IR 05000498/2006003

NRC Integrated Inspection Report 05000498-06-003 and 05000499-06-003

ML062220153
Person / Time
Site:	South Texas
Issue date:	08/10/2006
From:	Clay Johnson NRC/RGN-IV/DRP/RPB-A
To:	Sheppard J South Texas
References
IR-06-003
Download: ML062220153 (35)

Text

ust 10, 2006

SUBJECT:

SOUTH TEXAS PROJECT ELECTRIC GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000498/2006003 AND 05000499/2006003

Dear Mr. Sheppard:

On July 7, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your South Texas Project Electric Generating Station, Units 1 and 2, facility. The enclosed integrated report documents the inspection findings which were discussed on , 2006, with you and 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.

This report documents one self-revealing finding of very low safety significance (Green).

Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. However, because of the very low safety significance and because you entered it into your corrective action program, the NRC is treating this violation as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest this noncited violation in this report, 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 South Texas Project Electric Generating Station, Units 1 and 2, facility.

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

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

Sincerely,

/RA/

Claude E. Johnson, Chief Project Branch A Division of Reactor Projects Dockets: 50-498 50-499 Licenses: NPF-76 NPF-80

Enclosure:

NRC Inspection Report 05000498/2006003 and 05000499/2006003 w/Attachment: Supplemental Information and Significant Determination Process Phase 3 on Cold Overpressure Mitigation System

REGION IV==

Dockets: 50-498, 50-499 Licenses: NPF-76, NPF-80 Report: 05000498/2006003 and 05000499/2006003 Licensee: STP Nuclear Operating Company Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: FM 521 - 8 miles west of Wadsworth Wadsworth, Texas 77483 Dates: April 8 through July 7, 2006 Inspectors: T. Brown, Project Engineer K. Clayton, Operations Engineer J. Dixon, Senior Resident Inspector P. Elkmann, Emergency Preparedness Inspector J. Taylor, Resident Inspector G. Werner, Senior Project Engineer, PBD Approved By: Claude E. Johnson, Chief Project Branch A Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000498/2006003, 05000499/2006003; 04/08/06 - 07/07/06; South Texas Project Electric

Generating Station, Units 1 & 2; Integrated Resident and Regional Report, Event Follow-up The report covered a 3-month period of inspection by resident inspectors, project engineers and announced inspections by regional inspectors. Two Green findings, one of which was a licensee-identified noncited violation, were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using 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 managements 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

C

Green.

A self-revealing finding was identified for the failure to provide an adequate procedure, which resulted in an unexpected initiation of a Generator U/F (Under-Frequency) Loss of Field Voltage alarm. This alarm would have caused a generator/turbine/reactor trip in 30 seconds. Prompt action by the operators to terminate the test prevented the trip. The licensee performed a thorough root cause of the event to determine the short and long term corrective actions.

This finding was greater than minor because it was associated with the procedure quality attribute affecting the Initiating Event Cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. This finding was determined to be a finding of very low safety significance because, although the likelihood of a reactor trip increased, the likelihood that mitigating systems would not be available did not increase and no transient actually occurred (Section 4OA3).

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at essentially 100 percent rated thermal power throughout the inspection period.

Unit 2 operated at essentially 100 percent rated thermal power throughout the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

Readiness for Seasonal Susceptibilities

a. Inspection Scope

The inspectors completed a review of the licensee's readiness of seasonal susceptibilities involving hurricanes. The inspectors:

(1) reviewed plant procedures, the Updated Safety Analysis Report (USAR), 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 one system listed below to ensure that adverse weather protection features (heat tracing, space heaters, weatherized enclosures, temporary chillers, etc. . .) were sufficient to support operability, including the ability to perform safe shutdown functions;

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

(4) reviewed the corrective action program (CAP) to determine if the licensee identified and corrected problems related to adverse weather conditions.

C June 1, 2006, Units 1 and 2: Hurricane supply storage room inventory and general site cleanliness Documents reviewed by the inspectors included:

Operating Procedure 0PGP03-ZV-0001, Severe Weather Plan, Revision 13 Operating Procedure 0PGP03-ZV-0002, Hurricane Plan, Revision 0 The inspectors completed sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

Partial Walkdown

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 licensee's CAP to ensure problems were being identified and corrected.

• April 19, 2006, Unit 1: The inspectors verified the alignment of essential cooling water (ECW) Train A during and following a Train B outage. The inspectors verified the valve, control panel, local switch, and electrical lineups in accordance with Operating Procedure 0POP02-EW-0001, Essential Cooling Water Operations, Revision 37.

