IR 05000528/2010005

NRC Integrated Inspection Report 05000528/2010005, 05000529/2010005, and 5000530/2010005

ML110390109
Person / Time
Site:	Palo Verde
Issue date:	02/08/2011
From:	Ryan Lantz NRC/RGN-IV/DRP/RPB-D
To:	Edington R Arizona Public Service Co
References
IR-10-005
Download: ML110390109 (88)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGI ON I V 612 EAST LAMAR BLVD, SUITE 400 ARLINGTON, TEXAS 76011-4125

.

February 8, 2011 Randall K. Edington, Executive Vice President, Nuclear/CNO Mail Station 7602 Arizona Public Service Company P.O. Box 52034 Phoenix, AZ 85072 2034 SUBJECT: PALO VERDE NUCLEAR GENERATING STATION -- NRC INTEGRATED INSPECTION REPORT 05000528/2010005, 05000529/2010005, and 5000530/2010005

Dear Mr. Edington:

On December 31, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 5, 2011, with Mr. D. Mims, Vice President, Regulatory Affairs and Plant Improvement, and other members of your staff.

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

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

This report documents three NRC identified findings of very low safety significance (Green) and one Severity Level IV violation. All four of these issues were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section 2.3.2 of the NRC Enforcement Policy. Additionally, three licensee identified violations which were determined to be of very low safety significance are listed in the report.

If you contest the violations or the significance of the noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C.

20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas, 76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the facility. In addition, if you disagree with the crosscutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date

Arizona Public Service Company -2-of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at the facility.

In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its enclosures, and your response, if you choose to provide one for cases where a response is not required, will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response should not include any personal privacy or proprietary information so that it can be made available to the public without redaction.

Sincerely,

/RA/

Ryan Lantz, Chief Project Branch D Division of Reactor Projects Docket Nos.: 50-528, 50-529, 50-530 License: NPF-41, NPF-51, NPF-74

Enclosure:

NRC Inspection Report 05000528/2010005, 05000529/2010005, and 05000530/2010005 w/Attachment: Supplemental Information

REGION IV==

Docket: 50-528, 50-529, 50-530 License: NPF-41, NPF-51, NPF-74 Report: 05000528/2010005, 05000529/2010005, 05000530/2010005 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location: 5951 S. Wintersburg Road Tonopah, Arizona Dates: October 1 through December 31, 2010 Inspectors: J. Bashore, Acting Senior Resident Inspector M. Baquera, Resident Inspector D. Reinert, Acting Resident Inspector C. Smith, Acting Resident Inspector M. Young, Reactor Inspector T. Buchanan, Reactor Inspector B. Rice, Reactor Inspector K. Clayton, Senior Operations Engineer B. Larson, Senior Operations Engineer J. Mateychick, Senior Reactor Inspector S. Graves, Senior Reactor Inspector Approved By: Ryan Lantz, Chief, Project Branch D Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000528/2010005, 05000529/2010005, 05000530/2010005; 10/01/10 - 12/31/10; Palo

Verde Nuclear Generating Station, Units 1, 2, and 3, Integrated Resident and Regional Report.

The report covered a 3-month period of inspection by resident inspectors and an announced baseline inspection by region-based inspectors. Three Green, noncited violations and one Severity Level IV noncited violation were identified. The significance of most findings are indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609,

Significance Determination Process. The crosscutting 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: Mitigating Systems

Green.

The inspectors identified a noncited violation of 10 CFR 55.49, Integrity of Examinations and Tests, for the failure of the licensee to ensure that the integrity of an operating test administered to licensed operators was maintained. During the week of December 8, 2009, twenty-four licensed operators received three job performance measures and one additional licensed operator received five job performance measures for their operating tests that had been previously administered to other licensed operators in previous weeks. This failure resulted in a compromise of examination integrity because it exceeded the 50 percent overlap required by quality procedure LOCT-TPD-R56, Licensed Operator Continuing Training Program, Revision 56, for this portion of the examination, but did not lead to an actual effect on the equitable and consistent administration of the examination.

This issue was entered into the licensees corrective action program as Condition Report Disposition Request 3527071.

The failure of the licensees training staff to maintain the integrity of examinations administered to licensed operations personnel was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it adversely impacted the human performance attribute of the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Additionally, if left uncorrected, the performance deficiency could have become more significant in that allowing licensed operators to return to the control room without valid demonstration of appropriate knowledge on the biennial examinations could be a precursor to a more significant event. Using Manual Chapter 0609, Significance Determination Process, Phase 1 worksheets, and the corresponding Appendix I,

Licensed Operator Requalification Significance Determination Process, the finding was determined to have very low safety significance (Green) because, although the finding resulted in a compromise of the integrity of operating test job performance measures and compensatory actions were not immediately taken when the compromise should have been discovered in 2009, the equitable and consistent administration of the test was not actually impacted by this compromise. This finding has a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that procedures were accurately translated from industry standards such that the 50 percent maximum overlap was not exceeded H.2(c)(Section 1R11.2).

Green.

The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, for the failure of the licensee to follow their quality procedure 01DP-0EM13, Licensed Operator Medical Examinations, Revision, which provides the medical examination requirements for licensed operators at Palo Verde Nuclear Generating Station. Of the 15 medical records reviewed by the inspectors, 7 licensed senior reactor operator medical records did not contain the proper no-solo restrictions imposed by the NRC when these individuals were licensed. Additionally, the software that the licensee used to track these restrictions (Station Work Management System or SWMS) did not reflect the proper restrictions for these 7 individuals. This issue was entered into the licensees corrective action program as Condition Report Disposition Requests 3527072 and 3526979.

The failure of the licensees medical staff to follow their procedure for implementing the required medical examination program was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it adversely impacted the human performance attribute of the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609, Significance Determination Process, Phase 1 worksheets, and the corresponding Appendix I, Licensed Operator Requalification Significance Determination Process, the finding was determined to have very low safety significance and is being characterized as a Green, noncited violation. The finding was determined to be Green, using Appendix I of Manual Chapter 0609, because more than 20 percent of the medical records reviewed contained significant deficiencies. The finding was also determined to have very low safety significance (Green) because: (1) the finding did not result in any events in the control room; and (2) no health requirements required by ANS/ANSI 3.4-1983 Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants were exceeded by any licensed operator while on watch. This finding has a crosscutting aspect in the area of human performance associated with the work practices component because this procedure and its associated software are the two principle mechanisms that the facility uses to ensure that licensed operators are fit for duty H.4(a)(Section 1R11.2).

• SL-IV The inspectors identified a Severity Level IV violation of 10 CFR 55.3,

License Requirements, for the failure of the licensee to ensure that all individuals authorized by a license to operate the controls of the facility met all the conditions of their licenses as defined in 10 CFR 55.3. Specifically, the requirement to have a biennial physical completed and certified by the facilitys physician during the continuous two year period for all licensed operators was not met for three licensed operators. Two of these licensed operators performed licensed operator duties 42 times between February 8 and March 25, 2010, after the deadline for their biennial examinations had passed. Upon discovery, the licensee removed these individuals from watchstanding duties pending follow-up medical evaluations. This issue was entered into the licensees corrective action program as Condition Report Disposition Request 3526981.

The failure of the licensee to ensure that all individuals authorized by a license to operate the controls of the facility met all the conditions of their licenses as defined in 10 CFR 55.3 is a performance deficiency. Specifically, the requirement to have a biennial physical completed and certified by the facilitys physician during the continuous two year period for all licensed operators (as required in 10 CFR 55.21)was not met for three licensed operators, two of which were standing watch with expired medical examinations. The finding was evaluated using the traditional enforcement process because the failure to determine an operators medical condition and general health has the potential to impact the NRCs ability to perform its regulatory function; the NRC was not notified nor allowed an opportunity to review the specific medical conditions of the two operators whose medical qualifications had expired while they were standing watch or eligible to stand watch. Using the NRCs Enforcement Policy, section 6.4.d, Severity Level IV violation examples, this finding is similar to example 1 which states, in part that an unqualified individual performing the functions of an operator or senior operator. Two licensed operators stood watch without a certified medical examination within the two year period that the medical examination is required to be completed and certified by the physician. Because:

(1) the medical conditions of the two licensed operators did not change when they received their medical examinations in recent weeks; (2) the finding did not cause any plant events or transients while the individuals were on watch; (3) it was not repetitive or willful; and (4) it was entered into the corrective action program, the finding was determined to be of very low safety significance and is being treated as a Severity Level IV noncited violation consistent with the NRC Enforcement Policy.

This finding has a crosscutting aspect in the area of human performance associated with the work practices component because medical staff supervisors did not oversee the biennial physical examination due dates such that nuclear safety was supported H.4(c)(Section 1R11.2).

