IR 05000458/2007005

IR 05000458-07-005, on 09/30/2007 - 12/31/2007, River Bend Station; Access Control to Radiologically Significant Areas; Event Followup

ML080440388
Person / Time
Site:	River Bend
Issue date:	02/13/2008
From:	Hay M NRC/RGN-IV/DRP/RPB-C
To:	Mike Perito Entergy Operations
References
IR-07-005
Download: ML080440388 (41)

Text

ary 13, 2008

SUBJECT:

RIVER BEND STATION - NRC INTEGRATED INSPECTION REPORT 05000458/2007005

Dear Mr. Perito:

On December 31, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your River Bend Station. The enclosed integrated inspection report documents the inspection findings, which were discussed on January 3, 2008, with Mr. J. Venable, Senior Vice President, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

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

This report documents one inspector identified and five self-revealing findings of very low safety significance (Green). Five of these findings were determined to involve violations of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. However, because the findings were of very low safety significance and because they were 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 any NCV 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 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, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at River Bend Station.

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

Should you have any questions concerning this inspection, we will be pleased to discuss them with you.

Sincerely,

/RA/

Michael C. Hay, Chief Project Branch C Division of Reactor Projects Docket: 50-458 License: NPF-47

Enclosure:

NRC Inspection Report 05000458/2007005 w/Attachment: Supplemental Information

REGION IV==

Docket: 50-458 License: NPF-47 Report: 05000458/2007005 Licensee: Entergy Operations, Inc.

Facility: River Bend Station Location: 5485 U.S. Highway 61 St. Francisville, Louisiana Dates: September 30 through December 31, 2007 Inspectors: G. Larkin, Senior Resident Inspector, Project Branch C M. Miller, Resident Inspector, Project Branch C D. Bollock, Project Engineer, Project Branch C A. Barrett, Resident Inspector, Project Branch C G. Guerra, Health Physicist, Plant Support Branch Approved By: Michael C. Hay, Chief Project Branch C Division of Reactor Projects-1- Enclosure

SUMMARY OF FINDINGS

IR 05000458/2007005; 09/30/2007 - 12/31/2007; River Bend Station; Access Control to

Radiologically Significant Areas; Event Followup The report covered a 3-month period of routine baseline inspections by resident inspectors and an announced baseline inspection by a regional radiation protection inspector. Five Green noncited violations and one Green finding was 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: Initiating Events

C

Green.

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

Criterion V was identified involving the failure to adequately torque reactor protection system electrical terminal board connections during initial construction. This failure resulted in a loose terminal connection causing thermal degradation that subsequently resulted in an automatic reactor scram during average power range monitor surveillance testing. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2007-04264.

The finding was more than minor because it was associated with the initiating events cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations.

Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the finding was determined to have very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and that mitigating equipment or functions would not be available following a reactor trip (Section 4OA3).

C

Green.

A self-revealing Green noncited violation of 10 CFR 50.65(A)(3) was identified for failure to incorporate internal and external operating experience into preventive maintenance activities to prevent industry known electrical circuit breaker deficiencies. Specifically, inadequate breaker maintenance, leading to grease hardening degradation, resulted in inadequate electrical fault protection on November 7, 2007. The failure to adequately isolate the electrical fault resulted in a complicated reactor scram involving the loss of the main condenser and reactor feedwater. The licensee entered this into their CAP as CR-RBS-2007-04922.

The finding was more than minor because it was associated with the initiating events cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations.

The inspectors evaluated the finding using Manual Chapter 0609, Appendix A,

"Significance Determination of Reactor Inspection Findings for At-Power Situations." The finding required a Phase 2 analysis because the finding contributed to the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. A senior reactor analyst estimated the risk of the subject finding using the Risk-Informed Inspection Notebook for River Bend Station, Unit 1, Revision 2.1a. The analyst determined the finding was of very low safety significance.

This finding has a crosscutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because the licensee did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity (P.1(d)) (Section 4OA3).

C

Green.

A self-revealing finding was identified for failure to perform adequate preventive maintenance for control panels associated with providing make up water to the circulating water system. Adequate preventative maintenance was not performed on this system, resulting in failure, based on an inappropriate run to failure classification of this equipment. The failure of this system resulted in a significant unplanned reduction in reactor power to 20 percent. The licensee entered this issue into their corrective action program as Condition Report CR-RBS-2007-04447.

The finding was more than minor because it was associated with the initiating events cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations.

Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the finding has very low safety significance (Green) since the finding did not contribute to both the likelihood of a reactor trip and that mitigating equipment or functions would not be available following a reactor trip (Section 4OA3).

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing noncited violation of 10 CFR 20.1501(a) was identified for failure to evaluate the magnitude and extent of radiological hazards associated with performing inspections of equipment in the containment building after a reactor trip on May 4, 2007. This failure resulted in six personnel contaminations and uptakes. Followup surveys identified contamination levels of 60 mRad/smear beta/gamma and up to 1300 dpm alpha. Air sample results determined a derived air concentration value of 44 for noble gas. The licensee has placed this event in the radiation protection continuing training program and entered it into their corrective action program as Condition Report CR-RBS-2007-1822.

This finding was greater than minor because it was associated with the occupational radiation safety cornerstone attribute of program and process and affected the cornerstone objective in that the failure to evaluate the magnitude and extent of radiological hazards could cause unintentional dose to radiation workers. This finding was evaluated using the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green) because it did not involve: (1) ALARA planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding had a crosscutting aspect in the area of human performance related to the component of work control because the licensee did not communicate, coordinate, and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance H.3(b) (Section 2OS1).

Green.

A self-revealing noncited violation of Technical Specification 5.4.1 was identified for failure to follow radiation work permit instructions resulting in a worker entering a posted high radiation area without authorization. On April 20, 2007, an individual received an electronic alarming dosimeter dose rate alarm after entering a posted high radiation area. The individual was signed on to a radiation work permit that did not allow entry into a high radiation area. This violation was entered into licensees corrective action program as Condition Report CR-RBS-2007-1584.

