IR 05000275/2007004

IR 05000275-07-004 and 05000323-07-004; Pacific Gas and Electric Company; 07/01/2007 Through 09/30/2007; Diablo Canyon Power Plant, Units 1 and 2

ML072990316
Person / Time
Site:	Diablo Canyon
Issue date:	10/26/2007
From:	Vincent Gaddy NRC/RGN-IV/DRP/RPB-B
To:	Keenan J Pacific Gas & Electric Co
References
IR-07-004
Download: ML072990316 (37)

Text

ber 26, 2007

SUBJECT:

DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000275/2007004 AND 05000323/2007004

Dear Mr. Keenan:

On September 30, 2007, the U.S. Nuclear Regulatory Commission completed an inspection at your Diablo Canyon Power Plant, Units 1 and 2, facility. The enclosed integrated report documents the inspection finding that was discussed on October 3, 2007, with John Conway and members of your staff.

This 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.

This report documents one self-revealing finding of very low safety significance. However, because of its very low risk significance and because it is entered into your corrective action program, the NRC is treating this as a green finding.

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

Vincent G. Gaddy, Chief Project Branch B Division of Reactor Projects

Pacific Gas and Electric Company -2-Dockets: 50-275 50-323 Licenses: DPR-80 DPR-82

Enclosure:

NRC Inspection Report 05000275/2007004 and 05000323/2007004 w/attachment: Supplemental Information

REGION IV==

Dockets: 50-275, 50-323 Licenses: DPR-80, DPR-82 Report: 05000275/2007004 05000323/2007004 Licensee: Pacific Gas and Electric Company Facility: Diablo Canyon Power Plant, Units 1 and 2 Location: 7 1/2 miles NW of Avila Beach Avila Beach, California Dates: July 1 through September 30, 2007 Inspectors: T. Jackson, Senior Resident Inspector M. Peck, Senior Resident Inspector M. Brown, Resident Inspector D. Allen, Senior Resident Inspector, Comanche Peak G. Pick, Senior Reactor Inspector, Engineering Branch 2 J. Melfi, Resident Inspector, Palo Verde P. Elkmann, Emergency Preparedness Inspector G. George, Reactor Inspector, Engineering Branch 1 S. Graves, Reactor Inspector, Engineering Branch 1 S. Makor, Reactor Inspector, Engineering Branch 1 Approved By: V. G. Gaddy, Chief, Projects Branch B Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000275/2007-004, 05000323/2007-004; 7/1/07 - 9/30/07; Diablo Canyon Power Plant

Units 1; Maintenance Effectiveness.

This report covered a 13-week period of inspection by resident inspectors and announced inspections on emergency preparedness, safety evaluations and heat exchangers. One self-revealing finding (Green) was identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609 Significance Determination Process. Findings for which the Significance Determination Process does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified after an inadequate main turbine maintenance procedure resulted in an unplanned load reduction and a reactor shutdown. On August 9, 2007, the Unit 1 generator output decreased by 60MW due to failed main turbine stop valve. Pacific Gas and Electric Company shut down the plant the following day to repair the failed valve. The valve failed because the maintenance personnel did not properly adjust the external travel stop during outage related maintenance. The travel stop was not properly adjusted because the maintenance procedure did not require the maintenance personnel to verify that the disc was properly back seated against the internal stop during adjustment. This issue was entered into Pacific Gas and Electric Companys Corrective Action Program as Non Conformance Report N0002219.

The finding is greater than minor because if left uncorrected, the condition would become a more significant safety concern. Using Inspection Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the inspectors determined the finding to have very low safety significance because the condition did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding has a crosscutting aspect in the area of human performance, associated with the resources component because PG&E failed to provide an adequate main turbine maintenance procedure (H.2.c) (Section 1R12).

