IR 05000528/2007004

IR 05000528-07-004, 05000529-07-004, 05000530-07-004; 07/01/07 - 09/30/07; Palo Verde Nuclear Generating Station, Units 1, 2, and 3; Force-On-Force Exercise Eval., Follow-up of Events

ML073180736
Person / Time
Site:	Palo Verde
Issue date:	11/08/2007
From:	Thomas Farnholtz NRC/RGN-IV/DRP/RPB-D
To:	Edington R Arizona Public Service Co
References
IR-07-004
Download: ML073180736 (36)

Text

ber 08, 2007

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2007004, 05000529/2007004, AND 05000530/2007004

Dear Mr. Edington:

On September 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility. The enclosed integrated report documents the inspection findings, which were discussed on October 3, 2007, with you and other members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents one NRC identified finding and one self-revealing finding which involved violations of NRC requirements. One of these findings was evaluated under the risk significance determination process as having very low safety significance (Green). One finding was not suitable for evaluation under the significance determination process; however, it was determined to be of very low safety significance by NRC management review. Because of the very low safety significance of these violations and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations consistent with Section VI.A of the NRC Enforcement Policy. If you contest these 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 DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection

Arizona Public Service Company -2-in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Thomas R. Farnholtz, Chief Project Branch D Division of Reactor Projects Dockets: 50-528 50-529 50-530 Licenses: NPF-41 NPF-51 NPF-74

Enclosure:

NRC Inspection Report 05000528/2007004, 05000529/2007004, and 05000530/2007004 w/Attachment: Supplemental Information

REGION IV==

Dockets: 50-528, 50-529, 50-530 Licenses: NPF-41, NPF-51, NPF-74 Report: 05000528/2007004, 05000529/2007004, 05000530/2007004 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location: 5951 S. Wintersburg Road Tonopah, Arizona Dates: July 1 through September 30, 2007 Inspectors: J. Bartleman, Reactor Inspector, Region III J. Bashore, Resident Inspector M. Bloodgood, Project Engineer M. Catts, Resident Inspector S. Makor, Reactor Inspector D. Melendez-Colon, Reactor Inspector, Region III J. Melfi, Resident Inspector J. Reynoso, Reactor Inspector A. Sanchez, Resident Inspector G. Warnick, Senior Resident Inspector Approved By: Thomas R. Farnholtz, Chief, Project Branch D Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000528/2007004, 05000529/2007004, 05000530/2007004; 07/01/07 - 09/30/07; Palo

Verde Nuclear Generating Station, Units 1, 2, and 3; Force-On-Force Exercise Eval., Follow-up of Events.

This report covered a 3-month period of inspection by resident inspectors. The inspection identified two findings. The significance of most findings is indicated by their color (Green,

White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management's review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.

Cornerstone: Initiating Events

Green.

A self-revealing noncited violation of Technical Specification 5.4.1.a was identified for the failure of operations personnel to follow procedures to establish appropriate conditions prior to lowering pressurizer level, resulting in a partial vacuum condition in the reactor coolant system. Specifically, on July 7, 2007, operations personnel failed to perform Procedure 40OP-9ZZ06, "Mode 5 Operations," Revision 15,

Step 5.3.16.9, prior to lowering pressurizer level to 25 percent resulting in a partial vacuum condition in the reactor coolant system as the pressurizer was drained. This issue was entered into the licensees corrective action program as Condition Report/Disposition Request 3038774.

The finding is greater than minor because it is associated with the human performance attribute of the initiating events cornerstone and affects the associated cornerstone objectives to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using the Manual Chapter 0609, "Significance Determination Process," Appendix G, "Shutdown Operations Significance Determination Process," Checklist 4, a phase 2 analysis is required since the finding increased the likelihood of a loss of reactor coolant system inventory and could have impacted the operability of reactor coolant system level instrumentation. Manual Chapter 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria," was used since the Significance Determination Process methods and tools were not adequate to determine the significance of the finding. The finding is determined to have very low safety significance through management review because the finding does not degrade the licensee's ability to terminate a leak path, add reactor coolant system inventory, recover decay heat removal once it is lost, or establish an alternate core cooling path. Given the reactor coolant system drain rate, it would have taken over 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> to drain the reactor coolant system to midloop conditions, and due to the low decay heat load, the time to boil was greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This finding has a crosscutting aspect in the area of human performance, associated with work practices, since the pre-job brief and self/peer checking for the evolution were inadequate (H.4(a)). (Section 4OA3)

Cornerstone: Emergency Preparedness

Green.