This finding was greater than minor because it was associated with the occupational radiation safety cornerstone attribute of human performance and affected the cornerstone objective in that the failure to follow radiation work permit requirements could cause unintentional dose. This finding was evaluated using the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green) because it did not involve: (1) ALARA planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding had a crosscutting aspect in the area of human performance related to the component of work practices because the individual involved did not use proper self-checking and entered an area he was not authorized to enter H.4(a)

(Section 2OS1).

Green.

An NRC-identified noncited violation of 10 CFR 20.1902(a) was identified for failure to conspicuously post a radiation area. Specifically, the inspector identified an entrance to a radiation area on the 90-foot elevation of the radwaste building that was accessible by a permanently installed ladder from the 65-foot elevation, which was not conspicuously posted as a radiation area.

General area dose rates in the area were as high as 7 mrem/hour. This violation was entered into the licensees corrective action program as Condition Report CR-RBS-2007-4954.

This finding was greater than minor because it was associated with the occupational radiation safety cornerstone attribute of program and process and affected the cornerstone objective in that the failure to post radiation areas could cause unintentional dose to radiation workers. This finding was evaluated using the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green) because it did not involve: (1) ALARA planning and controls, (2) an overexposure, (3) a substantial potential for overexposure, or (4) an impaired ability to assess dose. This finding had a crosscutting aspect in the area of human performance related to the component of work practices because radiation protection personnel did not adhere to management expectations regarding procedural compliance and following station procedures [(H.4(b) (Section 2OS1).

Licensee-Identified Violations

One 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 action is listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

At the beginning of this report period, the plant was shut down for a forced outage due to a faulted terminal board connection in the reactor protection system (RPS) that resulted in a reactor scram. On October 4, 2007, the station began plant start-up activities and reached 86 percent power on October 6, when the plant down powered to 20 percent power due to an electronic fault that affected make-up water supply to the circulating water system (CWS). On October 7, the plant reached 100 percent power. On October 8, the plant down powered to 72 percent power for a control rod pattern exchange and resumed 100 percent power operations on October 9. On October 19, the plant down powered to 88 percent power for a control rod pattern exchange and was restored to 100 percent power on October 19. On October 28, reactor power was reduced to 75 percent power for planned work on various major balance-of-plant components. On November 2, reactor power was lowered to 45 percent power due to reactor feedwater Pump FWS-P1B inboard mechanical seal leakage. Power was restored to 75 percent power on November 5. On November 7, the reactor scrammed due to an electrical fault that resulted in a loss of all reactor feedwater. The plant began start-up activities on November 11 and reached 75 percent power on November 12. On November 19, the plant raised power to 80 percent power. On November 20, power was reduced to 75 percent power to repair reactor feedwater Pump FWS-P1A oil leaks. Power was increased to 80 percent power on the same day. On November 24, power was reduced to 75 percent power to start a third reactor feedwater pump. On November 25, the plant reached 80 percent power. On December 1, power was lowered to 71 percent power for a control rod pattern exchange and restored to 90 percent power. On December 7, reactor power was lowered to 81 percent power due to leakage from condensate demineralizer E manway cover. On December 8, power was later restored to 88 percent power. On December 14, power was lowered to 67 percent power to repair condenser water box tube leakage and to pull all reactor control rods full out. On December 16, the plant was returned to 100 percent power and since then, the plant has been in coast down to Refueling Outage 14. The plant ended the inspection period at 89 percent power in coastdown to Refueling Outage

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Readiness For Impending Adverse Weather Conditions On December 7, 2007, the inspectors completed a review of the licensee's readiness for impending adverse weather conditions involving winter storms for the site. The inspectors:

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

(2) walked down safety related systems exposed to the elements;

(3) reviewed maintenance records and

open cold-weather related corrective action work orders (WOs); and

(4) interviewed operators on their actions for cold weather and winter storms.

Documents reviewed by the inspectors included:

C December 5, 2007, control room logs C Operations Section Procedure OSP-0043, Revision 8, Freeze Protection and Temperature Maintenance C USAR Section 2.3, Meteorology C USAR Section 3.11, Environmental Design of Mechanical and Electrical Equipment The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

Partial System Walkdown(s)

a. Inspection Scope

The inspectors:

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

(2) compared deficiencies identified during the walkdown to the licensee's USAR and Corrective Action Program (CAP) to ensure problems were being identified and corrected.

C December 14, 2007, Division 1 standby diesel generator C December 17, 2007, Division 2 standby service water system Documents reviewed by the inspectors included:

C System Operating Procedure SOP-0053, Standby Diesel Generator and Auxiliaries, Revision 305 C USAR Section 9.2.7, Standby Service Water System C TS Section 3.7.1, Standby Service Water (SSW) System and Ultimate Heat Sink (UHS)

The inspectors completed two inspection samples.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

a. Inspection Scope

Quarterly Inspection The inspectors walked down the seven 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 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) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory condition;

(4) 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;

(5) 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

(6) reviewed the CAP to determine if the licensee identified and corrected fire protection problems.

