IR 05000528/2007002

IR 050000528-07-002, 05000529-07-002, & 05000530-07-002; 01/01/2007 Through 03/31/2007; Palo Verde Nuclear Generating Stations, Units 1, 2, & 3, Integrated Inspection

ML071210030
Person / Time
Site:	Palo Verde
Issue date:	04/26/2007
From:	Nease R NRC/RGN-IV/DRP/RPB-D
To:	Edington R Arizona Public Service Co
References
IR-07-002
Download: ML071210030 (56)

Text

ril 26, 2007

SUBJECT:

PALO VERDE NUCLEAR GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000528/2007002, 05000529/2007002, AND 05000530/2007002

Dear Mr. Edington:

On March 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility. The enclosed integrated report documents the inspection findings, which were discussed on March 30, 2007, with Mr. R. Bement, Vice President, Nuclear Operations, and other members of your staff.

The inspection examined activities conducted under your licenses as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. In addition, Region IV personnel performed oversight of your staffs activities in response to your entering the Multiple/Repetitive Degraded Cornerstone Column (Column 4) of the NRCs Action Matrix as described in our annual assessment letter dated March 2, 2007. Our oversight activities are summarized in this report.

The report documents four NRC identified findings and three self-revealing findings which involved violations of NRC requirements. Six of these findings were evaluated under the risk significance determination process as having very low safety significance (Green). One finding was not suitable for evaluation under the significance determination process; however, it was determined to be of very low safety significance by NRC management review. Because of the very low safety significance of these violations and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations consistent with Section VI.A of the NRC Enforcement Policy. One licensee-identified violation, which was determined to be of very low safety significance, is listed in Section 4OA7 of this report. If you contest these noncited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Palo Verde Nuclear Generating Station, Units 1, 2, and 3, facility.

Arizona Public Service Company -2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Rebecca L. Nease, Chief Project Branch D Division of Reactor Projects Dockets: 50-528 50-529 50-530 Licenses: NPF-41 NPF-51 NPF-74

Enclosure:

NRC Inspection Report 05000528/2007002, 05000529/2007002, and 05000530/2007002 w/Attachment: Supplemental Information

REGION IV==

Dockets: 50-528, 50-529, 50-530 Licenses: NPF-41, NPF-51, NPF-74 Report: 05000528/2007002, 05000529/2007002, 05000530/2007002 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, 2007 Inspectors: B. Baca, Health Physicist J. Bashore, Project Engineer, Project Branch B P. Benvenuto, Resident Inspector T. Brown, Resident Inspector, Project Branch B P. Elkmann, Emergency Preparedness Instructor T. Farnholtz, Senior Project Engineer, Project Branch A S. Garchow, Operations Engineer, Operations Branch T. Jackson, Senior Resident Inspector, Project Branch B W. Johnson, NRC Contractor G. Larkin, Senior Resident Inspector, Project Branch E J. Melfi, Resident Inspector L. Miller, Emergency Preparedness Instructor C. Osterholtz, Senior Resident Inspector G. Warnick, Senior Resident Inspector Approved By: Rebecca L. Nease, Chief, Project Branch D Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000528/2007002, 05000529/2007002, 05000530/2007002; 01/01/07 - 03/31/07; Palo

Verde Nuclear Generating Station, Units 1, 2, and 3; Integrated Res. and Reg. Rpt; Equip.

Alignment, Op. Eval., Surv. Testing, Access Cont. to Rad. Sig. Areas, and Ident. & Res. of Problems.

This report covered a 3-month period of inspection by resident inspectors, regional inspectors, and an NRC contractor. The inspection identified seven noncited violations. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management's review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 200

Cornerstone: Mitigating Systems

Green.

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

Appendix B, Criterion III, "Design Control," for the failure of engineering personnel to verify or check the adequacy of design for maintaining the emergency diesel generator air intake oil bath filters oil level below the "add oil" mark. Specifically, from approximately November 1994 to January 24, 2007, engineering personnel failed to translate vendor requirements for the Air Maze oil bath air filter oil level into an appropriate operating band. This issue was entered into the corrective action program as Condition Report/Disposition Request 2963525.

The finding is greater than minor because it is associated with the design control attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to be of very low safety significance because it did not represent an actual loss of system safety function, did not represent an actual loss of a single train for greater than its technical specification allowed outage time, and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event (Section 1R04).

Green.

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

Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure of engineering and operations personnel to follow procedures to adequately evaluate degraded and nonconforming conditions to support operability decision-making associated with a containment spray pump Train A motor bearing oil leak. Specifically, on February 8, 2007, operations and engineering personnel failed to consider all relevant information when determining the measured leak rate for an oil leak on containment spray Pump 1MSIAP03 to perform an adequate operability determination. This issue was entered into the corrective action program as Palo Verde Action Requests 2968212, 2968501, 2968213, and 2968767.

The finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to have very low safety significance because it only affected the mitigating systems cornerstone, and all subsequent operability evaluations determined that there was no adverse effect to mitigating equipment. This finding has a crosscutting aspect in the area of human performance associated with decision-making because the licensee did not use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions (Section 1R15.1).

Green.

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

Appendix B, Criterion XVI, "Corrective Action," for the failure of inservice inspection personnel to promptly identify misalignment of spring cans on safety-related piping. Specifically, between April 2005 and May 2006, inservice inspection personnel failed to identify misalignment of spring cans associated with the auxiliary feedwater system and the emergency diesel generators.

Section 8.3.5 of Procedure 73TI-9ZZ18 required that the examination of piping systems should be directed to detect any relevant conditions, including misalignment of supports. This issue was entered into the corrective action program as Palo Verde Action Request 2980767.

The finding is greater than minor because it would become a more significant safety concern if left uncorrected in that the failure to identify degraded and non-conforming equipment conditions could impact the availability of mitigating equipment. The finding affected the mitigating systems cornerstone. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to have very low safety significance since it did not represent a loss of system safety function, an actual loss of safety function of a single train for greater than its technical specification allowed outage time, or screen as potentially risk-significant due to a seismic flooding, or severe weather initiating event. The finding has a crosscutting aspect in the area of problem identification and resolution, associated with corrective action program, since inservice inspection personnel had an inappropriately high threshold for recognizing the misalignment of spring cans on safety-related piping (Section 1R15.2).

Green.

A self-revealing noncited violation of Technical Specification 3.1.6 was identified during the performance of surveillance testing of the control element assemblies when more than one shutdown control element assembly was less than 144.75 inches withdrawn. Specifically, on February 3, 2007, while performing surveillance Procedure 40ST-9SF01, CEA Operability Checks," Revision 21, more than one control element assembly was less than 144.75 inches withdrawn. Operations personnel did not use all available control element assembly position indications while verifying movement of the four control element assemblies in shutdown Subgroup 6 to ensure that each control element assembly was withdrawn greater than 144.75 prior to movement of the next control element assembly. This issue was entered into the corrective action program as Condition Report/Disposition Request 2967976.

The finding is greater than minor because it is associated with the mitigating systems cornerstone attribute of procedure quality and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is also associated with the barrier integrity cornerstone attribute of configuration control and affects the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radio nuclide releases caused by accidents or events. Using the Manual Chapter 0609, Significance Determination Process," Phase 1 Worksheet, a Phase 2 analysis is required since two cornerstones are degraded. Manual Chapter 0609, Appendix M,

"Significance Determination Process Using Qualitative Criteria," was used since the Significance Determination Process methods and tools were not adequate to determine the significance of the finding. The finding is determined to have very low safety significance through management review since it did not represent a loss of system safety function, in that the control element assemblies were still capable of shutting down the reactor in response to any postulated accident.

This finding has a crosscutting aspect in the area of a problem identification and resolution associated with corrective action program, because the licensee failed to thoroughly evaluate the problem described in Condition Report/Disposition Request 2760855 such that the issue was resolved. This finding also has a crosscutting aspect in the area of human performance associated with work practices because operations personnel did not appropriately self and peer check all available control element assembly position indications to ensure proper system response (Section 1R22.1).

Green.

A self-revealing noncited violation of Technical Specification 5.4.1.a was identified for the failure of operations personnel to follow procedure which resulted in declaring both actuator trains for main steam isolation Valve MSIV-170 inoperable. Specifically, on March 12, 2007, operations personnel did not follow Procedure 73ST-9SG01 or guidance from the pre-job brief and recognize a condition that could result in the inoperability of both main steam isolation valve actuator trains. Upon recognition of the abnormal condition, operations personnel took action to restore operability. This issue was entered into the corrective action program as Condition Report/Disposition Request 2982116.

The finding is greater than minor because it is associated with the human performance attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to have very low safety significance because the condition only affected the mitigating systems cornerstone and did not represent an actual loss of safety function. This finding has a crosscutting aspect in the area of human performance associated with work practices because operations personnel did not follow procedures or the guidance from the pre-job briefing that would have prevented a main steam isolation valve from becoming inoperable and the entry into a short duration technical specification condition (Section 1R22.2).

