IR 05000416/2006005

IR 05000416/2006-005; 10/1/06 - 12/31/06; Grand Gulf Nuclear Station; Post Maintenance Testing, Follow Up of Events and Notices of Enforcement Discretion

ML070360738
Person / Time
Site:	Grand Gulf
Issue date:	02/05/2007
From:	Hay M NRC/RGN-IV/DRP/RPB-C
To:	Brian W Entergy Operations
References
IR-06-005
Download: ML070360738 (30)

Text

February 5, 2007William R. Brian, Vice President of Operations Grand Gulf Nuclear Station Entergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150 SUBJECT:GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTIONREPORT 05000416/2006005

Dear Mr. Brian:

On December 31, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Grand Gulf Nuclear Station facility. The enclosed inspection report documents the inspection findings, which were discussed on January 10, 2007, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance 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 of very low safety significance (Green). Oneof the findings was determined to involve violations of NRC requirements; however, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating the finding as a noncited violation (NCV) consistent with Section VI.A of the NRC Enforcement Policy. If you contest this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Grand Gulf Nuclear Station facility.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be made available electronically for public inspection Entergy Operations, Inc.-2--2-in the NRC Public Document Room or from the Publicly Available Records (PARS) componentof NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/Michael C. Hay, ChiefProject Branch C Division of Reactor ProjectsDocket: 50-416License: NPF-29

Enclosure:

Inspection Report 05000416/2006005 w/Attachment: Supplemental Information

REGION IV Docket:50-416Licenses:NPF-29 Report No.:05000416/2006005 Licensee:Entergy Operations, Inc.

Facility:Grand Gulf Nuclear Station Location:Waterloo Road Port Gibson, Mississippi 39150Dates:October 1 through December 31, 2006 Inspectors:G. Miller, Senior Resident InspectorA. Barrett, Resident Inspector P. Elkmann, Emergency Preparedness InspectorApproved By:Michael C. Hay, ChiefProject Branch C Division of Reactor Projects Enclosure-2-

SUMMARY OF FINDINGS

IR 05000416/2006005; 10/1/06 - 12/31/06; Grand Gulf Nuclear Station; PostmaintenanceTesting, Followup of Events and Notices of Enforcement DiscretionThis report covered a 3-month period of inspection by resident inspectors and Regional officeinspectors. The inspection identified two Green findings, one of which was a noncited violation.

The significance of most findings is indicated by their color (Green, White, Yellow, or Red)using Inspection Manual Chapter 0609, "Significance Determination Process." Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management's review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.

Cornerstone: Initiating Events

Green.

The inspectors reviewed a Green, self-revealing finding for failure to implementpreventive maintenance on the bus duct cooling system components prior to system failures, causing a plant transient. The licensee entered this into their corrective action program as Condition Report CR-GGN-2006-3996.The finding is more than minor since it affects the equipment performance attribute ofthe 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 the NRC Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the finding has a very low safety significance since it did not contribute to the likelihood of a loss of coolant accident, did not contribute to a loss of mitigation equipment, and did not increase the likelihood of a fire or internal/external flood (Section 4OA3).

Cornerstone: Mitigating Systems

Green.

The inspectors reviewed a Green, self-revealing, noncited violation of TechnicalSpecification 5.4.1(a) for failure to follow station maintenance procedures while troubleshooting the control rod drive Pump A hand switch green indicating light socket.

The licensee entered this into their corrective action program as Condition Report CR-GGN-2006-4474.The finding is more than minor since it affects the human performance attribute of themitigating systems cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Additionally, improper maintenance practices on control room equipment could lead to a more significant safety concern. Using the NRC Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, inspectors determined that the finding has very low safety significance because it did not result in a loss of safety function. This finding has a crosscutting aspect in the area of Enclosure-3-human performance associated with work practices in that licensee personnelproceeded to troubleshoot the bulb in the face of uncertainty surrounding the required bulb type and expected system response (Section 1R19).

B.Licensee-Identified Violations

None.

Enclosure-4-

REPORT DETAILS

Summary of Plant StatusGrand Gulf Nuclear Station (GGNS) began the inspection period at 100 percent rated power. On November 8, 2006, power was reduced to approximately 75 percent due to high temperature on the generator to main transformer bus duct. Power was increased to 100 percent on November 9. On December 19 and 22, 2006, short duration power reductions to approximately 95 percent power were performed due to emergent maintenance on a condensate booster pump. On December 23, the plant reduced power to 80 percent due to a loss of feedwater heating event. The plant returned to 100 percent power on December 25.