C October 15, 2007, Diesel Generator Building, 98-foot level, Fire Area DG-5, DG-6, DG-4; Control Building, 116-foot level, Fire Area C-17, C-18, C-19, C-21, C-24, and C-27 C October 16, 2007, Control Building, 98-foot level; the main control room and Division I and III emergency diesel generator (EDG) rooms C October 18, 2007, Control Building, 70-foot level, 98-foot level, and electrical Tunnel ET-1 C October 23, 2007, Auxiliary Building, 70-foot level, 96-foot level, and 141-foot level C October 31, 2007, Turbine Building, 70-foot level and 123-foot level; Auxiliary Building, 70-foot level, 96-foot level, and 141-foot level C November 13, 2007, Turbine Building, 67-foot level C December 11, 2007, Turbine Building, 95-foot level; Reactor Building 70-foot level, 95-foot level, 114-foot level, and 141-foot level Documents reviewed by the inspectors included:

C Pre-Fire Plan/Strategy Book C USAR Section 9A.2, Fire Hazards Analysis

C CR-RBS-2004-00455 C CR-RBS-2007-01329 The inspectors completed seven inspection samples.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

On October 15, 2007, the inspectors observed operator team testing 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 a feedwater line break in the drywell and entry into emergency operating procedure for reactor pressure control and primary containment control. Later an EDG failed to automatically start on high drywell pressure.

Documents reviewed by the inspectors included:

C Simulator Scenario, RSMS-OPS-514, Revision 5, Feedwater Line Leak Inside Primary Containment The inspectors completed one inspection sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the Maintenance Rule scoped systems listed below that haves displayed performance problems to:

(1) verify the appropriate handling of structures, systems, and components (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 Specification (TS).

C Standby gas treatment system C RPS C Standby service water system C Condensate system C 13.8 kV electrical distribution system

Documents reviewed by the inspectors included:

C NUMARC 93-01, Nuclear Energy Institute Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2 C Maintenance rule function list C Maintenance rule performance criteria list C Standby gas treatment system maintenance rule performance evaluations The inspectors completed five inspection samples.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing

a. Inspection Scope

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

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

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

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

• WO 124384, Repair of B21-MOVF098C Bonnet Steam Cut and Actuator Motor Replacement, reviewed on October 1, 2007

• WO 126187, C71A-K7C & C71A-K8C Replace MDR Relay Global PM, reviewed on November 21, 2007

• WO 35802, NPS-SWG1A ACB03 Global PM, reviewed on November 14, 2007 (See Section 4OA3 b.2 for the related finding.)

C WO 131918, Standby Liquid Control Pump B, reviewed on December 6, 2007 C WO 126373, Division II EDG Jacket Water and Lube Oil Leak, reviewed on December 7, 2007

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed five inspection samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

Two forced outages occurred during the inspection period:

(1) Forced Outage 07-04, September 26 through October 4, 2007, in response to a reactor scram caused by a high resistance connection in the RPS; and

(2) Forced Outage 07-05, November 7 through November 11, 2007, in response to a reactor scram with the loss of all feedwater. The inspectors reviewed the following risk significant outage activities to verify defense in depth commensurate with the outage risk control plan and compliance with the TS:

(1) the risk control plan,

(2) tagging/clearance activities,

(3) reactor coolant system instrumentation,

(4) electrical power,

(5) decay heat removal,

(6) inventory control,

(7) containment closure,

(8) heatup and cooldown activities,

(9) restart activities, and

(10) licensee identification and implementation of appropriate corrective actions associated with outage activities. See Section 4OA3 for findings related to the initial events.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two inspection 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 TS to ensure that the two temporary modifications listed below were properly implemented.

The inspectors:

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

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

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

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

C Modification (EC-3275) to enable containment isolation valve to throttle steam flow C Modification (EC-3337) to install a temporary control switch for MWS-MOV 138 Documents reviewed by the inspectors included:

C EC-3275, Enable Slow Opening of B21-MOVF085 from the Main Control Room, October 19, 2007 C EC-3337, Issue Temp Mod for MWS-MOV138 to Support Emergency Modification, October 11, 2007 C EN-DC-136, Temporary Modifications, Revision 2 C RBS Temp Mod and Temp Installation Log The inspectors completed two inspection samples.

b. Findings

No findings of significance were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas

a. Inspection Scope

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

• Performance Indicator (PI) events and associated documentation packages reported by the licensee in the Occupational Radiation Safety Cornerstone

• Controls (surveys, posting, and barricades) of radiation areas and HRAs

• Radiation work permits (RWPs), procedures, engineering controls, and air sampler locations

• Conformity of electronic personnel dosimeter alarm set points with survey

indications and plant policy; workers knowledge of required actions when their electronic personnel dosimeter noticeably malfunctions or alarms.

• Barrier integrity and performance of engineering controls in airborne radioactivity areas

• Adequacy of the licensees internal dose assessment for any actual internal exposure greater than 50 millirem committed effective dose equivalent

• Physical and programmatic controls for highly activated or contaminated materials (nonfuel) stored within spent fuel and other storage pools

• Self-assessments, audits, licensee event reports(LERs), and special reports related to the access control program since the last inspection

• Corrective action documents related to access controls

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

• RWP briefings and worker instructions

• Adequacy of radiological controls such as, required surveys, radiation protection job coverage, and contamination controls during job performance

• Dosimetry placement in high radiation work areas with significant dose rate gradients

• Changes in licensee procedural controls of high dose rate - HRAs and very HRAs

• Controls for special areas that have the potential to become very HRAs during certain plant operations

• Posting and locking of entrances to all accessible high dose rate - HRAs and very HRAs

• Radiation worker and radiation protection technician performance with respect to radiation protection work requirements The inspector completed 17 of the required 21 samples.

b. Findings

===.1

Introduction:

The inspector reviewed a self-revealing, noncited violation (NCV) of===

10 CFR Part 20.1501(a) for failure to evaluate the magnitude and extent of radiological hazards associated with performing inspections of equipment in the containment building after a reactor trip on May 4, 2007, resulting in personnel contaminations. The violation had very low safety significance.

Description:

After a reactor trip on May 4, 2007, based upon procedural direction, a radiation protection technician was sent to the reactor building to verify radiological conditions. The technician found radiation levels as expected and noted water on the 114-foot elevation near the west hydraulic control unit bank. Contamination levels were 30,000 dpm/100cm2 loose contamination. The area was posted as a radiation and contamination area. However, surveys of the area where the engineers were to be working were not performed before radiation protection technicians allowed them to enter the containment building to perform their task. As a result, six personnel contaminations and uptakes occurred with the highest being 39.4 mRem committed effective dose equivalent.

