IR 05000528/2010002

IR 05000528-10-002; 05000529-10-002 and 05000530-10-002, on 01/01-03/31/2010; Palo Verde Nuclear Generating Station, Units 1, 2, and 3, Integrated Resident and Regional Report; Operability Evaluations; and Surveillance Testing

ML101250229
Person / Time
Site:	Palo Verde
Issue date:	05/05/2010
From:	Ryan Lantz NRC/RGN-IV/DRP/RPB-D
To:	Edington R Arizona Public Service Co
References
IR-10-002
Download: ML101250229 (73)

Text

UNITED STATES NU C LE AR RE G ULATO RY C O M M I S S I O N May 5, 2010

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2010002, 05000529/2010002, AND 05000530/2010002

Dear Mr. Edington:

On March 31, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Palo Verde Nuclear Generating Station, Units 1, 2, and 3 facility. The enclosed integrated inspection report documents the inspection findings, which were discussed on April 6, 2010, with Mr. Bement, Vice President, Nuclear Operations 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 self-revealing findings of very low safety significance (Green). Two of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations, consistent with Section VI.A.1 of the NRC Enforcement Policy. 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 Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV, and the NRC Resident Inspector at Palo Verde Nuclear Generating

Arizona Public Service Company -2-Station, Units 1, 2, and 3, facility. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and its enclosure, will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records 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/

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

Enclosure:

NRC Inspection Report 05000528/2010002, 05000529/2010002, and 05000530/2010002 w/Attachment: Supplemental Information

Arizona Public Service Company -3-

REGION IV==

Docket: 50-528, 50-529, 50-530 License: NPF-41, NPF-51, NPF-74 Report: 05000528/2010002, 05000529/2010002, 05000530/2010002 Licensee: Arizona Public Service Company Facility: Palo Verde Nuclear Generating Station, Units 1, 2, and 3 Location: 5951 S. Wintersburg Road Tonopah, Arizona Dates: January 1 through March 31, 2010 Inspectors: J. Bashore, Resident Inspector M. Catts, Resident Inspector M. Baquera, Resident Inspector R. Treadway, Senior Resident Inspector G. Guerra, CHP, Emergency Preparedness Inspector L. C. Carson II, Senior Health Physicist Approved By: Ryan Lantz, Chief, Project Branch D Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000528/2010002, 05000529/2010002, 05000530/2010002; 01/01/2010 - 03/31/2010; Palo

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

Operability Evaluations; and Surveillance Testing.

The report covered a 3-month period of inspection by resident and regional inspectors. Three Green findings, two of which were noncited violations, were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process. Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified for the failure of engineering personnel to follow procedures and adequately evaluate an identified adverse condition for corrective actions associated with containment isolation valve UV002 as required by Procedure 90DP-0IP10, Condition Reporting and Procedure 86DP-0EE01, Reliability Centered Maintenance Based System Reviews. Specifically, the licensee identified during a cause analysis performed in 1997 and by a system review conducted in 2004 and 2007 that the failure of containment isolation valve UV002 could result in a reactor trip, but failed to take any corrective actions. This issue was entered into the licensee's corrective action program as Condition Report Disposition Request 3411547 which included corrective actions to evaluate the condition in accordance with station procedures and plan a modification to eliminate the adverse condition associated with containment isolation valve UV002.

The finding was more than minor because it affected the design control attribute of the Initiating Events Cornerstone, and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety function during shutdown as well as power operations. Using Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," the finding was determined to have very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and mitigating equipment or functions would not be available. This finding was evaluated as not having a crosscutting aspect because the performance deficiency is not indicative of current performance. (Section 1R15)

Cornerstone: Mitigating Systems

Green.

A self-revealing noncited violation of Technical Specification 5.4.1,

"Procedures," was identified for the failure of operations personnel to adequately implement Procedure 40DP-9OP19, "Locked Valve, Breaker, and Component Tracking." Specifically, between December 24, 2009 and January 26, 2010, refrigerant head pressure bypass control valve 2-EWBV-349 was in the locked open position as opposed to its required position of locked closed. This issue has been entered into the licensee's corrective action program as Palo Verde Action Request 3430116 which included corrective actions to train operations personnel on the requirements for independent verification.

The finding is more than minor because it is associated with the configuration control attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," the finding was determined to require a Phase 2 and Phase 3 analysis by a senior reactor analyst, because the finding resulted in an actual loss of safety function of a single train for greater than its technical specification allowed outage time. A senior reactor analyst performed a bounding Phase 3 significance determination and found the finding to be of very low safety significance (Green) because the dominant core damage sequences only included a failure of multiple auxiliary feedwater pumps and because the chiller was only inoperable for a narrow range of initiating events. The finding has a cross-cutting aspect in the area of Human Performance associated with work practices because the licensee failed to use human error prevention techniques such as self and peer checking commensurate with the risk of the assigned task H.4(a). (Section 1R15)

Green.

A self-revealing noncited violation of 10 CFR 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, was identified for the failure of maintenance personnel to prevent the introduction of foreign material into the atmospheric dump valve nitrogen system as required by Procedure 30DP-9MP03, System Cleanliness and Foreign Material Exclusion Controls.

Specifically, on January 10, 2010, atmospheric dump valve 3-ADV-184 failed the nitrogen accumulator drop test when leakage exceeded an acceptance criterion which was caused by a check valve leaking by due to the presence of foreign material during maintenance. This issue was entered into the licensee's corrective action program as Palo Verde Action Request 3425640 which included corrective actions to flush the nitrogen lines for all the ADVs and train maintenance personnel on the foreign material exclusion requirements.

The finding was more than minor because it affected the equipment reliability 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 finding was determined to have 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. This finding was evaluated as not having a crosscutting aspect because the performance deficiency is not indicative of current performance. (Section 1R22)

Licensee-Identified Violations

None

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially full power until January 12, 2010, when an unplanned down power to 60 percent power occurred due to the manual trip of main feedwater pump B after experiencing speed oscillations. The unit retuned to full power on January 15, 2010, and operated at essentially full power until March 7, 2010, when an automatic reactor trip occurred when two reactor coolant pumps lost power due to the failure of a 13.8 kV bus. The unit returned to essentially full power on March 22, 2010, and remained there for the remainder of the inspection period.

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

Unit 3 operated at essentially full power for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of the adverse weather procedures for seasonal extremes and low temperatures. The inspectors verified that weather-related equipment deficiencies identified during the previous year were corrected prior to the onset of seasonal extremes, and evaluated the implementation of the adverse weather preparation procedures and compensatory measures for the affected conditions before the onset of, and during, the adverse weather conditions.

During the inspection, the inspectors focused on plant-specific design features and the procedures used by plant personnel to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures.