Green.

The inspectors identified a noncited violation of 10 CFR Part 50, Appendix B,

Criterion XVI, Corrective Action, for the failure of engineering personnel to promptly correct a condition adverse to quality associated with room cooler AHU-3MHAAZ05 blower shaft dimensions. Specifically, between July 2008 and November 2010, corrective actions for high vibrations in the Unit 3 essential cooling water system train A room cooler blower failed to promptly address the incorrect shaft dimensions at the bearing shaft interface. The licensee is developing corrective actions to replace the defective shaft by procuring a new shaft or machining a shaft on site. The licensee entered this issue into the corrective action program as Palo Verde Action Request 3559219.

The inspectors concluded the finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined the finding had a very low safety significance (Green) because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined this finding had a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that personnel, equipment, and procedure were available and adequate to assure nuclear safety by minimizing long standing equipment issues H.2(a)(Section 1R15).

Licensee-Identified Violations

Violations of very low safety significance, which were identified by the licensee, have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and corrective action tracking numbers are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially full power for the duration of the inspection period.

Unit 2 operated at essentially full power for the duration of the inspection period.

Unit 3 entered the inspection at essentially full power and was shutdown on October 2, 2010, for refueling outage 15. Unit 3 returned to essentially full power on November 14, 2010, and remained at essentially full power for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

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

• September 16, 2010, Unit 2, emergency diesel generator train B

• November 3, 2010, Unit 1, essential cooling water train A

• December 14, 2010, Unit 1, emergency diesel generator, train A The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. 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, Updated Final Safety Analysis Report (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. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

On October 15, 2010, the inspectors performed a complete system alignment inspection of the Unit 3 low pressure safety injection system, train B to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment.

The inspectors 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.

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

b. Findings

No findings were identified.

.3 System Walkdown associated with Temporary Instruction (TI) 2515/177, Managing Gas

Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems Additional activities were performed during this system walkdown that were associated with TI 2515/177, Managing gas accumulation in emergency core cooling, decay heat removal, and containment spray systems. These activities are described in bullet

.2 of

this section.

a. Inspection Scope

On October 15, 2010, the inspectors conducted a walkdown of low pressure safety injection system, train B, in sufficient detail to reasonably assure the acceptability of the licensees walkdowns (TI 2515/177, Section 04.02.d). The inspectors also verified that the information obtained during the licensees walkdowns was consistent with the items

identified during the inspectors independent walkdown (TI 2515/177, Section 04.02.c.3).

In addition, the inspectors verified that the licensee had isometric drawings that describe the low pressure safety injection system configurations and had acceptably confirmed the accuracy of the drawings (TI 2515/177, Section 04.02.a). The inspectors verified the following related to the isometric drawings:

• High point vents were identified

• High points that do not have vents were acceptably recognizable

• Other areas where gas can accumulate and potentially impact subject system operability, such as at orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves, were acceptably described in the drawings or in referenced documentation

• Horizontal pipe centerline elevation deviations and pipe slopes in nominally horizontal lines that exceed specified criteria were identified

• All pipes and fittings were clearly shown The inspectors verified that piping and instrumentation diagrams accurately described the subject systems, that they were up-to-date with respect to recent hardware changes, and any discrepancies between as-built configurations, the isometric drawings, and the piping and instrumentation diagrams were documented and entered into the corrective action program for resolution (TI 2515/177, Section 04.02.b).

Documents reviewed are listed in the attachment to this report. This inspection effort counts towards the completion of TI 2515/177 which will be closed in a later inspection report.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Fire Inspection Tours

a. Inspection Scope

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:

• October 19, 2010, Unit 3, containment, all elevations

• November 1, Unit 1, emergency diesel generator building all elevations

• November 2, Unit 1, auxiliary feedwater pump rooms and condensate storage tank pump house

• November 4, 2010, Unit 1, fuel building 100 foot, 120 foot, 140 foot elevations 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 of 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. 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 four quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

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.

• October 26, 2010, Unit 2, auxiliary building 52 foot and 40 foot elevations

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

b. Findings

No findings were identified.

1R08 In-Service Inspection Activities

.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. Inspection Scope

The inspectors observed 11 nondestructive examination activities and reviewed 5 nondestructive examination activities that included 4 types of examinations. The licensee did not identify any relevant indications accepted for continued service during the nondestructive examinations.

The inspectors directly observed the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Feedwater Down Comer Feedwater Steam Generator 1 Magnetic Particle (Welds 60-7, 60-14, 60-15)

Feedwater Down Comer Feedwater Steam Generator 1 Ultrasonic (Weld 60-14)

Feedwater Down Comer Feedwater Steam Generator 1 Ultrasonic (Weld 60-7)

Feedwater Down Comer Feedwater Steam Generator 1 Ultrasonic (Weld 60-15)

Shutdown Cooling Shutdown Cooling Loop 1 (Overlay 21-20 Liquid Penetrant and 6-11)

Shutdown Cooling Shutdown Cooling Loop 1 (Overlay 21-20 Ultrasonic and 6-11)

Reactor Coolant Reactor Coolant Pump 2A Cold Leg Safety Phased Array Injection Nozzle (Weld 13-10) Ultrasonic

The inspectors reviewed records for the following nondestructive examinations:

SYSTEM WELD IDENTIFICATION EXAMINATION TYPE Reactor Coolant Reactor Coolant Pump 1A Cold Leg Phased Array Ultrasonic Safety Injection Nozzle (Weld 9-10)

Reactor Coolant Reactor Coolant Pump 1B Cold Leg Phased Array Ultrasonic Safety Injection Nozzle (Weld 11-10)

Steam Generator Steam Generator 1 Pedestal Studs (3.25 Ultrasonic inch)

Steam Generator Steam Generator 2 Pedestal Studs (3.25 Ultrasonic inch)

Steam Generator Steam Generator 1 & 2 Pedestal Studs Ultrasonic (5.5 inch)

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 inspectors also verified the qualifications of all nondestructive examination technicians performing the inspections were current.

The inspectors observed one weld on the reactor coolant system pressure boundary.

The inspectors directly observed a portion of the following welding activities:

SYSTEM WELD IDENTIFICATION WELD TYPE Safety Injection Train A 24 SI-189 (3187449-2) Gas Tungsten Arc Weld The inspectors verified, by review, 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.

Completion of Sections

.1 through .5 constitutes completion of one sample as defined in

Inspection Procedure 71111.08-05. These actions constitute completion of the requirements for Section 02.01.

b. Findings

No findings were identified.

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

The Unit 3 reactor pressure vessel head was replaced during this outage. The required inspections were performed and will be documented in a subsequent report.

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

a. Inspection Scope

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 70TI-9ZC01, Boric Acid Walkdown Leak Detection, Revision 10. The inspectors also reviewed the visual records of the components and equipment. The inspectors verified that the visual inspections emphasized locations where boric acid leaks could cause degradation of safety-significant components. The inspectors also verified that the engineering evaluations for those components where boric acid was identified gave assurance that the ASME Code wall thickness limits were properly maintained. The inspectors confirmed that the corrective actions performed for evidence of boric acid leaks were consistent with requirements of the ASME Code. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the one requirement for Section 02.03.

b. Findings

No findings were identified.

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

a. Inspection Scope

The inspectors assessed the in situ screening criteria to assure consistency between assumed nondestructive examination flaw sizing accuracy and data from the Electric Power Research Institute (EPRI) examination technique specification sheets. No conditions were identified that warranted in situ pressure testing.

Due to the tube wear identified during the previous outage, a 100 percent review of all tubes in both steam generators was performed during this outage. The inspectors reviewed both the licensee site-validated and qualified acquisition and analysis technique sheets used during this refueling outage and the qualifying EPRI examination technique specification sheets to verify that the essential variables regarding flaw sizing accuracy, tubing, equipment, technique, and analysis had been identified and qualified through demonstration.

The inspection procedure specified comparing the estimated size and number of tube flaws detected during the current outage against the previous outage operational assessment predictions to assess the licensee's prediction capability. The number of identified indications (for Steam Generator 31 zero tubes were plugged and/or staked and for Steam Generator 32 six tubes were plugged and four tubes were staked) was consistent with predictions from the vendor for the previous outage (estimate of seven tubes plugged and three tubes staked per steam generator). No new damage mechanisms were identified during this inspection.

The inspection procedure specified confirmation that the steam generator tube eddy current test scope and expansion criteria meet technical specification requirements, EPRI guidelines, and commitments made to the NRC. The inspectors evaluated the recommended steam generator tube eddy current test scope established by technical specification requirements and the licensees degradation assessment report. The inspectors compared the recommended test scope to the actual test scope and found that the licensee had accounted for all known flaws and had, as a minimum, established a test scope that met technical specification requirements, EPRI guidelines, and commitments made to the NRC.

