IR 05000397/2005005

IR 05000397-05-005, on 09/24-31/2005, Columbia Generating Station

ML060440627
Person / Time
Site:	Columbia
Issue date:	02/13/2006
From:	Clay Johnson NRC/RGN-IV/DRP/RPB-A
To:	Parrish J Energy Northwest
References
IR-05-005
Download: ML060440627 (49)

Text

ary 13, 2006

SUBJECT:

COLUMBIA GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000397/2005005

Dear Mr. Parrish:

On December 31, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Columbia Generating Station. The enclosed inspection report documents the inspection findings which were discussed on January 5, 2006, with Mr. D. Atkinson and other members of your staff.

The inspections examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents two self-revealing findings. These findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as noncited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest these findings, 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, 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 Columbia Generating Station.

Energy Northwest -2-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.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Claude E. Johnson, Chief Project Branch A Division of Reactor Projects Docket: 50-397 License: NPF-21

Enclosure:

NRC Inspection Report 05000397/2005005 w/attachments

REGION IV==

Docket: 50-397 License: NPF-21 Report: 05000397/2005005 Licensee: Energy Northwest Facility: Columbia Generating Station Location: Richland, Washington Dates: September 24 through December 31, 2005 Inspectors: Z. Dunham, Senior Resident Inspector, Project Branch A, DRP R. Cohen, Resident Inspector, Project Branch A, DRP J. Keeton, Reactor Inspector, NRC Contractor P. Elkman, Emergency Preparedness Inspector, Operations Branch T. McKernon, Senior Operations Engineer D. Stearns, Health Physicist, Plant Support Branch Approved By: C. E. Johnson, Chief, Project Branch A, Division of Reactor Projects ATTACHMENT: Supplemental Information Enclosure

SUMMARY OF FINDINGS

IR05000397/2005005; 9/24/2005 - 12/31/2005; Columbia Generating Station; ALARA Planning and Controls, and Other Activities.

The report covered a 13-week period of inspection by resident inspectors, emergency preparedness inspectors, a health physicist, a senior operations engineer, and a reactor inspector. Two noncited green findings were identified. The significance of most findings is indicated by their color (Green, White, Yellow, 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: Mitigating Systems

Green.

A Green self-revealing noncited violation of 10 CFR Part 50, Appendix B,

Criterion III, "Design Control," was identified because Energy Northwest failed to maintain the design capability of the reactor core isolation cooling system consistent with Final Safety Analysis Report specified design functions.

Following the implementation of a design change in 2001, the reactor core isolation cooling system was not capable under all required plant conditions of initiating automatically upon reaching a predetermined low level in the reactor vessel or restarting automatically with no operator action. Specifically, during conditions where the reactor core isolation cooling system suction header pressure was reduced to that provided by the condensate storage tanks, the reactor core isolation cooling pump would inadvertently trip due to low suction pressure as a result of a momentary hydraulic perturbation in the system which occurred as the system was starting up. The design change made the reactor core isolation cooling system more susceptible to inadvertently tripping.

This finding was more than minor in accordance with Manual Chapter 0612,

Appendix B, in that it was a plant modification design issue which affected the mitigating systems cornerstone attribute of equipment performance and reliability which could impact the ability of the reactor core isolation cooling system to respond to an initiating event. Using Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, the inspectors determined that a Phase 2 evaluation was warranted since an actual loss of system safety function occurred. A subsequent Phase 2 and Phase 3 evaluation were performed. A senior reactor analyst conducted the Phase 3 evaluation using a Standardized Plant Analysis Risk model simulation of the failure of the reactor core isolation cooling pump to automatically start and inject into the reactor coolant system.

The analyst concluded that the core damage frequency associated with the event was 4.3 x 10-8 and that any increase in core risk due to external events was insignificant given the low core damage frequency (< 1 x 10-6). The inspectors concluded that the finding was of very low risk significance.

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing noncited violation was identified for the licensee's failure to have adequate procedures in accordance with Technical Specification 5.4.1.a to prevent the internal contamination of three workers during replacement of a blank flange on the equipment drain system.

This finding was more than minor in that the replacement of a contaminated flange without the use of an adequate radiation work permit was associated with the occupational radiation safetys attribute of procedures for exposure control and affected the cornerstone objective to ensure the adequate protection of the workers health and safety from exposure to radiation from radioactive material.

The cause of the finding is related to the crosscutting aspects of human performance. Using the occupational radiation safety significance determination process, the finding was determined to be of very low risk significance because it did not represent an ALARA or work controls issue, did not involve an overexposure, did not constitute a substantial potential for an overexposure, and did not compromise the ability to assess dose.