Specific documents reviewed during this inspection are listed in the attachment. The inspectors also reviewed corrective action program items to verify that plant personnel were identifying adverse weather issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. The inspectors reviews focused specifically on the systems in the following locations:

• January 12, 2010, Unit 2, fuel building, 100 foot, 120 foot and 140 foot elevations

• January 12, 2010, Unit 3, fuel building, 100 foot, 120 foot and 140 foot elevations

• January 12, 2010, Unit 2, control building, 74 foot, 100 foot, 120 foot, 140 foot, and 160 foot elevations

• January 12, 2010, Unit 3, control building, 74 foot, 100 foot, 120 foot, 140 foot, and 160 foot elevations Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings of significance were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for January 19-21, 2010, the inspectors reviewed the plant personnels overall preparations/protection for the expected weather conditions. On January 21, 2010, the inspectors walked down the condensate storage and transfer system and the normal auxiliary feedwater system because their safety-related functions could be affected, or required, as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the plant staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report and performance requirements for the systems selected for inspection, and verified that operator actions were appropriate as specified by plant-specific procedures. The inspectors also reviewed a sample of corrective action program items to verify the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the corrective action program in accordance with station corrective action procedures.

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

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

b. Findings

No findings of significance were identified.

1R04 Equipment Alignments

Partial Walkdown

a. Inspection Scope

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

• February 12, 2010, Unit 3, auxiliary feedwater system train B

• March 10, 2010, Unit 1, 4160 Vac and 480 Vac vital electrical systems

• March 11, 2010, Unit 2, auxiliary feedwater system 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 potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Report, 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 of significance were identified.

1R05 Fire Protection

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:

• January 26, 2010, Unit 3, auxiliary building 77 foot elevation

• January 27, 2010, Unit 3, main steam support structure 77 foot, 100 foot, 120 foot and 140 foot elevations

• February 3, 2010, Unit 3, auxiliary building 100 foot and 120 foot elevations

• February 9, 2010, Unit 3, control building 100 foot elevation including emergency diesel generator building

• February 10, 2010, Unit 3, auxiliary building 40 foot and 51 foot elevations

• February 11, 2010 Unit 2, auxiliary building 100 foot and 120 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, 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 six quarterly fire-protection inspection samples as defined in Inspection Procedure 71111.05-05.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, 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.

• January 21, 2010, Unit 1, emergency diesel generator cable vaults, station blackout generator vaults, and Unit 2, essential spray pond vaults These activities constitute completion of one bunker/manhole sample as defined in Inspection Procedure 71111.06-05.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industry standards, and reviewed critical operating parameters and maintenance records for the Unit 2 emergency cooling water heat exchanger train A. The inspectors verified that performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors; the licensee utilized the periodic maintenance method outlined in EPRI Report NP 7552, Heat Exchanger Performance Monitoring Guidelines; the licensee properly utilized biofouling controls; the licensees heat exchanger inspections adequately assessed the state of cleanliness of their tubes; and the heat exchanger was correctly categorized under 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

Quarterly Inspection On February 9, 2010, 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 and 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 senior reactor operators

• 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 of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

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

• February 12, 2010, Unit 2, emergency cooling water heat exchanger train A tube leak

• February 19, 2010, Unit 2, high pressure safety injection pump train B mechanical seal failure

• February 23, 2010, Unit 2, main transformer phase C neutral bushing failure The inspectors reviewed events caused by ineffective equipment maintenance that 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 three quarterly maintenance effectiveness samples as defined in Inspection Procedure 71111.12-05.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensees 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:

• January 10 - 16, 2010, Unit 3, atmospheric dump valve 3-ADV-184 out of service for emergent maintenance

• January 11, 2010, Units 1, 2 and 3, startup transformer NAN-X02 out of service for planned maintenance

• January 27 - 28, 2010, Unit 3, emergency diesel generator, emergency chiller, emergency cooling water, and essential spray pond train B out of service for planned maintenance

• February 11, 2010, Unit 2, emergency cooling water heat exchanger train A out of service for tube leak identification

• March 5, 2010, Unit 2, plant cooling water train A out of service coincident with start-up transformer NAN-X02 and atmospheric dump valve 3-ADV-184 out of service 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 of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• January 14, 2010, Unit 2, essential chiller train B refrigerant head bypass control valve 2-EWBV-349 found to be out of its required position

• January 26, 2010, Unit 1, operability determination for essential spray pond train A following failure of sodium hypochlorite addition valve

• February 2, 2010, Unit 2, essential cooling water heat exchanger train A tube leakage

• February 8 - 12, 2010, Unit 2, safety injection tank 1B nitrogen gas leakage past relief valve seat

• February 9, 2010, Unit 2, recirculation actuation system sump train A isolation valve 2-SIAUV-674 relay failure 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 Updated Final Safety Analysis Report to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. 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 five operability evaluations inspection samples as defined in Inspection Procedure 71111.15-05

b. Findings

===.1

Introduction.

A Green self-revealing finding was identified for the failure of engineering===

personnel to follow procedures and adequately evaluate an identified adverse condition for corrective actions associated with containment isolation valve UV002 as required by procedure 90DP-0IP10, Condition Reporting and procedure 86DP-0EE01, Reliability Centered Maintenance Based System Reviews. Specifically, the licensee identified during a cause analysis performed in 1997 and by a system review conducted in 2004 and 2007 that the failure of containment isolation valve UV002 could result in a reactor trip, but failed to take any corrective actions. This issue was entered into the licensee's corrective action program as Condition Report Disposition Request (CRDR) 3411547 which included corrective actions to evaluate the condition in accordance with station procedures and plan a modification to eliminate the adverse condition associated with containment isolation valve UV002.

Description.

On December 3, 2009, Unit 3 was operating at essentially 100 percent power when instrument air containment isolation valve UV002 failed closed and isolated instrument air to containment. The operators diagnosed a loss of instrument air to the containment, entered procedure 40AO-9ZZ06, Loss of Instrument Air, manually tripped the reactor and secured all four reactor coolant pumps. The decision to trip the reactor and secure all the reactor coolant pumps and their associated control bleed-offs was based on the desire to terminate the addition of reactor coolant to the reactor drain tank to avoid rupture disc actuation.

During troubleshooting, the licensee determined that the cause of valve UV002 failing was a short circuit in the solenoid, followed by a blown fuse, causing a loss of power to valve UV002. This caused valve UV002 to close and resulted in a loss of instrument air to containment. During the cause analysis, the licensee determined that in 1997 valve UV002 was identified as having an adverse condition because failure of the valve could result in a reactor trip. Additionally, in 2004, the licensee identified that an evaluation performed by engineering personnel determined that failure of valve UV002 could result in a reactor trip, but failed to screen the concern appropriately in accordance with procedure 86DP-0EE01, Reliability Centered Maintenance Based System Reviews.