Other than the above noted events, the plant remained at or near full rated thermal power, except for planned control rod pattern adjustments and control rod drive maintenance and testing.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection (71111.01)Readiness For Impending Adverse Weather Conditions

a. Inspection Scope

On October 16, 2006, the inspectors completed a review of the licensee's readiness forimpending adverse weather involving severe thunderstorms. The inspectors:

(1) evaluated implementation of the adverse weather preparation procedures and compensatory measures for the affected conditions before the onset of adverse weather conditions;

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

(3) reviewed maintenance records to determine that applicable surveillance requirements were current before the anticipated severe thunderstorms developed; and

(4) reviewed plant modifications, procedure revisions, and operator workarounds to determine if recent facility changes challenged plant operation.Documents reviewed by the inspectors included:

• Off-Normal Event Procedure 05-1-02-VI-2, "Hurricanes, Tornados, and SevereWeather," Revision 106*Corporate Procedure ENS-EP-302, "Severe Weather Response," Revision 4 The inspectors completed one sample.

-5-

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04).1Partial System Walkdowns

a. Inspection Scope

The inspectors:

(1) walked down portions of the three listed risk important systems andreviewed 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 UFSAR and corrective action program (CAP) to ensure problems were being identified and corrected. *On October 26, 2006, the inspectors walked down the reactor water cleanupsystem following a system outage for planned maintenance.*On December 4, 2006, the inspectors walked down Train B of the control room airconditioning and standby fresh air system following planned maintenance.*On December 19, 2006, the inspectors walked down Train B of the drywell purgesystem while Train A was out of service due to unplanned maintenance.Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed three samples.

b. Findings

No findings of significance were identified..2Complete System Walkdown

a. Inspection Scope

The inspectors:

(1) reviewed plant procedures, drawings, the UFSAR, TSs, and vendormanuals to determine the correct alignment of the standby service water system;

(2) reviewed outstanding design issues, operator workarounds, and UFSAR documents to determine if open issues affected the functionality of the standby service water system; and

(3) verified that the licensee was identifying and resolving equipment alignment problems.

-6-Documents reviewed by the inspectors included:*P&I Diagram M-1061A, "Standby Service Water System," Revision 61

• P&I Diagram M-1061B, "Standby Service Water System," Revision 47

• P&I Diagram M-1061C, "Standby Service Water System," Revision 36

• P&I Diagram M-1061D, "Standby Service Water System," Revision 38

• System Operating Instruction 04-1-01-P41-1, "Standby Service Water System,"Revision 124The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

a. Inspection Scope

Quarterly InspectionThe inspectors walked down the seven listed plant areas to assess the materialcondition of active and passive fire protection features and their operational lineup and readiness. The inspectors:

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

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

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

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

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

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

(7) reviewed the UFSAR to determine if the licensee identified and corrected fire protection problems. *October 2, 2006, Reactor Heat Removal A Pump Room (Room 1A103)

• October 2, 2006, Equipment Drain Transfer Room (Room 1A107)

• October 3, 2006, Reactor Heat Removal B Heat Exchanger Room (Room 1A206)

• October 3, 2006, Division II Switchgear Room (Room 1A207)

-7-*October 3, 2006, Reactor Core Isolation Cooling Pump Room (Room 1A104)*October 4, 2006, Division I Switchgear Room (Room 1A219)

• November 29, 2006, Auxiliary Building Elevator Shaft Documents reviewed by the inspectors included:

• Grand Gulf Nuclear Station Fire Pre-plans, Revision 15

• Procedure 10-S-03-4, "Fire Prevention: Control of Combustible Material,"Revision 14*Surveillance Procedure 06-ME-SP64-R-0045, "Ventilation System Fire DampersInspection," Revision 106*Plant Drawing M-1866, "Blockouts and Penetrations, Auxiliary Building El. 166'-0"Area 10," Revision 20*Plant Drawing M-1466, Heating Ventilation and Air Conditioning, Auxiliary BuildingEl. 166'-0" Area 10," Revision 15 The inspectors completed seven samples.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)Semiannual Internal Flooding

a. Inspection Scope

The inspectors:

(1) reviewed the UFSAR, the flooding analysis, and plant procedures toassess seasonal susceptibilities involving internal flooding;