Licensee Identified Violations

None.

REPORT DETAILS

Summary of Plant Status:

The inspection period began with Columbia Generating Station at 100 percent power. Except for scheduled reductions in power to accommodate testing and an unscheduled power reduction on November 5 through 6, 2005, to address a condenser tube leak, the plant was maintained at essentially 100 percent power for the entire inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness For Seasonal Susceptibilities

a. Inspection Scope

The inspectors completed a review of the licensee's readiness of seasonal susceptibilities involving extreme cold and freezing temperatures. The inspectors:

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

(2) walked down portions of safety related systems to ensure that adverse weather protection features and system lineup 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 to determine if the licensee identified and corrected problems related to adverse weather conditions.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Readiness For Impending Adverse Weather Conditions

a. Inspection Scope

On November 23, 2005, the inspectors completed a review of the licensee's readiness of the two systems listed below for impending adverse weather involving cold and freezing weather. The inspectors:

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

(2) walked down portions of the systems to ensure that adverse weather protection features were

sufficient to support operability, including the ability to perform safe shutdown functions;

(3) reviewed maintenance records to determine that applicable surveillance requirements were current before anticipated freezing conditions developed; and

(4) reviewed plant modifications, procedure revisions, and operator work arounds to determine if recent facility changes challenged plant operation.

• Standby service water

• Emergency diesel generator HVAC The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignments

.1 Partial Walkdown

a. Inspection Scope

The inspectors:

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

(2) compared deficiencies identified during the walk down to the licensee's corrective action program to ensure problems were being identified and corrected.

• High Pressure Core Spray Diesel Generator; October 20, 2005

• Reactor Feedwater; November 24, 2005 The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Inspection

a. Inspection Scope

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

(1) verified when applicable 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;

(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 when applicable that adequate compensatory measures were established for degraded or inoperable fire protection features; and

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

• Fire Area RC-10; Main Control Room; October 17, 2005

• Fire Area RC-3; Cable Chase; October 11, 2005

• Fire Area RC-5; Battery Room Number 1; October 11, 2005

• Fire Area RC-8; Division #2 Switchgear Room; November 21, 2005

• Fire Area RC-9; Remote Shutdown Room; November 21, 2005

• Fire Area RC-12; Control Room Air Conditioning Unit; November 22, 2005 The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures

.1 Internal Flood Protection

a. Inspection Scope

The inspectors where applicable:

(1) reviewed the Updated Safety Analysis Report, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding;

(2) reviewed the corrective action program to determine if the licensee identified and corrected flooding problems; and

(3) walked down the area listed below to verify the adequacy of floor and wall penetration seals and common drain lines.

• Room 208 Pipe Chase on the 471 foot level; October 31, 2005 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification

.1 Quarterly Inspection of a Licensed Operator Requalification Exam

a. Inspection Scope

On November 8, 2005, the inspectors observed testing and training of senior reactor operators and reactor operators to identify deficiencies and discrepancies in the training, to assess operator performance, and to assess the evaluator's critique. The training

scenario involved the crews ability to respond to a remote air intake radiation monitor (WOA-RIS-31A failure), a seismic event with a major rupture of the reactor closed cooling pumps suction piping, a loss of coolant accident requiring containment sprays, main turbine bypass valves fail to open, and a loss of high pressure feedwater.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

.2 Review of Annual Operating Examination Testing Cycle

a. Inspection Scope

Following the completion of the annual operating examination testing cycle, which ended the week of December 15, 2005, the inspectors reviewed the overall pass/fail results of the annual individual job performance measure operating tests, and simulator operating tests administered by the licensee during the operator licensing requalification cycle.

Seven separate crews participated in simulator operating tests, and job performance measure operating tests, totaling 54 licensed operators. All of the crews, but one, tested passed the simulator portion of the annual operating test. The licensed operators were successfully remediated prior to returning to shift. All of the licensed operators passed the job performance measure portion of the examination. These results were compared to the thresholds established in Manual Chapter 609, Appendix I, "Operator Requalification Human Performance Significance Determination Process."

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the maintenance activities listed below 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 Technical Specifications.

• Emergency Trip of Division 2 Emergency Diesel Generator; September 26, 2005

• High Pressure Core Spray Diesel Generator failed to stop normally and failed to shutdown by emergency tripping; November 2, 2005

• Main Steam Valve MS-V-22A, closed faster than expected during Main Steam Isolation Valve Closure Scram Functional Surveillance; November 23, 2005 The inspectors completed three samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Risk Assessment and Management of Risk

a. Inspection Scope

The inspectors reviewed the risk assessment activities listed below 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.