Green.

The inspectors identified a noncited violation of Technical Specification 3.8.1 for exceeding the allowed outage time for the Unit 2 emergency diesel generator, Train B. Specifically, for the period between May 14, 2005 and November 3, 2005, the licensee failed to maintain the emergency diesel generator Train B operable. The licensee did not identify a condition in which the associated fuel oil suction strainers and discharge filters were fouling, resulting in the emergency diesel generator Train B being unable to supply Train B of the onsite Class 1E AC Electrical Power Distribution System without significant operations and maintenance personnel actions. The licensee entered this into their corrective action program as Condition Report/Disposition Request 2963482.

This finding is more than minor because the failure to identify and correct this deficiency would become a more significant safety concern in that the performance of emergency diesel generator Train B could be reduced, due to fuel starvation to the engine, to the point that the unit would not be able to carry essential electrical loads in the event of a loss of off-site electrical power. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have very low safety significance because it did not result in an actual loss of safety function for greater than its technical specification allowed outage time. The finding has a crosscutting aspect in the area of problem identification and resolution, associated with corrective action program, since the licensee failed to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity (Section 4OA2).

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing noncited violation of Technical Specification 5.7.1 was identified for the failure to follow a radiation exposure permit requirement.

Specifically, on October 3, 2006, a mechanic entered a high radiation area without direct authorization and a specific briefing from radiation protection personnel. As a corrective action for this isolated case, the mechanic and his coworker were restricted from the radiologically controlled area until re-authorized by the director of radiation protection and appropriate disciplinary actions were taken. The licensee entered this into their corrective action program as Condition Report/Disposition Request 2929853.

The finding was greater than minor because it is associated with the occupational radiation safety exposure control attribute and affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation. The failure to follow a radiation exposure permit requirement for a high radiation area led to unintended and additional personnel dose. The finding was determined to be of very low safety significance because it did not involve: (1) as low as reasonably achievable (ALARA) planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding had a crosscutting aspect in human performance associated with work practices because the mechanics did not use human error prevention techniques such as self and peer checking so that work activities were performed safely (Section 2OS1).

Licensee Identified Violations

One violation of very low safety significance, which was identified by the licensee, has been reviewed by the inspector. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and the corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

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

Unit 2 operated at essentially full power until February 7, 2007, when a main turbine trip occurred resulting in a reactor power cutback to 45 percent. Following the reactor power cutback, power was further lowered to 11 percent. Main turbine repairs were completed on February 10, the main generator was synchronized to the electrical grid, and power was raised to essentially full power. On February 19, the unit was shutdown as required by technical specifications (TSs) for an inoperable high pressure safety injection (HPSI) pump. Following repairs to the HPSI pump, the unit was restarted and achieved essentially full power on February 27. On March 18, a reactor power cutback to 48 percent occurred when main feedwater Pump A was manually tripped due to unstable operations. Following repairs to the main feedwater pump, the unit was returned to essentially full power on March 19, and remained there for the duration of the inspection period.

Unit 3 operated at essentially full power until January 26, 2007, when the unit was shutdown to perform battery testing as required by TS surveillance requirements. The unit was restarted on January 31, achieved essentially full power on February 2, and remained there for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown The inspectors:

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

(2) compared deficiencies identified during the walkdown to the licensee's updated final safety analysis (UFSAR) and corrective action program (CAP) to ensure problems were being identified and corrected.

• January 10, 2007, Unit 2, HPSI, essential cooling water, essential chilled water, and spray pond systems Train B while Train A was out of service for preplanned maintenance

• January 16 - 26, 2007, Units 1, 2, and 3, emergency diesel generators (EDGs)

• February 15, 2007, Unit 3, low pressure safety injection system Train B while Train A was out of service for preplanned maintenance

• March 15, 2007, Unit 1, essential cooling water and spray pond systems Train B while Train A was out of service for preplanned maintenance Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

Complete Walkdown The inspectors:

(1) reviewed plant procedures, drawings, the UFSAR, TSs, and vendor manuals to determine the correct alignment of the essential chilled water system;

(2) reviewed outstanding design issues, operator work arounds, and UFSAR documents to determine if open issues affected the functionality of the essential chilled water system; and

(3) verified that the licensee was identifying and resolving equipment alignment problems. Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction.

The inspectors identified a Green noncited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, "Design Control," for the failure of engineering personnel to verify or check the adequacy of design for maintaining the EDG air intake oil bath filters oil level below the "add oil" mark.

Description.

The inspectors conducted a partial system walkdown for all six station EDGs between January 16, 2007 and January 26, 2007. During these walkdowns it was observed that the oil level for four of the six Air Maze air intake oil bath filters was below the "add oil" mark on the indicating sight glass. The indicating sight glass has two marks, "normal" and "add oil." Subsequent document review revealed that maintenance Procedure 73DP-9ZZ05, "Lubrication of Plant Equipment," Revision 23, directed maintaining the oil level between 1/8 inch below the "add oil" mark and 1/8 inch above the "add oil" mark. In addition, Procedure 40DP-9OPA4, "Area 4 Operator Logs Modes 1-4," Revision 75, reflected this practice in the prescribed operating band. Records show an instruction change request in November 1994, prescribing the new operating band. The procedure change, implemented in 1995, was based on engineering judgement even though the vendor indicated it did not approve of maintaining the oil level lower than the "add oil" line with the EDG in standby.

The change in the operating band was initiated to address oil spillage on the floor surrounding the air filters upon EDG startup. The problem of oil spillage was first documented in March 1987. Between March 1987 and November 1994, it was noted that the volume of oil spilled during engine startup was reduced when standby oil level was maintained near the "add oil" mark on the indicating sight glass. Design change packages were implemented to address the problem but proved to be ineffective. In November 1994, an instruction change request was initiated to change the operating band to the "add oil" mark, plus or minus 1/8 inch. Documents indicate that facility

personnel recognized a potential filter efficiency reduction but considered it a long-term wear issue. Facility engineers did not consider this a challenge to the EDG's ability to perform its safety-related function. There were no calculations performed to quantify the filter efficiency reduction. No documents were reviewed that analyzed the long-term cumulative effect on the EDG's ability to perform its safety-related function. Records indicate the vendor did not approve of maintaining the oil level below the "add oil" line while in a standby status.

Following the inspectors' observations, the licensee adjusted the oil level to greater than the "add oil" line with the EDG in standby. Additionally, Procedure 73DP-9ZZ05 and Procedure 40DP-9OPA4 were revised to ensure that the oil level was maintained in the appropriate band. Condition Report/Disposition Request (CRDR) 2963525 will evaluate and determine long-term corrective actions.

Analysis.

The performance deficiency associated with this finding involved the failure of engineering personnel to adequately translate the design basis of the EDG air intake oil bath filters into applicable procedures. The finding is greater than minor because it is associated with the design control attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operating the oil bath air filters with an oil level less than the "add oil" mark could result in diesel engine damage due to accumulation of particulate in the oil. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to be of very low safety significance because it did not represent an actual loss of system safety function, did not represent an actual loss of a single train for greater than its TS allowed outage time, and the finding did not screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event.

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that applicable regulatory requirements and design basis, as defined in 50.2 and as specified in the license application, for those structures, systems, and components to which this appendix applies are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, from approximately November 1994 to January 24, 2007, the licensee failed to correctly translate design basis information into specifications, drawings, procedures, and instructions.

Specifically, engineering personnel failed to translate vendor requirements for the Air Maze oil bath air filter oil level into an appropriate operating band. This failure was reflected in both Procedure 73DP-9ZZ05, "Lubrication of Plant Equipment," Revision 23 and Procedure 40DP-9OPA4, "Area 4 Operator Logs Modes 1-4," Revision 75.

Because the finding is of very low safety significance and has been entered into the CAP as CRDR 2963525, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000528; 05000529;05000530/2007002-01, "Inadequate Change to Emergency Diesel Generator Intake Air Oil Bath Filter Standby Oil Level Specification."

1R05 Fire Protection

a. Inspection Scope

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

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

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

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

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

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

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

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

C January 9, 2007, Unit 2, condensate storage tank pump house and tunnel

• January 9, 2007, Unit 2, fuel building, all elevations

• January 18, 2007, Unit 3, EDG building, all elevations

• January 19, 2007, Unit 3, auxiliary building, 100 foot, 120 foot, and 140 foot elevations

• January 20, 2007, Unit 1, EDG building, all elevations

• January 19, 2007, Unit 1, control room building, all elevations

• February 16, 2007, Unit 1, auxiliary building, 100 foot, 120 foot, and 140 foot elevations

• February 28, 2007, Unit 1, containment building, 80 foot elevation near reactor coolant Pump 1B Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed eight samples.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed one module of simulator training involving senior reactor operators and reactor operators to identify deficiencies and discrepancies in the training, to assess operator performance, and to assess the evaluators' critique. In addition, the inspectors reviewed the written examinations for licensed operator training Cycle NLR07-02, Weeks 1 and 2, as well as the training content for the current training cycle.