Licensee-Identified Violations

A violation of very low safety significance, which has been identified by Pacific Gas and Electric Company, has been reviewed by the inspectors. Corrective actions taken or planned by Pacific Gas and Electric Company have been entered into their corrective action program. This violation and corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

At the beginning of the inspection period, Pacific Gas and Electric Company (PG&E) was operating Diablo Canyon Unit 1 at full power. An unplanned power reduction to 95 percent rated thermal power occurred on August 9, 2007, after a main turbine stop valve disc separated from the swing arm, partially restricting steam flow. On August 10, PG&E shutdown Unit 1 and repaired the stop valve. The licensee restarted the reactor on August 16 and achieved full power on August 19. PG&E operated Unit 1 at full power for the remainder of the inspection period.

Pacific Gas and Electric operated Unit 2 at full power for the duration of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

The inspectors completed a review of PG&Es readiness for seasonal susceptibilities involving extreme storm surges and high temperatures. The inspectors:

(1) reviewed plant procedures, the Final Safety Analysis Report (FSAR) Update, and Technical Specifications (TSs) to ensure that operator actions defined in adverse weather procedures maintained the readiness of essential systems;

(2) walked down portions of the two systems listed below to ensure that adverse weather protection features were sufficient to support operability, including the ability to perform safe shutdown functions;

(3) evaluated operator staffing levels to ensure PG&E could maintain the readiness of essential systems required by plant procedures;

(4) reviewed the communications protocols between PG&E and the transmission operator; and

(5) reviewed the corrective action program (CAP) to determine if PG&E identified and corrected problems related to adverse weather conditions.

• July 11, 2007: Units 1 and 2, 480V Vital switchgear rooms, inverter/charger room and cable spreading room

• September 4, 2007: Units 1 and 2, Ultimate heat sink and intake structure Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples (site-specific and hot weather).

b. Findings

No findings of significance were identified.

1R02 Evaluation of Changes, Tests, or Experiments

a. Inspection Scope

Between September 10 through September 14, 2007, the inspectors reviewed the effectiveness of PG&Es implementation of changes to the facility structures, systems, and components; risk significant normal and emergency operating procedures; test programs; and the FSAR Update in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments."

The inspectors reviewed 7 samples of 10 CFR Part 50.59 safety evaluations. The evaluations were reviewed to verify that licensee personnel had appropriately considered the conditions under which the licensee may make changes to the facility or procedures, or conduct tests or experiments without prior NRCs approval. In addition, the inspectors reviewed 21 samples of 10 CFR Part 50.59 screens, in which licensee personnel determined that evaluations were not required, to ensure that the exclusion of a full evaluation was consistent with the requirements of 10 CFR Part 50.59.

The inspectors reviewed a sample of recent licensee action requests related to the 10 CFR Part 50.59 process to determine whether the licensee had identified problems and entered them into the corrective action program at the appropriate threshold.

The inspection procedure specifies the inspectors review a minimum sample of 5 licensee safety evaluations and a combination of 10 applicability determinations or screening. The inspectors completed a review of 7 licensee safety evaluations and 21 screens/applicability determinations.

Documents reviewed by the inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignments

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors:

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

(2) compared deficiencies identified during the walk down to the FSAR Update and CAP to ensure problems were being identified and corrected.

• July 18, 2007: Unit 1, Seismic trip system

• July 23, 2007: Unit 2, Component cooling water (CCW) system

• August 14, 2007: Unit 1 Control room ventilation system

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

.2 Complete System Walkdowns

a. Inspection Scope

The inspectors:

(1) reviewed plant procedures, drawings, the FSAR Update, TSs, and vendor manuals to determine the correct alignment of the Unit 2 auxiliary feedwater (AFW) system;

(2) reviewed outstanding design issues, operator workarounds, and FSAR Update documents to determine if open issues affected the functionality of the AFW system; and

(3) verified that PG&E was identifying and resolving equipment alignment problems.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors walked down the 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 that they remained functional;

(3) observed fire suppression systems to verify that 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 FSAR Update to determine if PG&E identified and corrected fire protection problems.