The inspectors noted that procedure 90DP-0IP10, Condition Reporting, required that conditions that have the potential to adversely affect the safe, reliable production of electricity will be evaluated. The inspectors also noted that the licensee failed to adequately screen an adverse condition, such that it would receive the appropriate level of scrutiny to determine an adequate mitigation strategy, in accordance with procedure 86DP-0EE01, Reliability Centered Maintenance Based System Reviews.

Based on these reviews the inspectors concluded that the Palo Verde failed to follow procedures and take corrective actions for an adverse condition

Analysis.

The performance deficiency associated with this finding involved the failure of engineering personnel to follow procedures and adequately evaluate an identified

adverse condition for corrective actions associated with containment isolation valve UV002. The finding was more than minor because it affected the design control attribute of the Initiating Events Cornerstone, and affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Using Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," the finding was determined to have very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and mitigating equipment or functions would not be available. This finding was evaluated as not having a crosscutting aspect because the performance deficiency is not indicative of current performance.

Enforcement.

Enforcement action does not apply because the performance deficiency did not involve a violation of regulatory requirements. Because this finding does not involve a violation of regulations or requirements, has a very low safety significance, and has been entered into the licensee's corrective action program as Palo Verde Action Request (PVAR) 3425640, it is identified as: FIN 05000530/2010002-01, Failure to Take Adequate Corrective Actions for an Identified Adverse Condition.

===.2

Introduction.

A Green self-revealing noncited violation of Technical Specification 5.4.1,===

"Procedures," was identified for the failure of operations personnel to adequately implement procedure 40DP-9OP19, "Locked Valve, Breaker, and Component Tracking."

Specifically, on January 26, 2010, refrigerant head pressure bypass control valve 2-EWBV-349 was found to be in the locked open position as opposed to its required position of locked closed.

Description.

On January 26, 2010, Unit 2 was at 100 percent power when the essential chiller train B was started for nuclear air treatment systems testing in accordance with plant procedures. During the nuclear air treatment systems test, operations personnel identified that the essential chilled water system was operating with condenser pressure in the range of 7 to 13 psig; however, the required range for condenser pressure is 15 to 45 psig. The lower condenser pressure was caused by excessive essential cooling water flow to the condenser with no load on the chiller. Subsequent troubleshooting efforts by operations personnel determined that valve 2-EWBV-349 was found locked open instead of the required position of locked closed.

The essential chilled water system essential chiller is vulnerable to low refrigerant temperature trips due to a phenomenon known as stacking under low chiller heat load and low essential cooling water system temperature conditions. Liquid refrigerant will remain in the condenser because there is insufficient refrigerant gas pressure to drive the liquid refrigerant from the condenser to the evaporator portion of the chiller. If this occurs, the emergency chillers refrigerant temperature will continue to decrease to the low refrigerant temperature trip setpoint.

In 1996, the licensees corrective action for stacking on the essential chillers was to incorporate an essential cooling water throttle valve, refrigerant head pressure control valve 2-EWBPCV-174. Reducing essential cooling water flow rate with the throttle valve can prevent stacking because the condenser will operate at higher temperatures as

essential cooling water cooling flow is modulated. However, a bypass essential cooling water flow path is available with refrigerant head pressure bypass control valve 2-EWBV-349, which ensures adequate cooling rates under the highest heat loads.

Valve 2-EWBV-349 is normally locked closed to prevent stacking in the condenser and a potential chiller trip.

For the essential chilled water low condenser pressure issue on January 26, 2010, the licensee performed engineering evaluation 3430163 and identified the lowest essential chilled water system heat load occurs during an auxiliary feedwater actuation signal, a type of engineering safety feature actuation signal. Palo Verde engineering evaluation 3430163 concluded that the essential chilled water system would not perform its safety function for the duration of an auxiliary feedwater actuation signal event with essential cooling water temperature less than 55 degrees and valve 2-EWBV-349 open. During the licensees apparent cause evaluation, engineering personnel determined that valve 2-EWBV-349 was incorrectly positioned on December 24, 2009, and left in that position until it was found on January 26, 2010.

The inspectors determined that valve 2-EWBV-349 was required to be closed and locked in accordance with procedure 40DP-9OP19, "Locked Valve, Breaker, and Component Tracking." The inspectors also noted that procedure 40AC-0ZZ06, "Locked Valve, Breaker, and Component Control," established a method to lock valves governed by procedure 40DP-9OP19. Procedure 40DP-9OP19, "Locked Valve, Breaker, and Component Tracking," Section 3.3, "Valve, Breaker, or Component Restoration," stated, in part, to place the valve, breaker, or component in its required locked position and then to install and lock the locking device. Section 3.3 also stated, in part, that a second individual shall check that the valve, breaker or component is in its required position using local and remote indication and that the locking device is locked. Procedure 02DP-0ZZ01, "Verification of Plant Activities," described the requirements and methods for independent verification of locked valves. The inspectors also noted that while valve 2-EWBV-349 had been signed for being closed, locked, and verified on December 24, 2009, this action was not completed in accordance with approved procedures to ensure that the valve was indeed in the closed position. Additionally, the inspectors reviewed the cause evaluation and determined the valve was mispositioned due to human error/failure to self-check. This issue was entered into the licensee's corrective action program as Palo Verde Action Request 3430116 which included corrective actions to train operations personnel on the requirements for independent verification.

Analysis.

The performance deficiency associated with this finding involved the failure of operations personnel to ensure that valve 2-EWBV-349 was closed prior to installing the locking device, as required by procedure 40DP-9OP19. The finding is more than minor because it is associated with the configuration control attribute of the Mitigating Systems Cornerstone and affected the cornerstone objective to ensure the reliability and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Using Manual Chapter 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," the finding was determined to require a phase 2 and phase 3 analysis by a senior reactor analyst, because the finding resulted

in an actual loss of safety function of a single train for greater than its technical specification allowed outage time.

A Region IV Senior Reactor Analyst performed a phase 2 and then performed a bounding phase 3 significance determination and found the finding to be of very low safety significance (Green). The dominant core damage sequences included: (1)transient, failure of multiple auxiliary feedwater pumps, and the failure to restore normal feedwater; and

(2) loss of main feedwater, with failure of multiple auxiliary feedwater pumps, and the failure to restore normal feedwater. Equipment that mitigated the significance included the remaining functional chiller and essential chiller 2-MECBE-01, because the chiller was only inoperable for a narrow range of initiating events. The finding has a crosscutting aspect in the area of human performance associated with work practices because the licensee failed to use human error prevention techniques such as self and peer checking commensurate with the risk of the assigned task H.4(a).

Enforcement.

Technical Specification 5.4.1, "Procedures," requires that procedures be established, implemented, and maintained covering the applicable procedures in Regulatory Guide 1.33, Appendix A. Regulatory Guide 1.33, Appendix A, Paragraph 1.c, requires procedures for equipment control, including locking of valves.