This inspection also included an assessment of operator performance on the Week 1 examination. The following training scenario was reviewed:

C March 1, 2007, Simulator Scenario NLR07S05 02, "Emergency Boration,"

Revision 00 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the three below listed maintenance activities to:

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

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

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

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

• January 16 - 26, 2007, Units 1, 2, and 3, EDG maintenance effectiveness

• January 25, 2007, Unit 2, HPSI pump Train A inboard bearing oil leak

• February - March, 2007, Units 1, 2, and 3, General Electric molded case and ABB K-Line circuit breaker performance Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

See NRC Inspection Report 05000528; 05000529; 05000530/2007007 for findings associated with HPSI pump Train A inboard bearing oil leak.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

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

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

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

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

• January 10, 2007, Unit 2, risk assessment and management during scheduled EDG Train A outage

• February 13, 2007, Unit 1, HPSI Train A hot leg flow inadequately tested following modification, as documented in CRDR 2972828

• February 14, 2007, Unit 1, Startup Transformer AE-NAN-X02 routine maintenance

• March 15, 2007, Unit 1, risk assessment and management during scheduled EDG Train A outage Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

Emergent Work Control The inspectors:

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

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

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

• February 7, 2007, Units 1, 2, and 3, containment spray (CS) pump bearing oil leakage

• March 6-7, 2007, Unit 2, replacement of turbine driven auxiliary feedwater pump steam supply warm-up line isolation Valve SGAV0138A via Work Order 29787231

• March 7, 2007, Unit 3, atmospheric dump Valve ADV-178 failure to close during surveillance testing Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors:

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

(2) referred to the UFSAR and design basis documents to review the technical adequacy of licensee operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

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

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

• January 12, 2007, Unit 1, leakage from spray pond Train A due to cracks that developed on the concrete structural wall

• February 8, 2007, Unit 1, immediate and prompt operability determinations (ODs) for CS Pump 1MSIAP03 motor bearing oil leak

• February 12, 2007, Units 1, 2 and 3, HPSI bearing oil leaks as documented in CRDR 2970675

• February 16, 2007, Unit 1, misalignment of Spring Can 1-SP-100-H004 on EDG Train A

• March 8 - 9. 2007, Unit 2, frequency oscillations observed on EDG Train A after unloading during its surveillance test on March 6, 2007

• March 16, 2007, Unit 1, operability justification for BOP-ESFAS load sequencer Train A lock-up Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

1. Operability Determination Procedure Adherence

Introduction.

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," for the failure of engineering and operations personnel to follow procedures and adequately evaluate degraded and nonconforming conditions to support operability decision-making associated with a CS pump Train A motor bearing oil leak.

Description.

On February 2, 2007, the licensee performed a search of the site work management system database as part of the component design basis review and identified nine corrective maintenance items associated with CS Pump 1MSIAP03.

The database search identified that a maintenance activity to investigate the build-up of oil in the pump bowl area, which could be indicative of a motor lower bearing oil leak, had not been performed in excess of 13 months. Palo Verde action request (PVAR) 2966226 was initiated to evaluate the lack of timeliness associated with the corrective maintenance.

On February 7, 2007, operations personnel completed a visual inspection of the CS pump and identified oil on the pump casing and oil dripping from the lower motor bearing cover. A conference call was conducted with operations management and engineering to discuss the observations. Containment spray Pump 1MSIAP03 was declared inoperable due to the inability to determine the leak rate and uncertainties about the pump being able to perform its 182 day mission time. On February 8, 2007, engineering provided an operability assessment to operations personnel which concluded that the pump was fully capable of performing its intended safety function for its full mission time since the measured leak rate was less than the calculated acceptable leak rate. The measured leak rate was determined by performing a four-hour pump run after thoroughly cleaning the area of the motor that had oil on it so that new leakage could be observed. During the four-hour run, engineering and operations personnel observed two drops fall from the bottom of the motor housing and a third begin to form. Based on the observation of three drops over four hours, the measured leak rate was determined to be 0.75 drops per hour. Operations personnel calculated that a leak rate up to 1.4 drops per hour was acceptable to have the oil necessary for the pump to complete the 182 day mission time. The pump was declared operable on February 8, since the measured leak rate was approximately a factor of two times lower than the calculated acceptable leak rate.

On February 8, the inspectors reviewed the engineering assessment of operability and performed a visual inspection of the CS pump bowl area with the pump secured.

The inspectors observed that oil was accumulated on the bottom of the motor housing. Based on the observations, the inspectors questioned engineering and operations personnel regarding the method used to determine the measured leak rate since the amount of oil observed appeared to be in excess of the oil that would result from a 0.75 drop per hour leak rate. The inspectors confirmed that the area of the motor that previously had oil on it was thoroughly cleaned prior to the initiation of the pump run to identify new leakage. Further, engineering personnel explained that, during the four-hour run, no drops fell until well into the third hour, at which time

two drops fell on the pump from the bottom of the motor housing and a third had begun to form. Based on the explanation, the inspectors concluded that the observed amount of oil on the bottom of the motor housing was oil leakage that accumulated during a majority of the four-hour pump run to re-establish the oil film necessary to allow formation of drips. The inspectors further observed that the measurement of the leak rate should have started once a steady drop rate was achieved. Consequently, the inspectors challenged the validity of the measured leak rate since not all of the oil that leaked from the motor bearing during the four-hour pump run was considered.

Based on these observations, the inspectors identified that the assessment of operability for CS Pump 1MSIAP03 did not meet the NRCs expectations as delineated in Regulatory Issue Summary 2005-20 or follow the OD process in Procedure 40DP-9OP26, "Operability Determination and Functional Assessment,"

Revision 18. As a result of the inspectors' observations, a second four-hour pump run was performed on February 8, 2007, in which sound engineering methods were applied to determine a measured leak rate of 1.8 drops per hour.

Since the measured leak rate during the valid pump run was greater than the previously calculated acceptable leak rate of 1.4 drops per hour, operability of CS Pump 1MSIAP03 was reevaluated. Additionally, an extent of condition review was performed for all other CS pumps in Units 1, 2, and 3, per PVARs 2968212, 2968501, 2968213, and 2968767. A prompt OD was issued on February 10, 2007, to include results of the reevaluation. The prompt OD considered an engineering white paper which evaluated the CS pump design time and justified the reduction of the 182 day mission time to 30 days. Furthermore, Work Order 2968943 was implemented using a spare pump in the warehouse to quantify the amount of excess oil available to make up for leakage during the pump's mission time. This information was then used to calculate a new acceptable leak rate of 10.1 drops per hour. The reevaluation determined that there was a reasonable expectation of operabilty since the measured leak rate for all CS pumps was much less than the acceptable leak rate.

Analysis.

The failure to adequately implement the OD process was a performance deficiency. The finding is greater than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to have very low safety significance because it only affected the mitigating systems cornerstone, and all subsequent operability evaluations determined that there was no adverse effect to mitigating equipment. This finding has a crosscutting aspect in the area of human performance associated with decision-making because the licensee did not use conservative assumptions for operability decision-making when evaluating degraded and nonconforming conditions.

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," requires that activities affecting quality shall be prescribed by

instructions, procedures, or drawings, and shall be accomplished in accordance with those instructions, procedures, and drawings. The assessment of operability of safety-related equipment needed to mitigate accidents was an activity affecting quality, and was implemented by Procedure 40DP-9OP26, "Operability Determination and Functional Assessment," Revision 18. Contrary to the above, on February 8, 2007, engineering and operations personnel failed to adequately evaluate degraded and nonconforming conditions to support operability decision-making as described in Procedure 40DP-9OP26. Specifically, operations and engineering personnel failed to consider all relevant information when determining the measured leak rate for an oil leak on CS Pump 1MSIAP03 to perform an adequate OD. Because the finding is of very low safety significance and has been entered into the CAP as PVARs 2968212, 2968501, 2968213, and 2968767, this violation is being treated as an NCV, consistent with Section VI.A of the Enforcement Policy: NCV 05000528/2007002-02, "Failure to Properly Implement Operability Determination Process."

2. Failure to Identify Degraded Conditions

Introduction.

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," for the failure of inservice inspection personnel to promptly identify misalignment of spring cans on safety-related piping. On December 19, 2006 and February 15, 2007, the inspectors identified several spring cans on the auxiliary feedwater system and the EDGs that were misaligned.

Although the misalignments were determined to be in existence for several years, inservice inspection personnel failed to identify the misalignments during previous visual examinations of the piping.

Description.