• Replace 250 VDC Battery cells #226 and #157 while performing scheduled instrumentation and control surveillances; November 21, 2005

• Down Power and work on Main Condenser; November 5 and 6, 2005

• Division II residual heat removal keep-fill pump work and service water Pump B planned surveillances; November 15, 2005

• Service Water Pump 1B pump replacement and Diesel Generator #2 planned outage; December 12-15, 2005 The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R14 Personnel Performance During Nonroutine Plant Evolutions and Events

a. Inspection Scope

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 the operator response was in accordance with the response required by plant procedures and training;

(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.

• Deep-down power to locate main condenser tube leak; November 7, 2005 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors:

(1) reviewed plants 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 Updated Safety Analysis Report 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 Technical Specifications;

(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.

• CR 2-05-09003; DG-GEN-DG2 engine speed setting outside of normal expected band; November 18, 2005

• CR-2-05-08982; Incorrect control power fuses installed for RHR-P-3; November 17, 2005

• CR-2-05-08510; Single Cell charger placed on 250 VDC Battery without regard for proper engineering review for the single cell charger; November 2, 2005

• CR-2-05-09179; Rain water leaking into Division I, Division II and Division III Diesel Rooms; November 25, 2005 The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R16 Operator Workarounds

.1 Cumulative Review of the Effects of Operator Workarounds

a. Inspection Scope

On December 12, 2005, the inspectors reviewed the cumulative effects of operator workarounds to determine:

(1) the reliability, availability, and potential for misoperation

of a system;

(2) if multiple mitigating systems could be affected;

(3) the ability of operators to respond in a correct and timely manner to plant transients and accidents; and

(4) if the licensee has identified and implemented appropriate corrective actions associated with operator workarounds.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

The inspectors selected the postmaintenance test activities of risk significant systems or components listed below for review. 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 corrective action program to determine if the licensee identified and corrected problems related to postmaintenance testing.

• WO 01102358; RHR-V-27B Recovery; September 26, 2005

• WO 01105461; HPCS-V-12 Investigate Overload Trip of MOV; September 27, 2005

• WO 01094756; SW-V-105D and SW-V-107D Repair Leaks; October 5, 2005

• WO 01109759; EB-2-1 Cell 157 Replacement; November 22, 2005 The inspectors completed four samples.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, procedure requirements, and Technical Specifications to ensure that the surveillance activities listed below demonstrated that the 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 Technical Specification 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.

• OSP-LPCS/IST-Q702; LPCS System Operability Test; Revision 15; October 6, 2005

• ISP-CRD-Q902; RPS - Channels B and D 1/2 scram SDV CFT; Revision 7; October 11, 2005

• OSP-RHR-Q703; RHR Loop B Operability Test; Revision 0; October 17, 2005 The inspectors completed three samples which included a review of an in-service pump test.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

The inspectors reviewed the Updated Final Safety Analysis Report, plant drawings, procedure requirements, and Technical Specifications to ensure that the temporary modification listed below 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 post-installation 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 modification was 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.

• TMR 05-019; Support risk management reduction for the Probability Risk Assessment during a station blackout by increasing the availability time of the batteries as a compensatory measure during Diesel Generator 2 outage; November 28, 2005.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1EP2 Alert Notification System Testing

a. Inspection Scope

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

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP3 Emergency Response Organization Augmentation Testing

a. Inspection Scope

The inspector reviewed the following documents related to the emergency response organization augmentation system to determine the licensees ability to staff emergency response facilities in accordance with the licensee emergency plan and the requirements of 10 CFR Part 50, Appendix E.

EPI-19; Communications Tests; Revision 5 PPM 13.10.1; Control Room Operations and Shift Manager Duties; Revision 29 PPM 13.4.1; Emergency Notification; Revision 32

Evaluation Reports for 7 pager and drive-in drills conducted between February 2004 and September 2005 The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

.1 Review of Revision 14

a. Inspection Scope

The inspector performed an in-office review of Revision 14 to the Columbia Generating Station emergency plan implementing Procedure13.1.1.A, Classifying the Emergency -

Technical Bases, received September 8, 2005. This revision:

• Clarified the definition of a failure of the reactor protection system to initiate a reactor scram

• Reworded the description of vital areas in the Turbine Building in 13 emergency action levels

• Added descriptions of the vital areas of the Radwaste/Control Building to 13 emergency action levels

• Deleted the description of a hostile force from 1 emergency action level

• Corrected minor errors in references The revision was compared to its previous revision, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to NEI 99-01, Methodology for Development of Emergency Action Levels, Revision 2, and to the requirements of 10 CFR 50.47(b) and 50.54(q) to determine if the licensee adequately implemented 10 CFR 50.54(q).