Procedure 40DP-9OP19, "Locked Valve, Breaker, and Component Tracking,"

Section 3.3, "Valve, Breaker, or Component Restoration," stated, in part, to place the valve, breaker, or component in its required locked position and then to install and lock the locking device. Section 3.3 also stated, in part, that a second individual shall check that the valve, breaker or component is in its required position using local and remote indication and that the locking device is locked. Contrary to these requirements, between December 24, 2009 and January 26, 2010, operations personnel did not ensure valve 2-EWBV-349 was closed prior to installing the locking device. However, because this finding is of very low safety significance and has been entered into the licensee's corrective action program as PVAR 3430116, this violation is being treated as a noncited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy:

NCV 05000529/2010002-002, Mispositioning of Valve Renders Essential Chiller Inoperable.

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:

• January 29, 2010, Unit 3, emergency diesel generator train B super train outage

• February 19, 2010, Unit 2, high pressure safety injection train B pump mechanical seal leakage

• March 8, 2010, Unit 2, atmospheric dump valve 2-ADV-184 accumulator nitrogen supply system check valve PSGE-985 replacement

• March 11, 2010, Unit 2, atmospheric dump valve 2-ADV-179 accumulator nitrogen safety relief valve 2-SGAPSV- 0309 replacement

• March 18, 2010, Unit 1, personnel airlock door inner seal repair for planned maintenance

• March 14, 2010, Unit 1, 4160 Vac Calvert bus repair and corrective maintenance following catastrophic failure 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 Updated Final Safety Analysis Report, 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 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 six postmaintenance testing inspection samples as defined in Inspection Procedure 71111.19-05.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the outage safety plan and contingency plans for the Unit 1 maintenance outage for replacement of the 4160 Vac Calvert electrical bus, conducted March 7 - 19, 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 maintenance outage, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below.

• 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

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

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

• Licensee identification and resolution of problems related to maintenance outage activities Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one other outage inspection sample as defined in Inspection Procedure 71111.20-05.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, 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 also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.

• January 28, 2010, Unit 3, atmospheric dump valve 3-ADV-184 accumulator drop surveillance test

• February 3, 2010, Unit 1, high pressure safety injection minimum flow inservice test

• February 11, 2010, Unit 1, low pressure safety injection train A header vent surveillance test

• February 11, 2010, Unit 2, core performance surveillance test

• March 1, 2010, Unit 2, auxiliary feedwater train A recirculation flow and inservice test The inspectors witnessed test performance and/or reviewed test performance documentation to verify the significant surveillance test attributes were adequate to address the following:

• Prevention of preconditioning

• Evaluation of testing impact on the plant

• Clear acceptance criteria and procedure guidance

• Adequacy of test equipment

• Adequacy of documentation of test results and data

• Adequacy of jumper/lifted lead controls

• 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.

Also, additional activities were performed during the review of the Unit 1, low pressure safety injection train A header vent surveillance test, that were associated with Temporary Instruction TI 2515/177, Managing gas accumulation in emergency core

cooling, decay heat removal, and containment spray systems. These activities are described in Section 1R22.2 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

Introduction.

A Green self-revealing noncited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure of maintenance personnel to prevent the introduction of foreign material into the atmospheric dump valve nitrogen system as required by procedure 30DP-9MP03, System Cleanliness and Foreign Material Exclusion Controls. Specifically, on January 10, 2010, atmospheric dump valve 3-ADV-184 failed the nitrogen accumulator drop test when leakage exceeded the acceptance criterion, which was caused by a check valve leaking by due to the introduction of foreign material during maintenance.

Description.

On January 10, 2010, Unit 3 operations personnel performed an inservice test of the atmospheric dump valve 3-ADV-184. During this evolution, the atmospheric dump valve failed the drop test due to leakage past check valve 3-SGEV-346. The leak rate was approximately 54 psi/hr, which exceeded the established acceptance criterion of 34 psi/hr. The surveillance was stopped and Unit 3 entered a 7-day Technical Requirements Manual Limiting Condition for Operation for one atmospheric dump valve inoperable. Maintenance personnel performed troubleshooting and identified that foreign material was the cause for the leakage past check valve 3-SGEV-346. During the cause evaluation, the licensee determined that work completed on the nitrogen system in March 2000 opened the system to atmosphere and had the potential to introduce foreign material into the system. Upon completion of this work, maintenance personnel were required to restore the system to meet ASME Section III cleanliness requirements. The Inspectors reviewed Palo Verdes ASME system cleanliness and foreign material controls program which were put into place by work order 00763286 and referenced procedure 30DP-9MP03, System Cleanliness and Foreign Material Exclusion Controls. Procedure 30DP-9MP03, Section 1.1.1 stated, in part, that administrative controls, instructions and criteria necessary to maintain foreign material exclusion are established before restoring plant mechanical systems and components to required levels of internal surface cleanliness. Procedure 30DP-9MP03 also stated, in part, Class C system cleanliness acceptance criteria will ensure that existing components will have no evidence of contamination and be free of particulate. Work order 00763286 stated that foreign material exclusion for a system breach was a necessity for each step and foreign material exclusion was to be maintained as described in procedure 30DP-9MP03. The inspectors determined the maintenance completed in March 2000 was the most probable cause of introducing foreign material to the atmospheric dump valve nitrogen system. This issue was entered into the licensee's corrective action program as Palo Verde Action Request 3425640 which included

corrective actions to flush the nitrogen lines for all the ADVs and train maintenance personnel on the foreign material exclusion requirements.

Analysis.

The performance deficiency associated with this finding involved the failure of maintenance personnel to follow the foreign material exclusion requirements and ensure foreign material would be excluded from the atmospheric dump valve nitrogen system.

The finding was more than minor because it affected the equipment reliability 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 finding was determined to have 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. This finding was evaluated as not having a crosscutting aspect because the performance deficiency is not indicative of current performance.

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Procedure 30DP-9MP03, System Cleanliness and Foreign Material Exclusion Controls, Section 1.1.1 stated, in part, that administrative controls, instructions and criteria necessary to maintain foreign material exclusion are established before restoring plant mechanical systems and components to required levels of internal surface cleanliness. Procedure 30DP-9MP03 also stated, in part, that Class C system cleanliness acceptance criteria will ensure that existing components will have no evidence of contamination and be free of particulate. Contrary to the above, maintenance personnel did not follow instructions to ensure that cleanliness requirements for the atmospheric dump valve nitrogen system were followed during maintenance activities, which resulted in the presence of foreign material in the nitrogen system from March 2000 until January 10, 2010. However, because this finding is of very low safety significance and has been entered into the licensee's corrective action program as PVAR 3425640, this violation is being treated as an noncited violation, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000530/2010002-03, ADV Drop Test Failure Due to Foreign Material.

.2 Surveillance Testing associated with Temporary Instruction (TI) 2515/177, Managing

gas accumulation in emergency core cooling, decay heat removal, and containment spray systems.

a. Inspection Scope

On February 11, 2010, the inspectors reviewed the Unit1 low pressure safety injection train A header vent surveillance test to verify that the procedure was acceptable for (1)testing associated with power operation, shutdown operation, maintenance, and system

modifications;

(2) void determination and elimination methods; and

(3) post-event evaluation.