As mentioned above, the base scope inspection plan required 100 percent tube inspection for this refueling outage. The inspection scope for Refueling Outage 3R15 included:

• 100 percent visual inspection of installed plugs

• Tube sheet periphery and tube lane foreign object search and retrieval

• 100 percent full bobbin examination using a 0.610 inch bobbin probe in rows 5 and higher and from hot leg tube end to batwing 1 in rows 1 through 4

• 100 percent bobbin examination using a 0.590 inch bobbin probe from batwing 1 to cold leg tube end in rows 1 through 4 (testing from both legs)

• 100 percent plus point inspection of bobbin flaw-like signals at tube support structures (including row 1 through 4 U-bends)

• Plus point inspection of special interest locations Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements of Section 02.04.

b. Findings

No findings were identified.

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

a. Inspection scope

The inspectors reviewed 26 condition reports, which dealt with in-service inspection activities and found the corrective actions were appropriate. The specific condition reports reviewed are listed in the documents reviewed section. From this review the inspectors concluded that the licensee has an appropriate threshold for entering in-service 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 industry operating experience. Specific documents reviewed during this inspection are listed in the attachment.

These actions constitute completion of the requirements of Section 02.05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review

a. Inspection Scope

On December 6, 2010, during licensed operator continuing training simulator scenarios, the inspectors observed a crew of licensed operators in the plants simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Crews ability to take timely, conservative actions

• Crews prioritization, interpretation, and verification of annunciator alarms

• Crews correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Crews ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications

The inspectors compared the crews performance in these areas to pre-established operator action expectations and successful critical task completion requirements.

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

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

b. Findings

No findings were identified.

.2 Biennial Inspection

The licensed operator requalification program involves two training cycles that are conducted over a two year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination.

a. Inspection Scope

To assess the performance effectiveness of the licensed operator requalification program, the inspectors conducted personnel interviews, reviewed both the operating tests and written examinations, and observed ongoing operating test activities.

The inspectors interviewed 10 licensee personnel, consisting of 4 operators, 3 instructors, 2 managers, and the simulator supervisor, to determine their understanding of the policies and practices for administering requalification examinations. The inspectors also reviewed operator performance on the written exams and operating tests. These reviews included observations of portions of the operating tests by the inspectors. The operating tests observed included two job performance measures and three scenarios that were used in the current biennial requalification cycle. These observations allowed the inspectors to assess the licensee's effectiveness in conducting the operating test to ensure operator mastery of the training program content. The inspectors also reviewed medical records of 15 licensed operators for conformance to license conditions and the licensees system for tracking qualifications and records of license reactivation for 2 operators.

The results of these examinations were reviewed to determine the effectiveness of the licensees appraisal of operator performance and to determine if feedback of performance analyses into the requalification training program was being accomplished.

The inspectors interviewed members of the training department and reviewed minutes of training review group meetings to assess the responsiveness of the licensed operator requalification program to incorporate the lessons learned from both plant and industry events. Examination results were also assessed to determine if they were consistent with the guidance contained in NUREG 1021, Operator Licensing Examination Standards for Power Reactors, Revision 9, Supplement 1, and NRC Manual

Chapter 0609, Appendix I, Operator Requalification Human Performance Significance Determination Process.

In addition to the above, the inspectors reviewed examination security measures, simulator fidelity and existing logs of simulator deficiencies.

On October 14, 2010, the licensee informed the lead inspector of the following Units 1, 2, and 3 results for the Licensed Operator Requalification Program:

• Of the 123 total licensed operators, 2 operators have not been tested due to medical reasons

• 23 of 23 crews passed the simulator portion of the operating test

• 121 of 121 licensed operators passed the simulator portion of the operating test

• 121 of 121 licensed operators passed the Job Performance Measure portion of the examination

• 116 of 121 licensed operators passed the biennial written exam The individuals that failed the applicable portions of their exams and operating tests were remediated, retested, and passed their retake exams.

On November 4, 2010, the licensee informed the lead inspector of the following results for the Licensed Limited Senior Reactor Operator (LSRO) Requalification Program:

• All 12 LSROs took the examinations and operating tests

• All 12 LSROs passed the written examination

• All 12 LSROs passed the simulator portion of the operating test

• All 12 LSROs passed the Job Performance Measure portion of the operating test The inspectors completed one inspection sample of the biennial licensed operator requalification program.

b. Findings

===.1

Introduction.

The inspectors identified a Green, noncited violation of 10 CFR 55.49,===

Integrity of Examinations and Tests, for the failure of the licensee to ensure that the integrity of an operating test administered to licensed operators was maintained. During the week of December 8, 2009, twenty-four licensed operators received three job performance measures and one additional licensed operator received five job performance measures for their operating test(s) that had been previously administered to other licensed operators in previous weeks. This failure resulted in a compromise of examination integrity because it exceeded the 50 percent overlap required by quality Procedure LOCT-TPD-R56 Licensed Operator Continuing Training Program, Revision 56, for this portion of the examination, but did not lead to an actual effect on the equitable and consistent administration of the examination.

Description.

On September 10, 2010, while performing a biennial requalification inspection in accordance with Inspection Procedure 71111.11, Licensed Operator Requalification Program, the inspectors discovered that during the week of December 8, 2009, twenty-four licensed operators received three Job Performance Measures (JPMs) for their operating test that had been previously administered to other licensed operators during the week of December 1, 2009. Also, during the week of December 8, 2009, one additional licensed operator received five JPMs for his operating test that had been previously administered to other licensed operators the week of December 1, 2009. This resulted in this group of licensed operators receiving 60 percent overlap and 100 percent overlap, respectively, on their operating test JPMs. Procedure LOCT-TPD-R56, Licensed Operator Continuing Training Program, Revision 56, requires that no more than 50 percent of each portion of the annual operating test (including JPMs) will be comprised of test items used in any other operating test in the same examination cycle. The inspectors concluded that failure to fulfill the requirements of this procedure constituted a compromise of examination integrity required by 10 CFR 55.49.

Seventeen of the affected operators had completed their 2010 JPMs and did not have to perform additional JPMs to maintain their qualifications. However, eight remaining operators had their qualifications suspended in the licensees Site Work Management System (SWMS). This is the system the licensee uses to track various licensed operator qualifications and requirements. The licensee removed these eight operators from shift until they had successfully passed their JPMs for the 2010 examination cycle.

Between September 11 and October 8, 2010, the licensee evaluated this issue using an apparent cause evaluation and associated condition report disposition request (CRDR)3527071 to fully understand the extent of condition, the causal factors, and appropriate corrective actions. The licensee maintained that they did not understand the 50 percent overlap requirement that they translated from the industry standard document ACAD 2007-001 Guidelines for the Continuing Training of Licensed Personnel to their procedure LOCT-TPD-R56. The licensee did not understand the 50 percent overlap requirement applied between and among all aspects of the examination and operating tests. The inspectors concluded from this discussion that the translation was not clear enough to prevent the overlap threshold of 50 percent from being exceeded and that the licensee did not fully understand the meaning of this industry standard and the NRCs expectation regarding examination and operating test overlap requirements.

The inspectors reviewed various items to ensure that examination security was effective at preventing an actual impact on examination integrity. The inspectors noted that licensee training personnel performed a formal briefing to all operations personnel prior to the administration of their 2009 operating test that specifically prohibited them from discussing the details of their test with other personnel. Additionally, all of the licensed operators signed a security agreement documenting that they would not discuss the details of their test with other personnel. The licensee and the inspectors also reviewed the grading of the 2009 operating tests to determine if there was any discernable discrepancy in evaluated performance between the different weeks that would indicate that the equitable and consistent administration of the test had actually been affected.

During this review it was determined that grades actually were lower for some of the operators who took their JPMs in the weeks where the overlap occurred. The inspectors concluded that, although the integrity of the 2009 operating test was not maintained, no

actual affect on the equitable and consistent administration of the 2009 operating test had occurred. The licensee documented this issue in CRDR 3527071.

Analysis.

The failure of the licensees training staff to maintain the integrity of examinations administered to licensed operations personnel was a performance deficiency. The performance deficiency is more than minor, and therefore a finding, because it adversely impacted the human performance attribute of the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Additionally, if left uncorrected, the performance deficiency could have become more significant in that allowing licensed operators to return to the control room without valid demonstration of appropriate knowledge on the biennial examinations could be a precursor to a significant event if undetected performance deficiencies develop. Using Manual Chapter 0609, Significance Determination Process, Phase 1 worksheets, and the corresponding Appendix I, Licensed Operator Requalification Significance Determination Process, the finding was determined to have very low safety significance (Green) because, although the finding resulted in a compromise of the integrity of operating test JPMs and compensatory actions were not immediately taken when the compromise should have been discovered in 2009, the equitable and consistent administration of the test was not actually impacted by this compromise. This finding has a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that procedures were accurately translated from industry standards such that the 50 percent maximum overlap requirement was not exceeded H.2(c).