• August 2, 2007: Fire Area TB-4, Unit 1, 4 kV F Bus switchgear room and associated cable spreading room

• August 2, 2007: Fire Area TB-5, Unit 1, 4 kV G Bus switchgear room and associated cable spreading room

• August 2, 2007: Fire Area TB-6, Unit 1, 4 kV H Bus switchgear room and associated cable spreading room

• August 3, 2007: Fire Area TB-10, Unit 2, 4 kV F Bus switchgear room and associated cable spreading room

• August 3, 2007: Fire Area TB-11, Unit 2, 4 kV G Bus switchgear room and associated cable spreading room

• August 3, 2007: Fire Area TB-12, Unit 2, 4 kV H Bus switchgear room and associated cable spreading room

• August 14, 2007: Fire Area CR-1, Units 1 and 2 Control room and associated ventilation rooms

• September 23, 2007: Fire Area AB-1, Zone 3N, Unit 2 Safety injection pump rooms Documents reviewed by the inspectors included:

• Diablo Canyon Power Plant Units 1 and 2 FSAR Update, Appendix 9.5A, Fire Hazards Analysis, Revision 17

• Diablo Canyon Power Plant Fire Protection Pre-Plan, dated May 14, 2003 The inspectors completed eight samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

.1 Semi-Annual Internal Flooding

a. Inspection Scope

The inspectors:

(1) reviewed the FSAR Update, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding;

(2) reviewed the FSAR

Update and CAP to determine if PG&E identified and corrected flooding problems;

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

(4) walked down the one below listed area to verify the adequacy of:

(a) equipment seals located below the floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain lines and sumps,

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

(f) temporary or removable flood barriers.

• August 7, 2007: Units 1 and 2, Turbine buildings, elevation 85' Documents reviewed by the inspectors included:

• PG&E, Probabilistic Risk Assessment Calculation File No. F.4 , PRA Internal Floods Analysis, Revision 1

• Component History/Work Order Closure Remarks, LS-16A, dated August 6, 2007 The inspectors completed one internal flooding sample.

b. Findings

No findings of significance were identified.

.2 Annual External Flooding

a. Inspection Scope

The inspectors:

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

(2) reviewed the FSAR Update and CAP to determine if PG&E identified and corrected flooding problems;

(3) inspected underground bunkers to verify the adequacy of:

(a) sump pumps,

(b) level alarm circuits,

(c) cable splices subject to submergence, and

(d) drainage for bunkers/manholes;

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

(5) walked down the one below listed area to verify the adequacy of:

(a) equipment seals located below the floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain lines and sumps,

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

(f) temporary or removable flood barriers.

• August 13, 2007: Units 1 and 2 Intake structure and auxiliary saltwater pump vaults Documents reviewed by the inspectors included PG&E, Probabilistic Risk Assessment Calculation File No. F.4 , PRA Internal Floods Analysis, Revision 1 The inspectors completed one external flooding sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

On September 20, 2007, the inspectors observed a licensed operator evaluation to identify deficiencies and discrepancies in the training to assess operator performance, and to assess the evaluators critique.

Documents reviewed by the inspectors included Lesson ECA3132-A, SGTR With Faulted Steam Generator, Revision 12.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

.1 Routine Maintenance Effectiveness Inspection

a. Inspection Scope

The inspectors reviewed the below listed maintenance activity to:

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

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

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

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

• August 9, 2007: Unit 1, Failure of Main Turbine Stop Valve FCV-146 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction.

The inspectors identified a self-revealing finding after an adequate main turbine repair procedure resulted in an unplanned power reduction and forced outage of Unit 1.

Description.

PG&E failed to develop an adequate main turbine maintenance procedure resulting in an unplanned load reduction and a reactor shutdown. On August 9, 2007, plant operators observed that the Unit 1 generator output had decreased by 60MW. On August 11, PG&E shut down the reactor to investigate the cause of the load reduction.