Followup surveys on May 5, 2007, found that contamination was more wide spread. The licensee identified high levels of alpha and significantly higher levels of airborne contamination. Followup surveys identified contamination levels up to 60 mRad/smear beta/gamma and 1300 dpm alpha. Air sample results determined a derived air concentration value of 44 for noble gas.

Analysis:

The failure to evaluate the magnitude and extent of radiological hazards is a performance deficiency. This finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of program and process and affected the cornerstone objective in that the failure to evaluate the magnitude and extent of radiological hazards could cause unintentional dose to radiation workers. This finding was evaluated using the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green)because it did not involve:

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

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose. This finding had a crosscutting aspect in the area of human performance related to the component of work control because the licensee did not communicate, coordinate, and cooperate with each other during activities in which interdepartmental coordination is necessary to assure plant and human performance

H.3(b).

Enforcement:

10 CFR Part 20.1501(a) requires that each licensee make or cause to be made surveys that may be necessary for the licensee to comply with the regulations in 10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, concentrations or quantities of radioactive materials, and the potential radiological hazards that could be present. Pursuant to 10 CFR 20.1003, a survey means an evaluation of the radiological conditions and potential hazards incident to the production, use, transfer, release, disposal, or presence of radioactive material or other sources of radiation. 10 CFR Part 20.1201(a) states, in part, that the licensee shall control the occupational dose to individual adults to specified limits. Contrary to the above, the licensee failed to evaluate the magnitude and extent of radiological hazards when it did not perform surveys resulting in personnel contaminations and uptakes thus failing to control the occupational dose to individuals. This violation was entered into licensees CAP as Condition Report (CR) CR-RBS-2007-1822. Because this finding is of very low safety significance and was entered into licensees CAP, it is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000458/2007005-01, Failure to Evaluate the Magnitude and Extent of Radiological Hazards Results in Personnel Contaminations.

===.2

Introduction:

The inspector reviewed a self-revealing, violation (NCV) of TS 5.4.1 for===

failure to follow RWP instructions resulting in a worker entering a posted HRA without authorization. The violation had very low safety significance.

Description:

On April 20, 2007, an individual received an electronic alarming dosimeter dose rate alarm after entering a posted HRA. The individual was signed on to a RWP that did not allow entry into HRAs. The radiation worker had been previously allowed access to the HRA for the project he was working on; however, for this entry he did not specify he needed to access the HRA and was directed to sign in on a RWP that did not allow entry to a HRA. The electronic dosimeter indicated a maximum dose rate of 131 mrem/hour and an accumulated dose of 1 mrem. Surveys by the licensee determined that actual HRA conditions existed (i.e., dose rates were greater than 100 mrem/hour at 30 centimeters).

Analysis:

The failure to follow RWP requirements is a performance deficiency. This finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of human performance and affected the cornerstone objective in that the failure to follow RWP requirements could cause unintentional dose. This finding was evaluated using the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green) because it did not involve:

(1) ALARA planning and controls,

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose. This finding had a crosscutting aspect in the area of human performance related to the component of work practices because the individual involved did not use proper self-checking and entered an area he was not authorized to enter H.4(a).

Enforcement:

TS 5.4.1, states, written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Appendix A, Section 7.e, specifies procedures for access control to radiation areas including a RWP system. Licensee implementing Procedure EN-RP-105, Radiation Work Permits, Section 4[5] states, Radiation Worker: Responsible for reviewing the RWP and complying with the requirements. Procedure EN-RP-100, Radworker Expectations, Section 5.4[3](b)states, Have read and understood all the requirements of the RWP. Contrary to the above, on April 20, 2007, a radiation worker did not comply with the requirements of the RWP and entered a posted HRA without authorization. This violation was entered into licensees CAP as CR-RBS-2007-1584. Because this finding is of very low safety significance and was entered into licensees CAP, it is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy:

NCV 05000458/2007005-02, Failure to Follow RWP and Radiation Worker Expectations.

===.3

Introduction:

The inspector identified an NCV of 10 CFR Part 20.1902(a) for failure to===

conspicuously post a radiation area on the 90-foot elevation of the radwaste building.

The violation had very low safety significance.

Description:

On November 7, 2007, the inspector identified a radiation area that was not conspicuously posted. Specifically, the inspector identified an entrance to a radiation area on the 90-foot elevation, accessible by a permanently installed ladder from the

65-foot elevation, that was not conspicuously posted. General area dose rates in the area were as high as 7 mrem/hour.

Analysis:

The failure to conspicuously post the radiation area is a performance deficiency. This finding was greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of program and process and affected the cornerstone objective in that the failure to post radiation areas could cause unintentional dose to radiation workers. This finding was evaluated using the Occupational Radiation Safety Significance Determination Process and determined to be of very low safety significance (Green) because it did not involve:

(1) ALARA planning and controls,

(2) an overexposure,

(3) a substantial potential for overexposure, or

(4) an impaired ability to assess dose. This finding had a crosscutting aspect in the area of human performance related to the component of work practices because radiation protection personnel did not adhere to management expectations regarding procedural compliance and follow station procedures H.4(b).

Enforcement:

10 CFR Part 20.1902(a), states, in part, that the licensee shall post each radiation area with a conspicuous sign or signs bearing the radiation symbol and the words Caution, Radiation Area. Contrary to the above, on November 7, 2007, the inspector identified a ladder in the radwaste building that could be used to access a radiation area that was not posted with a conspicuous sign bearing the radiation symbol and the words Caution, Radiation Area. This violation was entered into licensees CAP as CR-RBS-2007-4954. Because this finding is of very low safety significance and was entered into licensees CAP, it is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000458/2007005-03, Failure to Post a Radiation Area.