Enforcement.

Title 10 CFR 55.49, Integrity of Examinations, requires, in part, that facility licensees shall not engage in any activity that compromises the integrity of any application, test, or examination required by this part. The integrity of a test or examination is considered compromised if any activity, regardless of intent, affected, or, but for detection, could have affected the equitable and consistent administration of the test or examination. This includes activities related to the preparation, administration, and grading of the tests and examinations required by this part. Contrary to the above, during the week of December 8, 2009, the licensee engaged in an activity that compromised the integrity of a test required by 10 CFR Part 55. Specifically, training personnel administered three JPMs to twenty-four licensed operators and five JPMs to one additional licensed operator for their operating tests that had been previously administered to other licensed operators the week of December 1, 2009. This resulted in this group of licensed operators receiving 60 percent overlap and 100 percent overlap, respectively, on their operating test JPMs that had been administered in previous weeks of the requalification testing cycle. Administering an operating test with greater than 50 percent overlap from previously administered operating tests is considered a compromise of the integrity of the test in that it is a practice that, but for detection, could affect the equitable and consistent administration of the these tests. The inspectors determined that the compromise of the 2009 operating test did not result in an actual effect on the equitable and consistent administration of the test. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as CRDR 3527071, this violation is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000528;

05000529;05000530/2010005-01, Failure to Maintain Licensed Operator Examination Integrity.

===.2

Introduction.

The inspectors identified a Green noncited violation of 10 CFR Part 50,===

Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure of the licensee to follow their quality procedure 01DP-0EM13, Licensed Operator Medical Examinations, Revision 15, which provides the medical examination requirements for licensed operators at Palo Verde Nuclear Generating Station. Of the 15 medical records reviewed by the inspectors, seven licensed senior reactor operator medical records did not contain the proper no-solo restrictions imposed by the NRC when these individuals were licensed. Additionally, the system that the licensee uses to track these restrictions (Station Work Management System or SWMS) also did not reflect the proper restrictions for these seven individuals.

Description.

On September 9, 2010, while reviewing a 10 percent sample of medical records (15 of approximately 136 licensed operators), the inspectors were comparing NRC records for various licensing restrictions against the licensee medical records when they discovered that seven licensed senior reactor operator medical records did not contain the no-solo restrictions imposed by the NRC when these individuals were licensed. These restrictions are documented on NRC Form 396, Certification of Medical Examination by Facility Licensee. The inspectors reviewed the procedure that the licensee uses to implement the medical examination program and found that this was one of several procedural requirements that was not followed for the medical program. Procedure 01DP-0EM13, Licensed Operator Medical Examinations, Revision 15, requires that:

(1) Site Work Management System or SWMS is updated with regards to an individuals medical qualification;

(2) health services personnel are responsible to interface with Operations Management, Nuclear Regulatory Affairs, Nuclear Training, Nuclear Assurance and Quality Control Departments to ensure the medical examination of the Licensed Nuclear Operators are at all times, in compliance with NRC regulations, guidance, and interpretations as well as the guidance of ANSI/ANS 3.4-1983;

(3) the Appendix F, PVNGS Medical Evaluation Report shall be reviewed and signed by the physician and this form shall certify completion of the medical certification and should be signed by the licensed operator;

(4) the medical file will be processed for entering into APS Medical Monitoring computer system; and

(5) if a change in medical qualification or certification of a Licensed Operator occurs, subsequent to the examination date utilized for the current NRC Form 396, a new NRC Form 396 will be submitted to Nuclear Regulatory Affairs and it will reflect the necessary restrictions or waiver requests.

The inspectors found that the no-solo restrictions were missing from seven medical records and in some cases there were no NRC Form 396s. The inspectors asked the licensee how their staff controls licensing restrictions if the medical records do not contain these forms. The licensee responded that the SWMS system tracks this information. During the review of SWMS the licensees staff and inspectors identified that the SWMS medical code for the senior reactor operator no-solo restriction (Code 55) dropped off of operator licensing qualifications on July 31, 2010, and it was not known why this had occurred. Additionally, the SWMS system dates that the licensee uses to track the two year requirement for the physical did not reflect the dates in the

medical records. In addition, the licensee does not have a formal process to ensure correspondence or information related to an operator license that is sent to the site Vice-President, License Training, Regulatory Affairs, and the individual operator is communicated and shared with the medical staff. Another licensed operator had a medical restriction placed on his license by the NRC and the licensees medical staff was not aware of this restriction change. As a result of these issues, the licensees staff verified the medical status and certification of the crews that would be standing watch over the next two days (September 9-10, 2010) from this discovery and then completed the review of the remainder of the licensed operator medical records on September 10, 2010. The results of the licensees review confirmed the inspectors concern that two licensed operators stood watch while unqualified due to expired medical examinations.

As a result, the licensee removed these two licensed operators from watchstanding duties until they received new physical examinations. There were no new medical issues discovered during the physical examinations therefore they were allowed to return to watch. This issue was entered into the licensees corrective action program as CRDR 3527072, CRDR 3526981, and CRDR 3526979.

Analysis.

The failure of the licensees medical staff to follow their procedure for implementing the required medical examination program was a performance deficiency.

The performance deficiency is more than minor, and therefore a finding, because it adversely impacted the human performance attribute of the mitigating systems cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609, Significance Determination Process, Phase 1 worksheets, and the corresponding Appendix I, Licensed Operator Requalification Significance Determination Process, the finding was determined to have very low safety significance and is being characterized as a Green noncited violation because more than 20 percent of the medical records sampled contained significant deficiencies. The finding was also determined to have very low safety significance (Green) because:

(1) the finding did not result in any events in the control room; and

(2) no health requirements required by ANS/ANSI 3.4-1983 Medical Certification and Monitoring of Personnel Requiring Operator Licenses for Nuclear Power Plants were exceeded by any licensed operator while on watch. This finding has a crosscutting aspect in the area of human performance associated with the work practices component because this procedure and its associated software are the two principle mechanisms that the facility uses to ensure that licensed operators are fit for duty H.4(a).

Enforcement.

Title 10 CFR Part 55, 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. Contrary to the above, multiple examples were found by the inspectors where the licensees staff failed to follow their quality procedure, 01DP-0EM13, Licensed Operator Medical Examinations, Revision 15. Specifically, the licensee:

(1) did not ensure SWMS was updated with regards to an individuals medical qualification in that they lost track of no-solo restrictions in the individual medical records and in SWMS for seven senior reactor operators;

(2) health services personnel did not adequately interface with Nuclear Regulatory Affairs to ensure the medical examinations

of the licensed nuclear operators were in compliance with NRC regulations, guidance, and interpretations as well as the guidance of ANSI/ANS 3.4-1983;

(3) none of the no-solo restriction issues that were identified by the inspectors were entered into the medical files within the APS Medical Monitoring computer system; and

(4) one individual had a change in medical qualification or certification subsequent to the examination date utilized for the current NRC Form 396, however, a new NRC Form 396 was not submitted to Nuclear Regulatory Affairs because the individual did not inform them of the change in restriction status. Because this violation is of very low safety significance and has been entered into the licensees corrective action program as CRDR 3527072, CRDR 3526981, and CRDR 3526979, this violation is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000528; 05000529;05000530/2010005-02, Failure to Follow Procedures for Medical Examinations of Licensed Operators.

===.3

Introduction.

The inspectors identified a Severity Level IV violation of 10 CFR 55.3,===

License Requirements, for the failure of the licensee to ensure that all individuals authorized by a license to operate the controls of the facility met all the conditions of their licenses as defined in 10 CFR 55.3. Specifically, the requirement to have a biennial physical completed and certified by the facilitys physician during the continuous two year period for all licensed operators was not met for three licensed operators. Two of these licensed operators performed licensed operator duties 42 times between February 8 and March 25, 2010, after the deadline for their biennial examinations had passed.

Upon discovery, the licensee removed these individuals from watchstanding duties pending follow-up medical evaluations.

Description.

On September 9, 2010, the inspectors discovered that at least one licensed operators medical file had the Medical Reviewing Officer (MRO) or physicians signature dated 13 months after the physical was actually performed by the physicians assistant and the date placed on the NRC Form 396 Certification of Medical Examination by Facility Licensee was the date that the physicians assistant completed the hands-on portion of the physical.