On February 15, 2007, the inspectors performed a walkdown of the Unit 1 EDGs. During the walkdown, the inspectors noticed that Spring Can 1-SP-100-H-004, associated with the EDG Train A essential spray pond cooling line, was misaligned. Spring Can 1-SP-100-H-004 was a Type F spring can configuration, where the spring can is located underneath the piping and supports the weight of the piping through a load plate attached to the top of the spring can.

Upon further investigation, engineering personnel found that the support beam upon which the spring can rested was skewed and twisted. Engineering personnel concluded that the support beam was improperly welded into place during plant construction, which lead to the skew. They also determined that rigging operations sometime in the past had twisted the beam. The condition was documented in PVAR 2971506.

The inspectors and licensee engineering staff performed a walkdown of the other EDGs onsite. Subsequently, the following Type F spring cans were also found to be misaligned:

• 1-SP-106-H-003 (Unit 1)

• 3-SP-065-H-012 (Unit 3)

• 3-SP-080-H-017 (Unit 3)

• 3-SP-106-H-003 (Unit 3)

Engineering staff initiated PVARs 2974722 and 2975887 to document these conditions. The inspectors also reviewed PVAR 2948071, in which another inspector identified a misaligned Type F spring can (2-AF-018-H-002) on the Unit 2 auxiliary feedwater discharge header from Train B to Steam Generator A.

The inspectors questioned why these spring cans were not found misaligned by the inservice inspections performed under Procedure 73TI-9ZZ18, "Visual Examination of Support Components," Revision 9. Section 8.3.5 of Procedure 73TI-9ZZ18 required examination of piping systems to detect any relevant conditions, including misalignment of supports. Since the auxiliary feedwater discharge header and the EDG essential spray pond cooling lines are Class 1 piping, the licensee was required to perform visual examinations per ASME Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," 1992 Edition (including Addenda through the 1992 Addenda). However, previous visual examinations did not detect the misalignment, although the misalignments were considered to be in place for several years.

In reviewing the misalignments, the inspectors found that there were no misalignment limits for Type F spring cans, particularly in Specification 13-PN-0204, "Fabrication and Installation of Nuclear Piping Systems for the Arizona Public Service Company Palo Verde Nuclear Generating Station Units 1, 2, and 3,"

Revision 12. The same specification did identify misalignment limits for hanging spring cans as +/- 4E between the beam attachment load bolt/pin and the load stud of the pipe clamp when the pipe is at its design operating temperature and pressure.

The vendor manual did not provide misalignment limits for Type F spring cans.

While reviewing the various spring can misalignments, the inspector observed that some of the Type F spring can installations were different from those identified in the vendor manual and Specification 13-PN-0204. Specifically, the Type F spring can configurations illustrated in those documents consisted of the spring can load plate interfacing with a flat plate/pipe stanchion that was welded to the pipe. In some applications of Type F spring cans, the licensee interfaced the spring can load plate directly with the pipe. The potential problem is an increased risk of spring can misalignment, since a flat surface is interfacing with a rounded surface. The inspectors concluded that while this particular Type F configuration may be allowable, it should at least be evaluated and identified as stated in Specification 13-PN-0204.

Analysis.

The performance deficiency associated with this finding was the failure of inservice inspection personnel to promptly identify misalignment of spring cans on safety related piping. The finding is greater than minor because it would become a more significant safety concern if left uncorrected in that the failure to identify degraded and non-conforming equipment conditions could impact the availability of mitigating equipment. The finding affected the mitigating systems cornerstone.

Using the Inspection Manual Chapter 0609, "Significance Determination Process,"

Phase 1 Worksheet, the finding is determined to have very low safety significance since it did not represent a loss of system safety function, an actual loss of safety function of a single train for greater than its TS allowed outage time, or screen as potentially risk-significant due to a seismic flooding, or severe weather initiating

event. The finding has a crosscutting aspect in the area of problem identification and resolution, associated with corrective action program, since inservice inspection personnel had an inappropriately high threshold for recognizing the misalignment of spring cans on safety-related piping.

Enforcement.

10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action,"

requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are promptly identified and corrected. Contrary to this, between April 2005 and May 2006, inservice inspection personnel failed to identify misalignment of spring cans associated with the auxiliary feedwater system and the EDGs. Procedure 73TI-9ZZ18, "Visual Examination of Support Components," Revision 9, Section 8.3.5, required that the examination of piping systems should be directed to detect any relevant conditions, including misalignment of supports. Because the finding is of very low safety significance and has been entered into the CAP as PVAR 2980767, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000528; 05000529;05000530/2007002-03, "Failure to Identify Misalignment of Spring Cans."

1R19 Post-Maintenance Testing

a. Inspection Scope

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

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

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

(3) reviewed the test procedure to ensure it adequately tested the safety function that may have been affected. The inspectors either witnessed or reviewed test data to verify that acceptance criteria were met, plant impacts were evaluated, test equipment was calibrated, procedures were followed, jumpers were properly controlled, the test data results were complete and accurate, the test equipment was removed, the system was properly re-aligned, and deficiencies during testing were documented. The inspectors also reviewed the UFSAR to determine if the licensee identified and corrected problems related to post maintenance testing.

• January 12, 2007, Unit 2, replacement of essential cooling water Train A pump seal following maintenance per Procedure 31MT-9EW01, "Essential Cooling Water Pump Disassembly and Assembly," Revision 7

• February 12, 2007, Unit 3, retest associated with Steam Generator 2 steam supply to AFA-P01 bypass Valve SGA-UV-134A per Work Order 2969593

• February 21, 2007, Unit 2, retest of HPSI pump Train A following corrective maintenance and temporary modification installation for bearing oil leakage

• March 8, 2007, Unit 2, stroke test of turbine driven auxiliary feedwater pump steam supply bypass Valve 2JSGAUV0138A per Procedure 73ST-9AF02, "AFA-P01 -

Inservice Test," Revision 36, following valve replacement

• March 9, 2007, Unit 3, Procedure 73TI-9SG03, "ADV 30% Partial Stroke Test,"

Revision 6 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

Unit 2 Short Notice Outage for HPSI Pump Repairs The inspectors reviewed the following risk significant outage activities to verify defense in depth commensurate with the outage risk control plan, compliance with the TSs, and adherence to commitments in response to Generic Letter 88-17, "Loss of Decay Heat Removal:"

(1) the risk control plan;

(2) tagging/clearance activities;

(3) reactor coolant system instrumentation;

(4) electrical power;

(5) decay heat removal;

(6) spent fuel pool cooling;

(7) inventory control;

(8) reactivity control;

(9) containment closure;

(10) heatup and coldown activities;

(11) restart activities; and

(12) licensee identification and implementation of appropriate corrective actions associated with outage activities.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

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

(1) preconditioning;

(2) evaluation of testing impact on the plant;

(3) acceptance criteria;

(4) test equipment;

(5) procedures;

(6) jumper/lifted lead controls;

(7) test data;

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

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of ASME Code requirements;

(12) updating of performance indicator data;

(13) engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test

acceptance criteria were correct;

(14) reference setting data; and

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

• January 17, 2007, Unit 2, surveillance of low pressure safety injection pump per Procedure 73ST-9SI11, "Low Pressure Safety Injection Pumps Miniflow - Inservice Test," Revision 19

• January 28 - 29, 2007, Unit 3, capacity testing of station Batteries 3EPKAF11 and 3EPKCF13 per Procedure 32ST-9PK04, "60-Month Surveillance Test of Station Batteries," Revision 27

• February 3, 2007, Unit 2, Procedure 40ST-9SF01, "CEA Operability Checks,"

Revision 21

• March 5. 2007, Unit 2, inservice test of turbine driven auxiliary feedwater pump per Procedure 73ST-9AF02, "AFA-P01 - Inservice Test," Revision 36

• March 12, 2007, Unit 1, inservice test of main steam isolation Valve MSIV-170 per Procedure 73ST-9SG01, "MSIVs - Inservice Test," Revision 26

• March 22, 2007, Unit 1, Procedure 40ST-9SF01, "CEA Operability Checks,"

Revision 22 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

1. Exceeding Core Element Assembly Insertion Limits

Introduction.

A Green self-revealing NCV of TS Limiting Condition for Operation (LCO) 3.1.6 was identified during the performance of surveillance testing of the control element assemblies (CEAs) when more than one shutdown CEA was less than 144.75 inches withdrawn.

Description.