The licensee determined that the load reduction resulted from inlet steam blockage after the disc on Turbine Stop Valve FCV-146 uncoupling from the stem. The disc uncoupled because the stem nut assembly failed. The stem nut failed due to the flow induced vibration caused by the failure of the stop valve to properly back-seat during power operations. The stop valve did not properly back-seat because the maintenance personnel failed to properly adjust the external travel stop during the turbine maintenance performed during the June 2004 refueling outage. The inspectors concluded that the travel stop was not properly adjusted because Procedure MP M-4.20, HP Turbine Stop Valve Maintenance, Revision 12, did not require maintenance personnel to first verify that the disc was properly back seated against the internal stop during adjustment. Procedure ADI.ID1, Nuclear Generation Procedures, required that procedures be written to clearly state any special limits, tolerances and other requirements in the design and licensing bases, vendor manuals and other documents.

Analysis.

The failure of PG&E to develop an adequate procedure for the main turbine stop valve maintenance was a performance deficiency. The inspectors concluded that the finding is greater than minor because less than adequate turbine maintenance procedure, if left uncorrected, would become a more significant safety concern. Using Inspection Manual Chapter 0609, Significance Determination Process,@ Phase 1 Worksheet, the inspectors determined the finding to have very low safety significance because the condition did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. This finding has a crosscutting aspect in the area of human performance, associated with the resources component because PG&E failed to provide an adequate main turbine maintenance procedure (H.2.c).

Enforcement.

This issue was entered into the licensees corrective program as Non-Conformance Report N0002219. No violation of NRC requirements occurred because the turbine maintenance procedure, Procedure MP M-4.20, was neither Technical Specifications (TS) or quality related (FIN 05000275/2007004-01, Inadequate main turbine repair procedure resulted in an unplanned power reduction and forced outage).

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Risk Assessments and Management of Risk

a. Inspection Scope

The inspectors reviewed the removal of the 230 kV transmission line while Transformer 2-1 was out of service on July 24, 2007. The inspectors conducted the review 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 PG&E recognizes, and/or enters as applicable, the appropriate risk category according to the risk assessment results and licensee procedures; and

(4) PG&E identified and corrected problems related to maintenance risk assessments.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Emergent Work

a. Inspection Scope

The inspectors:

(1) verified that PG&E 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 FSAR Update to determine if PG&E identified and corrected risk assessment and emergent work control problems.

• August 14, 2007: Unit 2, Control Room Ventilation Condenser CR-37 motor replacement with inoperable Condenser CR-38 Documents reviewed by the inspectors included Procedure AD7.DC6, On-line Maintenance Risk Management, Revision 9.

The inspectors completed one sample.

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 standing orders to determine if an operability evaluation was warranted for degraded components;

(2) referred to the FSAR Update and design bases documents to review the technical adequacy of the operability evaluations;

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any TS;

(5) used the Significance Determination Process to evaluate the risk significance of degraded or inoperable equipment; and

(6) verified that PG&E has identified and implemented appropriate corrective actions associated with degraded components.

• August 28, 2007: Degraded Startup Power

• September 12, 2007: Units 1 and 2, Degraded residual heat removal and containment spray motor operated valves

• September 19, 2007: Unit 1, Degraded Auxiliary Feedwater Pump 1-2 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications

a. Inspection Scope

From September 10-14, 2007, the inspectors reviewed seven permanent plant modification packages and associated documentation, such as implementation reviews, safety evaluation applicability determinations, and screening, to verify that they were performed in accordance with regulatory requirements and plant procedures. The inspectors also reviewed the procedures governing plant modifications to evaluate the effectiveness of the program for implementing modifications to risk significant SSCs, such that these changes did not adversely affect the design and licensing basis of the facility.

Further, the inspectors interviewed the cognizant design and system engineers for the identified modifications as to their understanding of the modification packages and process.

The inspectors evaluated the effectiveness of the licensees corrective action process to identify and correct problems concerning the performance of permanent plant modifications by reviewing a sample of related condition reports.

The inspection procedure specifies that the inspector should review a minimum of five sample permanent plant modifications.

The inspectors completed seven samples.