• Unit 1: The inspectors verified the alignment and condition of auxiliary feedwater Train B while Train A was out of service. The inspectors verified that the auxiliary feedwater system equipment and control board were aligned in accordance with Operating Procedure 0POP02-AF-0001, Auxiliary Feedwater, Revision 22.

Operation, Revision 44.

The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

Quarterly Inspection

a. Inspection Scope

The inspectors walked down the six 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 CAP to determine if the licensee identified and corrected fire protection problems.

• April 10, 2006, Units 1 and 2: ECW intake structure (Fire Zones Z600-605)

• April 13, 2006, Unit 1: Safety injection cubicles (Fire Zones Z305-307)

• April 13, 2006, Unit 2: Isolation valves cubicles (Fire Zones Z401-405)

• Reactor containment building (Fire Zones Z207-214)

The inspectors completed samples.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactor operators on June 20, 2006, to identify deficiencies and discrepancies in the training, to assess operator performance, and to assess the evaluator's critique. The training scenario involved a plant cooldown from Mode 3 to Mode 4 with a failure of the cold overpressure mitigation system (COMS).

Documents reviewed by the inspectors included:

Operating Procedure 0POP03-ZG-0007, Plant Cooldown, Revision 46 Operating Procedure 0POP04-RP-0005, COMS Actuation or Failure, Revision 11

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the two 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.

• April 17-19, 2006, Unit 1: Preventative Maintenance Work Order PM MV-1-90001551 (WAN 290741), Containment Emergency Sump 1B to Safety Injection Train B Pumps Suction Isolation MOV Operator (ORC), for Valve SI-0016B inspection, lubrication, and static diagnostic test

• June 19-23, 2006, Units 1 and 2: ECW system health report, plan of action to address emergent maintenance, all ECW reports (CRs) from June 1, 2005, through June 23, 2006, and risk management review for CR 06-4982 The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management of Risk

a. Inspection Scope

The inspectors reviewed the six 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.

• April 27, 2006, Unit 2: Evaluation of risk for Train B equipment outage which included the 5 year standby diesel generator maintenance outage (Evaluation 1355)

• May 2, 2006, Unit 2: Evaluation of risk assessment process during loss of plant Radiological Assessment System for Consequence Analysis capability during Standby Diesel Generator 22 maintenance with Lane-Bay City Temporary 138kV line outage (one of two lines to the emergency transformer)

• May 11, 2006, Units 1 and 2: Evaluation of risk for both units during planned equipment outages and concurrent main switchyard modifications

• June 9, 2006, Unit 1: Evaluation of risk for the week during planned equipment outages on Train A with emergent issues associated with emergency response facility data acquisition and display system (ERFDADS) inverter and digital rod position indication power supply

• June 16, 2006, Unit 2: Evaluation of risk for the week during planned equipment outages on Train A

• June 30, 2006, Units 1 and 2: Evaluation of risk for the week during Unit 1 personnel air lock seal replacement concurrent with planned maintenance and Unit 2 freeze seal on pressurizer liquid sample line with planned maintenance The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R14 Operator Performance During Nonroutine Evolutions and Events

a. Inspection Scope

For the two nonroutine events described below, the inspectors:

(1) reviewed operator logs, plant computer data, and/or strip charts to evaluate operator performance in coping with nonroutine events and transients;

(2) verified that the 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 nonroutine evolutions sampled.

• June 2, 2006, Unit 2: Control room operator response to an unplanned grid voltage reduction, and recovery, due to main generator reactive power capability testing (See Section 4OA3 for additional information)

• June 6, 2006, Unit 2: Control room operator response to a fire in the ERFDADS inverter in the 4160 Volt Train B safety-related switchgear room

The inspectors completed two samples.

b. Findings

The inspectors reviewed the licensees response to a fire in a nonvital inverter in vital switchgear room Train B. The first indication of an inverter problem was several control board alarms associated with ERFDADS, part of the integrated computer system. All control board alarms cleared immediately. Several minutes later a smoke alarm was received and a control room operator was dispatched to investigate. Within the next minute a second smoke alarm was received. The operator reported to the control room that the fire was located in the vicinity of the Transformer T1 associated with the ERFDADS uninterruptible power supply (UPS) inverter.

The operators used four CO2 extinguishers to control/extinguish the fire, and the control room instructed the operators to open the breakers associated with the transformer. A continuous fire watch was posted and the fire brigade reported to the scene to evaluate the fire being out. The total time from identification to extinguishing the fire was approximately 8 minutes. Since the fire lasted less than 15 minutes, the licensee was not required to declare an unusual event.