The inspector completed one sample.

b. Findings

No findings of significance were identified.

.2 Review of Revision 15

a. Inspection Scope

The inspector performed an in-office review of Revision 15 to the Columbia Generating Station Emergency Plan Implementing Procedure 13.1.1A, Classifying the Emergency -

Technical Bases, received October 3, 2005. This revision:

• Restored the definition of civil disturbance in emergency action level 9.1.S.1

• Defines impeding access to safe shutdown buildings The revision was compared to its previous revision, to the criteria of NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, to NEI 99-01, Methodology for Development of Emergency Action Levels, Revision 2, and to the requirements of 10 CFR 50.47(b) and 50.54(q) to determine if the licensee adequately implemented 10 CFR 50.54(q).

The inspector completed one sample.

b. Findings

No findings of significance were identified.

1EP5 Correction of Emergency Preparedness Weaknesses and Deficiencies

a. Inspection Scope

The inspector reviewed the following documents related to the licensees corrective action program to determine the licensees ability to identify and correct problems in accordance with 10 CFR 50.47(b)(14) and 10 CFR Part 50 Appendix E.

• SWP-CAP-1, Corrective Action Program, Revision 9

• Four Final After-Action Event Reports

• Two Quality Assurance Audits

• Summaries of 127 Condition Reports assigned to the Emergency Preparedness department during calendar years 2004 and 2005

• Details of 23 selected Condition Reports

• Nine Drill and Exercise Evaluation Reports The inspector completed one sample during this inspection.

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

a. Inspection Scope

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

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

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

(3) determined whether licensee performance is in accordance with the guidance of the NEI 99-02 documents acceptance criteria.

• Plant wide emergency drill which included a fire in a residual heat removal pump room, a startup transformer lock-out, reactor water cleanup steam leak outside primary containment and a significant radioactive release to the environment; October 25, 2005 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS2 ALARA Planning and Controls (71121.02)

a. Inspection Scope

The inspectors 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 Technical Specifications as criteria for determining compliance. The inspectors interviewed licensee personnel and reviewed radiological surveys and biological assay reports.

b. Findings

Introduction.

A Green self-revealing noncited violation was identified for failure to have adequate procedures and instructions in accordance with Technical Specification 5.4.1.a to prevent the internal contamination of three workers during replacement of a blank flange on the Equipment Drain System (EDR).

Description.

On November 10, 2005, at approximately 1:00 p.m., maintenance technicians replaced a blank flange on the EDR pipe with a new flange that contained a flush port. The work was conducted in the northeast corner of Reactor Building 501 foot elevation and was performed to support EDR line cleaning to lower dose rates in the vicinity. A pre-job brief was conducted prior to commencement of work due to concerns with the risk associated with increased radiological dose and the potential for the spread of contamination during the work activity. The pre-job brief also discussed the possibility that some water may be present in the piping during the work and that precautions should be taken to address the potentially contaminated water.

Following the removal of the old flange, the workers placed the flange into the bottom of a glove bag which had been installed to minimize the potential for spread of contamination during the activity. Once the flange was removed, the technicians noted that contrary to the pre-job brief concerns for the possibility for water in the pipe/flange, that the pipe and flange internals were dry. The technicians also noted dry surface contamination on the interior of the pipe and cleaned the accessible internal areas of the pipe to minimize the radiation dose rate. There was no significant reduction in dose rate and the cleaning was discontinued.

Following the installation of the new flange, the technicians removed the glove bag containing the old flange. While removing the glove bag, a health physics technician squeezed the neck of the bag in order to twist the neck closed. The technician relocated the bag for later disposal.

After completion of the work, one mechanic found contamination on his hand while performing a self-frisk. Subsequently, Energy Northwest identified other workers who were contaminated. The following personnel contamination was identified:

a.

A health physics technician was contaminated to 30,000 dpm/probe area

(pa) on the neck.

b.

One worker was contaminated on the face, finger, and chest to 6000 dpm/pa maximum.

c.

One worker was contaminated on the shirt, chin, and hard hat to 15,000 dpm/pa maximum.

d.

One worker was contaminated on the chin at 1000 dpm/pa.

e.

Another health physics technician was contaminated on the hard hat, shoes, and left shoulder to 25,000 dpm/pa maximum.

Subsequent whole body counts demonstrated that three individuals were internally contaminated. Calculated internal doses for the individuals were as follows:

4 mrem CEDE, 1 mrem CEDE and 9 mrem CEDE. Energy Northwest determined that when the health physics technician squeezed the neck of the glove bag that a release of contamination to the surrounding area occurred and was the source of the personnel contaminations.