The inspectors reviewed procedure 40 ST-9SI13, LPSI and CS Alignment Verification, Revision 19, used for conducting surveillances and determining void volumes to ensure that the void criteria were satisfied and are reasonably assured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.a). Also, the inspectors reviewed procedures used for filling and venting following conditions which may have introduced voids into the systems to verify that the procedures acceptably addressed testing for such voids and provided acceptable processes for their reduction or elimination (TI 2515/177, Section 04.03.b). Specifically, the inspectors verified that:

• Gas intrusion prevention, refill, venting, monitoring, trending, evaluation, and void correction activities were acceptably controlled by approved operating procedures (TI 2515/177, Section 04.03.c.1)

• Procedures ensured the system did not contain voids that may jeopardize operability (TI 2515/177, Section 04.03.c.2)

• Procedures established that void criteria were satisfied and are reasonably assured to be satisfied until the next scheduled void surveillance (TI 2515/177, Section 04.03.c.3)

• The licensee entered changes into the CAP as needed to ensure acceptable response to issues. In addition, the inspectors confirmed that a clear schedule for completion was included for CAP entries that have not been completed (TI 2515/177, Section 04.03.c.5)

• Procedures included independent verification that critical steps were completed (TI 2515/177, Section 04.03.c.6)

The inspectors verified the following with respect to surveillance and void detection:

• Specified surveillance frequencies were consistent with technical specifications surveillance requirements (TI 2515/177, Section 04.03.d.1)

• Surveillance frequencies were stated or, when conducted more often than required by technical specifications, the process for their determination was described (TI 2515/177, Section 04.03.d.2)

• Surveillance methods were acceptably established to achieve the needed accuracy (TI 2515/177, Section 04.03.d.3)

• Surveillance procedures included up-to-date acceptance criteria (TI 2515/177, Section 04.03.d.4)

• Procedures included effective follow-up actions when acceptance criteria are exceeded or when trending indicates that criteria may be approached before the next scheduled surveillance (TI 2515/177, Section 04.03.d.5)

• Measured void volume uncertainty was considered when comparing test data to acceptance criteria (TI 2515/177, Section 04.03.d.6)

• Venting procedures and practices utilized criteria such as adequate venting durations and observing a steady stream of water (TI 2515/177, Section 04.03.d.7)

• An effective sequencing of void removal steps was followed to ensure that gas does not move into previously filled system volumes (TI 2515/177, Section 04.03.d.8)

• Qualitative void assessment methods were included only when expectations are that the void will be significantly less that allowed by acceptance criteria (TI 2515/177, Section 04.03.d.9)

• Venting results were trended periodically to confirm that the systems are sufficiently full of water and that the venting frequencies are adequate. The inspectors also verified that records of the quantity of gas at each location are maintained and trended as a means of preemptively identifying degrading gas accumulations (TI 2515/177, Section 04.03.d.10)

• Surveillances were conducted at any location where a void may form, including high points, dead legs, and locations under closed valves in vertical pipes (TI 2515/177, Section 04.03.d.11)

• The licensee ensured that systems were not pre-conditioned by other procedures that may cause a system to be filled, such as by testing, prior to the void surveillance (TI 2515/177, Section 04.03.d.12)

• Procedures included gas sampling for unexpected void increases if the source of the void is unknown and sampling is needed to assist in determining the source (TI 2515/177, Section 04.03.d.13)

The inspectors verified the following with respect to filling and venting:

• Revisions to fill and vent procedures to address new vents or different venting sequences were acceptably accomplished (TI 2515/177, Section 04.03.e.1)

• Fill and vent procedures provided instructions to modify restoration guidance to address changes in maintenance work scope or to reflect different boundaries from those assumed in the procedure (TI 2515/177, Section 04.03.e.2)

The inspectors verified the following with respect to void control:

• Void removal methods were acceptably addressed by approved procedures (TI 2515/177, Section 04.03.f.1)

• The licensee had reasonably ensured that the low pressure safety injection pump is free of damage following a gas-related event in which pump acceptance criteria was exceeded (TI 2515/177, Section 04.03.f.2)

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

This inspection effort counts towards the completion of TI 2515/177 which will be closed in a later Inspection Report.

b. Findings

No findings of significance were identified.

1EP2 Alert Notification System Testing

a. Inspection Scope

The inspector discussed with licensee staff the operability of offsite siren emergency warning systems and backup alerting methods, to determine the adequacy of methods for testing the alert and notification system in accordance with 10 CFR Part 50, Appendix E. The licensees alert and notification system testing program was compared with criteria in NUREG 0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1; FEMA Report REP 10, Guide for the Evaluation of Alert and Notification Systems for Nuclear Power Plants; and the licensees current FEMA approved alert and notification system design report, Palo Verde Nuclear Generating Station Alert and Notification System Updated Report, dated November 13, 2009. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.02-05.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing

a. Inspection Scope

The inspector discussed with licensee staff the operability of primary and backup systems for augmenting the on-shift emergency response staff to determine the

adequacy of licensee methods for staffing emergency response facilities in accordance with their emergency plan. The inspector evaluated the licensee=s ability to staff the emergency response facilities in accordance with the licensees emergency plan and the requirements of 10 CFR Part 50, Appendix E. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.03-05.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The inspector performed an in-office review of the Palo Verde Nuclear Generating Station Emergency Plan, Revision 43 and Emergency Plan Implementing Procedure EPIP-99, EPIP Standard Appendices, Revision 28. The emergency plan was revised to implement a new emergency action level methodology previously approved by the NRC in a safety evaluation dated September 4, 2009 (ADAMS Accession Number ML091870111). The emergency plan implementing procedure was also revised to include the new emergency action level methodology. Appendix A to this procedure was revised to implement the new emergency action level scheme and Appendix P was deleted as the basis information was relocated to Appendix A.

These revisions were compared to their previous revision, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to Nuclear Energy Institute (NEI) Report 99-01, Emergency Action Level Methodology, Revision 5, and to the standards in 10 CFR 50.47(b) to determine if the revisions adequately implemented the requirements of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, these revisions are subject to future inspection. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of two samples as defined in Inspection Procedure 71114.04-05.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the licensee=s corrective action program requirements in procedure 01PR-0AP04, Corrective Action Program, Revision 4. The inspector reviewed summaries of 887 corrective action program documents assigned to the emergency preparedness department and emergency response organization between February 2008 and February 2010, and selected 30 for detailed review against the program requirements. The inspector evaluated the response to the corrective action requests to determine the licensee=s ability to identify, evaluate, and correct problems in accordance with the licensee program requirements, planning standard 10 CFR 50.47(b)(14), and 10 CFR Part 50, Appendix E. The inspector also reviewed licensee audits, assessments, drill reports, and after action reports to determine whether the licensee was identifying weaknesses and deficiencies in the emergency preparedness program. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.05-05.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on February 24, 2010, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the control room (simulator) to determine whether the event classification and notifications were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the corrective action program. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the attachment. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one sample as defined in Inspection Procedure 71114.06-05.

b. Findings

No findings of significance were identified.