The inspectors identified a noncited violation of 10 CFR 50.54(q) for failure of the emergency planning organization's emergency exercise critique process to identify for correction an emergency plan weakness associated with a risk significant planning standard. Specifically, during the critique of the Emergency Preparedness portion of the August 22, 2007, Force-On-Force exercise, the licensee failed to identify for correction an event classification weakness. The weakness occurred during the exercise when the shift manager did not recognize a credible security threat notification was made to the facility. As a result, the shift manager did not declare a Notice of Unusual Event as required by EPIP-99, Appendix A, "Emergency Actions Levels - EAL 7-1." This issue was entered into the licensees corrective action program as Condition Report/Disposition Request 3056153.

This finding is greater than minor because it is associated with the Emergency Response Organization Performance attribute of the Emergency Preparedness Cornerstone and affects the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. In accordance with Manual Chapter 0609,

"Significance Determination Process," Appendix B, Emergency Preparedness Significance Determination Process, this finding is determined to have very low safety significance because, although it was a failure to comply with NRC requirements, it did not involve the risk-significant aspects of a planning standard as defined in Manual Chapter 0609, Appendix B, Section 2.0; and was not a planning standard functional failure because the critique failure occurred in a small scale drill with limited emergency response organization participation and evaluation. This finding has a crosscutting aspect in the area of problem identification and resolution associated with corrective action program because the threshold for identifying issues was not sufficiently low.

Specifically, the emergency planning evaluator did not recognize the shift manager's failure to make the Notice of Unusual Event classification during the Force-On-Force exercise. Therefore, the exercise critique did not identify and correct the event classification deficiency as required (P.1(a)). (Section 1EP7)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period shutdown for refueling Outage 1R13. The unit was restarted on July 14, 2007, achieved essentially full power on July 23, and remained there for the duration of the inspection period.

Unit 2 operated at essentially full power until July 26, 2007, when power was reduced to 40 percent to repair a main condenser tube leak. On July 28, following repairs to the main condenser, the unit returned to essentially full power and remained there for the duration of the inspection period.

Unit 3 operated at essentially full power until July 21, 2007, when power was reduced to 80 percent to repair a bearing oil leak on heater drain Pump A. Following pump replacement, the unit was returned to essentially full power on July 23. On September 27, power was reduced to 40 percent to repair a main condenser tube leak. On September 29, the unit was shutdown for refueling Outage 3R13. At the end of the inspection period, the unit was in Mode

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Readiness For Impending Adverse Weather Conditions On July 30, 2007, the inspectors completed a review of the licensee's readiness for impending adverse weather involving severe thunderstorm and high wind warnings.

The inspectors reviewed the licensees actual performance for the emergent developing weather conditions. Following the observation of severe weather approaching the site, the inspectors proceeded to the Unit 3 control room. Inspectors verified operations personnel appropriately entered the abnormal operating procedure for severe weather.

The inspectors also verified that all maintenance activities were reviewed for emergent plant risk (see Section 1R13) and restoration, and appropriate protected area announcements were made to advise site personnel to take shelter.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown The inspectors:

(1) walked down portions of the two below listed risk important systems and reviewed plant procedures and documents to verify that critical portions of the selected systems were correctly aligned; and

(2) compared deficiencies identified during the walk down to the licensee's Updated Final Safety Analysis Report (UFSAR) and corrective action program (CAP) to ensure problems were being identified and corrected.

• July 25, 2007, Unit 1, emergency diesel generator (EDG) Train B while EDG Train A was out of service for preplanned maintenance

• August 23, 2007, Unit 2, containment spray Train B while Train A was out of service for preplanned maintenance Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

Complete Walkdown The inspectors:

(1) reviewed plant procedures, drawings, the UFSAR, technical specifications (TSs), and vendor manuals to determine the correct alignment of the essential and non-essential auxiliary feedwater (AFW) systems;

(2) reviewed outstanding design issues, operator work arounds, and UFSAR documents to determine if open issues affected the functionality of the AFW systems; and

(3) verified that the licensee was identifying and resolving equipment alignment problems.

• July 16, 2007, Unit 2, essential AFW system Trains A and B

• July 17, 2007, Unit 2, non-essential AFW system Train N Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

Quarterly Inspection The inspectors walked down the seven below listed plant areas to assess the material condition of active and passive fire protection features and their operational lineup and readiness. The inspectors:

(1) verified that transient combustibles and hot work activities were controlled in accordance with plant procedures;

(2) observed the condition of fire detection devices to verify they remained functional;

(3) observed fire suppression systems to verify they remained functional and that access to manual actuators was unobstructed;

(4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory condition;

(5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems) were in a satisfactory material condition;

(6) verified that adequate compensatory measures were established for degraded or inoperable fire protection features and that the compensatory measures were commensurate with the significance of the deficiency; and

(7) reviewed the UFSAR to determine if the licensee identified and corrected fire protection problems.