A post critique analysis of the event by Energy Northwest determined that the radiological work procedure used for the flange replacement failed to incorporate several precautions and instructions which should have been implemented. These missed precautions included the potential for dry and airborne contamination and the proper installation, handling, and removal of radiological glove bags.

Analysis.

This issue was a performance deficiency, in that, the Radiological Work Procedure (RWP 30001598) was inadequate in that Energy Northwest failed to incorporate adequate precautions and instructions in the RWP to minimize the potential for personnel contamination. Also, there were no procedures or instructions on the installation, testing, and removal of the glove bag which is an infrequently performed evolution. With the levels of contamination in the system, precautions should have been specified in the Work Order and the RWP. This finding was more than minor in that the replacement of a highly contaminated flange without the use of an adequate radiation work permit was associated with the occupational radiation safetys cornerstone attribute of procedures for exposure control and affected the cornerstone objective to ensure the adequate protection of the workers health and safety from exposure to radiation from radioactive material. The cause of the finding is related to crosscutting aspects of human performance. Using the occupational radiation safety significance determination process (SDP), the finding was determined to be of very low risk significance (Green)because the finding was not an ALARA issue, did not involve an overexposure, did not constitute a substantial potential for an overexposure, and did not compromise the ability to assess dose.

Enforcement.

Technical Specification 5.4.1.a requires that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33, Appendix A, Section 7.e(1), requires radiation protection procedures, including a procedure for access control to radiation areas including a radiation work permit system for limiting personnel exposure. Contrary to this requirement, on November 10, 2005, RWP 30001598 was inadequate for limiting personnel exposure in that it did not provide adequate instructions to prevent workers from receiving internal contamination of radioactive material. In addition, the radiation work permit did not provide instructions for installation, use, and removal of the glove bag. Because the failure to provide an adequate radiation work permit was of very low safety significance and was entered into the corrective action program (Condition Reports 2-05-08798, -09113, -09114 and -09115 ), this violation is treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000397/2005005-01, Failure to provide adequate radiation work permit to prevent an unintended uptake of radioactive material).

4OA1 Performance Indicator Verification

a. Inspection Scope

The inspector sampled licensee submittals for the performance indicators listed below for the period July 1, 2004, through September 30, 2005. The definitions and guidance of NEI 99-02, Regulatory Assessment Indicator Guideline, Revisions 2 and 3, were used to verify the licensees basis for reporting each data element in order to verify the accuracy of performance indicator data reported during the assessment period.

Licensee performance indicator data were also reviewed against the requirements of Procedure 1.10.10, Consolidated Data Entry Process Description, Revision 5, and Emergency Planning Instruction EPI-18, Emergency Preparedness NRC Performance Indicators, Revision 8.

Emergency Preparedness Cornerstone:

• Drill and Exercise Performance

• Emergency Response Organization Participation

• Alert and Notification System Reliability The inspector 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 inspector reviewed emergency responder rosters and drill participation records. The inspector reviewed alert and notification system testing procedures, maintenance records, and a 100 percent sample of siren test records. The inspector also interviewed licensee personnel responsible for collecting and evaluating performance indicator data.

The inspector completed three samples during this inspection.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed Energy Northwests corrective action program (CAP) and associated documents to identify equipment trends that could indicate the existence of a more significant safety issue. The inspectors review included the six month period of July through December 2005, although some examples expanded beyond those dates when the scope of the trend warranted. The inspectors reviewed the repetitive and/or

rework maintenance lists, system health reports, quality assurance audit/surveillance reports and maintenance rule assessments. The inspectors reviewed selected corrective actions associated with any Energy Northwest identified trends to ensure that corrective actions were appropriately identified and documented.

b. Findings and Observations

No findings of significance were identified. The inspectors evaluated trending methodology and observed that Energy Northwest had performed a detailed review.

Energy Northwest routinely reviewed cause codes and key words to identify potential trends in their CAP data base. The inspectors compared Energy Northwests identified trends with the results of the inspectors evaluation and did not identify any discrepancies or potential trends that Energy Northwest had failed to identify. However, the inspectors noted that Energy Northwest had documented a trend associated with fuse replacement control (see section 4OA2.3 for a detailed discussion). The inspectors also identified in parallel with Energy Northwest a trend of missed opportunities associated with the failure to appropriately use operating experience which resulted in plant events, equipment deficiencies, and programmatic issues.