2RS0 4 Occupational Dose Assessment

a. Inspection Scope

The inspectors:

(1) determined the accuracy and operability of personal monitoring equipment;

(2) determined the accuracy and effectiveness of the licensees methods for determining total effective dose equivalent; and

(3) ensured occupational dose was appropriately monitored. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensees procedures required by technical specifications as criteria for determining compliance. During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

• External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters

• The technical competency and adequacy of the licensees internal dosimetry program

• Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment

• Audits, self-assessments, and corrective action documents related to dose assessment since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.04-05.

b. Findings

No findings of significance were identified.

2RS0 5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors verified that the licensee was assuring the accuracy and operability of radiation monitoring instruments that are used to:

(1) monitor areas, materials, and workers to ensure a radiologically safe work environment; and

(2) detect and quantify radioactive process streams and effluent releases. The inspectors used the requirements in 10 CFR Part 20, the technical specifications, and the licensee=s procedures required by technical specifications as criteria for determining compliance.

During the inspection, the inspectors interviewed licensee personnel, performed walkdowns of various portions of the plant, and reviewed the following items:

• Selected plant configurations and alignments of process, post-accident, and effluent monitors with descriptions in the Updated Final Safety Analysis Report and the offsite dose calculation manual

• Selected instrumentation, including effluent monitoring instruments, portable survey instruments, area radiation monitors, continuous air monitors, personnel contamination monitors, portal monitors, and small article monitors to examine their configurations and source checks

• Calibration and testing of process and effluent monitors, laboratory instrumentation, whole body counters, post-accident monitoring instrumentation, portal monitors, personnel contamination monitors, small article monitors, portable survey instruments, area radiation monitors, electronic dosimetry, air samplers, and continuous air monitors

• Audits, self-assessments, and corrective action documents related to radiation monitoring instrumentation since the last inspection Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of the one required sample as defined in Inspection Procedure 71124.05-05.

b. Findings

No findings of significance 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 fourth quarter 2009 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, Performance Indicator Program. Specific documents reviewed during this inspection are listed in the attachment.

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 of significance were identified.

.2 Unplanned Scrams per 7000 Critical Hours (IE01)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams per 7000 critical hours performance indicator for Palo Verde Units 1, 2 and 3 for the period from the first quarter 2009 through the fourth quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 2009 through December 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed are described in the attachment to this report.

These activities constitute completion of three unplanned scrams per 7000 critical hours samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.3 Unplanned Scrams with Complications (IE02)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned scrams with complications performance indicator for Palo Verde Units 1, 2 and 3 for the period from the first quarter 2009 through the fourth quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports for the period of January 2009 through December 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and one was identified. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three unplanned scrams with complications samples as defined in Inspection Procedure 71151-05.

b. Findings

Introduction.

The inspectors identified an unresolved item (URI) associated with the licensees evaluation for an NRC Performance Indicator. Specifically, for the December 3, 2009, Unit 3 reactor trip, the licensee did not submit data for the Unplanned Scrams with Complication Performance Indicator in accordance with NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. This discrepancy is a result of a difference in the interpretation of NEI 99-02 guidance, and shall be addressed by the Frequently Asked Questions process as defined by Inspection Procedure 71151, Performance Indicator Verification.

Description.

On December 3, 2009, Unit 3 was operating at essentially full power. At 3:39 a.m., a high pressure alarm was received for reactor coolant pump control bleed-off and the operators recognized that the control bleed-off isolation to the volume control tank valve CHAUV-506 was in the intermediate position and subsequently closed approximately one minute later. The crew determined that the control bleed-off would be redirected to the reactor drain tank through the system relief valve. At 3:54 a.m., a reactor drain tank high pressure alarm was received. During an attempt to pump down the reactor drain tank the crew discovered that valve CHAUV-560, the reactor drain tank isolation inside containment, was closed and would not reopen. At approximately 4:05 a.m., the crew identified valve UV002, instrument air to containment isolation valve, had lost indication. Operators diagnosed a loss of instrument air to the containment and entered procedure 40AO-9ZZ06, Loss of Instrument Air.

The operators manually tripped the reactor at 4:31 a.m. and entered emergency operating procedure 40EP-9EO01, Standard Post Trip Actions. At 4:32 a.m.,

operations personnel secured all four reactor coolant pumps to terminate the addition of

reactor coolant from the reactor coolant pump controlled bleed-off to the reactor drain tank to prevent the rupture of the reactor drain tank blow out disk. At 4:41 a.m.,

operations personnel entered emergency operating procedure 40EP-9EO07, Loss of Offsite Power/Loss of Forced Circulation, due to the loss of forced circulation when the operators turned off the reactor coolant pumps, and due to the inability to complete the standard post trip action acceptance criteria in emergency operating procedure 40EP-9EO01.

The guidance in NEI 99-02 provides criteria for determining if a scram was complicated.

Specifically, it states Was the scram response procedure unable to be completed without entering another emergency operating procedure? The scram must be completed without transitioning to an additional emergency operating procedure after entering the scram response procedure (e.g. ES01 for Westinghouse). This step is used to determine if the scram was uncomplicated by counting if additional procedures beyond the normal scram response required entry after the scram. The inspectors review determined the licensee was unable to complete the scram response procedure, emergency operating procedure 40EP-9EO01, without transitioning to another emergency operations procedure, emergency operating procedure 40EP-9EO07.

The licensee determined the scram was uncomplicated based on Palo Verde adopting a Westinghouse emergency operating procedure scheme. The licensee stated that for this sequence of events in a Westinghouse emergency operating procedure scheme, it would not count toward the Unplanned Scrams with Complications performance indicator. The inspectors reviewed this data and determined that based on the NEI 99-02 guidance, the licensee should count this event as an Unplanned Scram with Complications until the licensee either changes their emergency operating procedure scheme to match Westinghouse, or NEI 99-02 guidance changes to allow a plant specific exemption.

This URI is being opened because of a difference in the interpretation of NEI 99-02 guidance for Unplanned Scrams with Complications at Palo Verde Nuclear Generating Station: URI 05000530/2010002-04, Discrepancy with Unplanned Scrams with Complications Performance Indicator.