This fire occurred in the same component on Unit 1 on March 23, 2006, (for additional information on this event see NRC Inspection Report 05000498/2006002 and 05000499/2006002, Section 4OA3) and consequently the Unit 2 transformer was scheduled to be replaced within the next several months. The inspectors reviewed the licensees corrective actions from the first fire, to determine if appropriate corrective actions had been completed, and determined that appropriate measures had been implemented to address the concern. The inspectors did not identify any issues or concerns with the licensees response or timeliness of corrective actions.

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 USAR 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.

• June 8, 2006, Unit 1: Engineering evaluation of grease fitting found in compensator housing of containment isolation motor-operated Valve 1SIMOV0004C (CR 06-6802)

• June 8, 2006, Units 1 and 2: Engineering evaluation of loose emergency core cooling systems pump shaft sleeve retaining ring setscrews (CR 06-7459 and -7494)

• June 14, 2006, Unit 1: Engineering evaluation of ECW Train A self-cleaning strainer leak (CR 06-7085)

• July 5, 2006, Unit 2: Evaluation of vital Battery E2D11 computer indications (CR 06-8407)

• July 6, 2006, Unit 2: Engineering evaluation of main steam isolation valve bypass valve actuator volume booster leak (CR 06-8160)

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors selected the six 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) 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 realigned, and deficiencies during testing were documented. The inspectors also reviewed the USAR to determine if the licensee identified and corrected problems related to postmaintenance testing.

• April 14, 2006, Unit 1: Centrifugal charging Pump 1B air handling Unit 11B

• June 6-7, 2006, Unit 1: Preventative Maintenance Work Order PM:MMI-1-01000411, RHR Heat Exchanger 1A Outlet Valve, Revision 3, and RHR system Design Change Package 03-9384-88, Replace I/P Transducer for A1RHHCV-0864"

• June 5-6, 2006, Unit 1: ECW Train A self-cleaning strainer gasket replacement and system drain and refill

• June 12-13, 2006, Unit 2: Essential chilled water expansion tank pressure relief valve replacement per Design Change Package 05-4753-2

• June 13, 2006, Unit 2: Preventative Maintenance Work Order PM:MV-2-90001483, Hi Head Safety Injection Pump 2A Discharge to Loop 2A Hot Leg Isolation MOV Operator, Revision 3

• June 26-28, 2006, Unit 1: Personnel air lock reactor containment building side inner door seal and air supply tee fitting replacement Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the USAR, 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 demonstrated TS operability;

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of ASME Code requirements;

(12) updating of performance indicator (PI) 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.

• April 14, 2006, Unit 1: Operating Procedure 0PSP03-SP-0010B, Train B ESF Load Sequencer Manual Local Test, Revision 16

• April 24, 2006, Unit 1: Operating Procedures 0PSP03-RS-0001, Monthly Control Rod Operability, Revision 20 and 0PEP02-RS-0001, Control Rod Axial Repositioning, Revision 4

• April 26, 2006, Unit 1: Operating Procedure 0PSP03-DG-0003, Monthly Standby Diesel 13(23) Operability Test, Revision 30

• April 27, 2006, Unit 2: Operating Procedure 0PEP07-ZE-0008, Non-Intrusive Check Valve Testing, Revision 5

• June 13, 2006, Unit 2: Operating Procedure 0PSP03-CC-0007, Component Cooling Water System Train 1A(2A) Valve Operability Test, Revision 13, for inside containment isolation Valves MOV-0068 and -0049

• June 15, 2006, Unit 2: Operating Procedure 0PSP03-RC-0006, Reactor Coolant Inventory, Revision 1 The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

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

The inspectors:

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

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

(3) ensured that the postinstallation test results were satisfactory and that the impact of the temporary modification 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 licensee identified and implemented any needed corrective actions associated with temporary modifications.

• April 13, 2006, Unit 1: Temporary Modification T1 06-0195-1, removal of Panel DPL 434 temporary power installed during load center 1N outage (CR 06-0195-3)

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 2006 biennial emergency plan exercise to determine if the exercise would acceptably test major elements of the emergency plan. The scenario simulated a fire in a vital area lasting more than

15 minutes, mechanical damage to the core from loose parts, a reactor coolant leak which progressed to a loss of coolant accident, progressive core damage and a radiological release to the environment from a recirculation line leak in the fuel handling building.