Missed Opportunities To Use Operating Experience The inspectors identified an adverse trend in missed opportunities to use operating experience which if properly evaluated may have prevented several events from occurring. The inspectors noted the following corrective action documents from 2005 in which operating experience was identified or noted to have contributed to events at the station:

• PER 205-0428; A reactor scram occurred due to low RPV water level +13 inches from RFW-P-1B governor valve closure when electricians performed a continuity check on the RFP suction trip pressure switch while restoring the pressure switch to service; The station failed to incorporate 2002 BWR Owners Group Scram Reduction Committee Recommendations regarding single point vulnerabilities of the reactor feedwater system and in particular consideration of an installed time delay on the feedpump suction low header pressure trip.

• PER 205-0417; SW-P-1A displays abnormally low system pressure and flow due to degraded SW pump shafts; The station failed to incorporate operating experience from IN 93-68 and IN 94-45 which if properly evaluated and/or implemented may have identified the degraded pump shafts earlier.

• PER 205-0175; HPCS-M-P/1 upper air deflector shield is cracked approximately 180 degrees; The station failed to incorporate recommendations from GE SIL 484 to overhaul and inspect ECCS pump motors at a 10 year frequency which may have identified the cracked deflector earlier.

• PER 205-0128; CGS is not following the recommendations of GE SIL 484 for replacement of motor oil drain plug o-ring replacement.

The inspectors noted that Energy Northwest independently documented this adverse trend in PER 205-0417 on November 17, 2005. In addition to the events identified by the inspectors, ENW also identified the following additional issues that had elements of failing to incorporate operating experience:

• PER 205-0560; On August 25, 2005, the operations and engineering training programs were placed on probation by the National Academy for Nuclear Training.

• PER 205-0502; During review of fuse control log discovered SLC-P-1A had wrong type control fuse installed.

.2 Annual Sample - Substantive Crosscutting Issue in Human Performance

a. Inspection Scope

In the annual assessment letter, dated March 2, 2005, and a midcycle assessment letter, dated August 30, 2005, from the NRC to Energy Northwest, the NRC documented a substantive crosscutting issue in human performance. Human performance issues with a common performance characteristic of personnel performance associated with procedure adherence, contributed to a number of Green findings in different cornerstones. The inspectors performed a review of documented Condition Reports and Problem Event Resolutions during the periods of January 1 through December 31, 2005, focusing on significant human performance related errors caused by operations department and maintenance department personnel to determine the adequacy of corrective actions that Energy Northwest had taken to address the substantive crosscutting issue.

b. Findings and Observations

No significant findings were identified. The inspectors concluded that although there had been a few isolated significant events related to human performance and procedure usage that resulted in one significant plant event (Plant scram on June 23, 2005, see IR 0500397/2005003) and one equipment configuration control issue (incorrect lead terminated on the startup transformer, see IR 05000397/2005004) the overall number of significant human performance errors caused by operations and maintenance personnel over the year had declined as determined by the decrease in overall numbers of corrective action documents associated with procedure use and adherence as compared to the previous assessment cycle. The inspectors concluded that this overall improvement indicated that Energy Northwests corrective actions had made a positive impact on station performance in this area.

.3 Annual Sample - Fuse Replacement Control at the Station

a. Inspection Scope

The inspectors reviewed PER 205-0502 for a followup of identified and completed corrective actions. Energy Northwest initiated PER 205-0502, on July 6, 2005, to

document a configuration control issue associated with an incorrect fuse that had been installed in the motor control circuitry for standby liquid control pump 1A. Subsequently, Energy Northwest identified several additional fuse control issues which were of less significance than the fuse control issue associated with the standby liquid control pump.

These additional issues, although not operability issues, represented a lack of understanding by plant staff of the stations requirements for fuse control during maintenance activities. Energy Northwest documented this issue as an adverse trend.

The inspectors evaluated Energy Northwests root cause of the issue and assessed the adequacy of corrective actions to correct the root cause.

b. Findings and Observations

No significant findings or observations were identified.

.4 Annual Sample - Emergency Preparedness

a. Inspection Scope

The inspectors selected 27 condition reports 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 condition reports against the requirements of Procedures SWP-CAP-1, Corrective Action Program, Revision 9, and SWP-CAP-2, Cause Determination, Revision 3.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations (INPO) Audit and Evaluation Review

On November 3, 2005, the inspector completed a review of the final INPO audit and evaluation report for Columbia Generating Station. The INPO team was on site during January 2005.

.2 (Closed) URI 05000397/2005004-01: Adequacy of Design of the Reactor Core Isolation

Cooling System and Keepfill Pump

a. Inspection Scope

The inspectors completed an evaluation of the risk significance and assessment of applicable regulatory requirements associated with a failure of the RCIC system to start when operators attempted to start the system following a scram on June 23, 2005.

b. Findings

Introduction.

A Green self-revealing NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified because Energy Northwest failed to maintain the design capability of the RCIC system in accordance with the FSAR.