The licensees medical staff entered the date the hands-on physical examination was performed by the physician assistant in the Most Recent Biennial Medical Examination block on NRC Form 396 and for updating medical qualifications in SWMS. The date required on NRC Form 396 and for updating qualifications in SWMS is the date that the physical examination was signed and certified by the MRO. According to ANS/ANSI-3.4-1983, the medical examiner is a licensed medical practitioner designated by the facility to perform nuclear licensed operator medical examinations. The MRO is the licensed medical designee and has the responsibility for certifying that the medical examination was completed in accordance with regulatory standards and that the licensed operator or initial applicant for a license meets all of the medical requirements.

A clarification is provided in NUREG-1021, Revision 9, Supplement 1, Section ES-202, page 4, which states, in part, However, the physician has the ultimate responsibility for certifying that the medical examination was conducted in accordance with the standard and that the applicant meets the medical requirements. The directions provided for this specific date block on the NRC Form 396 require the date that the medical examination is certified complete. Additionally, in 10 CFR 55.21, it states that An applicant for a

license shall have a medical examination by a physician. A licensee shall have a medical examination by a physician every two years. The physician shall determine that the applicant or licensee meets the requirements of 10 CFR 55.33(a)(1). Furthermore, a physician is defined in 10 CFR 55.4 as Physician means an individual licensed by a state or territory of the United States, the District of Columbia, or the Commonwealth of Puerto Rico to dispense drugs in the practice of medicine. The inspectors asked the Arizona Public Service (APS) medical staff to clarify the State of Arizona Statutes regarding who can dispense medicine. Their research of the State of Arizona Statutes revealed that the state scope of practice requirements for a physician assistant in Arizona under Article 3: Scope of Practice R4-17-301 (page 7), indicates that the Physician Assistant must be delegated to dispense controlled medications, and must use the supervising physician's DEA number. This would require that the licensed operator medical records, qualifications, and SWMS are updated with the date that the physician (MRO) certifies the examination is complete and as mentioned above would also be the required date to be used on the NRC Form 396 Certification of Medical Examination by Facility Licensee for initial applications or license renewals.

The licensee initiated an Apparent Cause Evaluation (ACE), CRDR 3536981, which involved a complete a review of all 136 medical records for all licensed operators at the facility. The inspectors concerns were validated during the licensees review in that the requirement to have a biennial physical completed and certified by the facilitys physician during the continuous two year period for all licensed operators was not met for three licensed operators. Two of these licensed operators performed licensed operator duties 42 times between February 8 and March 25, 2010, after the deadline for their biennial examinations had passed. Upon discovery, the licensee removed these individuals from watchstanding duties pending follow-up medical evaluations. This issue was entered into the licensees corrective action program as CRDR 3526981.

Analysis.

The failure of the licensee to ensure that all individuals authorized by a license to operate the controls of the facility met all the conditions of their licenses as defined in 10 CFR 55.3 is a performance deficiency. Specifically, the requirement to have a biennial physical completed and certified by the facilitys physician during the continuous two year period for all licensed operators (as required in 10 CFR 55.21) was not met for three licensed operators, two of which were standing watch with expired medical examinations. The finding was evaluated using the traditional enforcement process because the failure to determine an operators medical condition and general health has the potential to impact the NRCs ability to perform its regulatory function in that the NRC was not notified nor allowed an opportunity to review the specific medical conditions of the three operators whose medical qualifications had expired while they were standing watch or eligible to stand watch. Using the NRCs Enforcement Policy, Section 6.4.d, Severity Level IV violation examples, this finding is similar to example 1 which states, in part, an unqualified individual performing the functions of an operator or senior operator. This finding is being characterized as Severity Level IV because two licensed operators stood watch without a certified medical examination within the two year period that the medical examination is required to be completed and certified by the physician.

Because:

(1) the medical conditions of the two licensed operators did not change when they received their medical examinations in recent weeks;

(2) the finding did not cause

any plant events or transients while the individuals were on watch;

(3) it was not repetitive or willful; and

(4) it was entered into the corrective action program, the finding was determined to be of very low safety significance and is being treated as a Severity Level IV noncited violation consistent with the NRC Enforcement Policy. This finding has a crosscutting aspect in the area of human performance associated with the work practices component because medical staff supervisors did not oversee the biennial physical examination due dates such that nuclear safety was supported H.4(c).

Enforcement.

Title 10 CFR 55.3, License Requirements, states that a person must be authorized by a license issued by the Commission to perform the function of an operator or senior operator as defined in this part. Furthermore, 10 CFR 55.21 requires, in part, that a licensee shall have a medical examination by a physician every two years. The physician shall determine that the applicant or licensee meets the requirements of 10 CFR 55.33(a)(1).

Contrary to the above, during the past two years of this requalification cycle, the licensee failed to ensure that all individuals authorized by a license to operate the controls of the facility met all the conditions of their licenses as defined in 10 CFR 55.3. Specifically, the requirement to have a biennial physical completed and certified by the facilitys physician during the continuous two year period for all licensed operators was not met for three licensed operators. Two of these licensed operators performed licensed operator duties 42 times between February 8 and March 25, 2010, after the deadline for their biennial examinations had passed. Because this violation is of low safety significance and has been entered into the licensees corrective action program as CRDR 3526981, this violation is being treated as a noncited violation consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000528; 05000529;05000530/2010005-03, Failure to Ensure that All License Conditions Are Met for Licensed Operators.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• October 21, 2010, Unit 1, pressurizer spray control valve packing leak

• November 18, 2010, Unit 3, containment spray valve SIA-UV672 failure to open 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 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 two quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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:

• October 5, 2010, Unit 3, refueling outage shutdown risk assessment

• November 17, 2010, Units 1 and 2, startup transformer AE-NAN-X03 out of service for planned maintenance

• November 22, 2010, Unit 1, risk management actions when emergency diesel generator, train B, was removed from service

• December 8, 2010, Unit 1, emergency diesel generator, essential chiller, essential cooling water, high pressure safety injection, and essential spray pond systems, train A out of service for planned maintenance

• December 16, 2010, Units 1, 2, and 3, station blackout generators out of service for planned maintenance 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 five maintenance risk assessments and emergent work control inspection samples as defined in Inspection Procedure 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• September 16, 2010, Unit 2, emergency diesel generator, train B, following a failure of train A fuel oil transfer pump

• October 4, 2010, Unit 3, steam generator pedestal bolt failed due to stress corrosion cracking

• October 27, 2010, Unit 1, essential chiller train A essential cooling water outlet valve open further than expected

• November, 2010, Units 1 and 2, relevant indications in welds associated with the reactor vessel head vent lines

• November 3, 2010, Unit 3, emergency diesel generator train B air intake manifold cracking

• November 15, 2010, Unit 3, essential cooling water train A room cooler fan shaft nonconformance

• November 23, 2010, Unit 1, emergency diesel generator train A air intake manifold hairline crack

• December 1, 2010, Unit 2, pressurizer back-up heater banks low resistance

• December 7, 2010, Unit 3, safety injection tank 2B nitrogen leaks

• December 12, 2010, Unit 2, essential chiller train A oil temperature low

• December 20, 2010, Unit 2, elevated containment hydrogen levels The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and 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 licensee personnels 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. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also 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 11 operability evaluations inspection samples as defined in Inspection Procedure 71111.15-04

b. Findings

Introduction.

The inspectors identified a Green noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, for the failure of engineering personnel to promptly correct a condition adverse to quality associated with room cooler AHU-3MHAAZ05 blower shaft dimensions. Specifically, between July 2008 and November 2010, corrective actions for high vibrations in the Unit 3 essential cooling water system train A room cooler blower failed to promptly address the incorrect shaft dimensions at the bearing shaft interface.

Description.

On November 15, 2010, Unit 3 operations and maintenance personnel completed performance of surveillance test 73ST-9EW01, Essential Cooling Water Pumps -Inservice Test, Train A. During the surveillance, the licensee discovered that data collected on the essential cooling water system train A room cooler blower AHU-3MHAAZ05 was in the high alarm range. The specified safety function of the room cooler is to maintain the essential cooling water pump room within design temperature limits. Although the immediate operability determination supported declaring the equipment operable, a subsequent prompt operability determination performed by engineering resulted in the equipment being declared inoperable. On November 16, 2010 the essential cooling water system, train A, was declared inoperable and Unit 3 entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> technical specification shutdown action statement. Blower AHU-3MHAAZ05 outboard bearing was replaced and the fan was returned to service on November 18, 2010.

In June 2007, condition notification report 4051 was issued by engineering personnel for vibration trending due to AHU-3MAAZ05 reaching the alert range. In April 2008, Palo Verde Action Request (PVAR) 3161162 documented increased vibration trends on the blower. This issue was documented again in PVAR 3168434 in May 2008. Corrective maintenance work order 3161812 was generated to inspect the blower components.