(2) reviewed the UFSAR and CAP to determine if the licensee identified and corrected flooding problems;

(3) inspected bunkers and manholes to verify the adequacy of:

(a) sump pumps,

(b) level alarm circuits,

(c) cable splices subject to submergence, and

(d) drainage;

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

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

(a) equipment seals located below the floodline,

(b) floor and wall penetration seals,

(c) watertight door seals,

(d) common drain lines and sumps,

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

(f) temporary or removable flood barriers. October 12, 2006, Residual heat removal system Train B pump room

-8-Documents reviewed by the inspectors are listed in the attachment.The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07A)

a. Inspection Scope

The inspectors reviewed licensee programs, verified performance against industrystandards, and reviewed critical operating parameters and maintenance records for the Division I drywell purge compressor oil cooler and control room air conditioning Train A heat exchanger. The inspectors verified that:

(1) performance tests were satisfactorily conducted for heat exchangers/heat sinks and reviewed for problems or errors;

(2) the licensee utilized the periodic maintenance method outlined in Electric Power Research Institute NP-7552, "Heat Exchanger Performance Monitoring Guidelines";

(3) the licensee properly utilized biofouling controls;

(4) the licensee's heat exchanger inspections adequately assessed the state of cleanliness of their tubes, and

(5) the heat exchanger was correctly categorized under the Maintenance Rule. Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11)

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactoroperators to assess training, operator performance, and the evaluator's critique.

Specifically, the training scenarios observed involved a variety of failures and events that could be chosen by simulator instructors to exercise the shift technical advisor overview function. This exercise also involved simulating human error in the operating crew's decision-making process, thus allowing the shift technical advisor to identify and correct the error. Documents reviewed by the inspectors included:

• Lesson Plan GSMS-LOR-STA00, "Shift Technical Advisor Training andExamination Scenarios," Revision 1

-9-The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed the following two systems in order to:

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

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

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

(4) evaluate the handling of SSC issues reviewed under the requirements of the maintenance rule; 10 CFR Part 50, Appendix B; and the TSs. *November 28, 2006, Plant Air System (P51)*December 5, 2006, Leak Detection System (E31)Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13).1Risk Assessment and Management of Risk

a. Inspection Scope

The inspectors reviewed the one listed assessment activity to verify:

(1) performance ofa risk assessment 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 recognized, and/or entered as applicable, the appropriate licensee-established risk category according to the risk assessment results and licensee procedures; and

(4) that the licensee-identified and corrected problems related to maintenance risk assessments.*Work Order (WO) 94052, Division I reactor protection system relay replacement Documents reviewed by the inspectors included:*GGNS Equipment Out of Service Risk Monitor User's Manual (Model 2d),February 14, 2006

-10-*Administrative Procedure 01-S-18-6, "Risk Assessment of Maintenance Activities,"Revision 3The inspectors completed one sample.

b. Findings

No findings of significance were identified..2Emergent Work Control

a. Inspection Scope

For the work activity listed below, the inspectors:

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

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

(3) reviewed the UFSAR to determine if the licensee identified and corrected risk assessment and emergent work control problems. *WO 95184, Division I containment hydrogen analyzer instrument line primarycontainment isolation valve control power failure*WO 97315, Division II load shedding and sequencing panel test light failure The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors:

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

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

(3) evaluated compensatory measures associated with operability evaluations;

(4) determined degraded component impact on any TS;

(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.

-11-*Condition Report CR-GGN-2006-03940, Error in emergency core cooling systempump and engineered safety features room cooler calculations*Condition Report CR-GGN-2006-03991, Degraded air flow in the fuel pool coolingand cleanup room cooler*Condition Report CR-GGN-2006-04198, Reactor water cleanup containmentisolation valve failure*Condition Report CR-GGN-2006-04660, Reactor core flow degradation

• Condition Report CR-GGN-2006-04698, Control rods experiencing friction duringstroke time testing due to suspected channel bowDocuments reviewed by the inspectors are listed in the attachment.

The inspectors completed five samples.

b. Findings

No findings of significance were identified.