Description.

As discussed in IR 05000397/2005004, Section 1R17, the inspectors determined that during the implementation of Basic Design Change (BDC) 394 that Energy Northwest failed to maintain the design of the RCIC system in accordance with the FSAR stated design function. Specifically, FSAR, Section 5.4.6, ,Reactor Core Isolation Cooling System, Amendment 56, described that the RCIC system was designed to initiate automatically upon reaching a predetermined low level in the reactor vessel and to restart automatically with no operator action after a reactor vessel level 8 shutdown of RCIC-P-1. Contrary to this design requirement, following the implementation of BDC 394 on June 18, 2001, the RCIC system was not capable under all required plant conditions of initiating automatically upon reaching a predetermined low level in the reactor vessel or restarting automatically with no operator action.

Analysis.

The performance deficiency associated with this finding was Energy Northwests failure to maintain the RCIC system design function with the implementation of BDC 394. This self-revealing finding was determined to be more than minor in accordance with Manual Chapter 0612, Appendix B, in that it was a plant modification design issue which affected the mitigating systems cornerstone attribute of equipment performance and reliability which could impact the ability of the RCIC system to respond to an initiating event. Using Manual Chapter 0609, Significance Determination Process, Phase 1 worksheet, the inspectors determined that since an actual loss of system safety function occurred that a Phase 2 evaluation was warranted. As a result, the inspectors performed a Phase 2 analysis using Appendix A, Technical Basis for At Power Significance Determination Process, of Manual Chapter 0609, Significance Determination Process, and the Phase 2 worksheets from Risk-Informed Inspection Notebook for Columbia Generating Station. The inspectors assumed that the duration of the susceptible condition of RCIC was greater than 30 days since BDC 394 was implemented in 2001. The inspectors also assumed no mitigating capability credit for the RCIC system, but that operator recovery credit was warranted since instructions for manually starting RCIC were proceduralized and the operators received periodic training on manual starting of RCIC. The preliminary results of the Phase 2 evaluation were referred to a regional senior reactor analyst for an evaluation of the final safety significance. The senior reactor analyst conducted a Phase 3 evaluation using a Standardized Plant Analysis Risk (SPAR) model simulation of the failure of the RCIC pump to start and inject into the Reactor coolant system. The analyst concluded that the )CDF associated with the event was 4.3 x 10-8 and that any increase in core risk due to external events was insignificant given the low )CDF (< 1 x 10-6). (See attachment in this inspection report for a full description of the risk analysis of the issue).

The inspectors concluded that the finding was of very low risk significance (Green).

Enforcement.

10 CFR Part 50, Appendix B, Criterion III, Design Control, required in part that design control measures shall provide for verifying or checking the adequacy of design. Contrary to this requirement, since the implementation of BDC 394 on June 18, 2001, Energy Northwest failed to ensure that the interaction of the RCIC keepfill pump

with the RCIC system suction header did not inadvertently cause a failure of RCIC-P-1 to start automatically under all required operating conditions as specified in FSAR, Section 5.4.6. Because this finding was of very low safety significance and entered into the licensees corrective action program as PER 205-0429, this violation is being treated as an NCV, consistent with Section VI.A of the Enforcement Policy (NCV 05000397/2005005-02, Failure to Maintain Design of RCIC in Accordance with FSAR Design Requirements). Energy Northwest took immediate corrective actions to correct the design deficiency by implementing a design change to delay the actuation of the RCIC suction header low pressure suction trip to ensure that any momentary hydraulic perturbations would not cause an inadvertent trip of RCIC-P-1 but still provide protection of the pump in the event of a loss of net positive suction head pressure.

.3 (Opened) URI 05000397/2005005-03: Acceptability of Applying WD-40 Lubricant to

Service Water Pump Shaft Coupling Components

a. Inspection Scope

The inspectors performed a review of Condition Report CR 2-05-09690, Problem Evaluation Request 205-0722, and an Energy Northwest evaluation of the use of WD-40 on the Service Water System, dated December 21, 2006 to identify the circumstances associated with applying WD-40 as lubricant to standby service water pumps during assembly and replacement and its impact on the Service Water system.

b. Findings

Introduction.

An unresolved item was identified pending completion of the licensees evaluation and the NRC's review of this evaluation associated with applying WD-40 as a lubricant to Standby Service Water Pumps SW-P-1A and SW-P-1B during assembly and replacement of these pumps.

Description.