The control element drive mechanism control system (CEDMCS)provides control signals and the motive power on the magnetic jacks of the control element drive mechanisms to position and hold the reactor CEAs. To verify that each CEA is able to be tripped, the CEAs are exercised every 92 days, by moving them into the core 5 inches from the fully withdrawn position of 150 inches. The movement of 5 inches is adequate to demonstrate motion without causing any power tilt or power oscillation in the core. The CEAs are put into subgroups that are symmetric about the core, to minimize radial power distributions. When exercising the CEAs into the core, the CEDMCS can move a CEA in either a Manual Group, which moves each CEA in a selected group, or in Manual Individual, which can move each CEA individually. To verify the movement of the CEAs, various indicators can be used including the pulse counter indication, reed switch position transmitters

(RSPTs), a CEA position display (CEAPD), and group display on the core protection calculators. The pulse counter does not directly measure CEA position, but determines the position by counting the signals from the CEDMCS. There is an RSPT every 1.5 inches on the CEA extension shaft, but since the CEA moves 0.75 inches every step, the RSPTs do not see every step of CEA movement. The CEAPD is a wide range indication that shows 0 to 150 inches by bar indication on a computer screen. The direction of movement of the CEAs is also noted on the CEDMCS panel by up and down indicating arrows.

On February 3, 2007, Unit 2 operations personnel were performing surveillance Procedure 40ST-9SF01, CEA Operability Checks," Revision 21, to verify the freedom of movement of the CEAs. The method was to step in a selected group 5 steps (3.75 inches) in Manual Group, and then insert each CEA individually another 2 steps (1.5 inches) in Manual Individual to complete the total exercise of 5.25 inches. At approximately 1232 hours0.0143 days <br />0.342 hours <br />0.00204 weeks <br />4.68776e-4 months <br />, the four CEAs in shutdown Subgroup 6 were tested and inserted normally, but failed to withdraw to greater than 144.75 inches.

The failure to withdraw was not immediately noticed by operations personnel. The reactor operator (RO) was monitoring pulse counter indication, CEAPDs indication, and the CEA withdrawal arrows. Based on the indications used, the RO believed that the CEAs were withdrawn greater than 144.75 inches. At 1315 hours0.0152 days <br />0.365 hours <br />0.00217 weeks <br />5.003575e-4 months <br />, the RO attempted to withdraw the CEAs in Manual Group to 150 inches; however, when the upper electrical limit light failed to illuminate, it became self-evident that the CEAs had not moved as expected. Operations personnel entered TS LCO 3.0.3 since more than one shutdown CEA was less than 144.75 inches withdrawn. Maintenance personnel were notified of the failure and commenced troubleshooting activities per Work Mechanism 2966511.

The licensee determined that the cause of the problem was the result of a failed capacitor on a Phase Sync Card, and corrected the condition. At 1616 hours0.0187 days <br />0.449 hours <br />0.00267 weeks <br />6.14888e-4 months <br />, CEAs in Subgroup 6 were withdrawn to the fully withdrawn position to restore compliance with TS LCO 3.1.6, and exited TS LCO 3.0.3.

The licensee's investigation determined the direct cause of the entry into TS LCO 3.0.3 was caused by the inability to ascertain CEA movement by RSPT indication when moving the CEAs a maximum of two steps by pulse counter indication. It is difficult to detect a movement of 1.5 inches using the CEAPD since the screen does not show all the CEAs at the same height due to the difference in RSPT indication for each CEA. The licensees investigation also concluded that the RO did not use good operator fundamentals since all indications for CEA movement were not monitored which contributed to the event. On March 9, 2007, Procedure 40ST-9SF01 was revised to incorporate requirements to use RSPT indication to confirm that each CEA was withdrawn greater than 144.75 prior to movement of the next CEA. On March 22, 2007, the inspectors observed performance of surveillance Procedure 40ST-9SF01, CEA Operability Checks,"

Revision 22, and concluded that the implemented corrective actions were effective.

In December 2004, operations personnel initiated CRDR 2760855, which identified the difficulty in using pulse counters to verify that each CEA has moved 5.25 inches while performing Procedure 40ST-9SF01, and recommended that all available

indication, including RSPT indication, be used to ensure proper system response.

The condition report action items associated with this CRDR were closed with no actions taken.

Analysis.

The performance deficiency associated with this finding was the failure of operations personnel to ensure that no more than one shutdown CEA was less than 144.75 inches withdrawn. The finding is greater than minor because it is associated with mitigating systems and barrier integrity cornerstone attributes and affects both cornerstone objectives. The finding is associated with the mitigating systems cornerstone attribute of procedure quality and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding is also associated with the barrier integrity cornerstone attribute of configuration control and affects the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radio nuclide releases caused by accidents or events. Using the Manual Chapter 0609, Significance Determination Process," Phase 1 Worksheet, a Phase 2 analysis is required since two cornerstones are affected.

Manual Chapter 0609, Appendix M, "Significance Determination Process Using Qualitative Criteria," was used since the Significance Determination Process methods and tools were not adequate to determine the significance of the finding.

The finding is determined to have very low safety significance through management review since it did not represent a loss of system safety function in that the CEAs were still capable of shutting down the reactor in response to any postulated accident. This finding has a crosscutting aspect in the area of a problem identification and resolution associated with CAP, because the licensee failed to thoroughly evaluate the problem described in CRDR 2760855 such that the issue was resolved. This finding also has a crosscutting aspect in the area of human performance associated with work practices because operations personnel did not appropriately self and peer check all available CEA position indications to ensure proper system response.

Enforcement.

Technical Specification LCO 3.1.6 requires that all shutdown CEAs shall be withdrawn to greater than 144.75 inches. Contrary to the above, on February 3, 2007, while performing surveillance Procedure 40ST-9SF01, "CEA Operability Checks," Revision 21, more than one CEA was less than 144.75 inches withdrawn. Specifically, operations personnel did not use all available CEA position indications while verifying movement of the four CEAs in shutdown Subgroup 6 to ensure that each CEA was withdrawn greater than 144.75 prior to movement of the next CEA. Because this violation is of very low safety significance and has been entered into the CAP as CRDR 2967976, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy:

NCV 05000529/2007002-04, "Inadequate Monitoring of CEA Position Results in Technical Specification Violation"

2. Inoperable Main Steam Isolation Valve While Performing Inservice Testing

Introduction.

A Green self-revealing NCV of TS 5.4.1.a was identified for the failure of operations personnel to follow procedure which resulted in declaring both actuator trains for main steam isolation Valve MSIV-170 inoperable.

Description.

On March 12, 2007, at 9:10am, Unit 1 operations personnel commenced the performance of Procedure 73ST-9SG01, "MSIVs - Inservice Test,"

Revision 26, Section 8.3, "SGE-UV-170 Partial Stroke Exercise (Train B)." During this exercise, the hydraulic accumulator for Train B depressurized to less than 5000 psig as expected, which resulted in the Train B actuator to be declared inoperable, in accordance with TS 3.7.2, Condition A. During the partial stroke exercise, MSIV-170 closed to the 10% close exercise limit, then reopened.

At the completion of this exercise, operations personnel noted that the Train A MSIV handswitch indicated an intermediate position. This condition is not uncommon. It is possible to have intermediate indication of the opposite train main steam isolation valve (MSIV) handswitch, due to limit switch arrangement. Procedure 73ST-9SG01, Section 6.0, "Personnel Indoctrination," and the pre-job brief (tailboard) paperwork discussed this possibility, and directed operations personnel to ensure both accumulators were greater than 5000 psig, prior to positioning the opposite train handswitch to the open position to clear the intermediate indication. However, before the Train B accumulator had repressurized above 5000 psig, operations personnel placed the Train A handswitch to the open position. This resulted in the Train A accumulator depressurizing below 5000 psig while the Train B accumulator was also below 5000 psig. As a result, both actuator trains for MSIV-170 were inoperable. At 0929 hours0.0108 days <br />0.258 hours <br />0.00154 weeks <br />3.534845e-4 months <br />, operations personnel entered TS 3.7.2, Conditions D and F, and declared MSIV-170 inoperable. TS 3.7.2, Condition F, requires that the MSIV be restored to operable status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. At 0942 hours0.0109 days <br />0.262 hours <br />0.00156 weeks <br />3.58431e-4 months <br />, the Train A accumulator was restored to greater than 5000 psig, and MSIV-170 was declared operable.

Analysis.

The performance deficiency associated with this finding involved the failure of operations personnel to follow procedure which resulted in declaring both actuator trains for MSIV-170 inoperable. The finding is greater than minor because it is associated with the human performance attribute of the mitigating systems cornerstone and affects the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding is determined to have very low safety significance because the condition only affected the mitigating systems cornerstone and did not represent an actual loss of safety function. This finding has a crosscutting aspect in the area of human performance associated with work practices because operations personnel did not follow procedures or the guidance from the pre-job briefing that would have prevented an MSIV from becoming inoperable and the entry into a short duration TS condition.

Enforcement.

Technical Specification 5.4.1.a requires that written procedures be established, implemented, and maintained covering the activities specified in Regulatory Guide 1.33, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 8, requires procedures for performing surveillance tests.