1R19 Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors selected the four listed postmaintenance test activities of risk significantsystems 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, test data results were complete and accurate, test equipment was removed, the system was properly realigned, and deficiencies during testing were documented. The inspectors also reviewed the UFSAR to determine if the licensee identified and corrected problems related to postmaintenance testing. *WO 91592, Postmaintenance test following replacement of hydraulic control unitscram valve diaphragm*WO 50325883, Postmaintenance test following replacement of reactor coreisolation cooling steam supply bypass valve and the trip/throttle valve motors *WO 94533, Postmaintenance test following replacement of a defective GM tube and calibration of the containment ventilation radiation monitor

-12-*WO 88849, Postmaintenance test following replacement of the reactor coreisolation cooling system trip and throttle control valve*WO 85335, Postmaintenance testing following control rod drive indicating lightsocket replacement Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed five samples.

b. Findings

Introduction:

The inspectors reviewed a Green, self-revealing, noncited violation (NCV)of TS 5.4.1(a) for failure to follow station maintenance procedures while troubleshooting the control rod drive (CRD) Pump A hand switch green indicating light socket.Description: On November 16, 2006, a maintenance supervisor was in the control roomwalking down control panels and reviewing deficiency tags. The maintenance supervisor noticed a deficiency tag on the CRD Pump A hand switch green indicating light. The deficiency tag indicated that the light socket was defective. It was suspected that debris, remnants from a previous broken bulb, was stuck in the socket. A work request had been written to repair the socket detailing this information. A conversation ensued between a nonlicensed operator and the maintenance supervisor regarding light bulbs used for a new air compressor in the plant. This conversation led the maintenance supervisor to suspect that the wrong bulb may have been installed in the CRD Pump A hand switch green indicating light. The shift manager was unaware that troubleshooting efforts for the CRD Pump A green indicating light socket were in progress.Although the deficiency tag indicated that a different problem existed and that a workrequest had been written, the maintenance supervisor was confident that the problem was an incorrect bulb. Neither the work request nor any other reference documents were consulted. At the request of the maintenance supervisor, a control room operator removed the bulb from the CRD Pump A hand switch green indicating light and replaced the bulb with a different type. When the light failed to illuminate as expected, they realized that, with the CRD Pump A running, the green indicating bulb should not light.

At this point, the control room operator and the maintenance supervisor decided to test the new style bulb in the nonrunning CRD Pump B hand switch green indicating light socket. The control room operator removed the CRD Pump B green indicating light bulb and the maintenance supervisor placed the new bulb into the socket. The socket immediately short circuited, causing extensive arcing and sparking and some residual smoke around the panel. Several Division 2 annunciators alarmed and there was physical damage to the light socket, including burn marks on the panel; however, no plant equipment tripped or was isolated. After further investigation, the licensee determined that the maintenance supervisor had installed a 25 volt dc light bulb into the lamp socket instead of the required 120 volt ac light bulb. Neither the work request for the CRD Pump A green indicating light nor any other reference documents were consulted.

-13-Analysis: The performance deficiency associated with this violation is a failure to follow station procedures while troubleshooting the CRD Pump A green indicating light. The finding is more than minor since it affects the human performance attribute of the mitigating systems cornerstone and affects the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Additionally, improper maintenance practices on control room equipment, if left uncorrected, could lead to a more significant safety concern. Using the NRC Manual Chapter 0609, "Significance Determination Process,"

Phase 1 worksheet, inspectors determined that the finding has very low safety significance because it did not result in a loss of safety function. This finding has a crosscutting aspect in the area of human performance associated with work practices inthat licensee personnel proceeded to troubleshoot the bulb in the face of uncertainty surrounding the required bulb type and expected system response.Enforcement: TS 5.4.1(a) requires written procedures to be implemented asrecommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Section 5.11[8](h) of Procedure EN-OP-115, "Conduct of Operations," Revision 2, requires operators to replace burned out indicating lamps with the proper bulb. Contrary to this requirement, on November 16, 2006, a control room operator installed an incorrect bulb causing arcing and sparking in a control room panel and several spurious annunciators. Because this violation was of very low safety significance and was entered into the CAP as CR-GGN-2006-4474, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy:

NCV 05000416/2006005-01, Failure to Follow Station Procedures for Conducting Maintenance Activities.

