridor building. From a review of the IPEEE, these sequences only affected offsite power and did not affect other safety equipment.

These fires would result in an increase in the LOOP frequency. For each area, the analyst considered the fire initiation frequency, the probability that the fire would not self-extinguish, 0.14, and the probability that the fire would spread in a significant manner, 0.1. The cumulative additional LOOP initiation frequency was 7.3E-6/yr. This was very small when compared to the internal events LOOP initiating frequency of 5E-2/yr. The analyst did not consider these sequences further.

One sequence involved damage to control room panel B01. A fire in this panel could cause a LOOP and cause a control room evacuation. From NRC Inspection Manual Chapter 0609, Appendix F, Attachment 4, Fire Ignition Source Mapping Information, the fire initiation frequency for a single control room panel was 6.0E-5/yr for a large electrical cabinet fire. Since the control room is continuously manned, a fire starting in the cabinet would likely be identify promptly and extinguished by control room personnel.

The analyst assumed a non-suppression probability of 0.05. A fire in this cabinet could also affect train A and train B circuits, if allowed to spread. Train B is the protected train at the remote shutdown panel and the train B EDG was non-functional because of the performance deficiency. The GTGs would still be available and could power the train B circuits. The failure probability for the GTGs was 0.02. The CCDP was:

CCDP = 6E-5 *0.05*0.02 = 6E-8 The delta-CDF was therefore:

delta-CDF = 6E-8*43/365 = 7E-9/yr While a fire in an adjacent compartment to B01 could also spread to B01, the potential for core damage from this fire was less that 7E-9/yr. The analyst did not consider adjacent fire sequences further.

The final fire sequence involved a fire in the upper cable spreading room. This fire could affect offsite power and train A. Since train B was affected by the performance deficiency, the only other available AC electrical power source was the GTGs. However, the cable spreading room was equipped with a fixed suppression system. From Appendix F, the fixed suppression failure probability was approximately 0.02. The frequency for a fire that would spread without the fixed suppression system was 9.3E-7 per year. Crediting the GTGs, the delta-CDF for this sequence was approximately:

delta-CDF = 9.3E-7*0.02**0.02 = 3.E-10 The total Delta CDF for all of the evaluated fire areas was:

delta-CDFfires = 7.3E-9/yr Large Early Release Frequency: To address the contribution to conditional large early release frequency, the analyst used NRC Inspection Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004. Since the breaker did not contribute directly to a steam generator tube rupture or an intersystem loss of coolant accident, the condition was not risk significant to the large early release frequency.

The total delta-CDF was:

delta-CDF = 7E-7 + 1.6E-8 + 7.3E-9 = 7.2E-7/yr (Green)

The dominant core damage sequences included LOOP events that lead to station blackout conditions. The GTGs, train A EDG, and the DC battery life extension to six hours helped to limit the risk.

The finding has a cross-cutting aspect in the area of Problem Identification and Resolution associated with the corrective action program component because the licensee failed to thoroughly evaluate problems such that the resolutions address causes and extent of condition, as necessary [P.1.(c)].

Enforcement.

Title 10 CFR, Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to the above, from February 22, 2011 to January 6, 2013, the licensee failed to assure that the cause of the significant condition adverse to quality was determined and that corrective action was taken to preclude repetition. Specifically, the licensee failed to identify and correct the cause of an induced voltage transient in the automatic voltage regulator circuitry

resulting in the Unit 2 train B emergency diesel generator failing to reach rated voltage.

As an immediate corrective action, the licensee replaced and retested electrical components that could allow a voltage transient on the instantaneous pre-positioning circuit board and increased monitoring of the Unit 2 train B emergency diesel generator during surveillance testing. The licensee also plans to implement a design change to install voltage suppression for the power supply to the IPP circuit board on all emergency diesel generators. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as CRDR 4329997, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000529/2013003-02, Failure to Prevent Recurrence of a Significant Condition Adverse to Quality.

.2 Failure to Implement Corrective Action for Embedded Operator Work Around

Introduction.

A self-revealing finding occurred because the licensee did not take action to correct an embedded operator work around in the condensate system. Specifically, the licensee did not evaluate and develop a plan to correct the practice of throttling the condensate polishing demineralizer bypass valve in manual control mode rather than automatic mode. As a result, a malfunction of the heater drain tank B level controller resulted in a feedwater pump B trip and a subsequent reactor power cutback.

Description.

On January 17, 2013, the licensee experienced a malfunction in the Unit 3 feedwater heater extraction steam, drains, and vents system that cause a reactor power cutback. The function of this system is to improve plant efficiency by extracting steam from the turbine and piping it to the shell side of the feedwater heaters to preheat the feedwater flowing to the steam generators. With the unit operating at 100 percent power, a spurious failure of the heater drain tank B level controller resulted in a low-low level in the heater drain tank. This low-low level initiated a trip of heater drain pump B.