Procedure 73ST-9SG01, "MSIV - Inservice Test," Revision 26, provided instructions for performing surveillance testing of safety-related valves. Contrary to the above, on March 12, 2007, operations personnel failed to follow Procedure 73ST-9SG01 which

resulted in declaring both actuator trains of MSIV-170 inoperable. Specifically, operations personnel did not follow the procedure or guidance from the pre-job brief and recognize a condition that could result in the inoperability of both MSIV actuator trains. Had operations personnel followed procedures, and waited for the Train B accumulator to recover to greater than 5000 psig before placing the Train A handswitch to open, they would not have rendered both trains inoperable. Upon recognition of the abnormal condition, operations personnel took action to restore operability. Because the finding is of very low safety significance and has been entered into the CAP as CRDR 2982116, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000528/2007002-05, "Failure to Follow Procedures Results in Declaring Both Actuator Trains of Main Steam Isolation Valve MSIV-170 Inoperable."

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the UFSAR, plant drawings, procedure requirements, and TSs to ensure that the below listed temporary modification was properly implemented. The inspectors:

(1) verified that the modifications did not have an effect on system operability/availability;

(2) verified that the installation was consistent with modification documents;

(3) ensured that the post-installation test results were satisfactory and that the impact of the temporary modifications on permanently installed SSCs were supported by the test;

(4) verified that the modifications were identified on control room drawings and that appropriate identification tags were placed on the affected drawings; and

(5) verified that appropriate safety evaluations were completed. The inspectors verified that the licensee identified and implemented any needed corrective actions associated with temporary modifications.

• February 20 - 23, 2007, Unit 2, Temporary Modifications 2972154 and 2972262, for the installation of increased capacity oil bearing reservoirs on HPSI pumps Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1EP1 Exercise Evaluation

a. Inspection Scope

The inspectors reviewed the objectives and scenario for the 2007 biennial emergency plan exercise to determine if the exercise would acceptably test major elements of the emergency plan. The scenario simulated damage to the condensate storage tank, tube

rupture in a steam generator, an unisolable steam leak outside containment affecting the ruptured steam generator, plant equipment failures, core damage and a radiological release to the environment to demonstrate the licensee's capabilities to implement their emergency plan.

The inspectors evaluated exercise performance by focusing on the risk-significant activities of event classification, offsite notification, recognition of offsite dose consequences, and development of protective action recommendations, in the simulator control room and the following emergency response facilities:

• Technical Support Center

• Operations Support Center

• Emergency Operations Facility The inspectors also assessed recognition of and response to abnormal and emergency plant conditions, the transfer of decision-making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and the overall implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility emergency plan, and emergency plan implementing procedures associated with operation of the above facilities and performance of the associated emergency functions. These procedures are listed in the Attachment to this report.

The inspectors compared the observed exercise performance with the requirements in the facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50 Appendix E; and with the guidance in the emergency plan implementing procedures and other federal guidance.

The inspectors attended the post-exercise critiques in each of the above facilities to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management.

The inspectors completed one sample during the inspection.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

For the below listed drill and simulator-based training evolution contributing to Drill/Exercise Performance and Emergency Response Organization Performance Indicators, the inspectors:

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

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

properly identifying failures; and

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

• January 31, 2007, emergency preparedness Scenario 07-D-FSD-01001 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control To Radiologically Significant Areas (71121.01)

a. Inspection Scope

This area was inspected to assess the licensees performance in implementing physical and administrative controls for airborne radioactivity areas, radiation areas, high radiation areas, and worker adherence to these controls. The inspector used the requirements in 10 CFR Part 20, the TSs, and the licensees procedures required by TSs as criteria for determining compliance. During the inspection, the inspector interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspector performed independent radiation dose rate measurements and reviewed the following items:

• Performance indicator events and associated documentation packages reported by the licensee in the Occupational Radiation Safety Cornerstone

• Conformity of electronic personal dosimeter alarm set points with survey indications and plant policy; workers knowledge of required actions when their electronic personnel dosimeter noticeably malfunctions or alarms

• Adequacy of the licensees internal dose assessment for any actual internal exposure greater than 50 millirem Committed Effective Dose Equivalent

• Self-assessments, audits, and special reports related to the access control program since the last inspection

• Corrective action documents related to access controls

• Licensee actions in cases of repetitive deficiencies or significant individual deficiencies

• Radiation exposure permit briefings and worker instructions

• Changes in licensee procedural controls of high dose rate-high radiation areas and very high radiation areas The inspector completed 11 of the required 21 samples.

b. Findings

Introduction.

A Green self-revealing NCV of TS 5.7.1 was identified for the failure to follow a radiation exposure permit requirement.

Description.

On October 3, 2006, two radioactive material mechanics entered containment to install blocks in spring cans for support of temporary shielding installations. The workers were on a high radiation area exposure permit and obtained a briefing from radiation protection personnel for areas they were designated to enter.

Because no activities were planned for high radiation areas, radiation protection personnel did not discuss high radiation area entries with the workers. However, during the work activity, an additional spring can was identified below the 117' grating in a high radiation area. The workers discussed, among themselves, a plan to access the spring can and one worker then proceeded to climb down from the 117' elevation walkway to reach the can. Upon returning to the 117' elevation, this workers electronic dosimeter was in a dose alarm. The licensees investigation into the alarm revealed the worker had entered a posted high radiation area without a briefing and direct authorization from radiation protection personnel.

Analysis.

The failure to follow a radiation exposure permit requirement is a performance deficiency. The finding is greater than minor because it is associated with the human performance attribute of the occupational radiation safety cornerstone and affected the cornerstone objective to ensure the adequate protection of the worker health and safety from exposure to radiation. The failure to follow a radiation exposure permit requirement for a high radiation area lead to additional personnel dose. The finding was determined to be of very low safety significance because it did not involve:

(1) an as low as reasonably achievable (ALARA) planning and controls,

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose.

This finding had a crosscutting aspect in the area of human performance associated with work practices because the workers did not use the human error prevention techniques of self and peer checking so that work activities are performed safely.

Enforcement.

Technical Specification 5.4.1.a requires that procedures listed in Regulatory Guide 1.33, Revision 2, Appendix A, be established, implemented and maintained. Section 7(e). of the regulatory guide lists procedures for access control to radiation areas including a radiation work permit system. Procedure 75DP-9RP01, "Radiation Exposure and Access Control," Revision 8, Section 3.6.2.1, states, in part, that by signing a radiation exposure permit, individuals have indicated they read and understood the radiation exposure permit requirements and will comply with them.

Radiation Exposure Permit 2-3512 states, in part, that radiation protection authorization is required before accessing high radiation areas. This authorization included a high radiation area specific briefing. Contrary to the above, on October 3, 2006, a radioactive material mechanic entered a posted high radiation area without a briefing and direct authorization from radiation protection personnel. Because this finding is of very low

safety significance and has been entered into the CAP as CRDR 2929853, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000529/2007002-06, "Failure to Follow a Radiation Exposure Permit Requirement."

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspector assessed licensee performance with respect to maintaining individual and collective radiation exposures ALARA. The inspector used the requirements in 10 CFR Part 20 and the licensees procedures required by TSs as criteria for determining compliance. The inspector interviewed licensee personnel and reviewed:

• Current 3-year rolling average collective exposure

• Six work activities from previous work history data which resulted in the highest personnel collective exposures

• Site-specific trends in collective exposures, plant historical data, and source-term measurements

• Site-specific ALARA procedures

• Six work activities of highest exposure significance completed during the last outage

• ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements

• Intended versus actual work activity doses and the reasons for any inconsistencies

• Integration of ALARA requirements into work procedure and radiation work permit (or radiation exposure permit) documents

• Person-hour estimates provided by maintenance planning and other groups to the radiation protection group with the actual work activity time requirements

• Dose rate reduction activities in work planning

• Post-job (work activity) reviews

• Assumptions and basis for the current annual collective exposure estimate, the methodology for estimating work activity exposures, the intended dose outcome, and the accuracy of dose rate and man-hour estimates

• Method for adjusting exposure estimates, or replanning work, when unexpected changes in scope or emergent work were encountered

• Exposure tracking system

• Self assessments, audits, and special reports related to the ALARA program since the last inspection

• Resolution through the corrective action process of problems identified through post-job reviews and post-outage ALARA report critiques

• Corrective action documents related to the ALARA program and followup activities, such as initial problem identification, characterization, and tracking

• Effectiveness of self-assessment activities with respect to identifying and addressing repetitive deficiencies or significant individual deficiencies The inspector completed 11 of the required 15 samples and 7 of the optional samples.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

Cornerstone: Initiating Events

The inspectors sampled licensee submittals for the three PIs listed below for the period January 2006 to December 2006, for Units 1, 2 and 3. The definitions and guidance of Nuclear Energy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the licensees basis for reporting each data element in order to verify the accuracy of PI data reported during the assessment period. The inspectors reviewed licensee event reports, monthly operating reports, and operating logs as part of the assessment. Licensee PI data were also reviewed against the requirements of Procedures 93DP-0LC09, "Data Collection and Submittal Using INPO's Consolidated Data Entry System," Revision 6 and 70DP-0IP01, "Performance Indicator Data Mitigating Systems Cornerstone," Revision 3.