Documents reviewed by the inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors selected the three below listed postmaintenance 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) evaluate 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 the 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 realigned, and deficiencies during testing were documented. The inspectors also reviewed the FSAR Update to determine if PG&E identified and corrected problems related to post-maintenance testing.

• July 12, 2007: Unit 2, Preventive maintenance on Auxiliary Feedwater Pump Discharge Level Control Valves LCV-113 and LCV-115

• August 30, 2007: Unit 1, Replacement of Component Cooling Water Pump 1-2 motor

• September 21, 2007: Unit 2, Corrective maintenance of Reactor Vessel Cavity Sump Level Detector LT-62 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed the plan for the Unit 1 shutdown and repair of the damaged Turbine Stop Valve 1-FCV-146 to verify that PG&E appropriately considered risk, industry experience and previous site specific problems. The inspection was focused on potential deficiencies with plant shutdown and startup, availability of required electrical sources, and maintenance and repair activities.

The inspectors completed one forced outage sample.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the FSAR Update, procedure requirements, and TSs to ensure that the below listed surveillance activities demonstrated that the SSCs tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed the 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) jumpers;

(7) test data;

(8) testing frequency and method demonstrated TS operability;

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of American Society of Mechanical Engineers 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 alarm setpoints. The inspectors also verified that PG&E identified and implemented any needed corrective actions associated with the surveillance testing.

• July 6, 2007: Unit 2, Inservice testing of Auxiliary Saltwater Pump 2-2

• September 5, 2007: Unit 1, Secondary side calorimetric

• September 23, 2007: Unit 1, Diesel generator 1-1, 2- hour surveillance

• September 22, 2007: Unit 2, Reactor coolant system leak rate test Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two routine, one reactor coolant system leakage, and one pump inservice test samples.

b. Findings

No findings of significance were identified.

1EP2 Alert Notification System Testing

a. Inspection Scope

The inspectors discussed with PG&E staff the status of offsite siren and tone alert radio systems to determine the adequacy of the methods for testing the alert and notification system in accordance with 10 CFR Part 50 Appendix E. PG&Es alert and notification system testing program was compared with the criteria in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, Federal Emergency Management Agency (FEMA) Report REP-10, Guide for the Evaluation of Alert and

Notification Systems for Nuclear Power Plants, and PG&Es current FEMA approved alert and notification system design report. The inspectors also reviewed the following procedures:

• EP MT-35, "Site Emergency Signal Audibility Test," Revision 3A

• EP MT-43, "Early Warning System Testing and Maintenance," Revision 8

• EWS Maintenance-Test-Operations Guidance, Revision 6 The inspectors completed one sample during the inspection.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation

a. Inspection Scope

The inspectors discussed with PG&E staff the status of primary and backup systems for augmenting the on-shift emergency response staff to determine the adequacy of the methods for staffing emergency response facilities. The inspectors reviewed the following documents related to the emergency response organization augmentation system to evaluate PG&Es ability to staff the emergency response facilities in accordance with the licensee emergency plan and the requirements of 10 CFR Part 50 Appendix E:

• Evaluation Report for the 2006 Recall Drill

• 2007 ERO On-Call Schedule

• EP-G-3, "Interim Emergency Response Organization," Revision 31

• OM 0.DC2, "Emergency Response Organization On Call," Revision 4 The inspectors completed one sample during the inspection.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspectors reviewed PG&Es CAP requirements in procedures OM7.ID1, "Problem Identification and Resolution, Action Requests," Revision 23, and OM7.ID4, "Root Cause Analysis and Apparent Cause Evaluations," Revision 9. The inspectors reviewed summaries of 448 action requests identified by or assigned to the emergency preparedness department between November 2005 and June 2007, and selected 29 for detailed review against the program requirements. The inspectors evaluated the response to the corrective action requests to determine that PG&Es ability to identify,

evaluate, and correct problems are in accordance with the licensee program requirements and 10 CFR Part 50.47(b)(14) and 10 CFR Part 50 Appendix E. The inspectors also reviewed other documents listed in the attachment to this report.