• July 12, 2007, Unit 3, fuel building 100 foot, 120 foot, and 140 foot elevations

• July 27, 2007, Unit 2, spray pond pump house, 108 foot elevation

• July 30, 2007, diesel and electrical driven fire pump rooms

• August 10, 2007, Unit 3, auxiliary building, 40 foot, 52 foot, 70 foot, and 88 foot elevations

• August 14, 2007, Unit 3, spray pond pump house, 108 foot elevation

• September 6, 2007, Unit 2, control building, 74 foot, 100 foot, 120 foot, 140 foot, and 160 elevations

• September 6, 2007, Unit 3, main steam support structure, 80 foot, 100 foot, 120 foot, and 140 foot elevations Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed seven samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors:

(1) reviewed the UFSAR, the flooding analysis, and plant procedures to assess seasonal susceptibilities involving external flooding;

(2) reviewed the UFSAR and CAP to determine if the licensee identified and corrected flooding problems;

(3) inspected underground bunkers/manholes to verify the adequacy of

(a) sump pumps,

(b) level alarm circuits,

(c) cable splices subject to submergence, and

(d) drainage for bunkers/manholes;

(4) verified that operator actions for coping with flooding can reasonably achieve the desired outcomes; and

(5) walked down the two below listed areas to verify the adequacy of:

(a) equipment seals located below the floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain lines and sumps,

(e) sump pumps, level alarms, and control circuits, and

(f) temporary or removable flood barriers.

• July 30, 2007, Unit 1, spray pond Pump B

• July 30, 2007, Units 1, 2, and 3, EDG fuel oil storage tank vaults Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On August 22, 2007, the inspectors observed testing and training of senior reactor operators and reactor operators (ROs) to identify deficiencies and discrepancies in the training, to assess operator performance, and to assess the evaluator's critique. The training scenario involved three events including:

(1) failure of volume control tank level instrument;

(2) EDG actuation on loss of Class 1E Bus; and

(3) loss of offsite power.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the below listed maintenance activity to:

(1) verify the appropriate handling of structure, system, and component (SSC) performance or condition problems;

(2) verify the appropriate handling of degraded SSC functional performance;

(3) evaluate the role of work practices and common cause problems; and

(4) evaluate the handling of SSC issues reviewed under the requirements of the maintenance rule, 10 CFR Part 50 Appendix B, and the TSs.

• August 20, 2007, Unit 1, EDG Train A voltage permissive relay failure, as documented in Corrective Maintenance Work Order (WO) 3043473 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

Risk Assessment and Management of Risk The inspectors reviewed the two below listed assessment activities to verify:

(1) performance of risk assessments when required by 10 CFR 50.65 (a)(4) and licensee procedures prior to changes in plant configuration for maintenance activities and plant operations;

(2) the accuracy, adequacy, and completeness of the information considered in the risk assessment;

(3) that the licensee recognizes, and/or enters as applicable, the appropriate licensee-established risk category according to the risk assessment results and licensee procedures; and

(4) the licensee identified and corrected problems related to maintenance risk assessments.

• August 1, 2007, Unit 2, risk assessment and management during scheduled EDG Train A outage

• August 28, 2007, Units 1, 2 and 3, risk assessment and management during scheduled station blackout Generator 1 outage Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

Emergent Work Control The inspectors:

(1) verified that the licensee performed actions to minimize the probability of initiating events and maintained the functional capability of mitigating systems and barrier integrity systems;

(2) verified that emergent work-related activities such as troubleshooting, work planning/scheduling, establishing plant conditions, aligning equipment, tagging, temporary modifications, and equipment restoration did not place the plant in an unacceptable configuration; and

(3) reviewed the UFSAR to determine if the licensee identified and corrected risk assessment and emergent work control problems.

• July 26 - 27, 2007, Unit 1, extended out of service time for essential chill water system Train A due to the discovery of a design issue with the Trico Oiler on the circulating pump bearing housing

• July 30, 2007, Units 1, 2, and 3, elevated plant risk due to a severe thunderstorm warning

• August 11, 2007, Unit 1, containment spray Train B piping system voids

• August 30, 2007, Unit 2, troubleshooting effort to fix ground fault relay of motor generator Set B via WO 3055461

• September 4, 2007, Unit 1, EDG Train B inoperable due to fuel oil transfer pump cycling

• September 13, 2007, Unit 2, replacement of EDG Train B lube oil filters via WO 3061974

• September 18 - 20, 2007, Unit 1, troubleshooting and repair efforts for steam Generator 2 steam supply to AFA-P01 bypass Valve SGAUV0138A Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed seven samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors:

(1) reviewed plant status documents such as operator shift logs, emergent work documentation, deferred modifications, and night orders to determine if an operability evaluation was warranted for degraded components;

(2) referred to the

UFSAR and design basis documents to review the technical adequacy of licensee operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any TSs; (5)used the Significance Determination Process to evaluate the risk significance of degraded or inoperable equipment; and

(6) verified that the licensee has identified and implemented appropriate corrective actions associated with degraded components.