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 dedicated 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 postexercise 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 one below listed drill and simulator-based training evolution contributing to drill/exercise performance and emergency response organization, PIs, 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, Regulatory Assessment Performance Indicator Guideline, Revision 2, acceptance criteria.

On May 17, 2006, the inspectors observed a drill in the simulator control room. The scenario included the following:

• Failure of a low pressure turbine rotor

• Loss of offsite power with the failure of two standby diesel generators

• Main Steam Line B rupture in the turbine building

• Steam Generator B tube rupture The inspectors completed one sample.

b. Findings

No findings of significance were identified.

4OA1 PI Verification

Cornerstone: Initiating Events

a. Inspection Scope

The inspectors sampled licensee submittals for the three PIs listed below for the period January 2004 through March 2006, for Units 1 and 2. The definitions and guidance of NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 2, were used to verify the licensees basis for reporting each data element in order to verify the accuracy of PI data reported during the assessment period. The inspectors reviewed licensee event reports (LER), monthly operating reports, and operating logs as part of the assessment. Licensee PI data was also reviewed against the requirements of Operating Procedures 0PGP05-ZN-0007, Preparation and Submittal of NRC Performance Indicators, Revision 1, and 0PGP05-ZV-0013, Performance Indicator Tracking Guide, Revision 1.

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.

b. Findings

No findings of significance were identified.

Cornerstone: Emergency Preparedness

a. Inspection Scope

The inspectors reviewed licensee evaluations for the three emergency preparedness cornerstone PIs of drill and exercise performance, emergency response organization participation, and alert and notification system reliability for the period October 1, 2005, through March 31, 2006. The definitions and guidance of NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revisions 2 and 3, and the licensee PI Operating Procedures 0PGP05-ZN-0007, Preparation and Submittal of NRC Performance Indicators, Revision 2, and 0PGP05-ZV-0013, Performance Indicator Tracking Guide, Revision 1, were used to verify the accuracy of the licensees evaluations for each PI 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 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.

C Drill and exercise performance C Emergency response organization participation C Alert and notification system reliability The inspectors completed three samples.

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 licensees CAP.

This assessment was accomplished by reviewing work orders, CRs, etc. . . and attending corrective action review and work control meetings. The inspectors:

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

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

(3) identified conditions that might warrant additional

follow-up through other baseline inspection procedures. The inspectors used the licensees Operating Procedure 0PGP03-X-002, Condition Reporting Process, Revision 30, for understanding the threshold level for generating a CR.

b. Findings

No findings of significance were identified.

.2 Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors selected the one below listed issue for a more in-depth review. The inspectors considered the following during the review of the licensees 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.

• July 7, 2006, Units 1 and 2: The inspectors completed an in-depth review of various failures associated with inverters, capacitors, and transformers. Notably, the recent failures of the Units 1 and 2 ERFDADS transformers that resulted in fires as well as failures of capacitors that have resulted in degraded inverter output.

Documents reviewed by the inspectors are listed in the attachment.

b. Findings

No findings of significance were identified.

.3 Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semi-annual trend review of repetitive or closely related issues that were documented in trend reports, problem lists, PIs, health reports, quality assurance audits, corrective action documents, etc. . . to identify trends that might indicate the existence of more safety significant issues. The inspectors review consisted of the 6-month period of January 1 through June 30, 2006. When warranted, some of the samples expanded beyond those dates to fully assess the issue. The inspectors compared and contrasted their results with the results contained in the licensees quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b. Findings

No findings of significance were identified. However, the inspectors did make the following observations which were shared with licensee management. The licensee has captured each of these events in their CAP under various CRs.

• The inspectors observed that during several prejob briefs operating experience from the industry was not being used. The operating experience that was being discussed was limited to events that occurred at the site, even when more current experience was relevant and available. In addition, old operating experience has not been effectively implemented into plant procedures and is a potential challenge to plant operations. The most recent occurrences of this missed opportunity to effectively implement operating experience was with motor-operated valve t-drains and zerk fittings.

• Inverters, capacitors, and transformers continued to be problematic and the number of recent failures may be indicative of a negative trend that might be age related. These failures included an EFRDADS inverter fire in each unit, a couple of failed voltage regulator transformers, and a couple of failed capacitors that power various nonsafety but potentially risk significant components from control room annunciators to digital rod position indication.