Corrective maintenance work order 3168911 was generated in June 2008 and implemented in July 2008 to replace the outboard bearing. The bearing was replaced and the fan was returned to service. Following the bearing replacement, PVAR 3202619 was generated documenting the condition of the blower shaft. The technician performing the bearing replacement noted that the shaft diameter was not consistent along the axial length of the inner bearing race. The technician also noted that the shaft was not concentric. Operations personnel performed an immediate operability determination to assess the impact of this nonconforming condition. Condition report disposition request (CRDR) 3202957 was generated to evaluate the identified condition adverse to quality. In December 2008, condition report action item (CRAI) 3212753 completed evaluation of potential corrective actions and determined no additional corrective actions were required.

In April 2009, condition notification report 4243 was issued by engineering personnel for vibration trending due to AHU-3MAAZ05 reaching the alert range. In July 2009, PVAR 335177 documented increased vibrations on the outboard bearing. A corrective maintenance work order was generated to adjust the set screws on the inner race that secure the outboard bearing in the correct position. Corrective maintenance work order 3352188 was also generated to replace the blower shaft. In February 2010, a new corrective maintenance work order again adjusted the set screws on the inner bearing race. In August 2010, condition notification report 4243 was closed due to acceptable vibration levels for several consecutive months. In November 2010, bearing and shaft vibrations forced the equipment to be removed from service for bearing replacement.

The nonconforming shaft dimension was first identified in July 2008. A full year elapsed between the time this condition adverse to quality was first identified and the decision was made to replace the shaft in July 2009. Procurement of a new shaft had not occurred by the November 2010 failure. The air handling unit was supplied to the site as

a complete unit. Consequently, the licensee did not have specific drawings for individual components within the unit. A replacement shaft was not listed on the parts list provided in the vendor technical document. The lack of specific procurement information was not discovered until May 2010. The licensee is currently pursuing obtaining the required technical data to purchase a new shaft, or machine a shaft on site.

Analysis.

The inspectors concluded that the failure of engineering personnel to promptly correct a condition adverse to quality with essential cooling water room cooler blower shaft was a performance deficiency. The finding was more than minor because it affected the equipment performance attribute of the Mitigating Systems cornerstone, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using Manual Chapter 0609.04, Phase 1 - Initial Screening and Characterization of Findings, the inspectors determined that the finding had a very low safety significance because the finding did not result in a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. The inspectors determined this finding had a crosscutting aspect in the area of human performance associated with the resources component because the licensee failed to ensure that personnel, equipment, and procedure were available and adequate to assure nuclear safety by minimizing long standing equipment H.2(a).

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. Procedure 01PR-0AP04, Corrective Action Program, Revision 5, step 3.1.3.1, stated, in part, that adverse conditions and conditions adverse to quality shall be promptly corrected. Contrary to the above, between July 2008, and November 2010, engineering personnel did not take corrective actions for an identified condition adverse to quality. Because the finding is of very low safety significance and has been entered into the licensees corrective action program as PVAR 3559219, this violation is being treated as a noncited violation consistent with Section 2.3.2 of the Enforcement Policy: NCV 05000530/2010005-04, Failure to Promptly Correct a Condition Adverse to Quality for the Essential Cooling Water Room Cooler.

1R18 Plant Modifications

Temporary Modifications

a. Inspection Scope

To verify that the safety functions of important safety systems were not degraded, the inspectors reviewed the following temporary modifications identified as:

• October 15, 2010, Unit 3, temporary cooling towers to nuclear cooling water heat exchanger for plant cooling water system outage

• October 27, 2010, Unit 2, pressurizer backup heater setpoint change

The inspectors reviewed the temporary modifications 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 two samples for temporary plant modifications as defined in Inspection Procedure 71111.18-05.

b. Findings

No findings were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

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

• September 16, 2010, Unit 2, emergency diesel generator, train A, following corrective maintenance for the failure of the fuel oil transfer pump

• October 24, 2010, Unit 3, auxiliary spray valve control circuit from remote shutdown panel

• November 18, 2010, Unit 3, essential cooling water train A room cooler returned to service following maintenance

• December 10, 2010, Unit 1, emergency diesel generator train A out of service for planned maintenance

• December 11, 2010, Unit 1, atmospheric dump valve ADV-179 low pressure nitrogen supply check valve 1PSEV334 soft seat replacement

• December 16, 2010, Units 1, 2, and 3, station blackout generators out of service for planned maintenance

• December 20, 2010, Unit 2, atmospheric dump valve ADV-185 nitrogen accumulator safety relief valve 2JSGBPSV0322 replacement

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 (as applicable):

• 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 postmaintenance 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 seven postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

c. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 3 refueling outage, conducted October 2, through November 14, 2010, to confirm 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. During the refueling outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• Shutdown and cooldown, including portions of the cooldown process to verify that technical specification cooldown restrictions are followed, primary containment walkdown immediately after shutdown to inspect plant areas which are inaccessible during power operations

• 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 primary containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing

• 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 sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors 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.

• October 7, 2010, Unit 1, recirculation actuation system line fill verification

• October 11, 2010, Unit 2, moderator temperature coefficient testing

• October 27, 2010, Unit 3, full flow inservice test of high pressure safety injection pump train A

• November 1, 2010, Unit 2, containment purge valve leak rate testing

• November 5, 2010, Unit 3, local leak rate testing on penetration 53, fuel transfer tube quick operating closure device Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Data Submission Issue

a. Inspection Scope

The inspectors performed a review of the performance indicator data submitted by the licensee for the third quarter 2010 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program.

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

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - Auxiliary Feedwater System

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index for Units 1, 2, and 3 - auxiliary feedwater system performance indicator for the period from the fourth quarter 2009 the through the third quarter 2010. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, mitigating systems performance index derivation reports, and NRC integrated inspection reports for the period of October 1, 2009, through September 30, 2010, 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 Nuclear Energy Institute 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 during this inspection are listed in the attachment.

These activities constitute completion of three mitigating systems performance index heat removal system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Residual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for the period from the fourth quarter 2009 the through the third quarter 2010. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. 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 October 1, 2009 through September 30, 2010, 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 during this inspection are listed in the attachment.

These activities constitute completion of three mitigating systems performance index residual heat removal systems sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the fourth quarter 2009 the through the third quarter 2010. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, was used. 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 October 1, 2009, through September 30, 2010, 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.

These activities constitute completion of three mitigating systems performance index cooling water system samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline 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.

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. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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.

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. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

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 July 1 through December 31, 2010, although some examples expanded beyond those dates where the scope of the trend warranted. 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 one single semi-annual trend review inspection sample as defined in Inspection Procedure 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the below listed issue for a more in-depth review. 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:

• October 12-13, 2010, Unit 3, seven containment spray nozzles partially obstructed with boric acid residue Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings were identified.

.5 In-depth Review of Operator Workarounds

a. Inspection Scope

The inspectors conducted a cumulative review of operator workarounds for Units 1, 2, and 3 and assessed the effectiveness of the operator workaround program to verify that the licensee is:

(1) identifying operator workaround problems at an appropriate threshold;

(2) entering them into the CAP; and

(3) identifying and implementing appropriate corrective actions. The review included walkdowns of the control room panels, interviews with licensed operators and reviews of the control room discrepancies log, the lit annunciators log, the operator workaround list, the operator burdens list, operations concerns list, the operator challenges tracking system, and site performance metrics for operator burdens, lit annunciators, control room discrepancies, and long term tagouts These activities constitute completion of one operator workaround program inspection sample as defined in Inspection Procedure 71152-05.

b. Findings

No findings were identified.

4OA3 Event Follow-up

.1 The inspectors reviewed the below listed event for plant status and mitigating actions to:

(1) collect information necessary to communicate event details to NRC management for determination of the appropriate agency response;

(2) observe plant system parameters and status;

(3) evaluate licensee actions; and

(4) confirm that the licensee properly classified the event in accordance with emergency action level procedures and made timely notifications to NRC and state/governments, as required.

• September 15, 2010, Unit 2 emergency diesel generator train A fuel oil transfer pump failure

• October 12, 2010, Units1, 2, and 3 response to suspicious device in vehicle entering site property at Security Owner Controlled Area checkpoint

• November 8, 2010, Units 1, 2, and 3 site card reader computer system failure

4OA5 Other Activities

.1 Temporary Instruction 2515/172, Reactor Coolant System Dissimilar Metal Butt Welds

(Closed)

Temporary Instruction 2515/172 was previously performed at Palo Verde Nuclear Generating Station, Unit 3, during Refueling Outage U3R14. The results of that inspection are documented in Inspection Report 05000530/2009003.

a. Inspection Scope

Portions of Temporary Instruction 2515/172 were performed at Palo Verde Nuclear Generating Station, Unit 3, during Refueling Outage U3R15. Specific documents reviewed during this inspection are listed in the attachment. This unit has the following dissimilar metal butt welds.