2OS2 ALARA Planning and Controls

a. Inspection Scope

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

• Current 3-year rolling average collective exposure

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

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

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

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

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

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

• Use of engineering controls to achieve dose reductions and dose reduction benefits afforded by shielding

• Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or HRAs

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

• Effectiveness of self-assessment activities with respect to identifying and addressing repetitive deficiencies or significant individual deficiencies The inspector completed 12 of the required 15 samples.

b. Findings

No findings of significance were identified.

4OA1 PI Verification

Cornerstone: Mitigating Systems

The inspectors sampled licensee data for the PI listed below for the period from July 1, 2006, through September 30, 2007.

• Safety System Functional Failures The inspectors sampled licensee data for the PIs listed below for the period from October 1, 2006, through September 30, 2007.

• Emergency AC Power Systems

• High Pressure Injection Systems

• Heat Removal Systems

• Residual Heat Removal Systems

• Cooling Water Systems The definitions and guidance of Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Revision 5, 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 LERs, daily plant status sheets, operating logs, limiting condition for operation logs, daily shift manager reports, plant computer data, CRs, WOs, the maintenance rule database, and PI data sheets as part of the assessment and compared this information to the reported data to verify the accuracy of the PIs. The licensees CAP records were also reviewed to determine if any problems with the collection of PI data occurred.

The inspectors completed six inspection samples.

Cornerstone: Occupational Radiation Safety

The inspector reviewed licensee documents from January 1 through September 30, 2007. The review included corrective action documentation that identified occurrences in locked HRAs (as defined in the licensees TS), very HRAs (as defined in 10 CFR 20.1003), and unplanned personnel exposures (as defined in Nuclear Entergy Institute (NEI) 99-02). Additional records reviewed included ALARA records and whole body counts of selected individual exposures. The inspector interviewed licensee personnel that were accountable for collecting and evaluating the PI data. In addition, the inspector toured plant areas to verify that high radiation, locked high radiation, and very HRAs were properly controlled. PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 5, were used to verify the basis in reporting for each data element.

• Occupational Exposure Control Effectiveness The inspector completed one inspection sample.

Cornerstone: Public Radiation Safety

• Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences The inspector completed two inspection 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 licensee's CAP.

This assessment was accomplished by reviewing CRs and WOs 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 followup through other baseline inspection procedures.

b. Findings

No findings of significance were identified.

.2 Annual Sample Review

a. Inspection Scope

In addition to the routine review, the inspectors selected the issue listed below 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.

• Preventive maintenance for motor-driven relays Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one inspection sample.

b. Findings

There were no findings identified associated with the review of licensee corrective actions in that the full extent of issues were identified and the licensee identified appropriate corrective actions. The inspectors determined that the corrective actions had been appropriately completed in all cases.

.3 Selected Issue Followup Inspection

a. Inspection Scope

The inspector evaluated the effectiveness of the licensees problem identification and resolution process with respect to the following inspection areas:

C Access Control to Radiologically Significant Areas (Section 2OS1)

C ALARA Planning and Controls (Section 2OS2)

b. Findings

No findings of significance were identified.

.4 Annual Review of Operator Workarounds

An operator workaround is defined as a degraded or nonconforming condition that complicates the operation of plant equipment and is compensated for by operator action.

During the week of December 17, 2007, the inspectors reviewed the cumulative effect of the existing operator workarounds and contingency plans. The inspectors concentrated on the effect the workarounds have on:

(1) the reliability, availability, and potential for misoperation of any mitigating system;

(2) whether they could increase the frequency of an initiating event; and

(3) their effect on the operation of multiple mitigating systems. In addition, the inspectors reviewed the cumulative effects the operator workarounds have on the ability of the operators to respond in a correct and timely manner to plant transients and accidents.

Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one inspection sample.

b. Findings

There were no findings of significance identified associated with the CRs and programs reviewed.

4OA3 Event Followup

.1 (Closed) LER 50-458/2007-004-00, EDG Failed Surveillance Test Due to Paint on Fuel

Injector Control Linkage The safety significance and the enforcement aspects of this finding are discussed in Section 4OA7. This LER is closed.

.2 (Closed) LER 50-458/2007-005-00, Unplanned Reactor Scram during Surveillance

Testing Due to Damaged Terminal Board

Introduction:

A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion V, was identified for failure to follow a procedure to install RPS terminal board connections.

The loose terminal connection resulted in Group 2 control rod insertion and a reactor scram.

Description:

On September 26, 2007, a partial scram occurred during performance of Surveillance Test Procedure STP-505-4501, RPS Control Rod Block - APRM Channel Functional Test and LSFT (C51-K605A). When the technicians placed the mode switch for APRM A to standby as directed by the surveillance test procedure, all RPS Group 2 control rods (36 control rods) scrammed. Approximately 6 seconds later, an automatic reactor scram initiated on a low reactor water level condition caused by the rod group insertion.

Troubleshooting by Entergy identified that an electrical terminal board connection in the RPS pilot SCRAM solenoid circuit had sustained thermal damage. The licensee concluded the most likely cause of the failure resulted from a terminal connection that wasnt adequately tightened during initial construction. Procedure II-GA-024, Visual Inspect FDI/FDDR Changes to Panels, Revision 9, Step 3.4.6 H., states Wire terminations shall be tight (reference torque specification EAP 304A1640AD.)

EAP 304A1640AD requires 10.8-in/lbs torque. The failure to adequately torque this connection would result in a loose connection causing a high impedance junction. The high impedance junction would result in the generation of excessive heat leading to thermal degradation. The thermally damaged circuit de-energized the Division 2 coils on the Group 2 pilot SCRAM solenoid valves. This degraded condition provided half the logic necessary to scram the 36 Group 2 control rods. During the surveillance test, when APRM A was taken out of operation, the logic was completed to fully insert Group 2 control rods that ultimately resulted in a full reactor scram.