• July 19, 2007, Units 1, 2, and 3, operability determination associated with required minimum volume of trisodium phosphate contained in the storage baskets inside containment

• July 25, 2007, Unit 1, essential chiller Train A design issue associated with the Trico Oiler

• August 9, 2007, Unit 2, Class 1E battery charger high voltage alarm dropout set too high as described in Palo Verde Action Request (PVAR) 3048575

• September 13, 2007, Unit 2, EDG Train B turbo lube oil filters degrading discharge pressure trend

• September 20, 2007, Unit 1, steam Generator 2 steam supply to AFA-P01 bypass Valve SGAUV0138A failure to open during surveillance testing due to foreign material and its potential transportability Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors selected the six below listed post-maintenance test activities of risk significant systems or components. For each item, the inspectors:

(1) reviewed the applicable licensing basis and/or design-basis documents to determine the safety functions;

(2) evaluated the safety functions that may have been affected by the maintenance activity; and

(3) reviewed the test procedure to ensure it adequately tested the safety function that may have been affected. The inspectors either witnessed or reviewed test data to verify that acceptance criteria were met, plant impacts were evaluated, test equipment was calibrated, procedures were followed, jumpers were properly controlled, the test data results were complete and accurate, the test

equipment was removed, the system was properly re-aligned, and deficiencies during testing were documented. The inspectors also reviewed the UFSAR to determine if the licensee identified and corrected problems related to post maintenance testing.

• May 15 - 24, 2007, Unit 1, testing associated with detector replacement for startup Channels 1 and 2 detectors

• July 25 - 26, 2007, Unit 1, EDG Train A per Procedure 40ST-9DG01,"Diesel Generator A Test," Revision 30

• July 30, 2007, Unit 1, high pressure safety injection Valve 1JSIAUV0666 per WOs 2946259, 2855494, and Procedure 39MT-9ZZ02, "PM or EQ Inspection of the GL-89-10 Limitorque SMB/SB Motor Operated Valve Actuators," Revision 21

• August 3, 2007, Unit 3, low pressure safety injection Valve 3-JSIAUV0645 per WOs 2855772, 2948743, and Procedure 39MT-9ZZ02, "PM or EQ Inspection of the GL-89-10 Limitorque SMB/SB Motor Operated Valve Actuators," Revision 21

• August 08, 2007, Unit 3, Procedure 77ST-9SB07, "CPC Channel A Functional Test," Revision 9, following maintenance

• August 27, 2007, overspeed test of station blackout Generator 1 following maintenance Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

Unit 1 Refueling Outage 13 The inspectors reviewed the following risk significant refueling items or outage activities to verify defense in depth commensurate with the outage risk control plan, compliance with the TSs, and adherence to commitments in response to Generic Letter 88-17, "Loss of Decay Heat Removal:"

(1) the risk control plan;

(2) tagging/clearance activities;

(3) reactor coolant system (RCS) instrumentation;

(4) electrical power;

(5) decay heat removal;

(6) spent fuel pool cooling;

(7) inventory control;

(8) reactivity control;

(9) containment closure;

(10) reduced inventory or mid-loop conditions;

(11) refueling

activities; and

(12) licensee identification and implementation of appropriate corrective actions associated with refueling and outage activities. The containment inspections included observations of the containment sump for damage and debris; and supports, braces, and snubbers for evidence of excessive stress, water hammer, or aging.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure that the four below listed surveillance activities demonstrated that the SSCs tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the following significant surveillance test attributes were adequate:

(1) preconditioning;

(2) evaluation of testing impact on the plant;

(3) acceptance criteria;

(4) test equipment;

(5) procedures;

(6) jumper/lifted lead controls;

(7) test data;

(8) testing frequency and method to demonstrate TS operability;

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of ASME Code requirements;

(12) updating of performance indicator data;

(13) engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test acceptance criteria were correct;

(14) reference setting data; and

(15) annunciators and alarms setpoints. The inspectors also verified that the licensee identified and implemented any needed corrective actions associated with the surveillance testing.