• Two 12-inch pressurizer surge line nozzles, one each on the pressurizer and hot leg sides. Both were mitigated during previous outages using a weld overlay process and both were categorized as Category F following the weld overlay process

• Four 8-inch pressurizer safety nozzles all mitigated during previous outages using a weld overlay process and classified as Category F after the weld overlay

• Two 16-inch shutdown-cooling nozzles, both of which were mitigated using a weld overlay process during the previous outage and classified as Category F after the weld overlay

• Four 14-inch safety injection nozzles classified as Category E. These nozzles have not been mitigated. No plans have been made to mitigate these nozzles at this time

• One 4-inch pressurizer spray nozzle and two 3-inch pressurizer spray nozzles.

The two 3-inch nozzles are categorized as Category K. The 4-inch nozzle was mitigated using a weld overlay process during a previous outage and is Category F

• Three 2-inch drain line nozzles, each classified as Category K

• Two additional 2-inch line nozzles, one for letdown and one for charging, each classified as Category K i.

Licensees Implementation of the Materials Reliability Program (MRP-139)

Baseline Inspections (03.01)

(a) MRP-139 baseline inspections: This portion of Temporary Instruction 2515/172 was documented in NRC Integrated Inspection Report 05000530/2009003 in Section 4OA5.2 for the pressurizer and hot leg welds. Specific documents reviewed for this portion are listed in the attachment to the above inspection report. The inspectors observed performance and reviewed records of nondestructive examination activities associated with dissimilar metal butt welds exposed to temperatures equivalent to the cold leg during Refueling Outage U3R15.

The baseline inspections of the pressurizer dissimilar metal butt welds were completed prior to the December 2007 deadline.

(b) The licensee did not take any deviations from the baseline inspection requirements of MRP-139, and all other applicable dissimilar metal butt welds were scheduled in accordance with MRP-139 guidelines.

ii. Volumetric Examinations (03.02)

(a) The inspectors directly observed and reviewed records of nondestructive examinations performed on the Unit 3 mitigated pressurizer surge line, one pressurizer safety valve, and the two shutdown cooling nozzles in NRC Integrated Inspection Report 05000530/2009003 Section 4OA5.2.

Documents reviewed for the inspection can be found in the attachment to the above inspection report. The inspectors directly observed and reviewed records of nondestructive examinations performed on the Unit 3 safety injection nozzles during Refueling Outage U3R15. The inspectors concluded that the ultrasonic examination for these welds were done in accordance with ASME Code,Section XI, Supplement VIII Performance Demonstration Initiative requirements regarding personnel, procedures, and equipment qualifications. No relevant conditions were identified during those examinations.

(b) Inspectors directly observed and reviewed records of nondestructive examination performed on the Unit 3 mitigated pressurizer surge line and one pressurizer safety valve in NRC Integrated Inspection Report 05000530/2009003 Section 4OA5.2. Documents reviewed for the inspection can be found in the attachment to the above inspection report.

Inspectors directly observed and reviewed records of nondestructive examination performed on the mitigated Loop 1 shutdown-cooling nozzle during Refueling Outage U3R15. Inspection coverage met the requirements of MRP-139 and no relevant conditions were identified.

(c) Inspectors reviewed the certification records of examination personnel for those personnel that performed the examinations of the nozzles. All personnel records showed that they were qualified under the EPRI Performance Demonstration Initiative. For the pressurizer surge line and one safety valve, this review was documented in NRC Integrated Inspection Report 05000530/2009003.

(d) No deficiencies were identified during the nondestructive examinations for the pressurizer surge line and safety nozzle as documented in NRC Integrated Inspection Report 05000530/2009003. No deficiencies were identified during the nondestructive examinations for the shutdown cooling nozzles or the safety injection nozzles.

iii. Weld Overlays (03.03)

Weld overlays on the Unit 3 shutdown cooling nozzles on the hot legs were performed during Refueling Outage U3R14 in the spring 2009. This portion of the temporary instruction was completed and documented in NRC Integrated

Inspection Report 05000530/2009003, Section 4OA5.2. Documents reviewed for the inspection can be found in the attachment to the above inspection report.

iv.

Mechanical Stress Improvement (03.04)

The licensee did not employ a mechanical stress improvement process.

v.

Inservice Inspection Program (03.05)

The licensees MRP-139 program is part of their Alloy 600 program and future inspections of the various dissimilar metal butt welds are in accordance with the MRP-139 requirements. All the welds in the MRP-139 in-service inspection program are appropriately categorized in accordance with MRP-139. The in-service inspection frequencies are consistent with the in-service inspection frequencies called for by MRP-139.

b. Findings

No findings were identified.

.2 (Open) NRC Temporary Instruction 2515/177, Managing Gas Accumulation in

Emergency Core Cooling, Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

As documented in Sections 1R04, the inspectors confirmed the acceptability of the described licensees actions. This inspection effort counts towards the completion of Temporary Instruction 2515/177 which will be closed in a later inspection report.

.3 (Open) Unresolved Item Related to Fire Damper Surveillance Frequencies

a. Inspection Scope

The inspectors performed an in-office inspection of the licensee's active fire protection features to verify that automatic gaseous suppression systems were installed, tested, and maintained in accordance with the National Fire Protection Association (NFPA) code of record or approved deviations. The inspectors reviewed the surveillance requirements for carbon dioxide (CO2) and Halon flooding systems.

b. Findings

Introduction.

The inspectors identified an unresolved item associated with the acceptability of a change made by the licensee to the approved fire protection program.

Specifically, the licensee made changes to the NRC-approved gaseous fire suppression system damper surveillance frequencies by increasing the period between surveillance testing from 18 months to 54 months. This unresolved item will address:

(1) the acceptability of using statistical or performance-based analysis methodologies at a plant licensed under deterministic rule (10 CFR 50.48(b)) using the provisions for a self-approved change under the standard license condition; and

(2) the technical bases used

by the licensee to conclude that the change did not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

Description.

In November 2009, the licensee initiated a change to the Technical Requirements Manual (TRM) surveillance requirements (TSR) associated with fire dampers in CO2 and Halon gaseous fire suppression systems (TSR 3.11.103.5 and TSR 3.11.106.5, respectively). These systems were used to protect 11 fire areas in each unit. The change to the surveillance requirements extended the functional testing frequencies for the ventilation dampers and their associated actuation devices from 18 months, as approved by the NRC, to 54 months.

License Condition 2.C.(7), 2.C.(6), and 2.F for Units 1, 2, and 3, respectively, allows the licensee to make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

Licensing Document Change Request 09-R003, Revise TRM surveillance requirements for fire damper testing, contained the Fire Protection Change Regulatory Review Checklist and an evaluation of the proposed change performed under the guidance of Generic Letter 86-10, Implementation of Fire Protection Requirements. The checklist contained screening questions used by the licensee to determine the impact of a potential change on their approved fire protection program, and whether these potential changes would require prior NRC approval before implementation, including whether the proposed change would adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

Engineering Evaluation 3304353 documented the technical basis for the surveillance frequency extensions. As part of the evaluation, the licensee used some of the guidance in Electric Power Research Institute (EPRI) Technical Report 1006756, Fire Protection Equipment Surveillance Optimization and Maintenance Guide, as a basis for the change. The inspectors determined that the methodology contained in this EPRI technical report have not been endorsed by the NRC. Using the statistical analysis methods of the EPRI technical report, the licensee concluded that the change did not have a statistically significant impact on the failure rates of the damper systems, did not adversely affect the ability to achieve and maintain safe shutdown, and, therefore, could be made without NRC approval.

The inspectors identified the following concerns regarding the technical bases used by the licensee to conclude that the change did not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire:

1. The methodology in EPRI Technical Report 1006756 was intended to establish a

performance-based maintenance and testing program for fire protection systems.

However, the licensee did not adopt important portions of the EPRI program that made it performance-based. Specifically, the licensee did not establish a monitoring program to identify whether the expected (i.e., extrapolated) reliability was being met after extending the testing interval, nor was any action threshold

established to address unacceptable reliability identified by future testing as described in the EPRI technical report.