.4 Unplanned Power Changes per 7000 Critical Hours (IE03)

a. Inspection Scope

The inspectors sampled licensee submittals for the unplanned power changes per 7000 critical hours performance indicator for Palo Verde Units 1, 2 and 3 for the period from the first quarter 2009 through the fourth quarter 2009. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed the licensees operator narrative logs, issue reports, maintenance rule records, event reports, and NRC integrated inspection reports for the period of January 2009 through December 2009 to validate the accuracy of the submittals. The inspectors also reviewed the licensees

issue report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of three unplanned transients per 7000 critical hours samples as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.5 Drill/Exercise Performance (EP01)

a. Inspection Scope

The inspectors sampled licensee submittals for the drill and exercise performance indicator for the period from the first quarter 2009 through the fourth quarter 2009. 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 records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during predesignated control room simulator training sessions, performance during the 2009 biennial exercise, and performance during other drills. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one drill and/exercise performance sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.6 Emergency Response Organization Drill Participation (EP02)

a. Inspection Scope

The inspectors sampled licensee submittals for the Emergency Response Organization Drill Participation performance indicator for the period from the first quarter 2009 through the fourth quarter 2009. 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 records associated with

the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator, rosters of personnel assigned to key emergency response organization positions, and exercise participation records. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one emergency response organization drill participation sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.7 Alert and Notification System (EP03)

a. Inspection Scope

The inspectors sampled licensee submittals for the Alert and Notification System performance indicator for the period from the first quarter 2009 through the fourth quarter 2009. 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 records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one alert and notification system sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.8 Occupational Radiological Occurrences (OR01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological Occurrences performance indicator for the fourth quarter 2009. 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 assessment of the performance indicator for occupational radiation safety to determine if indicator related data was adequately assessed and reported. To assess the adequacy of the licensees performance indicator data collection and analyses, the inspectors discussed with radiation protection staff, the scope and breadth of its data review, and the results of those reviews. The inspectors independently reviewed electronic dosimetry dose rate and accumulated dose alarm and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas.

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

These activities constitute completion of one occupational radiological occurrences sample as defined in Inspection Procedure 71151-05.

b. Findings

No findings of significance were identified.

.9 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (PR01)

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual Radiological Effluent Occurrences performance indicator for the fourth quarter of 2009. 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 corrective action report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. Specific documents reviewed during this inspection are listed in the attachment.

These activities constitute completion of one radiological effluent technical specifications/offsite dose calculation manual radiological effluent occurrences sample as defined by Inspection Procedure 71151-05.

b. Findings

No findings of significance 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:

(1) the complete and accurate identification of the problem;

(2) the timely correction, commensurate with the safety significance;

(3) the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and

(4) the classification, prioritization, focus, and timeliness of corrective actions.

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 of significance 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.

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

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 of significance were identified.

.3 Selected Issue Follow-up Inspection

a. Inspection Scope

During a review of items entered in the licensees corrective action program, the inspectors recognized a corrective action item documenting the failure of the medical staff to decertify a licensed senior reactor operator following failure of his physical exam.

The inspectors considered the following during the review of the licensees action: (1)complete and accurate identification of the problem in a timely manner;

(2) evaluation for reportability;

(3) consideration for the extent of condition;

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

(5) identification of corrective actions; and

(6) completion of corrective actions in a timely manner. Specific documents reviewed during this inspection are listed in the attachment.

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

b. Findings

No findings of significance were identified.

.4 Confirmatory Action Letter Follow-up Inspection

a. Inspection Scope

The inspectors reviewed the Site Integrated Improvement Plan tasks listed below for an in-depth review and final closure. These tasks were previously reviewed and closed on an interim basis pending completion of all actions and effectiveness reviews. The inspectors considered the following during the review of the licensees actions:

(1) Site Integrated Improvement Plan task matches the Condition Report Action Item (CRAI)description;

(2) corrective actions address and correct the Site Integrated Improvement Plan task;

(3) corrective actions address the action plan problem statement and primary causes;

(4) verification of Site Integrated Improvement Plan task completion;

(5) timely completion of corrective actions in accordance with the Site Integrated Improvement Plan schedule;

(6) review of metrics and measures for improved performance; (7)independent verification of improved performance; and

(8) closure of Site Integrated Improvement Plan task in accordance with procedures. The inspectors also: (1)reviewed results of self assessments and effectiveness reviews that were conducted to assess the success of Confirmatory Action Letter corrective actions;

(2) reviewed the status and progress of the component design basis review project;

(3) reviewed trends associated with metrics used by Palo Verde Nuclear Generating Station to gauge the success of performance improvement initiatives;

(4) reviewed results of Safety Culture Surveys performed in 2008 and 2009;

(5) reviewed progress and effectiveness of improvements in implementing the Operability Determination process; and

(6) reviewed the results of Palo Verde Nuclear Generating Station reviews of key performance areas identified in the Site Integrated Improvement Plan and the Confirmatory Action Letter.

• Task 2.1.D.5.f (Confirmatory Action Letter Item 8 and Site Integrated Improvement Plan Action Plan 6, Strategy 5) (CRAI 3075733) - Incorporate the expected behaviors from the Site Integrated Business Plan, Action 2.1.D.5.b (CRAI 3075713) into individual mid-year 2009 Performance Monitoring Plans for Department Leaders and above

• Task 3.4.7.i (Confirmatory Action Letter Item 3 and Site Integrated Improvement Plan Action Plan 6 part 1, Strategy 10) (CRAI 3047300) - Incorporate changes into the Palo Verde trend program such that the line organizations trend their own data and identify developing trends, including the area of human performance on a proactive basis

• Task 3.6.11 (Confirmatory Action Letter Item 2 and Site Integrated Improvement Plan Action Plan 14, Strategy 7) (CRAI 3074615) - Deficiency Maintenance Work Order 3089358 - K1 Relays replacement in emergency diesel generator control Cabinet XJDGA (B) B02 (x=1, 2, & 3) for all six onsite Class 1E emergency diesel generators. Implement modification in all three units and close DMWO paperwork

• Task 6.1.1.c (Confirmatory Action Letter Item 4 and Site Integrated Improvement Plan Action Plan 11 part 1, Strategy 1) (CRAI 3032686) - Conduct effectiveness review or self assessment on the implementation of the standards / expectations for leadership fundamentals

• Task 6.1.3.c (Confirmatory Action Letter Item 4 and Site Integrated Improvement Plan Action Plan 11 part 1, Strategy 1) (CRAI 3032692) - Conduct effectiveness review or self-assessment on the implementation of the engineering human performance tools, standard /expectations for engineering, and engineering fundamentals observations

• Task 6.2.10 (Confirmatory Action Letter Item 4 and Site Integrated Improvement Plan Action Plan 11 part 1, Strategy 8) (CRAI 3115664) - Develop Integrated Issues Identification Team to be used in conjunction with coach the coach program. Integrated Issues Identification Team should include a charter, observation training, field time (physical walkdowns) and cross-functional members. Develop additional actions for implementation, as appropriate during the development of the process/team