Contributing causes to the event include an inadequate original design that installed eight white lights, two per RPS channel, to represent the state of the RPS scram contractors.

When the lights are lit, no RPS scram signals are present. During this event, the scram lights remained lit because the electrical fault was located downstream of the lights. This design left power to the lights unaffected without alerting the operators that the plant was vulnerable to group and single control rod scram conditions. As a corrective action, the station plans to perform thermography on the pilot SCRAM solenoid valves within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of any plant evolution that requires a half-scram insertion to verify sufficient power is applied to the pilot SCRAM solenoid valves to prevent a repeat occurrence.

Additional actions, including a plant modification, are being evaluated.

Analysis:

The deficiency associated with this event was a failure to follow procedural guidance resulting in a loose terminal connection and subsequent failure in the RPS.

This deficiency resulted in an unexpected Group 2 rod insertion and automatic reactor scram during APRM surveillance testing. The finding was more than minor because it was associated with the initiating events cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations.

Using Manual Chapter (IMC) 0609, Significance Determination Process, Phase 1 Worksheet, the finding was determined to have very low safety significance because the finding did not contribute to both the likelihood of a reactor trip and that mitigating equipment or functions would not be available following a reactor trip.

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states that activities affecting quality shall be accomplished in accordance with documented instructions appropriate to the circumstances. Contrary to the above, the procedure to adequately torque RPS terminal board connections was not adequately implemented during initial construction resulting in thermal degradation and a subsequent reactor scram during APRM surveillance testing. Because the finding is of very low safety significance and has been entered into the licensees CAP as CR-RBS-2007-04264, this violation is being treated as an NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000458/2007005-04, RPS Terminal Board Loose Connection Results in a Reactor Scram. This LER is closed.

.3 (Closed) LER 50-458/2007-006-00, Unplanned Reactor Scram Due to Transformer

Fault

Introduction:

A self-revealing Green NCV of 10 CFR 50.65(A)(3) was identified for failure to incorporate internal and external operating experience into preventive maintenance activities to prevent industry known electrical circuit breaker deficiencies. Specifically, inadequate breaker maintenance, leading to grease hardening degradation, resulted in inadequate electrical fault protection on November 7, 2007. The failure to adequately isolate the electrical fault resulted in a complicated reactor scram involving the loss of the main condenser and reactor feedwater. The licensee entered this into their CAP as CR-RBS-2007-04922.

Description:

On November 7, 2007, River Bend Station was at 75 percent reactor power when a loss of Switchgear NPS-SWG1A, one of two primary nonvital 13.8 kV power distribution switchgears, occurred. Loss of Switchgear NPS-SWG1A resulted in loss of all running condensate pumps followed by low suction pressure trips of all operating reactor feed water pumps. In response to lowering reactor water level, due to loss of reactor feed water, operators appropriately inserted a manual reactor scram.

From field walkdowns and independent laboratory analysis, Entergy determined that a rodent most likely initiated the electrical fault that originated on the high side bus bars from a 13.8kV to 480V dry type Transformer NJS-X1J based on evidence of charring found inside the load break switch and transformer cabinets. The rodent initiated the fault apparently as a result of breaching the minimum dielectric breakdown distance from one phase to ground. Once the initial fault occurred, electrically charged ionized gases enveloped the remaining two phases and produced a three phase symmetrical fault downstream of Switchgear NPS-SWG1A Circuit Breaker ACB03. Circuit Breaker ACB03 should have cleared the fault. However, the event investigation found that the fault resulted in an over-current trip of the Feeder Breaker ACB11 which supplies power to ACB03. The three phase fault was a maximum symmetrical three phase fault lasting for approximately 43 cycles. Circuit Breaker ACB03 was designed to clear the fault within eight cycles of the faults initiation. Entergy determined that the most probable

cause of the slow operation of Circuit Breaker ACB03 was due to hardened grease in the breakers operating mechanisms.

Since 1998, Entergy was aware that industry operating experience recommended that breaker overhaul was needed on a programmatic basis. Industry guidance suggest that 8-12-year intervals should be used for complete tear downs to replace old lubricants with fresh grease. The inspectors noted that 2006 CR-RBS-2006-04478 documented that untimely breaker overhauls cause failures, such as from grease hardening. River Bend Stations 13.8 kV magne-blast breakers were last overhauled between 1990-1992.

Switchgear NPS-SWG1A Feeder Breaker ACB03 was last overhauled in 1990 and was 5 years beyond the longest time frame recommended by the industry for a complete overhaul. In addition, the inspectors noted that the NRC had previously identified hardened grease as a failure mechanism in magne-blast circuit breakers and provided this information to the industry in Information Notice 96-43, Failures of General Electric Magne-Blast Circuit Breakers, and Information Notice 95-22, Hardened or Contaminated Lubricants Cause Metal-Clad Circuit Breaker Failures. Entergy plans to replace all 13.8 kV switchgear breakers during their next refueling outage scheduled to start in January of 2008.

Analysis:

The finding was more than minor because it was associated with the initiating events cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. This finding has a crosscutting aspect in the area of Problem Identification and Resolution, Corrective Action Program, because the licensee did not take appropriate corrective actions to address safety issues and adverse trends in a timely manner, commensurate with their safety significance and complexity (P.1(d)). The inspectors evaluated the finding using Manual Chapter 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations." The finding required a Phase 2 analysis because the finding contributed to the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. A senior reactor analyst estimated the risk of the subject finding using the Risk-Informed Inspection Notebook for River Bend Station, Unit 1, Revision 2.1a. The analyst determined the finding was of very low safety significance (Green) using the following assumptions:

• The performance deficiency increased the likelihood of either a transient or a transient with loss of power conversion system because the failure of the breaker to clear the fault quickly resulted in the loss of Switchgear NPS-SWG1A. The loss of power to Switchgear NPS-SWG1A at full power will result in a reactor transient. Additionally, failure of this switchgear causes a loss of about one half of the power conversion system equipment.