• June 16 - 17, 2007 Unit 1, shiftly surveillances per Procedure 40ST-9ZZM6, "Operations Mode 6 Surveillance Logs," Revision 15

• July 24, 2007, Unit 3, Procedures 73ST-9AF02, "AFA-P01 Inservice Test,"

Revision 39, and 73ST-9XI38, "AF Pumps Discharge Check Valves - Inservice Test," Revision 14

• August 28, 2007, Unit 2, Procedure 40ST-9RC02, "ERFDADS (Preferred)

Calculation of RCS Water Inventory," Revision 43

• August 29, 2007, Unit 2, Procedure 74ST-9RC02, "RCS Specific Activity Surveillance Test," Revision 11 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

For the below listed drill contributing to Drill/Exercise Performance (DEP) and Emergency Response Organization (ERO) Performance Indicators, the inspectors:

(1) observed the training evolution to identify any weaknesses and deficiencies in classification, notification, and Protective Action Requirements (PAR) development activities;

(2) compared the identified weaknesses and deficiencies against licensee identified findings to determine whether the licensee is properly identifying failures; and

(3) determined whether licensee performance is in accordance with the guidance of the NEI 99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria.

• August 16, 2007, ERO exercise scenario Guide 07-D-FAC-08008 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1EP7 Force-On-Force Exercise Evaluation

a. Inspection Scope

For the drill listed below, inspectors:

(1) reviewed any Emergency Preparedness (EP)corrective actions identified during previous Force-On-Force (FOF) exercises that would be demonstrated during the current FOF exercise;

(2) observed the EP portion of the FOF exercise to identify any weaknesses and deficiencies in classification, notification, and PAR activities; and

(3) compared the identified weaknesses and deficiencies against licensee identified findings to determine whether the licensee is properly identifying and correcting failures.

• August 22, 2007, EP portion of the FOF exercise Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction.

The inspectors identified a Green noncited violation (NCV) associated with 10 CFR 50.54(q) for the failure of the emergency planning organization's critique process to identify an emergency plan weakness associated with a risk significant planning standard during the EP portion of the August 22, 2007, FOF exercise.

Description.

During the August 22, 2007, EP portion of the FOF exercise, the inspectors observed that the shift manager (SM) failed to declare a Notice of Unusual Event (NOUE) even though the Emergency Action Level (EAL) conditions existed. The SM entered Procedure EPIP-09, "E-Plan Implementation for Security Events," Revision 10, when conditions existed that posed a credible threat to the facility. This procedure directed the SM to enter Procedure 40AO-9ZZ24, "Deliberate Acts Against PVNGS,"

Revision 17, and to classify the event per Procedure EPIP-99, "Emergency Actions Levels," Appendix A, Revision 15. Procedure EPIP-99, Appendix A, EAL 7-1, states to declare a NOUE when a credible Site-Security Threat Notification condition exists. The SM failed to make this declaration. The subsequent critique conducted by the licensees organization failed to identify the missed classification by the SM for correction, resulting in the performance deficiency. In addition, the licensees exercise evaluators did not adequately prepare evaluation objectives before the start of the exercise which contributed to the failure to recognize the opportunity to declare the NOUE.

Analysis.

The performance deficiency associated with this finding involved the failure of the licensees critique process to identify for correction an emergency plan weakness associated with a risk significant planning standard. This finding is more than minor because it is associated with the Emergency Response Organization Performance attribute of the Emergency Preparedness Cornerstone and affects the cornerstone objective to ensure that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. In accordance with Manual Chapter 0609, "Significance Determination Process,"

Appendix B, Emergency Preparedness Significance Determination Process, this finding is determined to have very low safety significance because, although it was a failure to comply with NRC requirements, it did not involve the risk significant aspects of a planning standard as defined in Manual Chapter 0609, Appendix B, Section 2.0; and was not a planning standard functional failure because the critique failure occurred in a small scale drill with limited ERO participation and evaluation. This finding has a crosscutting aspect in the area of problem identification and resolution associated with corrective action program because the threshold for identifying issues was not sufficiently low. Specifically, the emergency planning evaluator did not recognize the SMs failure to make the NOUE classification during the FOF exercise. Therefore, the exercise critique did not identify and correct the event classification deficiency as required by 10 CFR 50, Appendix E, IV(F)(2)(g) (P.1(a)).

Enforcement.