C Unplanned Scrams Per 7,000 Critical Hours C Unplanned Scrams With Loss Of Normal Heat Removal C Unplanned Power Changes Per 7,000 Critical Hours The inspectors completed three samples during the inspection.

Cornerstone: Emergency Preparedness

The inspectors sampled licensee submittals for the PIs listed below for the period January through December 2006. The definitions and guidance of Nuclear Energy Institute 99-02, "Regulatory Assessment Indicator Guideline," Revisions 2 through 4, and the Licensee Performance Indicator Procedures 16DP-0EP19, "Performance Indicator Emergency Preparedness Cornerstone," Revision 2, and 93DP-0LC09, "Data

Collection and Submittal using INPO's Consolidated Data Entry System," Revision 6, were used to verify the accuracy of the licensees evaluations for each performance indicator reported during the assessment period.

• Drill and Exercise Performance

• Emergency Response Organization Participation

• Alert and Notification System Reliability The inspectors reviewed a sample of drill and exercise scenarios and licensed operator simulator training sessions, notification forms, attendance and critique records associated with training sessions, drills, and exercises conducted during the verification period. The inspectors reviewed 26 selected emergency responder qualification, training, and drill participation records. The inspectors reviewed alert and notification system testing procedures, maintenance records, and a 100 percent sample of siren test records. The inspector also reviewed other documents listed in the attachment to this report.

The inspector completed three samples during the inspection.

Cornerstone: Occupational Radiation Safety

The inspector reviewed licensee documents from April 1, 2006, through December 31, 2006. The review included corrective action documentation that identified occurrences in locked high radiation areas (as defined in the licensees TSs), very high radiation areas (as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in NEI 99-02). Additional records reviewed included as low as reasonably achievable records and whole body counts of selected individual exposures. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the performance indicator data. In addition, the inspector toured plant areas to verify that high radiation, locked high radiation, and very high radiation areas were properly controlled. Performance indicator definitions and guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the basis in reporting for each data element.

• Occupational Exposure Control Effectiveness The inspector completed the required sample

(1) in this cornerstone.

Cornerstone: Public Radiation Safety

The inspector reviewed licensee documents from April 1, 2006, through December 31, 2006. Licensee records reviewed included corrective action documentation that identified occurrences for liquid or gaseous effluent releases that exceeded performance indicator thresholds and those reported to the NRC. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the performance indicator data. Performance indicator definitions and guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 4, were used to verify the basis in reporting for each data element.

• Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences Documents reviewed by the inspectors are listed in the attachment.

The inspector completed the required sample

(1) in this cornerstone.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

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

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

The inspectors:

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

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

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

.2 Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the below listed issue for a more in-depth review. The inspectors considered the following during the review of the licensee's actions:

(1) complete and accurate identification of the problem in a timely manner;

(2) evaluation and disposition of operability/report ability issues; (3)consideration of extent of condition, generic implications, common cause, and previous occurrences;

(4) classification and prioritization of the resolution of the problem; (5)identification of root and contributing causes of the problem;

(6) identification of corrective actions; and

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

C March 16, 2007, Unit 1, completed review of CRDR 2950136 root cause of failure analysis for EDG Train B flange leak on 5-L fuel injection pump Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.3 Semiannual Trend Review of Unit 2 EDG Train B Fuel Oil Issues

a. Inspection Scope

The inspectors completed a semi-annual trend review of repetitive or closely related issues that were documented in corrective action and corrective maintenance documents, to identify trends that might indicate the existence of more safety significant issues. Documents reviewed by the inspectors are listed in the attachment.

• The inspectors performed a trend review of issues involving the Unit 2 EDG Train B fuel oil supply system

b. Findings and Observations

Introduction.

The inspectors identified a Green NCV of TS LCO 3.8.1 for exceeding the allowed outage time for the Unit 2 EDG Train B.

Description.

On April 21, 2005, the licensee completed a visual inspection of the Unit 2 EDG Train B fuel oil day tank. This activity involved draining, accessing the internal portion of the tank, and visually inspecting the tank. Following inspection, the tank was reassembled and filled with fuel oil. No cleaning of the tank was done. The licensee conducted a 24-hour surveillance test run of EDG Train B followed by a four-hour run on May 6 through 8, 2005. During these tests, the differential pressure (D/P) across the fuel oil discharge filters increased from 1.6 psid to 7 psid. The fuel oil discharge filters are located on the discharge side of the engine driven fuel oil pump. These filters are a duplex design with filters on two sides that can be shifted from one side in service to the other side while the unit is in operation. EDG Train B was declared operable on May 14, 2005.

On May 25, 2005, the licensee conducted a monthly surveillance test run of EDG Train B during which time the fuel oil discharge filter D/P increased to 8.7 psid and a EDG B Lo Priority Trouble Alarm on fuel filter high D/P was received. The alarm set point across these filters is 10 psid. A work control document was written for this high D/P condition following this run and the discharge filter was replaced 56 days later on July 20, 2005.

On August 11, 2005, EDG Train B was started for a monthly surveillance test. During this test, momentary fuel oil suction strainer high D/P alarms were received. The suction strainers are located between the fuel oil day tank and the engine driven fuel oil pump. The suction strainers are also of the duplex design with strainers on two sides that can be shifted from one side to the other while the unit is operating. The highest local reading across this strainer during this run was 3.9 psid. The alarm set point across these strainers is 5 psid.

On September 8, 2005, EDG Train B was started for a monthly surveillance test run.

During this test, four momentary EDG B Low Priority Alarms were received due to high D/P across the fuel oil suction strainer. The highest local reading across this strainer during this test was 4 psid.

On October 5, 2005, EDG Train B was started for a monthly surveillance test. The fuel oil suction strainer D/P was running between 4 and 4.5 psid during this run. The suction strainer was shifted from the 11B side to the 11A side. Following this run, a work control document was written to clean/replace the 11B fuel oil suction strainer due to the high D/P condition.

On November 2, 2005, EDG Train B was started for a monthly surveillance test run.

During this run, EDG B Low Priority Trouble Alarms were received due to high D/P across the fuel oil suction strainer. The 11A fuel oil suction strainer was still in service.

Operations personnel noted that there was an open work control document for the 11B strainer such that the action to shift to the standby strainer could not be taken. The surveillance test was completed and a work control document was written to determine the reason for the 11A fuel oil suction strainer fouling after only approximately four hours of diesel run time.

On November 3, 2005, the 11B fuel oil suction strainer was inspected and cleaned.

Mechanics found the strainer very dirty and plugged. Later that same day, mechanics started the inspection of the 11A strainer and found a filter cartridge installed in the location where a strainer cartridge should have been. CRDR 2844023 was written to document this condition and a strainer cartridge was installed. A filter cartridge is a much finer mesh than a strainer cartridge and would tend to foul at a much faster rate.

The inspectors noted that at no time did the licensee consider the EDG Train B inoperable due to the conditions described above. During a review of EDG issues during the period of January 16 through 26, 2007, the inspectors questioned the appropriateness of the licensees actions regarding these events. Specifically, the inspectors questioned the lack of trending of available data and the failure to identify a condition adverse to quality resulting in an EDG that was not able to perform its safety function without significant actions by station personnel in the event of a loss of off-site electrical power. As a result of these questions, the licensee generated significant CRDR 2963482 and performed a detailed root cause analysis to determine the causes, corrective actions, and extent of condition of this situation.

As a result of the root cause analysis investigation, the licensee determined that EDG Train B was inoperable for the period between May 14, 2005 and November 3, 2005, a period of 173 days. The inoperability determination was based on the amount of operator and station personnel intervention required to respond to the fouled strainer not being consistent with what is normally allowed to support operability.

As part of this detailed root cause evaluation, the licensee performed an examination of the ability of EDG Train B to function for the mission time with both sides of the duplex suction strainer showing high D/P. The mission time is defined as seven days of continuous operation. The licensee determined that a maximum of 22 psid across the suction strainer could be developed before the engine would experience degraded performance due to fuel starvation. Depending on the assumed filter loading rate, there would be from between approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> up to over 127 hours0.00147 days <br />0.0353 hours <br />2.099868e-4 weeks <br />4.83235e-5 months <br /> of available engine run time after the high D/P alarm is received at 5 psid prior to the engine experiencing fuel starvation or loss of load carrying capability. The licensee estimated that no more

than seven hours would be required to change out or clean the stainers which could be done while the EDG was operating. The inspectors reviewed this evaluation and considered it adequate to bound the conditions.

Analysis.