.4 Annual Sample Review (Emergency Preparedness)

a. Inspection Scope

The inspectors reviewed eight drill and exercise evaluation reports for drills conducted between May 2004 and February 2006 as listed in the attachment and reviewed summaries of 166 CRs generated between July 1, 2004, and May 31, 2006. Emergency response organization performance during the June 7, 2006, biennial exercise was compared to performance deficiencies identified in previous drill and exercise evaluation reports and emergency preparedness-related CRs to identify adverse performance trends and ineffective corrective actions.

b. Findings

No findings of significance were identified.

4OA3 Event Follow-up

.1 (Closed) LER 05000499/2005003-00, Inoperable Cold Overpressure Mitigation System

The inspectors reviewed LER 05000499/2005003-00 to verify that the cause of the COMS inoperability for more than the TS allowed outage time was identified and that corrective actions were reasonable. The inoperability was declared for Unit 2 due to discovery of the potential for COMS inoperability while preparing to install the same

modification during the Unit 1 refueling outage. The modification was completed during the previous Unit 2 refueling outage, but the condition for inoperability was not identified at that time. The licensee documented this failure in CR 05-3071. The enforcement aspects are discussed in Section 4OA7. This LER is closed.

.2 (Closed) LER 05000499/2005001-00, Unit 2 Shutdown Due to Reactor Coolant System

Pressure Boundary Leak The inspectors reviewed LER 05000499/2005001-00 to verify that the cause of the RCS pressure boundary leak requiring a Unit 2 shutdown on February 9, 2005, was identified and that corrective actions were reasonable. The leak, from a 3/4-inch vent line off of the A cold leg safety injection line, was determined to be unisolable and Unit 2 was shutdown to MODE 5 in accordance with TS 3.4.6. The root cause of the leak was determined to be a crack propagating from a flaw in a socket weld due to high cycle fatigue. The condition resulted in no personnel injuries, no offsite radiological releases, and no damage to safety-related equipment other than the leaking weld joint. No findings of significance were identified and no violation of NRC requirements occurred.

The licensee documented this failure in CRs 05-1620 and -1749. This LER is closed.

.3 Main Generator Reactance Testing

a. Inspection Scope

The inspectors reviewed CR 06-7272 identifying that a Unit 2 reactive and power capability test was terminated due to receipt of an unexpected Generator U/F (Under-Frequency) Loss of Field Voltage alarm. The inspectors also reviewed completed Operating Procedure 0POP07-GM-0001, Reactive and Power Capability Test, Revision 2, and earlier revisions, and discussed the test with licensee personnel.

b. Findings

Introduction.

A Green self-revealing finding was identified for the failure to provide an adequate procedure, which resulted in an unexpected initiation of a Generator U/F (Under-Frequency) Loss of Field Voltage alarm condition which would have opened the main generator breakers in 30 seconds.

Description.

On June 3, 2006, the licensee was performing a main generator reactive power capability test to meet Electric Reliability Council of Texas requirements. Unit 2 LEAD reactive power was being increased from 0 to 420 megavoltamps reactive (MVAR) when a 95% Generator Output Voltage computer point alarm was received.

The test was temporarily halted and the alarm evaluated against the generator capability curves, but protective relaying effects and how the lower generator voltage affected them were not considered. The test was resumed and continued to approximately 390 MVAR when the Generator U/F (Under-Frequency) Loss of Field Voltage alarm was received. This alarm coincided with initiation of a protective relaying 30-second

timer to open the main generator breakers. Prompt action by the operators and test director to stop the test and raise generator voltage back above the alarm setpoint (approximately 17 seconds) averted a generator and, therefore, a turbine and reactor trip.

Analysis.

The performance deficiency associated with this event is a failure to develop an adequate procedure in accordance with the provisions of Procedure , Plant Procedures, Revision 9. This resulted in the subsequent development and implementation of an inadequate Procedure 0POP07-GM-0001, which led to the unexpected receipt of a Generator U/F (Under-Frequency) Loss of Field Voltage alarm and initiation of a main generator trip timing relay. This event had an actual impact of initiating a relay operation that would have led to a reactor trip if it had not been immediately corrected by operator response.

This finding was greater than minor because it was associated with the procedure quality attribute affecting the Initiating Event Cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. This finding was determined to be a finding of very low safety significance (Green) because, although the likelihood of a reactor trip increased, the likelihood that mitigating systems would not be available did not increase and no transient actually occurred.

Enforcement.

No violation of regulatory requirements occurred. The inspectors determined that the finding did not represent a noncompliance because it occurred on nonsafety-related equipment. Licensee personnel entered this issue into the CAP as CR 06-7272. This issue is being treated as a finding: FIN 05000499/2006003-01, Inadequate Main Generator Reactive Power Test Procedure.