The inspectors completed one sample during the inspection.

b. Findings

No findings of significance were identified.

1EP6 Force-On-Force (FOF) Exercise Evaluation

a. Inspection Scope

For the exercise below, the inspectors:

(1) observed the evolution to identify any weaknesses and deficiencies in classification, notification, and the protective action requirements development activities, and

(2) reviewed the identified weaknesses and deficiencies against licensee-identified findings to determine whether PG&E is properly identifying deficiencies.

• August 8, 2007, Force-on-Force Drill, Day 2 The inspectors completed one sample during the inspection.

Documents reviewed by the inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

Cornerstone: Emergency Preparedness

a. Inspection Scope

The inspectors reviewed licensee evaluations for the three emergency preparedness cornerstone performance indicators of Drill and Exercise Performance, Emergency Response Organization Participation, and Alert and Notification System Reliability, for the period from October 1, 2006, through June 30, 2007. The definitions and guidance of NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 through 4, and PG&E Procedure, AWP-EP-001, "Emergency Preparedness Performance Indicators,"

Revision 8, were used to verify the accuracy of the licensees evaluations for each performance indicator reported during the assessment period.

The inspectors reviewed a 100 percent sample of drill and exercise scenarios and licensed operator simulator training sessions, notification forms, and attendance and critique records associated with training sessions, drills, and exercises conducted during the verification period. The inspectors reviewed 13 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 inspectors also reviewed other documents listed in the attachment to this report.

The inspectors completed one sample during the inspection.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a daily screening of items entered into the corrective action program. This assessment was accomplished by reviewing action requests and event trend reports, and attending daily operational meetings. The inspectors:

(1) verified that equipment, human performance, and program issues were being identified by PG&E 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.

b. Findings

No findings of significance were identified.

.2 Selected Issue Follow-Up Inspection

a. Inspection Scope

In addition to the daily screening, the inspectors conduct an in-depth review of Action Request A070680, September 10, 2007, related to a fuel handling error. The inspectors considered the following during the review of PG&Es actions:

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

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

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

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

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

(6) identification of corrective actions; and

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

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one in-depth review sample.

b. Findings

The inspectors reviewed a licensee-identified Green noncited violation of TS 5.4.1.a, Procedures. A discussion of this non compliance is provided in Section 4OA7 of this report.

.3 Annual Sample Review

a. Inspection Scope

The inspectors selected three root cause analyses and 39 action requests for detailed review. The reports were reviewed to ensure that the full extent of the issues were identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the action requests against the requirements of licensee Procedures OM7.ID1, "Problem Identification and Resolution, Action Requests," Revision 23, and OM7.ID4, "Root Cause Analysis and Apparent Cause Evaluations," Revision 9.

The inspectors completed one in-depth annual trend review sample.

b. Findings

No findings of significance were identified.

4OA5 Other

.1 (Closed) Unresolved Item 05000275; 05000323/2006005-01: Additional review of

material to determine if the residual heat removal heat exchangers will meet their safety function.

The inspectors had questioned whether PG&E had implemented adequate design control measures to demonstrate that the residual heat removal heat exchangers could perform their design safety function. The inspectors questioned whether the heat exchangers required testing to validate the design calculations and found out that PG&E did not perform the flow verification for each cooler under the Surveillance Test Program. PG&E adjusted the flow through the containment fan cooler units and validated the flow rated for the remaining heat exchangers and coolers by analysis.

During the in-office review, the inspectors determined that PG&E:

(1) had established an appropriate method to ensure that the required heat loads supplied by CCW would receive their design basis flow and

(2) had provided information that the residual heat removal heat exchangers could perform their design basis heat removal function. The inspectors verified that both the reactor coolant system and the closed-loop CCW system had good chemistry controls and had not been contaminated. Consequently,

the inspectors concluded that no additional testing would be required, as described in the Generic Letter 89-13, Supplement 1, "Service Water System Problems Affecting Safety-Related Equipment."