• The performance deficiency affected the likelihood that power conversion system equipment would be available to perform its mitigation function. However, at least one train of equipment would have been available to provide this function.

• No other mitigating equipment was affected and no other initiating event likelihood was impacted.

• The failure could have been recovered because, although slow, the fault was cleared from the bus. Therefore, operators could have reenergized Switchgear NPS-SWG1A following appropriate verification of bus conditions.

• The analyst determined that a Recovery Credit of 1 was appropriate given that sufficient time was available to implement the actions, environmental conditions would have been appropriate, procedures existed to reestablish power to the bus, and operators are appropriately trained to perform such operations.

• Given Assumptions 1 and 2 and Manual Chapter 0609, Appendix A, Attachment 2, Rule 2.1, Inspection Finding Involving a Loss of Redundancy of the Mitigation Capabilities, the analyst determined that all sequences containing the power conversion functions, affected by the loss of this switchgear (TRANS, TPCS, SLOCA, TCCP, TDCI, TDCII) should be quantified giving full mitigation capability credit to the function, and all TRANS and TPCS sequences should be quantified with the initiating event likelihood adjusted to 0.

Table 2 of the risk-informed notebook requires that those worksheets discussed in Assumption 6 be evaluated when a performance deficiency affects both the steam and feed sides of the power conversion system. The resulting dominant sequences are provided in the table below:

Phase 2 Worksheet Results Initiator Sequence IEL Mitigating Functions Result TRANS 4 0 PCS - RCIC - HPCS - DEP 9*

0 CHR - LICRD - LDEP 9 TPCS 0 RCIC - HPCS - DEP 7*

• Denotes sequences indicated as LERF contributors in the Phase 2 notebook.

By application of the counting rule, the internal event risk contribution of this finding to the change in core damage frequency (CDF) was of very low risk significance (Green).

External Events:

The plant-specific SDP worksheets do not currently include initiating events related to fire, flooding, severe weather, seismic, or other external initiating events. In accordance with Manual Chapter 0609, Appendix A, Attachment 1, Step 2.2.5, "Screen for the Potential Risk Contribution Due to External Initiating Events," experience with using the Site Specific Risk-Informed Inspection Notebooks has indicated that accounting for external initiators could result in increasing the risk significance attributed to an inspection finding by as much as one order of magnitude. The analyst determined that, in general, external initiators result in at least a loss of offsite power to the plant. Given that the risk impact from this performance deficiency is driven by failures that would

occur following a loss of offsite power, no increase in risk would be anticipated from external initiators.

Large Early Release Frequency:

In accordance with Manual Chapter 0609, Appendix A, Attachment 1, Step 2.2.6, "Screen for the Potential Risk Contribution Due to Large Early Release Frequency (LERF)," the analyst determined that the finding was not significant from a large early release frequency perspective and no further evaluation was necessary because the Phase 3 result provided a risk significance estimation of less than 1 x 10-7.

In accordance with Manual Chapter 0609, Appendix H, the only sequence that need be evaluated is Sequence 4 from the TPCS worksheet. Using the LERF factor of 0.2 from the Phase 2 worksheet, the estimated change in LERF is 2 x 10-8. Because this is below the threshold of 1 x 10-7, this finding is not considered significant to LERF.

Enforcement:

Title 10 CFR 50.65.A(3) states that Performance and condition monitoring activities and associated goals and preventive maintenance activities shall be evaluated at least every refueling cycle. The evaluations shall take into account, where practical, industry-wide operating experience. Adjustments shall be made where necessary to ensure that the objective of preventing failures of SSC through maintenance is appropriately balanced against the objective of minimizing unavailability of SSCs due to monitoring or preventive maintenance. Contrary to this requirement, the licensee failed to incorporate operating experience in a timely manner when it was practical to do so. Specifically, Entergy did not overhaul Switchgear NPS-SWG1A Feeder Breaker ACB 03 per industrys operating experience. As a consequence, Switchgear NPS-SWG1A Feeder Breaker ACB 03 failed to clear an electrical fault in a timely manner on November 7, 2007 resulting in the loss of all feedwater and a reactor scram. As a result of the Switchgear NPS-SWG1A Feeder Breaker ACB 03 failure, all 13.8 kV switchgear will now be replaced by the end of the next refueling outage beginning in January 2008. Because this finding is of very low safety significance and has been entered into the licensees CAP as CR-RBS-2007-0922, this violation is being treated as an NCV consistent with Section VI.A of the Enforcement Policy: NCV 05000458/2007005-05, Inadequate Preventive Maintenance Strategy Results in a Breakers Failure to Promptly Open Due to Hardened Grease Results in a Complicated Reactor Scram. This LER is closed.

.4 Unit Transient - October 6, 2007

a. Inspection Scope

On October 6, 2007, the inspectors responded to a plant downpower due to an electrical control panel malfunction resulting in a loss of makeup water to the CWS. The inspectors discussed the event with licensee management, engineering, operations, and maintenance personnel to understand the conditions leading to a potential loss of condenser vacuum. The inspectors reviewed the apparent cause evaluation report to assess the detail and thoroughness of the report and proposed corrective actions. The inspectors also reviewed the event for reportability in accordance with NUREG 1022, Event Reporting Guidelines.

b. Findings

Introduction:

A Green self-revealing finding was identified for failure to perform adequate preventive maintenance for control panels associated with providing makeup water to the CWS. Adequate preventative maintenance was not performed on this system, resulting in failure, based on an inappropriate run to failure classification of this equipment. The failure of this system resulted in a significant unplanned reduction in reactor power to 20 percent.