10 CFR 50.54(q) states in part, "A licensee authorized to possess and operate a nuclear power reactor shall follow and maintain in effect emergency plans which meet the standards in 10 CFR 50.47(b) and the requirements of Appendix E of this part" 10 CFR 50.47(b)(4) states in part, "A standard emergency classification and

action level scheme, , is (will be) in use by the nuclear facility licensee" 10 CFR Part 50, Appendix E, IV(B), states in part, "The means to be used for determining the magnitude of and for continually assessing the impact of the release of radioactive materials shall be described, including emergency action levels that are to be used as criteria for determining the need for notification and participation of Local and State agencies, the Commission, and other Federal agencies, and the emergency action levels that are used for determining when and what type of protective measures shall be considered within and outside the site boundary" 10 CFR 50.47(b)(14) states in part, "deficiencies identified as a result of exercises or drills are (will be) corrected."

10 CFR 50, Appendix E, IV(F)(2)(g), states in part, "All training, including exercises, shall provide for formal critiques in order to identify weak or deficient areas that need correction. Any weaknesses or deficiencies that are identified shall be corrected."

Contrary to the above, during the critique of the EP portion of the August 22, 2007, FOF exercise, the licensee failed to identify for correction an event classification weakness.

The weakness occurred during the exercise when the SM did not recognize and declare a NOUE emergency classification required by EAL 7-1, when the conditions existed.

Because this finding is of very low safety significance, and because it was entered into the licensees CAP as Condition Report/Disposition Request (CRDR) 3056153, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000528; 05000529;05000530/2007004-01, "Failure to Identify and Critique an Event Classification Weakness."

4OA1 Performance Indicator (PI) Verification

Cornerstone: Barrier Integrity

The inspectors sampled licensee submittals for the two performance indicators listed below for the period September 1, 2006, to July 31, 2007, for Units 1, 2, and 3. The definitions and guidance of Nuclear Energy Institute 99-02,"Regulatory Assessment Indicator Guideline," Revision 2, were used to verify the licensees basis for reporting each data element in order to verify the accuracy of PI data reported during the assessment period. The inspectors:

(1) reviewed RCS chemistry sample analyses for dose equivalent Iodine-131 and compared the results to the TS limit;

(2) observed a chemistry technician obtain and analyze a RCS sample;

(3) reviewed operating logs and surveillance results for measurements of RCS identified leakage; and

(4) observed a surveillance test that determined RCS identified leakage. Licensee performance indicator data were also reviewed against the requirements of Procedures 93DP-0LC09, "Data Collection and Submittal Using INPO's Consolidated Data Entry System,"

Revision 6, 73DP-9PP01, "Thermal Performance Monitoring and Evaluation Process," Revision 4, and 70DP-0PI01, "Performance Indicator Data Mitigating Systems Cornerstone," Revision 3.

• RCS Specific Activity

• RCS Leakage The inspectors completed six samples.

Documents reviewed by the inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

The inspectors performed a daily screening of items entered into the licensee's CAP.

This assessment was accomplished by reviewing daily summary reports for PVARs and CRDRs, and attending corrective action review and work control meetings. The inspectors:

(1) verified that equipment, human performance, and program issues were being identified by the licensee at an appropriate threshold and that the issues were entered into the CAP;

(2) verified that corrective actions were commensurate with the significance of the issue; and

(3) identified conditions that might warrant additional follow-up through other baseline inspection procedures.

.2 Multiple/Repetitive Degraded Cornerstone Column and Crosscutting Issues Follow-up

Activities In the NRC's Annual Assessment Letter of Palo Verde dated March 2, 2007, the NRC indicated that improvement efforts in addressing the substantive crosscutting issues through baseline inspections would be monitored, including a detailed assessment following the licensees notification of readiness for closure verification. In a Confirmatory Action Letter dated June 21, 2007, the NRC revised this to indicate the intent to address the substantive crosscutting issues within the Inspection Procedure 95003 supplemental inspection and followup process, since the issues are integral to the performance deficiencies being addressed by your staff.

The inspectors and Region IV personnel conducted weekly teleconferences and conducted periodic discussions with licensee management to monitor their progress in addressing their performance deficiencies and substantive crosscutting issues.

A public meeting was conducted during this inspection period. On September 6, 2007, a public meeting was held with PVNGS to discuss the status of their assessment and improvement efforts to address plant performance issues that contributed to entering Column 4 of the NRC Action Matrix. The meeting summary can be found in ADAMS under ML072550193.

During the week of August 27, 2007, in preparation for the upcoming inspections per Inspection Procedure 95003, scheduled for October 1 through October 12 and

October 29 through November 2, the team leader and six members of the inspection team conducted an information gathering trip to PVNGS. In addition, from September 10 through 21, 2007, the entire team began reviewing documentation and preparing for the upcoming inspection in the Region IV office. The inspection is still ongoing, and the results of the inspection will be documented in NRC Inspection Report 05000528; 05000529; 05000530/2007012. No findings of significance were identified during this preliminary review.