The trip of heater drain pump B caused a 7000 gallon per minute reduction in main feedwater flow. To compensate, the digital feedwater control system rapidly increased main feedwater pump speed and opened feedwater discharge valves which reduced the main feedwater pump suction pressure. Main feedwater pump B tripped due to low suction pressure, which resulted in a reactor power cutback and a power reduction to 50 percent.

Following the event, the licensee initiated PVAR 4330504 to evaluate the cause of the transient. The licensee determined the root cause of this event to be the stations tolerance of long standing equipment issues and normalizing actions that compensate for those equipment issues. Specifically, main feedwater pump suction pressure margin was reduced during this event due to operation of the condensate polishing demineralizers on full flow polishing with the condensate polishing demineralizer bypass valve controller in manual mode with a full closed signal to the valve. Operation in this configuration maximizes the removal of contaminants in the condensate to prevent degradation of the steam generators, but it reduces the suction pressure available to the main feedwater pumps. If the controller had been in automatic mode, the suction pressure would have been greater and a reactor power cutback would not have occurred.

The bypass valve controller had been operated in this mode because of valve seating issues since the late 1980s. In 2007, the licensee initiated an extensive root cause investigation of weaknesses in design control and configuration management processes.

The practice of throttling the condensate polishing demineralizer bypass valve in manual control mode rather than automatic mode was identified at that time as one of several embedded operator work arounds. The licensee issued a corrective action, CRAI 3064842, to review each of the weaknesses and develop a plan for resolution.

This corrective action, however, was never performed. CRAI 3064842 was ultimately closed in 2008 to a separate engineering disposition, CRAI 3260024, which did not address the condensate polishing demineralizer bypass valve controller.

The licensees corrective action program procedure, 01DP-0AP10, Revision 2, described measures to assure that conditions adverse to quality are promptly identified and corrected. In 2008, the licensee recognized the practice of throttling the condensate polishing demineralizer bypass valve in manual control mode rather than automatic mode was a design control weakness. However, the licensee did not evaluate the issue to determine the need for corrective action as required by their corrective action program. The licensee has captured this issue in their corrective action program as CRDR 4330879. The licensee has implemented changes to operating procedures to allow the condensate polishing demineralizer bypass valve controller to operate in automatic control mode during full power operations.

Analysis.

The failure to evaluate and determine corrective actions in accordance with established corrective action program procedures is a performance deficiency. This performance deficiency is more than minor, and therefore a finding, because it was associated with the configuration control attribute of the Initiating Events Cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the practice of throttling the condensate polishing demineralizer bypass valve in manual control mode rather than automatic mode resulted in a reactor power cutback that upset plant stability. The inspectors used the NRC Inspection Manual Chapter 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination (SDP) for Findings At-Power to determine the significance. The inspectors determined that the finding was of very low safety significance (Green)because it only contributed to the likelihood of a reactor trip and not the likelihood that mitigation equipment or functions would not be available. This issue did not have a cross-cutting aspect associated with it because it is not indicative of current performance.

Enforcement.

Enforcement action does not apply because the performance deficiency did not involve a violation of a regulatory requirement. Specifically, the feedwater heater extraction steam, drains, and vents system does not perform a safety-related function.

Because this finding does not involve a violation of a regulatory requirement and has very low safety significance, it is identified as a finding: FIN 05000530/2013003-03, Failure to Implement Corrective Action for Embedded Operator Work Around.

4OA5 Other Activities

(Closed) Temporary Instructions 2515/182 - Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks

a. Inspection scope

.

Leakage from buried and underground pipes has resulted in groundwater contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, NEI 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS Accession No.

ML110700122) with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued Temporary Instruction 2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.

b.

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the Temporary Instruction and it was confirmed that activates which correspond to completion dates specified in the program which have passed since the Phase 1 inspection was conducted, have been completed.

Additionally, the licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the Temporary Instruction and responses to specific questions were submitted to the NRC headquarters staff. Based upon the scope of the review described above, Phase II of TI-2515/182 was completed.

Observations and Findings No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On April 11, 2013, the inspectors presented the inspection results of the review of inservice inspection activities to Mr. R. Bement, Senior Vice President, Nuclear Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On July 10, 2013, the inspectors presented the inspection results to Mrs. M. Lacal, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as a Non-cited Violation.