Description:

On October 6, 2007, operators reported that the operating Make-up Water System Pump MWS-P4A, had tripped off line. Operators began a series of operations to restore make-up water to the CWS, including reducing reactor power from 86 percent reactor power to 20 percent reactor power. Troubleshooting determined that the control panel, that provides indication and controls for major nonsafety-related equipment associated with the CWS, make up water system, and service water system, had malfunctioned affecting the supply breakers trip control functions for Make-up Water Pumps MWS-P4A and MWS-P4C. Specifically, the scanner receiver Card B7, which controls the trip functions for the two make-up water pumps supply breakers, had malfunctioned. As a result, the operators were not able to control the breakers position and lost power to each pump. Entergy restored power to the pumps after installing a temporary plant modification to bypass the system control logic.

Procedure EN-DC-153, Preventive Maintenance Component Classification classifies run-to-failure components as those that do not have the ability to cause a plant down power, cause the loss of a critical system function, or promote the failure of other components. Contrary to Procedure EN-DC-153, the subject control panel components were classified as run-to-failure even though a failure had the ability to cause a plant down power from a loss of the CWS. The inspectors noted that Entergy had no replacement strategy for the system cards. The failed cards had been in service for 20 years. Had the licensee properly classified this equipment, the preventative maintenance strategy would utilize a 12-year replacement interval for the control components.

Analysis:

The performance deficiency for this event was the failure to perform adequate preventive maintenance for control panels associated with providing make up water to the CWS resulting in a manual plant down power from a potential loss of circulating water affecting condenser vacuum. The finding is more than minor since it affects the equipment performance attribute of the initiating events cornerstone and affects the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions. Using Manual Chapter 0609, Significance Determination Process, Phase 1 Worksheet, the finding has very low safety significance (Green) since the finding did not contribute to both the likelihood of a reactor trip and that mitigating equipment or functions would not be available following a reactor trip.

Enforcement:

Because the affected equipment was nonsafety related, no violation of regulatory requirements occurred. This issue was entered into the CAP as CR-RBS-2007-04447. This finding is identified as Finding FIN 05000458/2007005-06, Inadequate Preventative Maintenance Results in a Plant Down Power.

4OA6 Meetings, Including Exit

Exit Meetings On November 9, 2007, the inspector presented the occupational radiation safety inspection results to Mr. Joe Venable, Senior Vice President, and other members of licensee management who acknowledged the findings. The inspector confirmed that proprietary information was not provided or examined during the inspection.

On January 2, 2008, the inspectors presented the safety evaluation and permanent plant modifications inspection results to Mr. J. Venable, Senior Vice President, and other members of licensee management who acknowledged those results. No proprietary information was included in this report.

On January 3, 2008, the inspectors presented the integrated baseline inspection results to Mr. J. Venable, Senior Vice President, and other members of licensee management.

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

4OA7 Licensee-Identified Violations

The following finding of very low safety significance was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section VI of the NRC Enforcement Policy for being dispositioned as an NCV.

• Surveillance Requirement 3.8.1.7 requires, in part, that the EDG output frequency stabilizes between 58.8 and 61.2 hertz within 10.0 seconds of the start signal. On August 15, 2007, Division 2 EDG was started for a scheduled surveillance test.

The licensee identified that the EDG output frequency took 13.1 seconds to stabilize within the required frequency range due to paint overspray on the fuel injector metering rods that occurred approximately 4 months earlier. This event is described in the licensees CAP as CR-RBS-2007-3609. This issue is more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events. This issue was of very low safety significance (Green) because it did not represent an actual loss of safety function associated with the EDG providing power to safety related equipment during accident conditions.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

M. Chase, Manager, Training and Development

J. Clark, Assistant Operations Manager - Training

C. Forpahl, Manager, Engineering Programs & Components

B. Heath, Superintendent, Chemistry

K. Higginbotham, Assistant Operations Manager - Shift

B. Houston, Manager, Radiation Protection

A. James, Superintendent, Plant Security

J. Leavines, Manager, Emergency Preparedness

J. Loque, Manager, Plant Maintenance

D. Lorfing, Manager, Licensing

J. Maher, Superintendent, Reactor Engineering

W. Mashburn, Manager, Design Engineering

B. Matherne, Manager, Planning and Scheduling/Outage

R. McAdams, Manager, System Engineering

J. Miller, Manager, Operations

E. Olson, General Manager - Plant Operations

E. Roan, Manager, Outage

J. Roberts, Director, Nuclear Safety Assurance

P. Russell, Manager, Corrective Action Program

J. Venable, Senior Site Vice President

D. Wiles, Director, Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000458/2007005-01 NCV Failure to Evaluate the Magnitude and Extent of Radiological Hazards Results in Personnel Contaminations (Section 2OS1.1)

05000458/2007005-02 NCV Failure to Follow RWP and Radiation Worker Expectations (Section 2OS1.2)

05000458/2007005-03 NCV Failure to Post a Radiation Area (Section 2OS1.3)

05000458/2007005-04 NCV RPS Terminal Board Loose Connection Results in a Reactor Scram (Section 4OA3)

05000458/2007005-05 NCV Inadequate Preventive Maintenance Strategy Results in a Breakers Failure to Promptly Open Due to Hardened Grease Results in a Complicated Reactor Scram (Section 4OA3)

Attachment

05000458/2007-06 FIN Inadequate Preventative Maintenance Results in a Plant Down Power (Section 4OA3)

Closed

50-458/2007-004-00 LER EDG Failed Surveillance Test Due to Paint on Fuel Injector Control Linkage (Section 4OA3)

50-458/2007-005-00 LER Unplanned Reactor Scram During Surveillance Testing Due to Damaged Terminal Board (Section 4OA3)

50-458/2007-006-00 LER Uplanned Reactor Scram Due to Transformer Fault (Section 4OA3)