1R22 Surveillance Testing

(71111.22)

a. Inspection Scope

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

(1) preconditioning;

(2) evaluation of testing impact on the plant;

(3) acceptance criteria;

(4) test equipment;

(5) procedures;

(6) jumper/lifted lead controls;

(7) test data;

(8) testing frequency and method demonstrated TS operability;

(9) test equipment removal;

(10) restoration of plant systems;

(11) fulfillment of ASME Code requirements;

(12) updating of performance indicator data;

(13) the accuracy of engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test acceptance criteria;

(14) reference setting data; and

(15) annunciator and alarm setpoints. The inspectors also verified that the licensee identified and implemented any needed corrective actions associated with the surveillance testing. *October 10, 2006, Reactor heat removal quarterly valve inservice testing perSurveillance Procedure 06-OP-E12-Q-0006, "LPCI Subsystem B MOV Functional Test," Revision 107

-14-*October 13, 2006, Standby gas treatment system valve operability testing perSurveillance Procedure 06-OP-1T48-Q-0002, "Standby Gas Treatment System A Valve Test," Revision 103*October 13, 2006, Suppression pool makeup system valve operability testing perSurveillance Procedure 06-OP-1E30-Q-0001, "Suppression Pool Makeup Valve Operability Test," Revision 101*December 7, 2006, Control rod friction testing for channel bow per EquipmentPerformance Instruction 04-1-03-C11-7, "Control Rod Settle and Insertion Test,"

Revision 004Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed four samples.

b. Findings

No findings of significance were identified.

===Cornerstone: Emergency Preparedness1EP6Drill Evaluation (71114.06)

a. Inspection Scope

For the two listed drills contributing to Drill/Exercise Performance and emergencyresponse organization performance indicators, the inspectors:

(1) observed the training===

evolution to assess classification, notification, and Protective Action Requirement development activities;

(2) compared 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 Nuclear Energy Institute 99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria. *On October 18, 2006, the inspectors observed the emergency responseorganization during the force-on-force exercise documented in NRC Inspection Report 05000416/2006201. This included the emergency response organization simulating activation of the Technical Support Center and the notification of offsite authorities. *On November 1, 2006, the inspectors observed the emergency responseorganization's quarterly drill which simulated a fire and subsequent anticipated transient without scram, core damage, and containment breach. The inspectors also observed a shift turnover between two emergency response organization teams.

-15-Documents reviewed by the inspectors included:*Emergency Plan Procedure 10-S-01-1, "Activation of the Emergency Plan,"Revision 115*2006 4 th Quarter Emergency Preparedness Drill Evaluator's Summary*Drill Emergency Notification Forms

• December 13, 2006, Memorandum to M. F. Guynn from R. Van Den Akker, "2006 4 th Quarter ERO Training Drill Report"*Condition Report CR-GGN-2006-04274

• Condition Report CR-GGN-2006-04336 The inspectors completed two samples.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems

.1Routine 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 WOs and condition reports and attending corrective action review and work control meetings. The inspectors:

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

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

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

b. Findings

No findings of significance were identified.

-16-.2Selected Issue Follow-up Inspection

a. Inspection Scope

In addition to the routine review, the inspectors reviewed the cumulative effects ofoperator 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.Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings and Observations

No findings of significance were identified..3Semiannual Trend Review

a. Inspection Scope

The inspectors completed a semiannual trend review of repetitive or closely relatedissues that were documented in condition reports, maintenance WOs, system health reports, and corrective action trend reports to identify trends that might indicate the existence of more safety significant issues. The inspectors' review consisted of the 6-month period from June 1 through December 31, 2006. When warranted, some of the samples expanded beyond those dates to fully assess the issue. The inspectors compared and contrasted their results with the results contained in the licensee's quarterly trend reports for the second and third quarter of 2006. Corrective actions associated with a sample of the issues identified in the licensee's trend report were reviewed for adequacy. The review also included issues documented outside the corrective action process, including repetitive and/or rework maintenance lists, departmental problem lists, system health reports, quality assurance audits/surveillances, self-assessment reports, and maintenance rule assessments.Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings and Observations

No findings of significance were identified.