On December 14, 2005, Energy Northwest documented in CR 2-05-09690 that WD-40 was applied to the SW-P-1B stainless steel shaft sleeves and pump shafts to lubricate the components to aid in assembly during a replacement of service water pump SW-P-1B. WD-40 contains chlorine which is a known initiator and contributor to intergranular stress corrosion cracking, a long term degradation concern in stainless steel components given sufficient concentrations. SW-P-1B was replaced because of pump shaft degradation which occurred as a result of intergranular stress corrosion cracking. The condition report documented the concern that the application of WD-40 on the pump stainless steel shaft components may not have been appropriate.

Additionally, the condition report provided that it was reasonable to assume that the WD-40 would be flushed out with water after the pump shafts were wetted and the pump had been operated, therefore no WD-40 would remain in contact with any stainless steel surfaces. The condition report stated that WD-40 was also applied to SW-P-1A which had been replaced in June 2005. At the end of this inspection Energy Northwest had plans to inspect both affected pumps in 2013 per the originally established inspection frequency. During a conference call held on December 21, 2005 the NRC expressed concerns regarding the licensees proposed plan to inspect and remove WD-40 from the shaft couplings in 8 years. The licensee informed the NRC staff that they would re-evaluate this concern. An URI was opened pending further

evaluation by the licensee and NRC's review of the evaluation results. URI 05000397/2005005-03, Application of WD-40 to Service Water Pump Shaft Components.

Analysis.

The issue associated with applying WD-40 as lubricant to the standby service water pumps to aid in assembly during replacement and its impact on the service water system is pending completion of the licensee s evaluation and NRC review of the evaluation results. A determination of the safety significance of any performance deficiencies will be addressed in the resolution of the URI.

Enforcement.

Pending further evaluation by the licensee and NRC's review of the evaluation results, this item remains unresolved.

4OA6 Meetings, Including Exit

On September 29, 2005, the inspector (P. Elkmann) conducted a telephonic exit meeting to present the inspection results to Mr. C. Moore, Supervisor, Emergency Preparedness, who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On October 5, 2005, the inspector (P. Elkmann) conducted a telephonic exit meeting to present the inspection results to Mr. C. Moore, Supervisor, Emergency Preparedness, who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On November 3, 2005, the inspector (P. Elkman) presented the inspection results to Mr. W. Oxenford, Vice President, Technical Services, and other members of his staff who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On December 15, 2005, senior Energy Northwest management met with NRC Region IV regional management to discuss actions that Energy Northwest has taken to address a previously identified substantive crosscutting issue in human performance.

Discussions regarding equipment reliability also occurred.

On January 4, 2006, C. Johnson, NRC RIV Branch Chief, communicated to Doug Coleman, Manager, Performance Assessment and Regulatory Programs, the conclusions of inspection report 05000397/2005010. This inspection report documented the implementation and results of IP 95001, Inspection For One Or Two White Inputs In A Strategic Performance Area, which was performed in response to a white performance indicator in High Pressure Injection System Unavailability.

On January 5, 2006, the resident inspectors presented the inspection results to Mr. D.

Atkinson, Vice President - Nuclear Generation, and other members of his staff who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

On January 23, 2006 the inspectors discussed the results of the inspection with Mr. Randy Guthrie, Operations Training Supervisor of the licensee's management. The

licensee acknowledged the findings presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Energy Northwest

D. Atkinson Vice President, Nuclear Generation

S. Belcher Manager, Operations

I. Borland Manager, Radiation Protection

D. Coleman Manager, Performance Assessment and Regulatory Programs

G. Cullen Licensing Supervisor, Regulatory Programs

D. Dinger Planning Supervisor, Radiation Protection

A. Khanpour General Manager, Engineering

W. LaFramboise Manager, Technical Engineering

T. Lynch Plant General Manager

W. Oxenford Vice President, Technical Services

J. Parrish Chief Executive Officer

C. Moore Supervisor, Emergency Preparedeness

F. Schill Engineer, Licensing

C. Whitcomb Vice President, Organizational Performance and Staffing

NRC Personnel

Z. Dunham Senior Resident Inspector

R. Cohen Resident Inspector

ITEMS OPENED AND CLOSED

Items Opened, Closed, and Discussed During this Inspection

Opened

05000397/2005005-03 URI Application of WD-40 to Service Water Pump Shaft

Components (Section 4OA5.3)

Opened and Closed

05000397/2005005-01 NCV Failure to Provide Adequate Instructions to Prevent

an Unintended Uptake of Radioactive Material

(Section 2OS2)05000397/2005005-02 NCV Failure to Maintain Design of RCIC in accordance

with FSAR Design Requirements (Section 4OA5.2)

Closed

05000397/2005004-01 URI Adequacy of Design of the Reactor Core Isolation

Cooling System and Keepfill Pump (Section

4OA5.2)

Attachment

Discussed

None.

PARTIAL