• Task 6.5.2.h (Confirmatory Action Letter Item 4 and Site Integrated Improvement Plan Action Plan 11 part 1, Strategy 2) (CRAI 3022277) - First quarter 2009, review and determine if additional analysis is required for declining performance, including organizational and programmatic trends. Generate and document PVAR/CRDR for trends

• Task 6.5.2.i (Confirmatory Action Letter Item 4 and Site Integrated Improvement Plan Action Plan 11 part 1, Strategy 2) (CRAI 3022278) - Second quarter 2009, review and determine if additional analysis is required for declining performance, including organizational and programmatic trends. Generate and document PVAR/CRDR for trends

• Task 6.5.2.j (Confirmatory Action Letter Item 4 and Site Integrated Improvement Plan Action Plan 11 part 1, Strategy 2) (CRAI 3022279) - Third quarter 2009, review and determine if additional analysis is required for declining performance, including organizational and programmatic trends. Generate and document PVAR/CRDR for trends

• Task 20.10.1 (Confirmatory Action Letter Item 7 and Site Integrated Improvement Plan Action Plan 12, Strategy 8) (CRAI 3083294) - Complete the Safety Culture Improvement Plan: Security

• Task 20.10.2 (Confirmatory Action Letter Item 7 and Site Integrated Improvement Plan Action Plan 12, Strategy 8) (CRAI 3083295) - Close the Plan based on the results of the Departments Site Wide Fall 2008 Safety Culture Assessment showing: 1) An improving trend to the issues contained in this plan. 2) The Department is no longer identified as a Priority Group based on the results of the Site Wide Fall 2008 Safety Culture Assessment. 3) An effectiveness review by the Safety Culture Team The inspectors considered all of the above tasks closed.

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

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

Event Follow Up

a. Inspection Scope

The inspectors reviewed the below listed event 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 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.

• March 7, 2010, Unit 1, automatic reactor trip from 100 percent power on a loss of two reactor coolant pumps due to the catastrophic failure of a 13.8 kV bus

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

These activities constitute completion of one sample as defined in Inspection Procedure 71153-05.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 (Closed) Notice of Violation (NOV) 05000528; 05000529;05000530/2009006-04,

Failure to Implement Adequate Design Control

a. Inspection Scope

On March 20, 2009, Palo Verde Nuclear Generating Station received a NOV for the failure to translate design basis maximum condensate storage tank (CST) temperature requirements into procedures to ensure the plant is operated within its design basis. The issue was previously identified and documented as NCV 05000528; 05000529;05000530/2007012-02. The NOV was issued due to the licensees failure to restore full compliance within a reasonable amount of time. This NOV represented a significant condition adverse to quality.

Inspectors reviewed licensee corrective actions associated with monitoring CST temperatures to determine the appropriateness of the corrective actions and to determine whether any generic weaknesses existed in the licensees corrective action program. The inspectors reviewed significant CRDR 3303334 which was written to perform a significant root cause investigation for the NOV. The significant root cause investigation report addressed both the failure to restore compliance within a reasonable amount of time following the original noncited violation as well as the failure to translate the maximum CST temperature requirements into procedures to ensure the plant is operated within its design basis. Inspectors also reviewed appropriate supporting documentation to verify restoration of full compliance and ensuring design basis maximum CST temperature requirements were translated into procedures, operator logs, and engineering studies. Inspectors also reviewed certain site integrated improvement plan initiatives that address weaknesses in implementing the corrective action program.

The inspectors discussed the corrective actions with licensee personnel. The topics discussed included adequacy of the corrective actions to restore compliance and the thoroughness of root cause evaluations including the subsequent reviews by the corrective action review board. The inspectors considered the root cause evaluation and the corrective actions sufficient to address both the technical issues associated with translating the CST temperature requirements into procedures as well as the weakness associated with implementing the corrective action program. This NOV is closed.

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

b. Findings

No findings of significance were identified.

.2 (Open) NRC TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling,

Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

As documented in Section 1R22, the inspectors confirmed the acceptability of the described licensees actions. The remaining inspection effort for TI 2515/177 will be documented in a later Inspection Report.

4OA6 Meetings

Exit Meeting Summary

On February 4, 2010, the inspectors presented the radiation safety inspection results to Mr. D. Mims, Vice President, Regulatory Affairs and Plant Improvement, and other members of the licensee staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

On February 11, 2010, the inspectors presented the onsite emergency preparedness inspection results to Mr. R. Bement, Vice President, Nuclear Operations, and other members of the licensees staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection. .

On April 6, 2010, the inspectors presented the inspection results of the integrated inspection to Mr. R. Bement, Vice President, Nuclear Operations, and other members of his staff who acknowledged the findings. The licensee acknowledged the issues presented. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

4OA7 Licensee-Identified Violations

None.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Andrews, Unit 3 Assistant Plant Manager

R. Barnes, Director, Regulatory Affairs

S. Bauer, Department Leader, Regulatory Affairs

R. Bement, Vice President, Nuclear Operations

P. Borchert, Unit 1 Assistant Plant Manager

F. Burdick, Regulatory Affairs

R. Buzard, Section Leader, Compliance

D. Carnes, Unit 2 Assistant Plant Manager

K. Chavet, Senior Consultant, Regulatory Affairs

L. Cortopossi, Plant Manager, Nuclear Operations

D. Coxon, Unit Department Leader, Operations

E. Dutton, Acting Director of Nuclear Assurance

J. Gaffney, Director, Radiation Protection

T. Gray, Department Leader, Radiological Support Services

D. Hautala, Senior Engineer, Regulatory Affairs

J. Hesser, Vice President, Engineering

G. Hettel, Director, Operations

J. McDonnell, Department Leader, Radiation Protection Operations

D. Mims, Vice President, Regulatory Affairs and Performance Improvement

P. Paramithas, Department Lead, Modification Engineering

C. Podgurski, Section Leader, Dosimetry, Radiation Protection

T. Radtke, General Manager, Emergency Services and Support

M. Ray, Director, Emergency Planning Programs

H. Ridenour, Director, Maintenance

S. Sawtschenko, Department Leader, Emergency Preparedness

J. Summy, Director, Plant Engineering

J. Taylor, Unit Department Leader, Operations

T. Weber, Section Leader, Regulatory Affairs

NRC Personnel

R. Treadway, Senior Resident Inspector, Palo Verde

G. Repogle, Senior Reactor Analyst, Region IV

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

Discrepancy with Unplanned Scrams with

05000530/2010002-04 URI Complications Performance Indicator (Section 4OA1)

Opened and Closed

05000530/2010002-01 FIN Failure to Take Adequate Corrective Actions for an Identified Adverse Condition (Section 1R15)

05000529/2010002-02 NCV Mispositioning of Valve Renders Essential Chiller Inoperable (Section 1R15)

05000530/2010002-03 NCV ADV Drop Test Failure Due to Foreign Material (Section 1R22)

Closed

Failure to Implement Adequate Design Controls

05000528;529;530/2009006-04 NOV (Section 4OA5)