During discussions with design engineering, PG&E agreed that the description in the FSAR Update did not clearly or accurately describe the system operation and response.

PG&E initiated an AR A0704443 to document this deficiency and indicated that they would clarify the description.

Documents reviewed by the inspectors are listed in the attachment.

This unresolved item is closed.

40A6 Meetings, Including Exit

Exit Meeting Summary

On July 12, 2007, the inspectors presented the inspection results on emergency preparedness to Mr. J. Becker, Vice President and Station Director, Diablo Canyon Operations, and other members of his staff, who acknowledged the findings.

On July 25, 2007, the inspector conducted a telephonic meeting with Mr. C. Dougherty, Senior Engineer, Regulatory Services, to discuss the final characterization of one inspection issue on emergency preparedness.

On September 14, 2007, the inspectors presented the results on Inspection Procedure 71111.02, Evaluations of Changes, Tests, or Experiments, and Inspection Procedure 71111.17, Permanent Plant Modifications, to Ms. D. Jacobs, Vice President, Nuclear Services, and other members of licensee management. The licensee's management acknowledged the issues and observations presented.

On September 18, 2007, the inspectors discussed the results of their additional review of the material to determine if the residual heat removal heat exchangers would have met their safety function with Mr. S. Hamilton, Supervisor Regulatory Services. The inspectors returned all proprietary information to PG&E.

On October 3, 2007, the resident inspection results were presented to Mr. John Conway, Site Vice President and other members of PG&E management. PG&E acknowledged the findings presented.

In each case, the inspectors asked PG&E whether any materials examined during the inspection should be considered proprietary. Proprietary information was reviewed by the inspectors and left with PG&E at the end of the inspection.

4OA7 Licensee-Identified Violations

One very low safety significance (Green) violation of NRC requirements was identified by PG&E. This violation met the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as a noncited violation.

• The inspectors reviewed one noncited violation of Technical Specification Procedure 5.4.1.a, after PG&E failed to adequately implement a fuel handling procedure. On September 10, 2007, operations personnel began moving the Unit 2 fuel handling bridge while a spent fuel assembly was still attached and partially inserted into the fuel rack. A second operator identified that the fuel assembly was still latched and alerted the bridge operator to stop the bridge prior to damaging the affected fuel assembly. Operating Procedure, OP B-8H, Spent Fuel Pool Work Instructions, Section 6.2, required the operator to use the load cell to verify that the fuel assemble is disengaged prior to moving the bridge.

Contrary to the above, the operator failed to use the load cell and to verify that the fuel assemble was disengaged prior to moving the bridge.

Pacific Gas and Electric determined that plant operations had not established a qualification process or standard for fuel handlers. None of the operations personnel involved, including the fuel handling senior reactor operator, had previously performed fuel handling activities. Contributing to the event was poor communications between the operators and that the supervisor was physically involved in latching the fuel assembly rather than overseeing the work. The inspectors determined that the finding was of very low safety significance because there was no damage to the fuel assembly. This event was documented in PG&E=s corrective action program as AR A0706980.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

PG&E personnel

J. Becker, Vice President - Diablo Canyon Operations and Station Director

J. Che, Transient and Accident Analysis Engineer

S. Hamilton, Supervisor, Regulatory Services

R. Hite, Manager, Radiation Protection

D. Jacobs, Vice President - Nuclear Services

S. Ketelsen, Manager, Regulatory Services

K. Langdon, Director, Operations Services

R. Lovell, Senior Nuclear Engineer

M. Meko, Director, Site Services

K. Peters, Director, Engineering Services

J. Purkis, Director, Maintenance Services

P. Roller, Director, Performance Improvement

D. Taggart, Manager, Quality Verification

R. Waltos, Manager, Emergency Preparedness

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000275/2007004-01 FIN Inadequate main turbine repair procedure resulted in an unplanned power reduction and forced outage (Section 1R12)

Closed

05000275; URI Additional review of material to determine if the residual

05000323/2006005-01 heat removal heat exchangers will meet their safety function (Section 4OA5)

Attachment