.3 Cross-References to Problem Identification and Resolution Findings Documented

Elsewhere Section 1EP7 describes a finding where emergency planning personnel failed to identify a drill weakness at a low enough threshold and in a complete, accurate, and timely manner.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

a. Inspection Scope

Event Follow-Up The inspectors reviewed the below listed degraded condition for plant status and mitigating actions to:

(1) provide input in determining the appropriate agency response in accordance with Management Directive 8.3, "NRC Incident Investigation Program;"

(2) evaluate performance of mitigating systems and licensee actions; and

(3) 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 20 - 28, 2007, Unit 1, steam Generator 2 steam supply to AFA-P01 bypass Valve SGAUV0138A failure to open during surveillance testing Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

Personnel Performance The inspectors:

(1) reviewed operator logs, plant computer data, and/or strip charts for the below listed evolution to evaluate operator performance in coping with non-routine events and transients;

(2) verified that operator actions were in accordance with the response required by plant procedures and training; and

(3) verified that the licensee has identified and implemented appropriate corrective actions associated with personnel performance problems that occurred during the non-routine evolutions sampled.

• On July 7, 2007, Unit 1, the RCS was taken below atmospheric pressure while lowering pressurizer level. A pressurizer cooldown, purge, and level reduction had been performed to support pressurizer manway removal and RCS drain to

establish conditions for emergent check valve maintenance. During turnover, the oncoming operations shift recognized that RCS pressure was less than atmospheric and took action to increase RCS pressure to atmospheric conditions and recover pressurizer level. Pressurizer level stabilized to a partial drain condition of 6 percent once atmospheric conditions were restored. This event was documented in CRDR 3038774.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction.

A Green self-revealing NCV of TS 5.4.1.a was identified for the failure of operations personnel to follow procedures to establish appropriate conditions prior to lowering pressurizer level, resulting in a partial vacuum condition in the RCS.

Description.

On July 5, 2007, during refueling Outage 1R13, safety injection system check Valve SIE-V123 failed a surveillance test while the unit was in Mode 3. The unit had to be returned to Mode 5 with the RCS partially drained to establish plant conditions needed to conduct repairs. On July 7, 2007, operations personnel performed a cooldown and purge of the pressurizer in accordance with Procedure 40OP-9ZZ06, "Mode 5 Operations," Revision 15, prior to lowering pressurizer level to support pressurizer manway removal and partial drain of the RCS.

The RO implementing the procedure had conducted two cycles of purging the pressurizer gas space to the gaseous radwaste system. During this phase of the evolution, nitrogen is added to raise pressure in the RCS to 100 psia and the pressure is then bled to the gaseous radwaste system. The purging evolution is conducted with pressurizer level between 93 to 98 percent. RCS pressure ends up at approximately 20 psia after a purging evolution.

Following the final purging evolution, Procedure 40OP-9ZZ06, Step 5.3.16.9, directed the addition of nitrogen to raise pressure in the RCS to 100 psia prior to lowering pressurizer level to 25 percent. The RO performing this evolution incorrectly signed off that Step 5.3.16.9 was complete following the final purging evolution, even though RCS pressure was at 20 psia. The RO believed that since he had previously performed the step during earlier purging evolutions, it could be signed off as complete. Consequently, draining was commenced with RCS pressure still at approximately 20 psia, resulting in RCS pressure lowering to below atmospheric pressure (less than 15 psia) as the pressurizer was drained. Actual RCS pressure was stabilized at 9 psia when pressurizer level reached the required 25 percent. The evolution was suspended at this point for turnover to the oncoming operations crew. The oncoming crew noted the partial vacuum condition in the RCS and initiated actions to raise RCS pressure to a normal, positive value and add inventory to recover level. Indicated pressurizer level stabilized at approximately 6 percent after pressure was restored to atmospheric conditions.

The RO performing the evolution was also performing other duties, including monitoring RCS pressure and temperature in accordance with Procedure 40ST-9RC01, "RCS and Pressurizer Heatup and Cooldown Rates," Revision 15. The RO did not recognize the partial vacuum condition in the RCS, in part, because he did not make the mental connection that indicated pressure was in absolute units (psia) versus gauge units (psig). With RCS pressure at 15 psia, gauge pressure would be 0 psig, or atmospheric.

Additionally, the RO failed to recognize that the change in pressurizer drain rate due to the changing pressure conditions was indication that the adverse condition was developing.

The licensee's event evaluation determined that:

(1) there was inadequate job preparation for the evolution, including an inadequate pre-job briefing;

(2) the RO was not proficient at performing this evolution since the individual was a control room supervisor filling in due to departmental manning issues;

(3) at least two ROs involved in the evolution failed to realize they were below atmospheric pressure when indicated pressure dropped below 15 psia; and

(4) procedure guidance for the evolution was inadequate in that it did not allow for proper use of the place keeper standard.