-17-4OA3Followup of Events and Notices of Enforcement Discretion (71153).1Personnel Performance

a. Inspection Scope

The inspectors responded to an unplanned transient on November 8, 2006, to:

(1) evaluate operator performance by reviewing operator logs, plant computer data, and strip charts;

(2) evaluate the initiating cause of the transient; and

(3) determine if operator response was appropriate and in accordance with procedures.Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

b. Findings

Introduction:

The inspectors reviewed a Green, self-revealing finding for failure toimplement preventive maintenance on the bus duct cooling system components prior to system failures, causing a plant transient.Description: On November 8, 2006, the station lowered reactor power to 75 percent inorder to maintain isophase bus bar temperatures below their rated design limits due to a failure of the isophase bus duct cooling system. The isophase bus duct cooling system employs two redundant forced-air cooling trains, each consisting of a blower, a heat exchanger, a cooling water flow control valve, and associated dampers. The cooling water system combines on the discharge side of the heat exchangers and uses a single common flow switch. The inspectors determined that the licensee failed to follow the vendor manual recommendations for system operation and preventive maintenance, which led to a degraded cooling system. A series of events challenged both trains of the system and ended with an unplanned plant power reduction. *On October 22, 2006, the Train A isophase bus duct cooler fan shaft separatedfrom the motor with the motor running. The standby isophase bus duct cooling Train B was placed into service.*Two days later on October 24, 2006, a vibration analysis found that the Train Bmotor was experiencing high vibrations. Although the vendor manual recommended vibration analysis on an annual basis, no previous vibration data had been taken, leaving the licensee with no vibration data for comparison. As compensatory action, the licensee implemented daily fan shaft bearing vibration monitoring and operator rounds to check the bus duct temperatures twice per shift.*On November 8, 2006, in order to remove Train B from service due to continuinghigh vibrations, operations swapped to bus duct Train A once the corrective maintenance, including replacement of the motor, shaft, and fan assembly was complete. No system anomalies were discovered during postmaintenance testing.

During the system swap, the operator observed cooling water control valve

-18-movement on the Train A flow control valve. The operator assumed that the valvedid a full open stroke, but in reality the valve had only partially opened. In addition, the associated flow switch had concurrently failed upscale, inhibiting a low flow alarm that should have annunciated.*Later in the evening of November 8, 2006, the turbine building operator noticedthat both bus duct cooling train flow control valves were closed. The operator checked the isophase bus bar temperatures and discovered that the West bus bar was 135 degrees Celsius and the East bar was 115 degrees Celsius. The design rating, as set by Institute of Electrical and Electronics Engineers C37.23-1987, is 105 degrees Celsius. The bus duct coolers had limited cooling water flow for approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Operations placed Train B of bus duct cooling back in service; however, the train could not provide enough cooling to return the isophase bus bar temperatures below the design limit. Consequently, reactor power was reduced to approximately 75 percent to reduce current on the generator to main transformer busses, thereby lowering heat output and restoring bus duct temperature.Vendor manuals recommend fan shaft lubrication on a 3-month basis and annualpreventive maintenance and inspections of system components. The inspectors determined that preventive maintenance had only been performed on the blower motors.

The licensee had failed to perform preventive maintenance on the blower couplings, blower bearings, heat exchangers, cooling water flow control valves and valve actuators, system dampers, or the flow switch from the beginning of plant operation. In addition to the preventive maintenance recommendations, the forced-air cooling vendor manual also recommends periodically operating standby system trains and components for 30 minutes, once a month. The inspectors discovered that no operating strategy existed to periodically alternate isophase bus duct cooling system trains, and Train B had not been in operation for several years prior to being placed in service on October 22, 2006.Analysis: The performance deficiency associated with this finding was a failure to followvendor recommendations for the operation and maintenance of the bus duct cooling system. 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 the NRC Manual Chapter 0609, "Significance Determination Process,"

Phase 1 worksheet, the finding has a very low safety significance since it did not contribute to the likelihood of a loss of coolant accident, did not contribute to a loss of mitigation equipment, and did not increase the likelihood of a fire or internal/external flood.Enforcement: Because the affected equipment was nonsafety-related, no violation ofregulatory requirements occurred. This issue was entered into the Corrective Action Program as CR-GGN-2006-3996. This finding is identified as Finding FIN 05000416/2006005-02, Neglect of Bus Duct Cooling System Results in Unplanned Power Reduction.