4OA5 Other

Implementation of Temporary Instruction (TI) 2515/165 - Operational Readiness of Offsite Power and Impact on Plant Risk TI 2515/165, Operational Readiness of Offsite Power and Impact on Plant Risk, was performed on March 6-17, 2006. For additional information and documentation see NRC Inspection Report 05000498/2006002 and 05000499/2006002, Section 4OA5, including the Errata to NRC Inspection Report 05000498/2006002 and 05000499/2006002.

4OA6 Meetings, Including Exit

On June 9, 2006, the inspectors conducted an on-site debrief meeting to discuss preliminary inspection results with Mr. E. Halpin, Site Vice President/Plant General Manager, and other members of his staff. On June 20, 2006, the inspectors conducted a telephonic exit meeting with Mr. P. Serra, Manager, Plant Protection, and other members of his staff, who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

The results of the resident inspection were presented to Mr. James J. Sheppard, President and Chief Executive Officer, and other members of licensee management on July , 2006. Mr. Claude E. Johnson, Chief, Project Branch A, Division of Reactor Projects was also present at this exit meeting.

4OA7 Licensee-Identified Violations

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

• TS 3.9.4.3 requires, in part, that with both PORVs unavailable, the RCS must be depressurized and vented through at least a 2-square inch vent within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Contrary to the above, in March 2004 during Refueling Outage 2RE10 a modification was made which de-energized both solid state protection system trains, which made COMS inoperable. This condition was identified in Unit 2 during a review process that resulted from identifying a similar condition that would have existed during Refueling Outage 1RE12. Refueling Outage 1RE12 work was rearranged such that COMS operability was not a concern, but the condition was determined to have existed for approximately 39 hours4.513889e-4 days <br />0.0108 hours <br />6.448413e-5 weeks <br />1.48395e-5 months <br /> 53 minutes without the required actions being completed in Unit 2 during Refueling Outage 2RE10. The licensee entered this failure into their CAP as CR 05-3071. Manual Chapter 0609, Significance Determination Process, Appendix G, Shutdown Operations Significance Determination Process, requires that any finding associated with low temperature overpressure protection be evaluated using a significance determination process Phase 3 analysis. The Phase 3 analysis determined that the issue was of very low safety significance, the entire Phase 3 analysis can be found in Attachment 2.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Bowman, Manager, Operations

W. Bullard, Manager, Health Physics

J. Calvert, Manager, Operations Training

K. Coates, Manager, Maintenance

J. Crenshaw, General Manager Oversight

T. Frawley, Manager Performance Improvement

R. Gangluff, Manager, Chemistry

R. Grantum, Manager, PRA

E. Halpin, Site Vice President/Plant General Manager

W. Harrison, Senior Engineer, Quality and Licensing

S. Head, Manager, Licensing

B. Jenewel, Supervisor, Engineering

T. Jordan, Assistant to CEO

J. Jump, Manager, Process Improvement Leadership Team

S. Kasper, Shift Supervisor

M. Kistler, Specialist, Licensing

M. McBurnett, Manager, Nuclear Safety Assurance

L. Meier, Acting Supervisor, Emergency Preparedness

M. Meier, General Manager, Station Support

W. Mookhoek, Senior Engineer, Licensing

A. Morgan, Supervisor, Emergency Response

G. Powell, Manager, System Engineering

D. Rencurrel, Manager, Plant Engineering

M. Ruvalcaba, Supervisor, Systems Engineering

R. Savage, Staff Specialist, Licensing

C. Sayko, Co-Owner Liaison

P. Serra, Manager, Plant Protection

J. Sheppard, President and CEO

D. Stillwell, Supervisor, Configuration Control and Analysis

K. Taplett, Senior Engineer, Licensing

NRC

J. Dixon, Senior Resident Inspector

G. Apger, Operations Engineer

R. Patterson, Physical Security Inspector

Attachment

Other

J. Mitchell, Sheriff, Matagorda County

J. Nortan, Mayor, City of Palacios

G. Westmoreland, County Judge, Matagorda County

R. Watts, Emergency Management Coordinator, Matagorda County

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000499/2006003-01 FIN Inadequate Main Generator Reactive Power Test Procedure (Section 4OA3)

Closed

05000499/2005-001 LER Unit 2 Shutdown Due to RCS Pressure Boundary Leak (Section 4OA3)

05000499/2005-003 LER Inoperable Cold Overpressure Mitigation System (Section 4OA3)

Discussed

None