Analysis.

The performance deficiency associated with this finding involved the failure of operations personnel to adequately implement procedures to maintain configuration control of the plant. The finding is greater than minor because it is associated with the human performance attribute of the initiating events cornerstone and affects the associated cornerstone objectives to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using the Manual Chapter 0609, "Significance Determination Process,"

Appendix G, "Shutdown Operations Significance Determination Process," Checklist 4, a phase 2 analysis is required since the finding increased the likelihood of a loss of RCS inventory and could have impacted the operability of RCS level instrumentation. Manual Chapter 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria," was used since the Significance Determination Process methods and tools were not adequate to determine the significance of the finding. The finding is determined to have very low safety significance through management review because the finding does not degrade the licensee's ability to terminate a leak path, add RCS inventory, recover decay heat removal once it is lost, or establish an alternate core cooling path. Given the RCS drain rate, it would have taken over 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> to drain the RCS to midloop conditions, and due to the low decay heat load, the time to boil was greater than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. This finding has a crosscutting aspect in the area of human performance, associated with work practices, since the pre-job brief and self/peer checking for the evolution were inadequate (H.4(a)).

Enforcement.

TS 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specified in Regulatory Guide 1.33, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Item 3(a), requires procedures for venting and draining the RCS. Procedure 40OP-9ZZ06 "Mode 5 Operations,"

Revision 15, Step 5.3.16.9, provided instructions to establish appropriate plant conditions to ensure that RCS pressure would be above atmospheric pressure when pressurizer level was lowered to 25 percent. Contrary to the above, on July 7, 2007,

operations personnel failed to perform Procedure 40OP-9ZZ06, Step 5.3.16.9, prior to lowering pressurizer level to 25 percent resulting in a partial vacuum condition in the RCS as the pressurizer was drained. Because this violation is of very low safety significance and has been entered into the licensee's CAP as CRDR 3038774, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000528/2007004-02, "Failure to Follow Procedure Results in Partial Vacuum of the RCS."

4OA6 Meetings, Including Exit

On October 3, 2007, the inspectors presented the inspection results to Mr. R. Bement, Vice President, Nuclear Operations, and other members of the licensee management staff. The licensee acknowledged the findings presented.

The inspectors noted that while proprietary information was reviewed, none would be included in this report.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Andrews, Director, Performance Improvement

S. Bauer, Department Leader, Regulatory Affairs

R. Bement, Vice President, Nuclear Operations

P. Borchert, Director, Operations

P. Brandjes, Department Leader, Maintenance

R. Buzard, Senior Consultant, Regulatory Affairs

D. Carnes, Director, Nuclear Assurance

P. Carpenter, Department Leader, Operations

R. Cavalieri, Director, Outages

K. Chavet, Senior Consultant, Regulatory Affairs

D. Coxon, Unit Department Leader, Operations

R. Eddington, Executive Vice President, Chief Nuclear Officer

D. Elkington, Consultant, Regulatory Affairs

J. Gaffney, Director, Radiation Protection

T. Gray, Department Leader, Radiation Protection

K. Graham, Department Leader, Fuel Services

M. Grigsby, Unit Department Leader, Operations

R. Henry, Site Rep., SRP

J. Hesser, Vice President, Engineering

M. Karbasian, Director, Engineering

D. Marks, Section Leader, Regulatory Affairs

S. McKinney, Department Leader, Operations Support

E. O<Neil, Department leader, Emergency Preparedness

M. Perito, Plant Manager, Nuclear Operations

M. Radspinner, Section Leader, Systems Engineering

T. Radtke, General Manager, Emergency Services and Support

H. Ridenour, Director, Maintenance

F. Riedel, Director, Nuclear Training Department

J. Scott, Section Leader, Nuclear Assurance

M. Shea, Director, ImPACT Project

E. Shouse, Representative, EPE

M. Sontag, Department Leader, Performance Improvement

K. Sweeney, Department Leader, Systems Engineering

J. Taylor, Nuclear Project Manager, PNM

J. Taylor, Unit Department Leader, Operations

D Vogt, Section Leader, OPS STA

T. Weber, Section Leader, Regulatory Affairs

J. Wood, Department Leader, Nuclear Training Department

NRC Personnel

M. Runyan, Senior Reactor Analyst

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000528;

05000529; NCV Failure to Identify and Critique an Event Classification

05000530/2007004-01 Weakness (Section 1EP7)

05000528/2007004-02 NCV Failure to Follow Procedure Results in Partial Vacuum of the RCS (Section 4OA3)

Discussed

None