Title 10 CFR 50.59(c)(1) requires, in part, that a licensee may make changes in the facility as described in the final safety analysis report without obtaining a license amendment pursuant to Section 50.90 only if a change to the technical specifications incorporated in the license is not required. Contrary to the above, between 2003 and March 8, 2013, the licensee made changes to the reactivity of fuel discharged to the spent fuel pool without obtaining a license amendment. Specifically, the licensee received license amendments for power uprates in 2003 and 2005, but did not recognize the impact of the power uprates relative to spent fuel pool criticality. Consequently, the licensee did not update the spent fuel pool criticality analysis of record and did not request a license amendment to revise the affected Technical Specifications 3.7.17 and 4.3.1.1.

On March 8, 2013, the licensees engineering staff discovered that the spent fuel pool analysis of record had not been updated to account for the replacement steam generator power uprate. The power uprate required higher moderator and fuel temperatures within the core, thereby increasing plutonium production, which in turn increases the reactivity of the spent fuel. This condition resulted in Technical Specifications 3.7.17 and 4.3.1.1 being non-conservative. The licensee initiated PVAR 4363316 to document the condition and issued an Event Notification to the NRC to report an unanalyzed condition.

The licensee also performed a prompt operability determination to show that despite the non-conservative technical specifications, the fuel in the spent fuel pool remains in a safe configuration. The licensee planned corrective actions to revise the spent fuel pool analysis of record using updated methodology and input parameters. Traditional enforcement applied to this finding because it involved a violation that impacted the regulatory process. Assessing the violation in accordance with Enforcement Policy, the team determined it to be of Severity Level IV because it resulted in a condition evaluated by the SDP as having very low safety significance (Enforcement Policy example 6.1.d.2).

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

A. Bassett, Engineer, System Engineering

A. Krainik, Department Leader Nuclear Engineering, Operations

B. Berryman, Plant Manager, Plant Operations

C. Moeller, Manager, Radiation Protection

C. Tubman, Section Leader, Radiation Protection Operations

D. Arbuckle, Manager, Operations

D. Hansen, Senior Consultant Engineer

D. Jennings, Supervisor, Radiation Protection

D. Mims, Senior Vice President, Regulatory and Oversight

D. Van Allen, Engineer, Engineering Inspections

D. Wheeler, Department Leader, Performance Improvement

E. Dutton, Director, Nuclear Assurance Department

E. Fernandez, Senior Engineer

E. Kirkland, Program Advisor, Maintenance

F. Oreshack, Consultant, Regulatory Affairs

F. Puleo, Peer Evaluator, STARS/South Texas Project

G. Andrews, Manager, Operations Support

G. Jones, Team Leader, Radiation Protection

J. Bettencourt, Technical Advisor, Radiation Protection

J. Bungard, Supervisor, Radiological Engineering

J. Cadogan, Vice President, Nuclear Engineering

J. Cox, Engineer, Program Engineering

J. McDonnell, Department Leader, Radiation Protection

K. Foster, Department Leader, Fire Department

K. House, Director, Nuclear Design Engineering

K. Schrecker, Section Leader, Engineering Programs

M. Brannin, Senior Engineer, Program Engineering

M. Debolt, Team Leader, Nuclear Maintenance

M. Lacal, Vice President, Operations Support

M. McGhee, Manager, Regulatory Affairs

M. McLaughlin, Director, Technical Services

M. Radspinner, Department Leader, System Engineering

M. Ray, Director, Emergency Preparedness/Security

M. Shea, Director, Safety Culture

N. Aaronscooke, Engineer, Regulatory Affairs

N. Nelson, Senior Technician, Radiation Protection

P. Anderson, Engineer, Program Engineering

P. McSpaman, Director, Nuclear Training

R. Barnes, Director, Regulatory Affairs

R. Bement, Senior Vice President, Site Operations

R. Bethke, Department Leader, Emergency Preparedness

R. Folley, Engineer, Engineer Inspections

R. Routolo, Operations Department Leader, Radiation Services

R. Sims, Instrumentation Technician, Radiation Protection

R. Witzak, Operations Superintendant, Radiation Protection

S. Lantz, Section Leader, Radiation Protection Technical Services

S. Pobst, Section Leader, Engineering

T. Gray, Department Leader, Radiation Protection

T. Mitchell, Component Engineer, Engineering

T. Mock, Director, Operations

T. Weber, Department Leader, Regulatory Affairs

W. Blaxton, Radiation Monitoring Technician, Radiation Protection

W. Leaverton, Engineer, System Engineering

NRC Personnel

T. Brown, Senior Resident Inspector

D. Reinert, Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000528;529; 530/2013003-01 NCV Failure to Follow Operability Determination Procedure for Maintaining Administrative Limits (Section 1R15)

05000529/2013003-

NCV Failure to Prevent Recurrence of a Significant Condition Adverse to Quality (Section 4OA2)

05000530/2013003-

FIN Failure to Implement Corrective Action for Embedded Operator Work Around (Section 4OA2)

Closed

2515/182 TI Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks (Section 4OA5)