The performance deficiency is associated with the failure to identify and correct a condition that rendered EDG Train B inoperable for a time period greater than that allowed by TSs. This finding is more than minor because the failure to identify and correct this deficiency would become a more significant safety concern in that the performance of EDG Train B could be reduced, due to fuel starvation to the engine, to the point that the unit would not be able to carry essential electrical loads in the event of a loss of off-site electrical power. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 Worksheet, the finding was determined to have very low safety significance because it did not result in an actual loss of safety function for greater than its TS allowed outage time. The finding has a crosscutting aspect in the area of problem identification and resolution, associated with corrective action program, since the licensee failed to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity.

Enforcement.

Technical Specification 3.8.1, AC Sources - Operating, Limiting Condition for Operation 3.8.1.b requires that two diesel generators each capable of supplying one train of the onsite Class 1E AC Electrical Power Distribution System be operable. TS Required Action B.4 of this section specifies the required action with one DG inoperable as "Restore DG to OPERABLE status" with a completion time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Contrary to this, for the period between May 14, 2005 and November 3, 2005, the licensee failed to maintain the EDG Train B operable, exceeding the TS allowed outage time. Specifically, the licensee did not identify a condition in which the associated fuel oil suction strainers and discharge filters were fouling such that the EDG Train B would be unable to supply Train B of the onsite Class 1E AC Electrical Power Distribution System without significant operations and maintenance personnel actions.

The EDG Train B was inoperable for a time period of 173 days. Because this violation is of very low safety significance and has been entered into the CAP as CRDR 2963482, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000529/2007002-07, "Failure to Maintain EDG Train B Operable."

.4 Multiple/Repetitive Degraded Cornerstone Column Follow-up Activities

As described in the Palo Verde Annual Assessment letter of March 2, 2007, the performance of Unit 3 was assessed to be in the Multiple/Repetitive Degraded Cornerstone column (Column 4) of the NRC's Action Matrix due to identification of two separate safety significant inspection findings (one Yellow and one White) in the Mitigating Systems cornerstone. As a result of the transition to Column 4, the licensee began reevaluating their performance improvement plan. The licensee agreed to inform the NRC when their performance improvement plan has been revised and action plans developed to support an assessment of their corrective actions to improve plant performance.

On April 3, 2007, the NRC conducted a public annual assessment meeting where they discussed the licensees decline in performance and NRC actions to address this performance. In addition, the NRC established weekly teleconferences and conducted periodic discussions with licensee management to monitor their progress in addressing their performance deficiencies and substantive crosscutting issues. The NRC also met with the licensee at NRC headquarters to discuss the conduct of their independent safety culture assessment. From April 3 - April 18, 2007, NRC inspectors observed numerous licensee briefings for the administration of their safety culture survey.

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

Elsewhere Section 1R15.2 describes a finding where inservice inspection personnel had an inappropriately high threshold for recognizing degraded and nonconforming conditions.

Section 1R22 describes a finding where the licensee failed to thoroughly evaluate a problem and implement corrective actions to resolve the issue.

Section 4OA2 describes a finding where the licensee failed to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity.

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

a. Inspection Scope

Personnel Performance The inspectors:

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

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

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

• On February 7, 2007, a main turbine generator trip and reactor power cutback to 48 percent power occurred to Unit 2. The event occurred during planned testing of the thrust bearing wear detector lower test per Procedure 40OP-9MT02, "Main Turbine" Revision 55. The licensee's investigation of the event determined that the failure was an electrical component failure, although the exact electrical component was not determined. The licensee revised Procedure 40OP-9MT02 to test the thrust bearing wear detector only at the direction of the control room supervisor. The licensee does not plan to test the thrust bearing wear detector until modifications are made to the test circuitry. This event was documented in CRDR 2967761.

• On February 25, 2007, a reactor startup was in progress for Unit 2, in accordance with Procedure 40OP-9ZZ03, "Reactor Startup," Revision 44. The CEAs had been pulled in sequence with Regulating Group 3 at 20 inches. The inverse multiplication

(1/M) plots for startup Channel 1 indicated that the previous two CEA withdrawals would result in an anticipated critical position of more than 500 percent millirho from the estimated critical position. In accordance with Procedure 40OP-9ZZ03, the regulating groups were fully inserted and adequate shutdown margin was verified.

This event was documented in CRDR 2967761.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

a. Inspection Scope

The inspectors reviewed the mid-cycle INPO assessment dated January 18, 2007

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On January 12, 2007, the radiation protection inspectors presented the occupational radiation safety inspection results, with an emphasis on ALARA, to Mr. C. Eubanks, Vice President, Operations, and other members of his staff who acknowledged the findings.

On March 9, 2007, the emergency preparedness inspectors presented the inspection results to Mr. R. Eddington, Senior Vice President, and other members of his staff who acknowledged the findings.

The resident inspectors presented the inspection results to Mr. R. Bement, Vice President, Nuclear Operations, and other members of the licensee's management staff at the conclusion of the inspection on March 30, 2007. The licensee acknowledged the findings presented.

The inspectors confirmed that proprietary information was not provided or examined during the inspections.

4OA7 Licensee-Identified Violations

The following violation of very low significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section VI.A of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.

• Technical Specification 5.7.2 states, in part, that areas accessible to personnel with radiation levels such that an individual could receive in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> a dose greater than 1000 mrem shall be provided with locked or continuously guarded doors to prevent unauthorized entry. On October 3, 2006, during shiftly rounds, a radiation protection technician found the 140' containment incore instrumentation tower hatch locked but that the slack in the cable permitted unauthorized personnel access. This event was documented in the licensees corrective action program as CRDR 2929812. The finding was determined to be of very low safety significance because it did not involve:

(1) ALARA planning and controls,

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Andrews, Director, Performance Improvement

S. Bauer, Department Leader, Regulatory Affairs

R. Bement, Vice President, Nuclear Operations

P. Borchert, Director, Operations

P. Brandjes, Department Leader, Maintenance

R. Buzard, Senior Consultant, Regulatory Affairs

D. Carnes, Director, Nuclear Assurance

P. Carpenter, Unit Department Leader, Operations

K. Chavet, Senior Consultant, Regulatory Affairs

D. Coxon, Unit Department Leader, Operations

R. Eddington, Senior Vice President, Nuclear

D. Elkington, Consultant, Regulatory Affairs

C. Eubanks, Vice President, Nuclear Operations

J. Gaffney, Director, Radiation Protection

T. Gray, Department Leader, Radiation Protection

D. Hautala, Senior Compliance Engineer

R. Henry, Site Rep., SRP

J. Hesser, Vice President, Engineering

M. Hooshmand, Section Leader, Systems Engineering

V. Huntsman, Technical Management Assistant, Radiological Services, Radiation Protection

M. Karbasian, Director, Engineering

D. Marks, Section Leader, Regulatory Affairs

M. McGhee, Unit Department Leader, Operations

S. McKinney, Department Leader, Operations Support

J. Mellody, Department Leader, PV Communications

E. O<Neil, Department leader, Emergency Preparedness

M. Perito, Plant Manager, Nuclear Operations

C. Podgurski, Section Leader, Dosimetry/Technology, Radiation Protection

J. Proctor, Section Leader, Regulatory Affairs - Compliance

M. Radspinner, Section Leader, Systems Engineering

T. Radtke, General Manager, Emergency Services and Support

F. Riedel, Director, Nuclear Training Department

J. Scott, Section Leader, Nuclear Assurance

M. Shea, Director, 95003

E. Shouse, Representative, EPE

M. Sontag, Department Leader, Performance Improvement

D. Straka, Senior Consultant, Regulatory Affairs

K. Sweeney, Department Leader, Systems Engineering

J. Taylor, Nuclear Project Manager, PNM

B. Theile, Site Manager, Design Engineering

D. Vogt, Section Leader, OPS STA

M. Wagner, Section Leader, ALARA Planning, Radiological Services, Radiation Protection

T. Weber, Section Leader, Regulatory Affairs

J. Wood, Department Leader, Nuclear Training Department

C. Zell, Director, Work Management

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000528;05000529; NCV Inadequate Change to Emergency Diesel Generator Intake

05000530/2007002-01 Air Oil Bath Filter Standby Oil Level Specification (Section 1R04)

05000528/2007002-02 NCV Failure to Properly Implement Operability Determination Process (Section 1R15.1)

05000528;

05000529; NCV Failure to Identify Misalignment of Spring Cans

05000530/2007002-03 (Section 1R15.2)

05000529/2007002-04 NCV Inadequate Monitoring of CEA Position Results in Technical Specification Violation (Section 1R22.1)

05000528/2007002-05 NCV Failure to Follow Procedures Results in Declaring Both Actuator Trains of Main Steam Isolation Valve MSIV-170 Inoperable (Section 1R22.2)

05000529/2007002-06 NCV Failure to Follow a Radiation Exposure Permit Requirement (Section 2OS1)

05000529/2007002-07 NCV Failure to Maintain EDG Train B Operable (Section 4OA2)

Discussed

None