2. The licensees evaluation did not address the potential increase in the probability

of non-suppression for a fire in one of the areas protected by these gaseous suppression systems caused by the increased probability of one or more dampers failing to close created by the change to the test frequency. Failure of a damper to close and isolate the fire could prevent reaching a high enough concentration of CO2 or Halon to suppress a fire. Specifically, the licensees historical data demonstrated 99 percent reliability for dampers associated with the gaseous suppression systems, but the change in question established the new testing frequency based on an extrapolated 95 percent reliability. The evaluation credited manual suppression by the fire brigade, but the inspectors questioned how the fire brigade would know the fire was not suppressed, since the areas would be inaccessible, and entry to check for the continued presence of a fire would further reduce the concentration of suppressant. The failure to address the change in non-suppression probability impacted the bases for the NRC approving a deviation:

• The licensees fire confinement evaluation stated that an unsuppressed fire in either Fire Zone 10A or Fire Zone 10B could challenge the 2-hour rated fire wall separating the rooms that was an NRC-approved deviation from the requirement to have a 3-hour fire-rated wall. The two rooms are in different fire areas and contain equipment from different safe shutdown trains, so challenging that fire barrier could result in loss of safe shutdown capability. The inspectors were concerned that the evaluation did not address failure of a fire damper resulting in insufficient concentrations of Halon for the gaseous suppression system to suppress the fire.

• The licensee did not consider an updated plant analysis which may have invalidated the basis for a deviation identified in the original fire protection program. The NRC accepted a fire wall with a 2-hour rating between Fire Zone 10A and Fire Zone 10B based, in part, on the fire loading in both fire zoned being moderate. Reanalysis of combustible loading reclassified Fire Zone 10B to have a high fire loading.

• Further, this deviation was approved with consideration that the associated gaseous suppression systems were being tested at the NRC approved frequency. National Fire Protection Association (NFPA) codes NFPA-12-1973, Carbon Dioxide Extinguishing Systems, Section 171 and NFPA 12A-1973, Halogenated Fire Extinguishing Agent Systems -

Halon 1301, Section 1710 require that these systems shall be thoroughly inspected and tested annually for proper operation. The NRC, as the authority having jurisdiction under NFPA codes, approved a code alternative to perform this testing at 18-month intervals as part of the approved fire protection program.

The licensee did not extend testing incrementally to verify that the expected reliability was being met prior to extending the test frequency to the full 54 months.

In addition to the above concerns, the inspectors questioned the acceptability of using statistical or performance-based analysis methodologies at a plant licensed under a deterministic rule (10 CFR 50.48(b)) using the provisions for a self-approved change under the standard license condition. Specifically, the staff questioned the technical basis for the method used to extrapolate equipment reliability based on an assumed extended test frequency. Further, the licensees historical data demonstrated 99 percent reliability for dampers associated with the gaseous suppression systems, but the change in question established the new testing frequency based on an extrapolated 95 percent reliability. Neither the licensees change evaluation nor the EPRI technical report provided a basis for why this value was acceptable or met the requirements of the approved fire protection program. This change appeared to be a reduction in the margins that could affect safe shutdown capability, but was not assessed as such in the change evaluation.

Regulatory Guide 1.189, Fire Protection for Nuclear Power Plants, Revision 2, Regulatory Position 1.8.1.2 states in part that the phrase not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire, means to maintain sufficient safety margins. It goes on to state that with sufficient safety margins, codes and standards or their alternatives approved for use by the NRC are met, and safety analyses acceptance criteria in the licensing basis are met or proposed revisions provide sufficient margin to account for analysis and data uncertainty. The inspectors were concerned that the reduction of safety margins could invalidate the basis for deviations accepted in the approved fire protection program.

The licensee documented this issue in CRDR 3493945. This issue is unresolved pending review by the staff to assess whether this type of change is permitted under the standard fire protection license condition. It is also unresolved pending additional information from the licensee on items 1-3 above. Therefore, this issue is being treated as an unresolved item: URI 05000528/05000529/05000530-2010005-05, Assess Acceptability of Licensee-Approved Change to Fire Damper Test Frequency.

4OA6 Meetings

Exit Meeting Summary

On October 15, 2010, the inspectors presented the inspection results of the review of in-service inspection activities to Mr. J. Hesser, Vice President Engineering, and other members of the licensee staff. The licensee acknowledged the issues presented. All proprietary information was returned or disposed of upon completion of the inspection.

The inspectors discussed the results of the licensed operator requalification program inspection with Mr. J. Waid, Director of Operations Training, and other members of the licensee's staff on September 10, 2010. The lead inspector obtained the final biennial examination results and telephonically exited with Mr. R. Bement, Vice President of Nuclear Operations, on

December 14, 2010. The licensee representatives acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.

On January 5, 2011, the inspectors presented the inspection results to Mr. D. Mims, Vice President, Regulatory Affairs and Plant Improvement, and other members of the licensee staff.

The licensee acknowledged the issues presented. All proprietary information was returned or disposed of upon completion of the inspection.

On January 7, 2011, the inspectors presented the inspection results to Ms. M. Lacal, General Manager Emergency Services and Support, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as noncited violations.

• 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, on October 6, 2010, the licensee did not preclude repetition of the failure of valve 3SI-V-0672 to fully open. A licensee valve services technician heard an unexpected noise when stroking open containment spray valve 3JSI-V-0672 and the attempt to open the valve was aborted. Subsequent inspection of the valve body and internals revealed that previous corrective actions implemented between April 16, 2009 and May 18, 2009 had been inadequate to prevent recurrence of the valves failure to fully open. This finding was entered into the licensees corrective action program as PVAR 3548317. This finding is of very low safety significance because it did not result in a loss of safety function, and actual loss of safety function of a single train for greater than it technical specification allowed outage time, or screen as potentially risk significant due to seismic, flooding, or severe weather initiating event.

• 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, between December 5, 2007, and October 13, 2010, the licensee did not preclude repetition of a significant condition adverse to quality. Specifically, corrective actions to prevent recurrence of seven Unit 3 containment spray nozzles obstruction due to boric acid residue were inadequate. This finding was entered into the licensees corrective action program as PVAR 3548317. This finding is of very low safety significance because it did not result in a loss of safety function, and actual loss of safety function of a single train for greater than it technical specification allowed

outage time, or screen as potentially risk significant due to seismic, flooding, or severe weather initiating event.

• Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, 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. Contrary to the above, the licensee failed to ensure that activities affecting quality were prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances. Specifically, in May 2009, work instructions used to implement design modifications and conduct design validation testing for auxiliary spray valve auxiliary spray valve 3J-CHB-HV-0203 were inadequate. In October 2010, the auxiliary spray valve control circuit was restored to plant design and retested satisfactorily. The licensee entered the inadequate design validation testing following a design modification work order into their corrective action program as PVAR 3548317. The finding had a very low safety significance because the finding only affected the ability to achieve and maintain cold shutdown.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Barnes, Director Regulatory Affairs

B. Bement, Vice President Nuclear Operations

M. Brannin, Engineering Programs

J. Cadogan, Engineering Director Program and Support

J. Clark, Project Engineer Strategic Projects

L. Cortopasi, Plant Manager

E. Fernandez, Engineering Programs

J. Gaffney, Director Radiation Protection

B. Haley, In-service Inspection Section Lead

D. Hansen, Engineering

J. Hesser, Vice President Engineering

M. McGhee, Operations

D. Mims, Vice President Nuclear Regulatory Assurance

J. Ruoff, Engineering Programs

B. Thiele, Department Leader Program Engineering

T. Trieckel, Nuclear Projects

M. Webb, Compliance Section Leader

M. Winsor, Director Strategic Projects

J. Waid, Director Operations Training

G. Brown, Operations Training Section Leader

T. Weber, Regulatory Affairs Dept. Leader

T. Miller, Nuclear Assurance Assessor for Training Oversight

P. McSparran, Dept. Leader Operations Training

G. Cameron, Fire Protection Supervisor

M. Lacal, General Manager Emergency Services and Support

G. Michael, Licensing Engineer

R. Stroud, Licensing Section Leader

NRC Personnel

J. Bashore, Senior Resident Inspector (Temp)

G. Repogle, Senior Reactor Analyst, Region IV

M. Baquera, Resident Inspector

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000528; 529; Assess Acceptability of Licensee-Approved Change to Fire URI 530-2010-005-05 Damper Test Frequency (Section 4OA5)

Opened and Closed

05000528; 529; Failure to Maintain Operator Licensing Examination Integrity NCV 530/2010-005-01 (Section 1R11)

05000528; 529; Failure to Follow Procedures for Medical Examinations of Licensed NCV 530/2010-005-02 Operators (Section 1R11)

05000528; 529; Failure to Ensure All License Conditions Are Met for Licensed SLIV 530/2010-005-03 Operators (Section 1R11)

05000530/2010- Failure to Promptly Correct a Condition Adverse to Quality for the NCV 005-04 Essential Cooling Water Room Cooler (Section 1R15)