-19-.2Event Report Review(Closed) Licensee Event Report 05000416/2005002-00, Incorrect Assumption Used inDevelopment of Air Operated Valve ProgramThe inspectors determined that a licensee-identified violation of very low safetysignificance (Green) occurred. This issue is documented in Section

4OA7 of NRC

Integrated Inspection Report 05000416/2005003. This licensee event report is closed.4OA5Other Activities.1(Closed) Temporary Instruction 2515/169: Mitigating Systems PerformanceIndex (MSPI) Verification

a. Inspection Scope

The inspectors sampled licensee data to verify that the licensee correctly implementedthe MSPI guidance for reporting unavailability and unreliability of the monitored safety systems. The monitored systems included the emergency alternating current power, high pressure injection (HPCI), heat removal (RCIC), residual heat removal, and cooling water (SW). The inspectors reviewed operating logs, limiting condition of operation database records, maintenance records, condition reports, surveillance test data, and the maintenance rule database to verify that the licensee properly accounted for planned unavailability, unplanned unavailability, and equipment failures. Documents reviewed by the inspectors are listed in the attachment.

(1)For the sample selected, did the licensee accurately document the baseline plannedunavailability hours for the MSPI systems?No. The inspectors validated the baseline planned unavailability hours for each of thefive monitored systems and identified a generic error in the methodology used to determine reported baseline planned unavailability data. Per Nuclear Energy Institute 99-02, unavailability data that is designated as "short duration unavailability,"

which includes surveillance tests that result in less than 15 minutes of unavailability time per train, need not be counted as unavailable hours. The inspectors discovered that the licensee was including the short duration unavailability in the calculation for the baseline planned unavailability time and not including it in the submitted quarterly unavailability data. This would have a nonconservative impact on the unavailability index calculation.

The licensee has documented this discrepancy in Condition Report CR-GGNS-2006-04606. The licensee plans to correct this discrepancy during a revision to the MSPI Basis Document in the next quarter.

(2)For the sample selected, did the licensee accurately document the actual unavailabilityhours for the MSPI systems?

Yes.

-20- (3)For the sample selected, did the licensee accurately document the actual unreliabilityinformation for each MSPI monitored component?

Yes.

(4)Did the inspector identify significant errors in the reported data, which resulted in achange to the indicated index color? Describe the actual condition and correctiveactions taken by the licensee, including the date when the revised PI information wassubmitted to the NRC.The licensee has not performed a calculation to verify that the index has exceeded theGreen to White threshold due to the discrepancy documented in question one. The licensee has documented in the condition report that the "differences should be very small, insignificant, and will not change Grand Gulf's current MSPI status." The licensee plans to submit a revision to the MSPI Basis Document in the next quarter.

(5)Did the inspector identify significant discrepancies in the Basis Document which resultedin:

(1) a change to the system boundary;

(2) an addition of a monitored component; or(3) a change in the reported index color? Describe the actual condition and correctiveactions taken by the licensee, including the date of when the Basis Document wasrevised.No such issues were identified.

b. Findings

No findings of significance were identified.4OA6Meetings, Including ExitOn January 10, 2007, the resident inspectors presented the inspection results toMr. W. Brian, Vice President, Operations, and members of his staff, who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspections by the resident inspectors. ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Abbott, Supervisor, Quality Assurance

C. Bottemiller, Manager, Plant Licensing

R. Brian, Vice President, Operations

M. Causey, Senior Lead Technical Specialist

R. Collins, Manager, Operations

D. Coulter, Licensing Specialist, Plant Licensing

L. Eaton, Senior Lead Engineer

C. Ellsaesser, Manager, Planning and Scheduling

M. Guynn, Manager, Emergency Preparedness

E. Harris, Acting Director, Nuclear Safety Assurance

M. Krupa, Acting General Manager, Plant Operations

M. Larson, Senior Licensing Engineer

J. Miller, Manager, Training

J. Robertson, Manager, Refueling Services

M. Rohrer, Manager, System Engineering

T. Tankersley, Manager, Training

D. Wiles, Director, Engineering

D. Wilson, Supervisor, Design Engineering

R. Wilson, Superintendent, Radiation Protection

P. Worthington, Supervisor, Engineering

NRC personnel

W. Walker, Senior Project Engineer, Reactor Project Branch C

R. Bywater, Senior Reactor Analyst, Region IV

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and

Closed

05000416/2006005-01NCVFailure to Follow Station Procedures for ConductingMaintenance Activities05000416/2006005-02FINNeglect of Bus Duct Cooling System Results inUnplanned Power Reduction

AttachmentA-2

Closed

05000416/2005-002-00LERIncorrect Assumption Used in Development of AirOperated Valve Program

LIST OF DOCUMENTS REVIEWED

In addition to the documents referred to in the inspection report, the following documents wereselected and reviewed by the inspectors to accomplish the objectives and scope of the